HomeMy WebLinkAbout2020-10-15; Clean Energy Alliance JPA; ; Clean Energy Alliance Operational, Administrative and Regulatory Affairs UpdateClean Energy Alliance
JOINT POWERS AUTHORITY
Staff Report
DATE: October 15, 2020
TO: Clean Energy Alliance Board of Directors
FROM: Barbara Boswell, Interim Chief Executive Officer
ITEM 2: Clean Energy Alliance Operational, Administrative and Regulatory Affairs Update
RECOMMENDATION:
1)Receive and File Community Choice Aggregation Update Report from Interim CEO.
2)Receive Community Choice Aggregation Regulatory Affairs Report from Special Counsel.
BACKGROUND AND DISCUSSION:
This report provides an update to the Clean Energy Alliance (CEA) Board regarding the status of the
operational, administrative and regulatory affairs activities.
OPERATIONAL UPDATE
CEA is meeting its milestones for the implementation of its community choice aggregation (CCA)
program and is on track to begin serving customers in May 2021/June 2021. (Attachment A - Clean
Energy Alliance Timeline of Implementation Action Items).
CEA Launch Schedule
San Diego Gas & Electric (SDG&E) has been working over the past several years on their Customer
Information System replacement program, known as Envision. They had committed to, and were on
track, for a January 4, 2021 go live, despite the challenges of working remote in the COVID-19
environment. With a January 2021 go live, SDG&E committed to supporting the CEA launch of May
2021. On Friday July 10, CEA staff, its regulatory attorney Ty Tosdal and data manager Calpine Energy
Solutions participated in a call with San Diego Community Power and SDG&E regarding the recently
approved California Public Utilities Commission (CPUC) Decision D. 20-06-003, which requires the
Investor Owned Utilities (IOU) to adopt rules and policy changes designed to reduce the number of
residential disconnections, provide assistance with debt forgiveness and offer extended payment plans.
The decision is required to be implemented by the IOUs April 2021. This timing has presented a
challenge to SDG&E to keep its go live date of January 4, 2021 while also meeting the requirements of
the decision. SDG&E submitted a letter to the CPUC requesting an extension to September 30, 2021, for
implementing the new procedures and policies required by the decision. This request was denied by the
CPUC, resulting in SDG&E postponing implementation of its Envision project to April 2021.
CEA and its consultants have been working diligently with SDG&E to develop a launch schedule that
minimized impact to CEA while also minimizing the risk of incorrect bills being sent to customers.
SDG&E has proposed a two-phased schedule with accounts transitioning to CEA in May and June 2021.
May 2021 Phase 1 would include the transition of Solana Energy Alliance customers to CEA as well as
customers who do not have complex billing plans in Carlsbad and Del Mar. Those customers who have
been identified with complex billing plans would transition in June 2021. CEA is working with its
consultants, Pacific Energy Advisors and Calpine Energy Solutions to evaluate the impact of this two-
phased approach from an operational and financial perspective. Preliminary analysis indicates that the
October 15, 2020
Operational & Regulatory
Update
Page 2 of 4
proposed phasing does not have a material impact from a financial perspective. Staff continues to work
with Calpine and SDG&E to fine tune the customer list for each phase.
Staff anticipates providing the Board with an updated pro forma reflecting this new phased approach, as
well as updated rates related to the SDG&E ERRA Rate Proceeding at the November Board meeting.
The CEA Board is being asked to authorize the Interim Chief Executive Officer to execute a letter
agreement with SDG&E for the two-phased implementation at today's meeting.
Expansion of Clean Energy Alliance
Staff has no update regarding CEA expansion.
Resource Adequacy Compliance
As a load serving entity, serving customers in 2021, CEA has an obligation to procure Resource Adequacy
(RA), based on quantities allocated by CPUC and California Independent System Operator (CAISO). RA
procurements does not supply any energy to CEA or its customers, rather it commits the seller to be
available to supply energy to the grid if called upon by the CAISO and reduce the possibility of outages.
This process is key to ensuring grid reliability. The RA compliance requirements, CEA has monthly and
annual reporting requirements. Upcoming reporting requirements are:
•Year-Ahead Compliance Demonstration — October 31, 2020
o Must demonstrate CEA has entered into contracts to meet CPUC requirements
•Monthly RA Compliance Reports begin in November 2020 (for January 2021 requirements)
CEA has been working diligently towards meeting CEA's Resource Adequacy procurement requirements
that must be reported by October 31, 2020 and expects to be compliant with requirements.
Long-Term Renewable Procurement
As a load serving entity, CEA will be required to procure 65% of its minimum state required renewable
portfolio standards in contracts of 10-years or longer. To ensure compliance with this requirement,
CEA's initial renewable energy solicitation is underway. The solicitation process, from beginning through
final execution can be lengthy, particularly in light of the impacts of COVID-19 on the renewable
development industry. The solicitation opened on July 1, 2020 with proposals due July 27, 2020. CEA's
consultant, Pacific Energy Advisors, has identified a short list of projects and negotiations are
proceeding. It is anticipated final contracts will be before the Board in late 2020/early 2021.
Administrative and Operational Policies
During the coming months as CEA prepares for its implementation and operation, policies will be
brought to the Board for consideration in future Board meetings. The policies as proposed will be based
on Government Code or regulatory requirements and best practices of successfully operational CCAs.
The policies and timeline as currently anticipated are:
November 19 Board Meeting
•Energy Risk Management Policy Approval
•January 21 Board Meeting
•Investment Policy
October 15, 2020
Operational & Regulatory
Update
Page 3 of 4
Contracts $50,000 - $100,000 entered into by Interim Chief Executive Officer
VENDOR DESCRIPTION AMOUNT
None to report
REGULATORY UPDATE
San Diego Gas & Electric Advice Letter 3605-E Requesting Approval of System Reliability Contracts
CEA filed a protest of the San Diego Gas & Electric Advice Letter 3605-E, Requesting Approval of System
Reliability Contracts. The basis of the protest was related to SDG&E's procurement of long-term
resources without taking into account the departing load related to CEA's implementation. CEA's
customers would carry the burden of the costs of these long-term contracts. The protest is consistent
with the adopted 2020 CEA Legislative and Regulatory Policy Platform that established that CEA would
support regulatory actions that jeopardize CEA's ability to self-procure. The necessity to submit the
protest came up after the last CEA Board meeting and prior to the October meeting. The filing of the
protest was completed in consultation with the CEA Board Chair.
San Diego Gas & Electric Advice Letter 3257-E, Regarding CCA Financial Security Requirement
At its October 8, 2020 meeting, the CPUC adopted its Resolution 5059, approving SDG&E's Advice Letter
(AL) 3257-E regarding the CCA Financial Security Requirement. Currently, CCAs were required to post a
$100,000 "bond" (in CEA's case a cash deposit) to provide funds to cover SDG&E costs should CEA have
an unplanned termination of service and return to customers to SDG&E service. SDG&E's AL 3257-E
implements new rules concerning the deposits, which, among other things, establishes a minimum
amount of $147,000, and provides the ability to satisfy the requirement with the option of a letter of
credit, surety bond, or cash deposit held in escrow by a third party commercial bank. CEA will be
required to fulfill the new requirements by December 7, 2020, and file an Advice Letter with the CPUC
confirming that it has satisfied the requirement. Staff has begun working on options to determine the
best course of action, and will provide a recommendation to the Board at its November Board meeting.
Attached is a regulatory report from Ty Tosdal, Special Counsel, providing a summary of key regulatory
proceedings (Attachment B - Tosdal APC Energy Regulatory Update).
FISCAL IMPACT
There is no fiscal impact by this action.
ATTACHMENTS:
Attachment A - Clean Energy Alliance Timeline of Implementation Action Items
Attachment B —Tosdal APC Regulatory Update
October 15, 2020
Operational & Regulatory
Update
Page 4 of 4
Attachment A
Clean Energy Alliance
Timeline of Action Items
CCA Program Related
Timing Description
3rd Qtr
10
4th Qtr
'20
1st Qtr
'21 Apr-21 May-21 Jun-21 Jul-21
9/1120 Marketing/Customer Outreach Plan Development & Kickoff
9/17/20 Bid Evaluation and Criteria Scoring System
9/17/20 Award Scheduling Coordinator Services Complete
Introduce/Adopt Energy Risk Ma nagement Policy
10/15
&
11/19
10/15/20 Records Retention Policy
System Testing with SDG&E
Set up Call Center/Scripting/IVR Recordings
11119/20 Credit Solution
12/17/20 CEA Default Products/programs/renewable energy policies
1/1/21 Create Customer Pre- a nd Post-Enrollment Notices
1121/21 investment Policy
2/1/21 Rate Setting
3/1/21 Customer Noticing
5/1/21 Launch - 2 phases May &June 2021
Key:
Board Actions/Activity
Staff/Consultant Activity
Marketing/Customer Outreach
CC_A Launch
Attachment B T SDAL
ENERGY & ENVIRONMENTAL LAW
ENERGY REGULATORY UPDATE
To: Barbara Boswell, Interim Executive Officer, Clean Energy Alliance
From: Ty Tosdal, Regulatory Counsel, Tosdal APC
Re: Energy Regulatory Update
Date: October 8, 2020
The energy regulatory update summarizes important decisions, orders, notices and
other developments that have occurred at the California Public Utilities Commission
("Commission") and that may affect Clean Energy Alliance ("CEA"). The summary presented
here describes high priority developments and is not an exhaustive list of the regulatory
proceedings that are currently being monitored or the subject of active engagement by CEA. In
addition to the proceedings discussed below, Tosdal APC monitors a number of other regulatory
proceedings as well as related activity by San Diego Gas & Electric ("SDG&E") and other
Investor-Owned Utilities ("IOUs").
1. SDG&E PCIA Trigger Application (A. 20-07-009)
SDG&E filed with the CPUC an update to their PCIA undercollection balancing account
(CAPBA) as directed by a September 18, 2020 All Ruling. SDG&E's CAPBA update is in
Attachment A of this report. SDG&E states that nothing has occurred since their filing of the
PCIA Trigger Application in July that would necessitate a change in the CAPBA balance
amount. The PABA is a rolling true-up between the forecasted components of the Indifference
Amount used to set the PCIA rates and the actual costs and revenues SDG&E experiences
during the year.
As SDG&E explained at the August 27 prehearing conference, amortizing the recovery
of the CAPBA undercollection from departing load customers for a period extending beyond
2020 creates logistical issues with respect to tracking, accounting and reimbursement that are
unique to SDG&E. These "logistical issues" refer to the administrative difficulties that will occur
due to CEA and SDCP launching service in early 2021 (with SDCP initiating service in several
phases), as well as the re-opening of Direct Access (DA) in January of 2021. The combination
of the large number of departing accounts and the unpredictability of how many customers will
depart at various times throughout 2021, along with the fact that these load departures will take
place after rates have been implemented on January 1, increases SDG&E's accounting
complexities.
In order to accurately track, account for and issue reimbursements for the CAPBA
balance, SDG&E would need to have a system that tracks the CAPBA balance at the individual
customer level. However, SDG&E does not have CAPBA balances recorded at a customer
1
Attachment B
T SDAL
ENERGY 8, ENVIRONMENTAL LAW
level; it only records CAPBA balances by vintage. SDG&E states they may be able to
accommodate an amortization period that extends beyond 2020 provided that bundled
customers who depart during the amortization period agree to forfeit the remainder of their
CAPBA refund.
2.SDG&E ERRA Forecast Proceeding (A. 20-04-014)
CEA and SDPC's counsel submitted to the CPUC a joint Opening Brief on September
25, 2020 which makes several requests of SDG&E. The Opening Brief is in Attachment A. First,
the brief asks the Commission to require SDG&E to provide a greater level of transparency
through substantially more detailed information regarding actual and forecasted PABA
balances, and the background information and testimony that make up the components of the
PABA calculations.
Second, the CCAs request that SDG&E correct an erroneous calculation of its Total
Indifference Amount. SDG&E has already acknowledged this approximate $84.5 million mistake
and has committed to correcting it prior to the November 2021 PABA revenue requirement
forecast. If this calculation had been done correctly, following Commission guidance to include
RA and RPS sales revenue as an offset to CRS Eligible Portfolio Costs, then SDG&E's
forecasted Indifference Amount would decrease by $49.2 million for RA sales and $35.3 million
for RPS sales, for a total reduction of $84.5 million.
Third, SDG&E's proposal to calculate the PCIA rate cap based on rates approved in the
CAPBA Trigger application would undercut the Commission's clear policy preference to avoid
rate shock for unbundled customers. If cap methodology is approved, it would result in capped
rates that are more than three times what the capped rate would otherwise be. The CCAs ask
that SDG&E rate cap methodology proposal is rejected.
Lastly, the CCAs request that the Commission conduct further review and clarification of
SDG&E's Green Tariff Shared Renewables (GTSR) program, which is in direct competition with
CCAs. Further review is needed because SDG&E has provided little to no information on the
justification for its GTSR rate forecasts and customer consumption estimates. More detail on
GTSP rates must be provided in this and future ERRA proceedings.
SDG&E's cooperation and transparency will be necessary to ensure that intervenors in
this proceeding have adequate time to analyze the data and to ensure that the PABA balance
SDG&E presents in the November Update is accurate and based on reasonable assumptions.
3.Direct Access Expansion (R. 19-03-009)
Phase 1 of the expansion (or "re-opening") of non-residential Direct Access (DA) will
begin on January 1, 2021 with an additional 4,000 GWh opening up for DA providers, per the
requirement of SB 237. On September 28, 2020 the CPUC Energy Division released a "Staff
Report Providing Recommendations on the Schedule to Reopen Direct Access" (Staff Report)
2
Attachment B
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ENERGY 8 ENVIRONMENTAL LAW
to inform the Legislature on issues concerning the additional expansion of the DA program
(Phase 2). The Staff Report is in Attachment A.
The Staff Report makes multiple recommendations regarding pre-requisites to any
further expansion of DA. Most notably, the report recommends that Direct Access NOT be
reopened until at least 2024, after the next IRP Compliance Period.
Ongoing lack of transparency and poor compliance by a number of DA providers
(Energy Service Providers) creates load uncertainly for both CCAs and IOUs. The report calls
out the numerous compliance citations, penalties and reporting shortcomings of these ESPs
and how the lack of transparency is detrimental to the planning and procurement activities of
CCAs. Additionally, because most ESPs procure the minimum amount of mandated renewable
energy, (as opposed to CCAs and IOUs that consistently exceed minimum RPS requirements)
the expansion of DA may have a negative effect on state-wide criteria air pollutant and GHG
reduction goals. The Staff Report calls for DA providers' compliance with IRP, RA and RPS
requirements prior to any further expansion of the program.
Reopening DA would allow nearly two-thirds of existing non-residential load, including
load that has recently migrated to CCA service, to freely migrate between IOU, ESP and CCA
service. The report cites The Customer Choice Project, which found that a central procurement
entity that procures on behalf of all load-serving entities may resolve some of the procurement
challenges caused load migration, since central procurement would be indifferent to which load-
serving entity is serving load. In addition, the Staff Report includes a recommendation of setting
an initial re-opening schedule in increments equal to 10 percent of eligible non-residential load
per year.
4.Integrated Resources Planning (R. 20-05-003)
CEA and SDCP submitted a Joint Protest (in Attachment A) to SDG&E's Advice Letter
3605-E on October 1, 2020. The protest is centered on SDG&E request to procure expensive,
long-term energy contracts despite knowing that 60% of their load will migrate to CCAs and DA
by 2022. This overprocurement will lead to increased non-bypassable charges for CCA
customers. The protest asks that the procurement requests be denied, or at the very least,
CCAs be permitted to purchase SDG&E's excess procurement.
5.Disconnections and Reconnections (R. 18-07-005)
The Joint IOUs submitted Advice Letter 3602-E in accordance with D. 20-06-003, the
decision implementing the Arrearage Management Plan program (AMP). CalCCA filed a protest
of AL 3602-E asking for clarification from the IOUs on (1) SDG&E's intent to render payments to
CCAs forgiven amounts (2) the frequency of AMP data reporting to CCAs (3) when SDG&E will
automate the AMP program. CalCCA's protest is in Attachment A.
3
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ENERGY 3 ENVIRONMENTAL LAW
Attachment A
4
Expedited Application of San Diego Gas &
Electric Company (U 902 E) Under the Power
Charge Indifference Adjustment Account
Trigger Mechanism.
BEFORE THE .PU ;LIC UTILITIES COMMISSION
OF TH STATE OF CALIFORNIA
Application 20-07-009
(Filed on July 10, 2020)
1,•A 4t • •ON'Fit0 -
FILED
10/01/20
04:59 PM
40 0%1E8
SAN DIEGO GAS & ELECTRIC COMPANY'S (U 902-E) UPDATE ON CAPBA
BALANCE AND REPORT RE ACCOUNTING AND BILLING SYSTEM PURSUANT
TO AL'S SEPTEMBER 18, 2020 RULING
Roger A. Cerda
San Diego Gas & Electric Company
8330 Century Park Court, CP32D
San Diego, CA 92123
Telephone: (858) 654-1781
Facsimile: (619) 699-5027
Email: rcerda@sdge.com
Attorney for:
SAN DIEGO GAS & ELECTRIC COMPANY
October 1, 2020
BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF CALIFORNIA
Expedited Application of San Diego Gas &
Electric Company (U 902 E) Under the Power
Charge Indifference Adjustment Account
Trigger Mechanism.
Application 20-07-009
(Filed on July 10, 2020)
SAN DIEGO GAS & ELECTRIC COMPANY'S (U 902-E) UPDATE ON CAPBA
BALANCE AND REPORT RE ACCOUNTING AND BILLING SYSTEMS PURSUANT
TO AL'S SEPTEMBER 18, 2020 RULING
I.INTRODUCTION
Pursuant to the September 18, 2020 email ruling issued by the Administrative Law Judge
("ALF) in the above-captioned proceeding ("Ruling"), San Diego Gas & Electric Company
("SDG&E") hereby submits this report providing an update on its Power Charge Indifference
Adjustment ("PCIA") undercollection balancing account ("CAPBA") balance, with the latest
amount, including an explanation of any events that may have impacted that balance. In
addition, as required by the AL's Ruling, SDG&E is also providing a more detailed explanation
of "the limitations of its accounting and billing systems and how those limitations prevent it from
collecting revenue in Calendar Year 2021 in order to bring the undcrcollection under seven
percent."
II.UPDATED CAPBA BALANCE
Table 1 below shows SDG&E's recorded CAPBA data for January 2020 through August
2020 and presents, for illustrative purposes, its current forecast of the CAPBA balance for
September 2020 through December 2020.
CAPBA Monthly Summary
ACTUAL January 31, 2020
ACTUAL February 29, 2020
ACTUAL March 31, 2020
ACTUAL April 30, 2020
ACTUAL May 31, 2020
ACTUAL June 30, 2020
ACTUAL July 31, 2020
ACTUAL August 31, 2020
FORECAST September 30, 2020
FORECAST October 31, 2020
FORECAST November 30, 2020
FORECAST December 31, 2020
TABLE 1: CAPBA BALANCES
($ in Millions)
Beginning
Balance
Exceeding
Cap for DL
(Including
, Interest)
Ending
Balance
Calculated Trigger
Percentage .
80.000 S0.000 $0.000 0.0%
$0.000 S0.752 $0.752 2.7%
$0.752 S0.737 $1.489 5.3%
$1,489 S0.728 $2.218 7.9%
$2.218 $0.741 $2.959 10.6%
82.959 $0.782 83.741 13.4%
83.741 $0.867 $4.608 16.5%
$4.608 $0.883 $5.491 19.6%
$5.491 $0.970 $6.461 23.1%
$6.461 $0.866 $7.327 26.2%
$7.327 $0.792 $8.120 29.0%
$8.120 $0.801 $8.922 31.9%
As presented in Table 1, SDG&E's CAPBA balance through August 31, 2020 is
undercollected by $5.49 million, or 19.61%) Based on its forecasts and assumptions, SDG&E
still expects the CAPBA undercollection to reach $8.92 million (or 32% of forecasted PCIA
revenues of S28 million) by December 31, 2020.
Since the filing of the PCIA Trigger Application in July, there have been no particular
events that have impacted or affected the CAPBA balance. This is because SDG&E records
monthly departed load under-collections to CAPBA based on forecasted authorized departed
load Portfolio Allocation Balancing Account ("PABA") revenues that arc above the PCIA rate
cap using electric seasonality factors. Since neither the forecasted authorized departed load
SDG&E'S CAPBA balance for the period ending September 30, 2020 will not be available until
approximately October 12, 2020 when SDG&E closes its September books.
2
PABA revenues that is above the PCIA rate cap or the electric seasonality factors have changed,
there has been no material impact to SDG&E's forecast. Rather, for the most part, the CAPBA
balance has continued to increase as SDG&E's forecasted it would. The only immaterial
difference is in actual interest rates and forecasted interest rates.
SDG&E'S ACCOUNTING AND BILLING SYSTEMS
As SDG&E explained at the August 27 prehearing conference, amortizing the recovery
of the CAPBA undercollection from Departing Load customers2 for a period extending beyond
Calendar Year 2020 creates logistical issues with respect to tracking, accounting and
reimbursement that are unique to SDG&E. To understand why that is, it is helpful to first
explain the events that are expected to occur in Calendar Year 2021 with respect to new
Departing Load customers in SDG&E's service territory.
First, Direct Access ("DA") opens up in SDG&E's service territory on January 1, 2021
pursuant to D.19-05-043, which predetermined the number of non-residential megawatts
("MW") that will be departing from bundled service. However, it is unlikely that all of these DA
customers will depart at the same time in 2021. Rather, their departures will likely occur on a
rolling or staggered basis. Second, San Diego Community Power ("SDCP") is expected to
depart a portion of their customers from bundled service throughout 2021.3 Finally, Clean
2 Departing Load customers include Direct Access, Community Choice Aggregation (CCA) and Green
Tariff Shared Rcnevvables (GTSR) customers. The CCA that is currently established in SDG&E's
service territory is Solana Energy Alliance.
3 San Diego Community Power Community Choice Aggregation Implementation Plan and Statement of
Intent at p.17.
3
Energy Alliance ("CEA") is expected to depart all customer classes from bundled service
throughout 2021.4
What this means is that a significant number of bundled load customers will be departing
in staggered phases throughout 20215 — which of course would occur during any extended
amortization period. When bundled customers begin to depart, they would necessarily stop
receiving the refund for the CAPBA undercollection through commodity rates and would start
paying the PCIA rate.6 It is the fact that these multiple departures are occurring after rates will
have been implemented on January 1 that creates the logistical issues with respect to tracking,
accounting and reimbursement. Moreover, SDG&E cannot change PCIA rates in the middle of
the year because PCIA rates are established in the Energy Resource Recovery Account
("ERRA") Forecast (or CAPBA trigger) proceedings.
A. Accounting & Billing System "Limitations"
In order to accurately track, account for and issue reimbursements for the CAPBA
balance, SDG&E would need to have a system that tracks the CAPBA balance at the individual
customer level. However, SDG&E does not have CAPBA balances recorded at a customer level;
it only records CAPBA balances by vintage. Furthermore, SDG&E does not develop rates at the
customer level; rather rates are developed at either the class and vintage level (as is the case for
PCIA rates) or at the rate schedule level (as is the case for commodity rates). These system
4 Clean Energy Alliance Community Choice Aggregation Implementation Plan and Statement of Intent
at.p. 4.
5 SDG&E estimates this to be about half a million customers.
6 There is also a possibility that certain individual departing load customers return back to bundled
service, which further complicates issues.
4
constraints make it nearly impossible to track, account for, and reimburse the CAPBA credits
and refunds at a customer level.
Moreover, tracking the individual customers who depart (or return) in Calendar Year
2021 during the extended amortization period and adjusting who gets a credit, who gets a refund,
how much, etc. is extremely difficult and ultimately unsupported by SDG&E's legacy billing
system or its new billing system (Envision), which is expected to go live in 2021. From a
logistical perspective, SDG&E's billing system is not able to handle this as it would require
tracking this movement on an individual customer level (which SDG&E estimates to be about
half a million customers). Moreover, SDG&E's legacy billing system, and its new Envision
billing project, can only support one PCTA rate per vintage and per customer class, and one
bundled commodity rate for the applicable rate schedule. For example, SDG&E's billing system
cannot include separate PC1A rates for CAPBA versus PCTA rates resulting from its ERRA
Forecast Application. Rather, CAPBA's PCTA rates need to be additive to the ERRA Forecast
Application's Pelf& rates in order to determine the total PCIA rate by vintage and by customer
class.
B. SDG&E's Proposed Solution
SDG&E understands and appreciates the Commission's efforts to find a solution that
would allow bundled customers to recover the CAPBA undercollection in Calendar Year 2021.
To that end, SDG&E may be able to accommodate an amortization period that extends beyond
Calendar Year 2020 provided that bundled customers who depart during the amortization period
agree to forfeit the remainder of their CAPBA refund. Given the amount of the refund, SDG&E
does not expect that the amount forfeited would be significant at an individual customer level.
For example, as stated in SDG&E's application, under a 3 month amortization schedule a typical
non-California Alternative Rates for Energy ("CARE") residential bundled customer in the
5
inland climate zone using 400 kilowatt hours ("kWh") is estimated to receive a monthly refund
of roughly $0.94 per month from the CAPBA Trigger refund.7
SDG&E has considered whether it is possible to establish a credit for the amount to be
forfeited. However, SDG&E is not able to establish a credit for the amount forfeited because
there is no way SDG&E would be able to transfer any of the CAPBA undercollection refund to
the 2020 or 2021 PCIA vintages to account for the numerous and staggering departure dates for
Departing Load customers (as described above). This is because the 2021 vintage does not exist
today, as it is established in the 2021 ERRA Forecast Application, and the number of 2020 or
2021 departing load vintage customers is not known and/or finalized. SDCP's implementation
plan would enroll customers in phases throughout 2021 — and even then, after service cutover,
customers will have approximately 60 days (two billing cycles) to opt-out of SDCP without
penalty and return to SDG&E bundled service.8 Similarly, CEA will start enrollment in May
2021, but customers will have multiple opportunities to opt out and choose to remain full
requirement ("bundled") customers of SDG&E, in which case they will not be enrolled.9 In
addition, DA customers may not all depart at the same time in 2021. As discussed above,
SDG&E cannot change PCIA rates in the middle of the year because PCIA rates are established
in the ERRA Forecast (or CAPBA trigger) proceedings.
7 Under any extended amortization period beyond 3 months (e.g., a 12-month amortization schedule),
the monthly refund bundled customers would receive would necessarily decrease. Actual savings
would vary due to actual kWh usage by a customer and potential IOU pricing for the customer's
applicable commodity rate schedule.
San Diego Community Power Com2unity Choice Aggregation Implementation Plan and Statement of
Intent at p. S.
9 Clean Energy Alliance Community Choice Aggregation Implementation Plan and Statement of Intent
at p. 4.
6
IV. CONCLUSION
SDG&E looks forward to working with the Commission and other parties to move this
proceeding towards resolution.
Respectfully submitted,
/s/ _Roger A. Cerda
Roger A. Cerda
San Diego Gas & Electric Company
8330 Century Park Court, CP32D
San Diego, CA 92123
Telephone: (858) 654-1781
Facsimile: (619) 699-5027
Email: rcerda@sdge.com
Attorney for:
SAN DIEGO GAS & ELECTRIC COMPANY
October 1, 2020
7
BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF CALIFORNIA FILED
09/25/20
04:59 PM
Application of SAN DIEGO GAS &
ELECTRIC COMPANY (U902E) for
Approval of its 2021 Electric Procurement
Revenue Requirement Forecasts and GHG
Related Forecasts
Application 20-04-014
OPENING BRIEF OF SAN DIEGO COMMUNITY POWER
AND CLEAN ENERGY ALLIANCE
Jacob Schlesinger
Keyes & Fox LLP
1580 Lincoln St. Suite 880
Denver, CO 80203
Phone: (970) 531-2525
Email: jschlesinger@keyesfox.com
Tim Lindl
Keyes & Fox LLP
580 California Street, 12th Floor San
Francisco, CA 94104
(510) 314-8385
E-mail: tlindl@keyesfox.eom
Counsel to San Diego Community Power
September 25, 2020 and Clean Energy Alliance
SUBJECT MATTER INDEX
I. INTRODUCTION 1
II. LEGAL STANDARD 2
III. BACKGROUND
IV. DISCUSSION OF ISSUES IN SCOPING MEMO 7
C. Scoping Issue No. 3 — Whether the Commission should approve a 2021 Portfolio
Allocation Balancing Account forecast revenue requirement of $373.828 million 7
1.The Commission Should Require SDG&E to Provide Significantly More Detail
Regarding Actual PABA balances, Forecasted PABA Balances and The Underlying Data
Required to Analyze Their Accuracy. 7
2.The Commission Cannot Approve SDG&E's 2021 PABA Forecasted Revenue
Requirement of $373.828 Million Until SDG&E Corrects its Erroneous Calculation of the
Total Indifference Amount. 11
I.Scoping Issue No. 9 — Whether the Commission Should Approve SDG&E's Proposed
Vintage Power Charge Indifference Adjustment in Rates: Commission Approval of
SDG&E's Vintage PCIA Rate Cap Proposal Would Run Contrary to Established
Commission Policy. 12
J.Scoping Issue No. 10 — Whether the Commission Should Approve SDG&E's Proposed
2021 Rate Components for the Green Tariff Shared Renewables Program 16
V. CONCLUSION 19
SDCP and CEA Opening Brief
TABLE OF AUTHORITIES
Commission Decisions
D.11-12-018 4, 5
D.12-12-030 3
D.15-01-051 2, 17
D.15-07-044 3
D.18-10-019 passim
D.19-10-001 2, 4, 8
D.20-01-005 13
Commission Rules of Practice and Procedure
Rule 13.11 1
Statutes
Pub. Util. Code § 451 3
Pub. Util. Code §§ 366.2(0(2), (g) 2
SDCP and CEA Opening Brief
BEFORE THE PUBLIC UTILITIES COMMISSION
OF THE STATE OF CALIFORNIA
Application of SAN DIEGO GAS &
ELECTRIC COMPANY (U902E) for
Approval of its 2021 Electric Procurement
Revenue Requirement Forecasts and GHG
Related Forecasts
Application 20-04-014
OPENING BRIEF OF SAN DIEGO COMMUNITY POWER
AND CLEAN ENERGY ALLIANCE
Pursuant to Rule 13.11 of the Rules of Practice and Procedure of the California Public
Utilities Commission ("Commission") and the July 6, 2020 Scoping Memo and Ruling setting
the schedule for this proceeding, San Diego Community Power ("SDCP") and Clean Energy
Alliance ("CEA"), hereby submit this Opening Brief regarding San Diego Gas and Electric
Company's ("SDG&E") Application for Approval of its 2021 Electric Procurement Revenue
Requirement Forecasts and GIIG Related Forecasts, submitted on April 15, 2020
("Application"). This Opening Brief adheres to the common briefing outline requested by
assigned Administrative Law Judge Wercinski and agreed upon by all parties; however, SDCP
and CEA have omitted references to scoping ruling issues outside the scope of SDCP and CEA
comments.
I. INTRODUCTION
The Commission cannot approve SDG&E's Application as requested because, in its
present form, SDG&E's presentation relies on inaccurate and inadequate evidence and
calculations in support of its requested ERRA forecasts. Further, approval of certain of
SDG&E's Portfolio Charge Indifference Amount ("PCIA") components would result in
SDCP and CEA Opening Brief 1
impermissible cost-shifting from bundled to unbundled customers, contrary to California law and
Commission precedent.1 Specifically, SDG&E's proposed changes to key components related to
its PCIA rates, underlying PCIA-eligible costs, and the Portfolio Allocation Balancing Account
("PABA") would result in impermissibly high rates, including for those customers that will
receive service from SDCP and CEA in 2021. Lastly, SDG&E's Application includes requests
for approval of its proposed 2021 vintaged PCIA rates and proposed rate components for the
Green Tariff Shared Renewables ("GTSR") program, a program that directly competes with
CCA programs.
As explained below, SDG&E's Application cannot be approved as proposed; instead, the
Commission should order the following:
*SDG&E must correct its erroneous calculation of its Total Indifference Amount;
•SDG&E must provide significantly more detail in this docket, and future ERRA
Forecast applications, regarding its actual PABA balances, forecasted PABA
Balances and SDG&E's underlying volumetric data to improve transparency and
accuracy;
•Reject SDG&E's proposal to abandon the PCIA rate cap; and
•Conduct a further review and clarification of SDG&E's GTSR program.
II. LEGAL STANDARD
SDG&E, as the applicant, bears the burden of affirmatively establishing the
reasonableness of all aspects of its application,2 and that burden of proof generally is measured
I See, e.g., Pub. Util. Code §§ 366.2(0(2), (g); Rulemaking ("R.") 17-06-026, Decision Modifying the
Power Charge Indifference Adjustment Methodology, p. 6 (October 19, 2018) ("D. 18-10-0191; R.17-06-
026, Decision Refining the Method to Develop and True Up Market Price Benchmarks (October 17,
2019) ("D.19-10-001"); Application ("A.") 12-01-008 et al, Approving Green Tariff Shared Renewables
Program for San Diego Gas & Electric Company, Pacific Gas and Electric Company, and Southern
California Edison Company Pursuant to Senate Bill 43 (February 2, 2015) ("D.15-01-051").
SDCP and CEA Opening Brief 2
based upon a preponderance of the evidence.3 As further explained below, SDG&E fails to meet
this standard because components of its Application are neither just nor reasonable, consistent
with the law, or compliant with the rules and regulations set forth by the Commission.
III. BACKGROUND
Community Choice Aggregation ("CCA") customers receive generation services from
their local CCA but receive transmission, distribution, billing, and other services from the
incumbent for-profit utility—here, SDG&E. CCA rates vary and are partially influenced by local
mandates to procure and maintain clean electricity portfolios that often exceed state requirements
for renewable and greenhouse gas-free generation. CCA and other unbundled customers are also
subject to several non-bypassable charges ("NBCs"), including the PCIA, the 2021 level of
which will be determined in this proceeding, and which is also subject to $0.005 cap.
The Commission adopted the PCIA to ensure that when investor-owned utility ("IOU")
customers depart from bundled service and opt into receiving certain electric services from a
non-IOU provider, such as SDCP or CEA, those customers nevertheless remain responsible for
costs that IOUs previously incurred for those customers—but only those costs.4 To calculate the
PCIA, the IOU must establish its "Total Indifference Amount," which is updated annually in
2 R.11-02-019, Decision Mandating Pipeline Safety Implementation Plan, Disallowing Costs, Allocating
Risk of Inefficient Construction Management to Shareholders, and Requiring Ongoing Improvement in
Safety Engineering, p. 42 (Dec. 28, 2012) ("D.12-12-030"); Pub. Util. Code § 451 (requiring that rates be
"just and reasonable").
3 D.18-10-019, p. 5; R.11-02-019, Order Modi&ing Decision (D.) 12-12-030 and Denying Rehearing, as
Modified, p. 29 (July 27, 2015) ("D.15-07-044") (observing that the Commission has discretion to apply
either the preponderance of evidence or clear and convincing standard in a ratesetting proceeding, but
noting that the preponderance of evidence is the "default standard to he used unless a more stringent
burden is specified by statute or the Courts.").
4 D.18-10-019; see also R.17-06-026, Scoping Memo and Ruling of Assigned Commissioner, p. 2
(September 25, 2017).
SDCP and CEA Opening Brief 3
TOTAL
PORTFOLIO
COST
each IOU's ERRA proceeding. The Total Indifference Amount is calculated by subtracting the
market value of the IOU's supply portfolio from the Total Portfolio Cost.
Total Portfolio Costs includes Utility-Owned Generation ("UOG"), fixed maintenance
costs, purchased power (including that from power purchase agreements ("PPAs")), fuel costs
for UOG and PPAs with tolling agreements, and California Independent System Operator
("CAISO") grid charges and revenues, net of any sales.5 The Portfolio Market Value is derived
from total eligible generation portfolio multiplied by the Market Price Benchmark ("MPB"),
which is an administratively determined set of proxy values that represents the market value of
the IOU's resource portfolio.6 A benchmark for each type of resource is applied to the forecasted
energy use for each resource type to obtain a market value. The resource market value is
calculated as follows:
•For non-Renewable Portfolio Standard ("RPS")-eligible power in an IOU's portfolio, the
forecasted amount of energy from such resources in the portfolio is multiplied by the
brown power benchmark!
•For RPS-eligible power in an IOU's portfolio, the forecasted amount of energy from such
resources in the portfolio is multiplied by the green power benclunark.8
5 R.07-05-025, Decision Adopting Direct Access Reforms, pp. 8-9 (December 1, 2011) ("D.11-12-018").
6 D.19-10-001, p. 6 (October 10, 2019) ("Market Value is the estimated financial value, measured in
dollars, that is attributed to a utility portfolio of energy resources for the purpose of calculating the Power
Charge Indifference Adjustment for a given year.").
7 See D.19-10-001, p. 7.
8 1d.
SDCP and CEA Opening Brief 4
CAPACITY
BENCHMARK
(s/Mw)
RAW
PORTFOUO
MARKET
VALUE
•For RA capacity in an IOU's portfolio, the monthly average RA capacity in an IOU's
portfolio is multiplied by a capacity or resource adequacy benchmark.9
Adjusting for line losses, the sum of the market value of the IOU portfolio's brown power, green
power, and capacity creates the Portfolio Market Value.
Finally, each generation resource and departing customer is assigned a "vintage." A
distinct portfolio of generation resources is identified for each vintage year based on when a
commitment to procure each resource was made. Customers are assigned to vintage years
according to the date they depart bundled IOU service.1° Customers continuing to receive
bundled service from the IOU are included in the latest vintage (e.g., vintage 2021 in the present
Application). Each vintage is assigned a separate Indifference Amount," and customers are
responsible for the cumulative PCIA rates for their vintage.
Prior to Commission Decision ("D.") 18-10-019, the PCIA rate was set on a forecast basis
and not trued-up for unbundled customers; only bundled customers' rates were subject to a true-
up. In D.18-10-019, however, the Commission adopted a true-up for the PCIA rate to "ensure that
9 Id,
1° Unlike portfolio resources, customers arc assigned to vintages using a July to June calendar period. For
example, customers departing bundled service between July 2019 and June 2020 are assigned to the 2019
vintage.
11 D.11-12-018, p. 9.
SDCP and CEA Opening Brief 5
bundled and departing load customers pay equally for PCIA-eligible resources."I2 This true-up
will occur via including the year-end PABA balance as part of this proceeding.' 3
In sum, SDG&E's PCTA rates for 2021 will be set based on two key components, prior to
applying the cap: (1) the Indifference Amount, i.e., the difference between the forecasted cost of
SDG&E's generation portfolio in 2021 and the forecasted market value of SDG&E's generation
portfolio in 2021; and (2) the 2020 year-end balance in the PABA, i.e., the rolling true-up
between (a) the forecasted costs and revenues used to set the 2020 PCIA last year and (b) the
actual costs and revenues SDG&E is realizing this year. The Indifference Amount and the year-
end PABA overcollection (or undercollection) are added together to form the PABA revenue
requirement underlying PCIA rates.
As noted above, and especially germane to this proceeding, the Commission also adopted
a price cap to "limit the change of the PCIA from one year to the next" and to "provide a degree
of stability and predictability" for departing load customers.I4 The aim of this price cap, created
in D.18-10-019, was to ensure rate stability for both bundled and departing load customers as
related to PCIA rates.I5 The Commission established a balancing account and trigger mechanism
to account for accumulated undercollection due to the PCIA cap, and IOUs are directed to file a
trigger application if the PCIA Balancing Account ("CAPBA") balance exceeds the 7%
12 111 8-10-019, p. 72.
13 See A.20-07-009, Expedited Application of San Diego Gas & Electric Company (U 902 E) Under the
Power Charge Indffference Adjustment Account Trigger Mechanism (July 10, 2020) ("SDG&E Trigger
Application"); SDG&E Advice Letter ("AL") 3436-E (establishing its PCIA undercollection balancing
account, CAPBA).
14 D.18-10-019, p. 72.
15 Id., p. 15 [stating that the price cap "should have reasonably predictable outcomes that promote
certainty and stability for all customers within a reasonable planning horizon."]
SDCP and CEA Opening Brief 6
threshold. SDG&E recently filed such a trigger application in A.20-07-009, filed on July 10,
2020.
IV. DISCUSSION OF ISSUES IN SCOPING MEMO
C. Seeping Issue No. 3 — Whether the Commission should approve a 2021 Portfolio
Allocation Balancing Account forecast revenue requirement of $373.828 million.
First, SDCP and CEA discuss the lack of information and support contained in SDG&E's
initial application filing and testimony related to the 2020 PABA balance, which is an important
component of the overall PABA revenue requirement calculation, and recommend process
improvements for this case as well as future ERRA proceedings. Second, SDCP and CEA
provide an explanation of an error it discovered in SDG&E's calculation of the Indifference
Amount, which is another important input to the 2021 PABA revenue requirement. This error
must be fixed in the November Update of the 2021 PABA revenue requirement forecast. To its
credit, SDG&E has already acknowledged this approximate $84.5 million mistake and has
committed to correcting it.
1. The Commission Should Require SDG&E to Provide Significantly More
Detail Regarding Actual PABA balances, Forecasted PABA Balances and
The Underlying Data Required to Analyze Their Accuracy.
As discussed above, the PABA constitutes a rolling true-up between the forecasted
components of the Indifference Amount used to set the PCIA rates and the actual costs and
revenues SDG&E experiences during the year. Any resulting over- or under-collection in the
PABA at end of 2020 is added to the revenue requirement used to establish the 2021 PCIA
'6 Id., pp. 86-87, OP 10.
SDCP and CEA Opening Brief 7
rates.17 However, in its amended testimony submitted at the end of April, SDG&E reports that its
2020 balances recorded to PABA are "$0 million."18
In fact, the rolling PABA balance at the time SDG&E filed its revised testimony was not
$0 million. In discovery, SDG&E provided data demonstrating that its June monthly report
showed a PABA balancing account under-collection of $271 million (without Franchise Fees and
Uncollectables) as of the end of June.19 Further, SDG&E provided in discovery, but not in its
Application, a forecasted year end PABA under-collection of S167 million. In other words,
SDG&E's Application understated the 2021 PABA revenue requirement in its direct case by at
least $167 million.
By failing to provide a forecast of the PABA under-collection in its Application, SDG&E
did not provide an accurate forecast of its PABA revenue requirement. Instead, SDG&E
maintains that "the 2020 PABA account balance will be determined in SDG&E's 2021 ERRA
November update."2° Waiting until the November update to provide any forecast of the PABA
balance creates the potential for huge shifts in forecasted PCIA rates between the Application
and ultimate disposition of the proceeding, limits parties' ability to understand, forecast and plan
for what those changes will be priot to the end of the proceeding, and fails to provide a
reasonable estimate of the PABA revenue requirement.
17 D.19-10-001, p. 11 ("The year-end overcollections or undercollections in the PABA subaccounts for
yearn arc included in the vintage PCIA rate calculation for year (n+1) as part of each utility's ERRA
Forecast Application.").
18 Exhibit SDG&E-06 (Amended Prepared Direct Testimony of Stacy Fuhrer at SF-3, line 2).
19 Exhibit SDCP-8 (San Diego Gas & Electric Company Response to SDCP Data Request 4.09);
Confidential SDCP-18 (CONFIDENTIAL — SDG&E Response — PCIA Model_2021 ERRA Forecast
SDCP DR 4 Question 9.xlsx).
20 Exhibit SDCP-8 and Exhibit SDCP-9 (San Diego Gas & Electric Company Response to SDCP Data
Request 4.10).
SDCP and CEA Opening Brief 8
To remedy this lack of transparency in the future, the Commission should order SDG&E
to include its year to date PABA balance as well as its forecasted year-end PABA balance in all
future ERRA forecast applications. The year-end PABA balance is an important input to the
overall PABA revenue requirement and by excluding it in its initial application, SDG&E paints
an unrealistic picture of the actual PABA revenue requirement and resulting PCIA rates that
CCA customers must pay. Including the balance for the first time in the November Update
creates a major, last-minute update to one of the core issues in an EERA forecast proceeding (the
PABA balance) and does not give intervenors adequate time to evaluate its impact on rates.
Moreover, the Commission, SDCP, CEA, and other intervenors do not currently have the
tools necessary to understand the difference between forecasted PABA revenue requirements and
actual PABA balances, the causes of an over- or under-collected balance, or the direction the
balance is heading because SDG&E has not produced the underlying data necessary for such an
evaluation. Such understanding is critical for the Commission and other parties to reach a
conclusion that the proposed PCIA rates, which will include the PABA true up, are accurate and
reasonable.
To remedy this lack of transparency the Commission should require that future ERRA
Forecast applications include monthly forecast PABA balance dollar amounts and the underlying
volumetric data (e.g,. MWh generation, kWh retail sales, etc.). As customer-facing load serving
entities, it is imperative that CCAs are granted access to the data required to analyze the
accumulating PABA balances on a timely basis in order to anticipate and plan for potential rate
impacts on their customers and to operate their own programs to serve their customers.
SDCP and CEA Opening Brief 9
Specifically, in future ERRA Forecast applications, the Commission should require
SDG&E to provide in its confidential workpapers, and in routine updates throughout the
proceeding, the data required to review actual PABA activity. Such data must include:
•Confidential versions of the monthly ERRA/PABA/CAPBA reports;
•Additional detail supporting the monthly PABA reports, including subcategories for
su.mmarized line items such as UOG costs and Contracts (e.g., provide by resource type,
and whether RPS or non-RPS eligible);
•Actual volumetric quantities underlying each relevant dollar figure; such categories
include UOG generation, power purchases and sales, CAISO market sales, and retail
customer sales;
•Monthly volumes of Actual Sold, Retained, and Unsold RA;
•Monthly volumes of Actual Sold, Retained, and Unsold RPS.
Not only will requiring this data upfront increase transparency and understanding within
this proceeding, it will diffuse controversy around the November Update. As has been seen in
other IOUs' ERRA forecast cases,21 coupling the short timeline for comments on the November
Update with the large swings in revenue requirement can create substantial controversy and
necessitate delays in the timely implementation of rates. Giving intervenors and the Commission
a better understanding of the drivers of PABA balances will allow them to better predict the
direction (rising or falling) of the balances as November approaches.
21 A.19-06-001, Joint Motion of the Joint CCAs and DA CC for Evidentiary Hearings and Additional
Briefing, or, Alternatively, to Amend Proceeding Schedule, and to Shorten Time for Response, (November
12, 2019); A.19-06-001, Response of Pacific Gas and Electric Company (U 39 E) to Joint Motion for
Evidentiary Hearings and Additional Briefing or To Amend Proceeding Schedule, (November 14, 2019);
A-19-06-00I, Email Ruling Revising the Schedule, (November IS, 2019).
SDCP and CEA Opening Brief 10
In this ERR.A Forecast proceeding, SDCP and CEA have worked with SDG&E to gain an
understanding of the impact the PABA balance will have on SDG&E's proposed PCIA rates.22
SDCP and CEA will continue to request that SDG&E provide its rolling 2020 PABA balance as
well as underlying data on an ongoing monthly basis via discovery.23 SDG&E's cooperation and
transparency will be necessary to ensure that intervenors in this proceeding have adequate time
to analyze the data and to ensure that the PABA balance SDG&E presents in the November
Update is accurate and based on reasonable assumptions.
2. The Commission Cannot Approve SDG&E's 2021 PABA Forecasted
Revenue Requirement of $373.828 Million Until SDG&E Corrects its
Erroneous Calculation of the Total Indifference Amount.
The Commission must consider SDG&E's admitted mistake in calculating its
indifference amount and, accordingly, cannot approve SDG&E's 2021 PABA forecasted revenue
requirement of $373.828 million until SDG&E corrects this error and supports the corrected
value.
As detailed above, there are two main components to the PABA revenue requirement
used to set PCTA rates: (1) the Total Indifference Amount and (2) the forecasted year-end
balance in PABA, discussed above. The Total Indifference Amount is calculated by subtracting
the market value of the IOU's supply portfolio from its Total Portfolio Cost, Here, SDG&E
omitted key components from its portfolio market value. Specifically, SDG&E failed to include
RA and RPS sales revenues when calculating its indifference amount.24
SDCP and CEA's review of SDG&E's Indifference Amount Calculation Table showed
that SDG&E removed RA and RPS sales volumes from the market value calculation rather than
22 Exhibit SDCP-8 and Exhibit SDCP-9.
23 SDCP requested underlying volumetric data on an ongoing basis in this proceeding, but so far SDG&E
has objected and refused to provide it.
24 See Exhibit SDCP-15 (San Diego Gas & Electric Company Response to SDCP Data Request 6.04).
SDCP and CEA Opening Brief 11
reflecting the value of such sales as an offset to portfolio costs.25 In other words, SDG&E's filed
application incorrectly calculated the Indifference Amount and thereby artificially increased
PCIA rates. SDCP and CEA posit that if this calculation had been done correctly, following
Commission guidance to include RA and RPS sales revenue as an offset to CRS Eligible
Portfolio Costs, then SDG&E's forecasted Indifference Amount would decrease by $49.2 million
for RA sales and $35.3 million for RPS sales, for a total reduction of $84.5 million.26
SDG&E acknowledged its error in a supplemental discovery response to SDCP and
committed to correcting the error in its November Update.27 Accordingly, Commission
evaluation of this issue must wait until SDG&E presents its corrected calculation, which should
result in an approximate $84.5 million reduction to the PABA revenue requirement.
I. Scoping Issue No. 9 — Whether the Commission Should Approve SDG&E's
Proposed Vintage Power Charge Indifference Adjustment in Rates: Commission
Approval of SDG&E's Vintage PCIA Rate Cap Proposal Would Run Contrary to
Established Commission Policy.
Commission approval of SDG&E's stated method for capping vintaged PCIA rates
would result in cost increases that exceed the price caps recently established by this Commission.
Such price caps were established for sound policy reasons—to avoid customer rate shock. There
is no reason for the Commission to abandon this price cap a mere two years after having put it in
place, particularly since the policy concerns still apply. Moreover, even if justified, SDG&E's
25 Confidential Exhibit SDCP-20 (CONFIDENTIAL — PCIA Model_2021 ERRA Forecast
April_Fuhrer.xlsx; Tab "Indifference Amount Cale", Rows 11, 15-17 Columns F:AB); Confidential
Exhibit SDCP-21 (CONFIDENTIAL — SDG&E Response — SDCP DR_02 2021 ERRA Forecast Q2-
10.xlsx; Tab "DR 2-Q5-7", Row 16, Columns C:U; Tab "DR 2-Q8-10", Rows 25-27, Columns C:U).
26 Confidential Exhibit SDCP-21 (CONFIDENTIAL — SDG&E Response — SDCP DR_02 2021 ERRA
Forecast Q2-10.xlsx; Tab "DR 2 — Q5-7", Row 14, Columns C:11; Tab "DR 2 — Q8-10", Rows 21-23,
Columns C:U).
27 Exhibit SDCP-10 (San Diego Gas & Electric Company Supplemental Response to SDCP Data Request
4.15) and SDCP-11 (San Diego Gas & Electric Company Supplemental Response to SDCP Data Request
4.17).
SDCP and CEA Opening Brief 12
ERRA application is not the proper venue for the Commission to implement such a policy
change. The Commission should not depart from its clearly stated policy objective of
maintaining PCIA rate stability.
As noted above, the Commission has established a price cap limiting year-over-year
changes to vintaged PCIA rates to no greater than $0.005 per kWh above the prior year's
approved PCIA rates by vintage.- In D.18-10-019, the Commission lists its "Final Guiding
Principles" regarding the PCIA rulcmaking. In pertinent part, the Guiding Principles state that
lajny PCIA methodology adopted by the commission to prevent cost increases for either
bundled or departing load.., should have reasonably predictable outcomes that promote certainty
and stability for all customers within a reasonable planning horizon.29 Consistent with that
principle, SDG&E's final implemented PCIA rates by vintage for forecast year 2020 were
capped at $0.005 per kWh above the effective 2019 PCIA rates by viritage.3°
Further, to ensure consistency with statutory directives against cost-shifting among
bundled and unbundled customers, the Commission also directed each utility to establish an
interest-bearing balancing account, here the CAPBA, to track any obligation that accrues for
departing load customers if the cap is reached.31 The Commission directed that if the di fference
between capped rates and costs reaches 7%, and the utility also forecasts that the balance will
reach 10%, it shall, within 60 days, file an application to propose a rate that will bring the
projected balance down below 7%.32
28 D.18-10-019, p. 133, OP 9; see also A.19-04-010, Decision Adopting San Diego Gas & Electric
Company's 2020 Electric Procurement Cost Revenue Requirement Forecast and 2020 Forecast of
Greenhouse Gas Related Costs, January 16, 2020 ("D.20-01-005"); implemented via AL 3500-E.
29 D.18-10-019, p. IS.
30 D.20-01-005, Implemented via AL 3500-E.
31 D.18-10-019, p. 86.
32 Id., pp. 86 -87.
SDCP and CEA Opening Brief 13
Because of the capped rates for forecast year 2020, SDG&E's CAPBA balance grew
above the 7% trigger threshold, leading SDG&E to file an expedited trigger application on July
10, 2020 ("SDG&E Trigger Application").33 SDG&E's Trigger Application requested
Commission authority to adjust its PCIA rates to allow for recovery of full CAPBA balance,
rather than simply lowering it below 7%.34 Specifically, SDG&E proposes increasing the
"current effective vintage PCIA rates in order to bring the CAPBA account balance below 7%"
and to refund bundled customers for the undercollection amount.35 The propriety of that proposal
is the subject of another proceeding, but is an important factor in considering the appropriate
basis for calculating 2021 capped PCIA rates.
In its Application in this docket, SDG&E presents PCIA rates that are uncapped based on
its forecasted revenue requirements, for which it seeks approval. However, in discovery SDG&E
explained that if the Commission approves its CAPBA trigger application, it believed the rates
approved in that docket would form the basis for determining whether the $0.005/kWh PCIA
rate cap applies for 2021. In other words, rather than using the approved 2020 PCIA rates
approved in the 2020 ERRA Forecast proceeding, which SDG&E presented in this proceeding,
as the baseline to set the 20201 PCIA rate cap, SDG&E would use whatever rates the
Commission approves in its CAPBA trigger application. As noted above, SDG&E proposes in
its CAPBA trigger application to bring the CAPBA balance to zero, rather than just under the
33 A.20-07-009, Expedited Application of San Diego Gas & Electric Company (U 902 E) Under the
Power Charge Indifference Adjustment Account Trigger Mechanism (July 10, 2020) ("SDG&E Trigger
Application").
34 A.20-07-009, SDG&E Trigger Application, Prepared Direct Testimony of Eric L. Dalton on Behalf of
SDG&E, p. ED-3, lines 8-9 (July 10, 2020),
https://www.sdge.com/sites/default/files/regulatory/SDGE%2OCAPBA%20Trigger%20Testimony%20of
%20Eric%20Dalton.pdf.
35 SDG&E Trigger Application, p. 2.
SDCP and CEA Opening Brief 14
7%, meaning the rates it proposes in that proceeding arc as high as they could possibly be and
are higher than what is required to mcct Commission directives.
SDG&E's proposal to calculate the cap based on rates approved in the CAPBA Trigger
application would entirely undercut the Commission's clear policy preference to create stability
and avoid rate shock for unbundled customers. In fact, SDG&E's PCIA rate cap approach
described in its discovery response, if approved, would result in capped rates that are more than
three times what the capped rate would otherwise be.36
For example, using SDG&E's forecast year 2020 PCIA rates presented in this proceeding
as the basis for the cap, the capped rate for vintage 2015 customers would be $0.035001.37 In
comparison, using the proposed PCIA rates in SDG&E's CAPBA Trigger Application as the
basis for the cap, the capped rate for vintage 2015 customers would be $0.11125 per kWh — more
than three times higher.38 Thus, if the proposed PCIA rates in SDG&E's CAPBA trigger
application are used as the basis for calculating the 2021 capped rates, the cap would be set
significantly higher than $0.005 per kWh above the prior year's rate. This approach would
entirely obliterate the purpose of the Commission-established cap mechanism, which is to ensure
rate stability and predictability for departing load customers.39
SDG&E admitted in response to DR 6.01 and 6.02 that including the current PABA
balance as well as the forecasted year-end PABA balance, respectively, would cause forecast
year PGA rates to capped when using the implemented forecast year 2020 PCTA rates as the
basis for determining the cap. Thus, if the proposed PCTA rates in SDG&E's CAPBA Trigger
36 See Exhibit SDCP-7 (San Diego Gas & Electric Company Response to SDCP Data Request 3.26).
37 Confidential Exhibit SDCP-17 (CONFIDENTIAL - PCIA Model_2020 CAPHA Trigger 3 Mo._Equal
Cents Alloc_Fuhrer.xlsx) (Submitted with S DG&E response to SDCP Data Request 3.26). (S.005 was
added to the rates presented to show what the capped rate would be under SDG&E's proposal).
38 Id.
39 D.18-10-019, p. 3.
SDCP and CEA Opening Brief 15
Application arc approved as the basis for determining the cap; the uncapped rates estimated for
example in SDG&E's response to DR 4.09 and 4.10 would become effective because the basis
for the cap would be well above the uncapped rates.° These rates are significantly higher than
the forecasted PCIA rates presented in SDG&E's Application.
Overall, the unequivocal intent of implementing a price cap in D.18-10-019 was to
provide rate stability and a degree of predictability to departing load customers. Allowing the
basis for forecast year 2021's capped PCIA rates to be those proposed in SDG&E's CAPBA
expedited trigger application, would be directly counter to this clear—and recent—Commission
policy. Accordingly, if the PCIA rate must be capped based on updates provided in November,
the Commission should order SDG&E to use the approved 2020 PCIA rates as the basis for
establishing the $.005 cap for 2021 vintaged PCIA rates.
The cap and trigger mechanisms represent a standing policy requirement, which the
Comtnisison prescribed in D.18-10-019. If SDG&E wishes to depart from the Commission
established rate cap, it would need to file a petition for modification of D.18-10-019, pursuant to
the Commisison's Rule 16.4. Thus, this ERRA Forecast application is not the proper venue for
SDG&E to propose removal or modificaiton of the PCIA cap.
J. Scoping Issue No. 10 — Whether the Commission Should Approve SDG&E's
Proposed 2021 Rate Components for the Green Tariff Shared Renewables Program
The GTSR program, similar to CCA programs, allows customers to purchase a greater
proportion of their electricity from renewable resources. While SDCP and CEA support the goals
of the GTSR program and its contribution to increased customer choice and renewable resource
4° Exhibit SDCP-8; Exhibit SDCP-9; Confidential Exhibit SDCP-18 (CONFIDENTIAL — SDG&E
Response — PCIA Model_2021 ERRA Forecast SDCP DR 4 Question 9.xlsx); Confidential Exhibit
SDCP-19 (CONFIDENTIAL — SDG&E Response — PCIA Model_2021 ERRA Forecast SDCP DR 4
Question 10.xlsx).
SDCP and CEA Opening Brief 16
development, the proposed Renewable Power Rate ("RPR") must reflect the actual costs of the
renewable resources that will be utilized to serve GTSR customers.
In accordance with D.15-01-051 and Resolution E-5028, SDG&E requests approval in its
Application for the forecast 2021 costs and proposed rate components for the GTSR Program.41
For the Green Tariff ("GT") portion of the GTSR Program, SDG&E estimates total customer
usage in 2021 to be 103.8 GWh resulting in a total estimated program cost of S6.35 million.42
Among the proposed GT rates, SDG&E estimates the commodity rate component known as the
RPR to be $56.27/114Wh.43 In D.15-01-051, the Commission set forth the GTSR generation rate
structure comprised of credits, representing the benefits of GSTR Program generation and
capacity, and charges, representing costs incurred on behalf of GTSR customers.44 The
commodity rate for the GT portion is called the RPR and calculated by averaging: (1) the
incremental cost of local solar projects procured specifically for the program and (2) the
weighted average cost of the power from the GTSR Interim Poo1.45 SDG&E proposes a 2021
RPR of $56.27/MWh, which is $13.08/MWh, or 23.2 %, cheaper than the currently approved
2020 RPR of $69.35.46
Through Discovery, SDCP sought to investigate and verify the expected resources to be
included in the RPR, to ensure compliance with the ratemaking methodology set out in D.15-01-
051. Discovery was necessary on this subject because SDG&E's testimony and Application did
not provide this data clearly. Unfortunatley, SDG&E's data responses on this topic were
41 Resolution E-5028, Approves Extension of; and modifications to, the Utilities' Green Tariff Shared
Renetvables Program, pp. 31-32 (September 30, 2019).
421d.
43 Exhibit SDG&E-06 (Amended Prepared Direct Testimony of Stacy Fuhrer at SF-17)
44 D.15-01-051, pp. 95-96.
45 D.15-01-051, pp. 97-98; Exhibit SDG&E-06 (Amended Prepared Direct Testimony of Stacy Fuhrer at
SF-17).
46 Exhibit SDG&E-06 (Amended Prepared Direct Testimony of Stacy Fuhrer at SF-19).
SDCP and CEA Opening Brief 17
incomplete and failed to include all of the data needed for SDCP and CEA to conduct their
anlayis.
In SDCP's data request 5.02, it requested "unredacted copies of the pricing terms contained
within the PPAs whose resources are being used to supply power to SDG&E's GTSR customers in
2021." In response SDG&E supplied all contracts for the Interim Pool resources and the dedicated
Midway PPA, but it did not include the dedicated Wister PPA. It was not until SDG&E responded to
SDCP's seventh data request that it provide information regarding the utilization and costs of Wister.
SDG&E's Application is also unclear as to whether total forecast 2021 GT customer
usage accounts for the drop in the estimated 2021 RPR. SDG&E estimates that, based on
consumption estimates for each customer class in conjunction with program enrollment targets,
2021 GT customer usage is estimated to be 103.8 GWh.47 Though total GT subscribed capacity
increased from 44.236 MW in December 2018 to 50.50 MW in December 2019, total GT
subscribed capacity stayed about the same over the year, reported at 50.487 MW as of June
2020.48
SDG&E's Application provides no explanation as to how forecast usage was determined
and whether that forecast impacted the reduction in the 2021 RPR. Given the lack of clarity
surrounding forecast consumption, and the role that this forecast plays in calculating the RPR,
SDG&E, must make a more detailed showing in this and future ERRA proceedings to allow for a
proper determination as to whether the proposed RPR was calculated in accordance with
Commission requirements.
47 Exhibit SDGE-03 (Prepared Direct Testimony of Stefan Covic SC-12 to SC-13).
48 Exhibit SDCP-40 (Annual GTSR Program Progress Report of San Diego Gas & Electric company for
Activities Occurring in 2018 at 4); Exhibit SDCP-41 (Annual GTSR Program Progress Report of San
Diego Gas & Electric company for Activities Occurring in 2019 at 4); Exhibit SDCP-38 (Quarterly
GTSR Program Progress Report of San Diego Gas & Electric company for Activities Occurring Q2
2020, A.12-01-008, July 31, 2020 at 3).
SDCP and CEA Opening Brief 18
V. CONCLUSION
For the foregoing reasons, SDG&E's SDG&E's Application cannot be approved as
requested; rather, SDG&E should be directed to (1) provide more clarity on its underlying costs
and data regarding its PABA balances; (2) correct its miscalculation of the Total Indifference
Amount; (3) follow the Commission's established policy capping PCIA rate increases and (4)
provide greater information and clarity in support of its rates for the GTSR program. Overall,
SDG&E has not provided sufficient information and cost transparency in its Application to meet
its burden of proof.
Respectfully submitted,
Jacob Schlesinger
Tim Lindl
Keyes & Fox LLP
1580 Lincoln St. Suite 880
Denver, CO 80203
Phone: (970) 531-2525
Email: jschlesinger@keyesfox.com
counsel to San Diego Community Power
September 25, 2020 and Clean Energy Alliance
SDCP and CEA Opening Brief 19
Report Providing Recommendations on tog,
Schedule to Reopen Direct Access =A
California Public Utilities Commission Staff Report
Pursuant to Senate Bill 237 (2018) and R. 19-03-009
September 28, 2020
Table of Contents
Key Acronyms 3
Executive Summary 4
1.Introduction 6
1.1 Objectives and Scope 6
1.2 Background on Direct Access and Retail Choice 8
1.3 Potential Benefits of Expanding Direct Access 11
1.4 Challenges of Expanding Direct Access 12
2.Assessment of Statutory Provisions of Reopening Direct Access 13
2.1 Impact of Direct Access Expansion on Greenhouse Gas Emission Reduction Goals 14
2.2 Impact on Criteria Air Pollution and Toxic Air Contaminants 19
2.3 Ens ming Reliability with Expansion of Direct Access 20
2.4 Ensuring Direct Access Expansion Does Not Result in Cost Shifting to Bundled
Customers 24
3.Recommendations on the Schedule to Reopen Direct Access 27
2 I P age
Key Acronyms
AB Assembly Bill
CCA Community Choice Aggregation
CEC California Energy Commission
ESP Electric Service Provider
GIIG Greenhouse Gas Emissions
IRP Integrated Resource Planning
IOU Investor-Owned Utility
LSE Load Serving Entity (includes CCAs, ESPs, and IOUs)
LLTP Long Term Procurement Planning
NEM Nct Energy Metering
PCIA Power Charge Indifference Adjustment
POLR Provider of Last Resort
SB Senate Bill
RA Resource Adequacy
REC Renewable Energy Credits
RPS Renewables Portfolio Standards
3 1 Page
Executive Summary
In 2018 the Legislature approved Senate Bill (SB) 237 (Hertzberg), which required the California
Public Utilities Commission (CPUC) to 1) increase the cap on the amount of demand that can be
serviced by competitive Electricity Services Providers (ESPs) through Direct Access; and 2) provide
recommendations to the Legislature on implementing further expansion of Direct Access, including,
but not limited to, the phase-in period over which the further Direct Access shall occur for all
remaining nonresidential customer accounts in each electrical corporation's service territory.
Consistent with the requirements of SB 237, this Staff Report provides an assessment of the
provisions identified in Public Utilities (P.U.) Code Section 365.1 (f)(1) for the Legislature's
consideration in its determination of further reopening. Should the Legislature elect to enact a
further reopening of Direct Access, this report provides recommendations for the schedule of
actions that should occur prior to the reopening, consistent with these provisions. In this document,
the California Public Utilities Commission's (CPUC) Energy Division staff presents
recommendations for the schedule. CPUC Energy Division staff recommends the following:
Prior to Further Direct Access Reopening:
Staff recommends that reopening be conditioned on ESPs' demonstrated compliance with the
following obligations:
>ESPs submit robust, transparent Integrated Resource Planning (IRP) filings and meet all
procurement requirements pursuant to Decision (D.) 19-11-016.
>ESPs meet their Renewables Procurement Standards (RPS) obligations for the 2021-2024
compliance period.
>ESPs comply with all Resource Adequacy (RA) requirements including multi-year local, year
ahead flexible and system, and month ahead system and flexible obligations.
Recommended Schedule if Direct Access is Reopened:
If the Legislature directs further reopening of nonresidential Direct Access, the legislation should
allow the CPUC to:
>Set an initial re-opening schedule in increments equal to 10 percent of eligible non-residential
load per year.
>Condition each annual expansion on CPUC review and approval of compliance with IRP, RA
and RPS requirements, as subject to CPUC approval.
>Order annual expansion to take place on a schedule that will allow Load Serving Entities
(LSEs) the ability to fully comply with RA requirements.
Staff suggests that a re-opening schedule that raises the Direct Access cap by 10 percent of non-
residential load per year should minimize planning disruptions associated with load departure and
4 I Page
allow the CPUC and market actors sufficient time to develop the regulatory and market structures
needed to ensure long-term resource development in a fragmented retgil market.
Recommendations for Legislative Action:
If the Legislature establishes a schedule to reopen Direct Access to all non-residential customers,
CPUC staff recommends that the following legislative actions be considered to ensure that the
greenhouse gas (GHG) emissions, reliability and cost shifting provisions of SB 237 are met:
•Provide clear authority to enforce compliance with IRP GHG goals by all LSEs subject to
P.U. Code Section 454.52 (b).
•Ensure that the CPUC continues to have clear authority to enforce the State's Resource
Adequacy goals defined in P.U. Code Section 380.
•Amend P.U. Code Section 949.25 to provide the CPUC with the authority to revoke ESP
licenses and CCA registration for repeated non-compliance with RA, RPS or IRP
requirements.
9 Consider provisions to ensure that no cost shifting as the result of customer moving between
different Load Serving Entities (Electric Corporations, Community Choice Aggregators
(CCAs), and ESPs) are applied equitable to all customers.
5 I Page
1. Introduction
1.1 Objectives and Scope
Pursuant to Senate Bill (SB) 237 (Hertzberg, 2018), the CPUC is required to provide the Legislature
with recommendations on the further reopening of Direct Access, which is also referred to as direct
transactions. Energy Division staff prepared this Staff Report in order to support the, CPUC in
meeting requirements of SB 237.
Public Utilities (P.U.) Code 365.1 (f) states that:
(f)(1) On or before June 1, 2020,1 the commission shall provide recommendations to the
Legislature on implementing a further direct transactions reopening schedule, including, but not
limited to, the phase-in period over which the further direct transactions shall occur for all
remaining nonresidential customer accounts in each electrical corporation's service territory.
(2) in developing the recommendations pursuant to paragraph (1), the commission shall find all
of the following:
(A)The recommendations ate consistent with the State's greenhouse gas emission reduction
goals.
(B)The recommendations do not increase criteria air pollutants and toxic air contaminants.
(C)The recommendations ensure electric system reliability.
(D)The recommendations do not cause undue shifting of costs to bundled service customers of
an electrical corporation or to direct transaction customers.
The intent of this Staff Report is to provide an assessment of the provisions identified in P.U. Code
Section 365.1(f) for the Legislature's consideration in their determination of further reopening.
Should the Legislature elect to enact a further reopening of Direct Access, this report provides
recommendations for the schedule of actions that should occur prior to the reopening, consistent
with these provisions.
Direct Access, originally adopted in 1996 as part of California's energy restructuring initiative and
authorized by P.U. Code Section 365.1, is a retail electric service option whereby non-residential
customers may purchase electricity from a competitive non-utility entity called an Electric Service
Provider (ESP). The amount of electric load that can be serviced by Direct Access has been capped
by statute since 2002. SB 237 required the CPUC to increase the allowable Direct Access load by
4,000 gigawatt-h our (GWh).
In 2002, Assembly Bill (AB) 117 added P.U. Code Section 331.1, which created CCAs as an
alternative provider or retail electricity services. In 2014 CCAs served only around 0.5 percent of all
load in IOU territory; in 2021 it is estimated that Community Choice Aggregators (CCAs) will
account for approximately 29 percent of load in Investor Owned Utility (IOU) territory.
Issuance of this report was delayed due to the Covid-19 and economic emergency.
6 I Page
While CCA growth is an important market context for assessing the possible effects of expanding
the market for Direct Access, pursuant to SB 237, this report focuses specifically on an assessment
of the likely effects and risks of expanding Direct Access and is not intended to assess the impacts
of CCA growth.
Direct Access currently serves approximately 14 percent of load in IOU service territory and is
projected to increase to over 16 percent by 2021 with the implementation SB 237. Figure 1 shows
the estimated 2021 load shares served by Direct Access, CCAs, and IOUs and the load that will
become eligible to switch to Direct Access in 2021 and 2022 with the 4,000 GWh increase allowed
by SB 237.
Figure 1: 2021 Direct Access Load and Eligible Direct Access Load
24,488
9921
•Current Direct Access
Load
• •Additional Direct Access
Load (SB 237)
CCA Load
•IOU Load
Figure 2 shows current Direct Access load and the additional load that could become eligible for
Direct Access pursuant to SB 237. As Figure 2 shows, 47 percent of the current IOU and CCA load
could move to Direct Access if the Legislature decides to re-open the entire non-residential market
to Direct Access, as contemplated in SB 237. The 38 percent of IOU and CCA load that serves
residential customers would not be eligible for Direct Access under SB 237.
4,304
2%
68,784
38%
85 (144
47%
Figure 2: Direct Access Load (GW11) and Direct Access Eligible Load (GWh) if Direct
Access Becomes Eligible to All Non-Residential Load.
24,488
13% • Current Direct Access Load
•Additional Direct Access
Load (SB 237)
NIOU and CCA. Non-
Residential Load Potentially
Eligible for Direct Access
o. IOU and CCA Residential
Load
1.2 Background on Direct Access and Retail Choice
Direct Access was originally adopted in 1996 as part of California's Electric Utility Industry
Restructuring Act, AB 1890 (Brulte, 1996). Prior to AB 1890, vertically integrated IOUs owned and
operated generation, transmission, and distribution systems and provided retail services to all
customers under regulation from the CPTJC. Direct Access offered retail choice to customers by
allowing them to purchase electricity directly from an ESP while the IOUs continued to supply the
transmission and distribution services needed to transport power to the customer. AB 1890 opened
Direct Access to both residential and non-residential customers.
In 2000-2001, market manipulation in a tight energy market led to large spikes in electricity costs and
rolling blackouts across the state. The IOUs were unable to recover the costs of procuring electricity
in the wholesale energy market due to fixed retail rates and mounting costs to procure generation.
Ultimately, this led to PG-&E's first bankruptcy in 2001. During this period, many Direct Access
providers left the market, returning their customers to IOU service.
In response to the crisis, the Legislature approved AB1X (Keely, 2001) to resolve the shortage of
energy available in the day ahead energy markets and stabilize energy prices. Among other actions,
AB1X suspended additional Direct Access enrollment.
From 2001 to 2010, existing Direct Access customers were allowed to continue using Direct Access
and to shift between ESPs, but no additional customers were allowed to move to Direct Access. SB
695 (Kehoe, 2009) opened Direct Access to a limited amount of new non-residential load, which
8 I Page
would be phased in over several years. SB 6952 created a capacity "cap" of electric load that ESPs
may serve but otherwise retained the main aspects of Direct Access suspension until further
legislative action. The cap set by SB 695 was equal to the peak amount of load served by Direct
Access prior to the electricity crisis, roughly 13% of total load.
In 2002, AB 11:73 established P.U. Code Section 331.1, which authorizes the implementation of
Community Choice Aggregation. AB 117 allows local government entities to form CCAs to
purchase power for their communities from non-utility power suppliers. Per AB 117, customers are
defaulted into CCA service when a CCA is formed in their service area, with an option to opt-out
and return to utility service.
Following passage of SB 237 in 2018, the CPUC opened Rulemaking (R.) 19-03-009. In the first
phase of the rulemaking, the CPUC allocated the additional 4,000 GWh Direct Access load from
SB 237 among the three IOU territories according by load share. To provide sufficient time for
ESPs to comply with current year-ahead Resource Adequacy requirements, the implementation of
additional Direct Access load will not occur until January 1, 2021. In Phase 2 of R.19-03-009, the
CPUC is addressing SB 237's requirement that Energy Division provide recommendations to the
Legislature on further reopening of non-residential Direct Access.
Since 2001, the Legislature and the CPUC have implemented a series of new regulations to ensure
there is sufficient generation capacity available for system religbility that have created new
obligations for ESPs. Among the key requirements adopted were the creation of long-term and
short-term procurement requirements for Load Serving Entities (LSEs) through the Long-Term
Procurement Planning (LTPP) and Resource Adequacy proceedings. AB 380 (Nunez, 2005)
established Resource Adequacy requirements to meet near-term capacity needs. Resource Adequacy
requirements were updated by SB 1136 (Hertzberg, 2018) to ensure sufficient capacity to meet
system, local and re_newables integration (flexible) needs. Following SB 350 (de Leon, 2015), the
CPUC moved long-term planning into the Integrated Resource Planning (IRP) process, which
considers both reliability and greenhouse gas emissions reductions goals in a single proceeding and
seeks to define an optimal path for realizing, both goals.
1.2.1 California Customer Choice Project
In 2017, the CPUC initiated California Customer Choice Project to examine the rapid evolution of
California's electric sector and develop a report evaluating competitive retail electricity options. The
results of the project were published in August 2018 as C4fornia Customer Choice: An Evaluation of
Regulatog Framework Options for an Evolving Electricity Market (Customer Choice Paper). The Customer
Choice Paper identifies shifts occurring in the electricity sector as a result of expanding customer
choice and assesses markets outside of California for lessons learned. The paper also raises
fundamental questions on how California can simultaneously create more market choice for
2 See P.U. Code Section 365.1(b)
3 Sec P.U. Code Section 331.
9 I Page
consumers, meet statewide goals, and ensure California's energy policy core principles of
affordability, reliability and decarbonization.
Following the Customer Choice Paper, CPUC staff published the Choice Action Plan and Gap Analysis
(Action Plan) in December 2018 to identify critical policy issues associated with increased
disaggregation of load and supply. CPUC staff also conducted an internal analysis to identify
regulatory gaps that exist and actions that would help to ensure core principles are met if retail
choice is pursued.
The Action Plan identified a list of policy areas and relevant proceedings that would be impacted by
the expansion of retail choice. Some of these topics are relevant to the provisions required by
SB 237 regarding a recommendation for Direct Access expansion. This report is informed by, and
expands upon, the analysis of these topics in the Action Plan.
1.Disclosure of Green House Gas (GHG) and Renewables Content for use in LSE
Electricity Portfolios':
The Action Plan raises the issue that consumers lack transparency into the power content of
electricity sold by LSEs and identifies the need for clear disclosures for GHG emissions and
Renewables Content from all LSEs. The California Energy Commission (CRC) provides
"Power Content Labeling" and AB 1110 (Ting, 2016) requires that the CEC amend the
Power Source Disclosure (PSD) to include GHG emissions intensity factors and guidance
for disclosure of unbundled Renewable Energy Credits (RECs) beginning in 2020 for the
2019 calendar year.
The Action Plan recommended that there be disclosure for all power content, including
imports and unbundled RECs.
2.Resource Adequacy':
The Action Plan identifies challenges to maintaining adequate electric capacity to ensure
reliability caused by structural changes to the energy market. These challenges include: the
increasing use of intermittent renewable resources; the upcoming retirement of natural gas
power plants due to once through cooling requirements; retirement requests from
generators; and the rapid expansion of CCAs resulting in customer load migration. A
competitive electricity market structure may cause uncertainty for market participants who
must procure capacity for an unknown amount of load and generators who must now sell
generation to new market entrants. Since publication of the Action Plan, R.17-09-020 has
considered refinements to the Resource Adequacy program. This work is ongoing. Load
migration and load fragmentation continue to create complex issues for electric system
reliability that this Staff report will explore.
3.Contracting for Reliability and Renewable Resource Requirements':
4 California Customer Choice Project: Choice Action Plan and Gap Analysis, December 2018, p. 27-28
5 Ibid. p. 50-53
6 Ibid. p. 57-61
10 I Page
The Action Plan highlights the concern over resource procurement that is necessary for the
state's long-term energy supply, particularly new renewable energy resources, noting that
some LSEs rely almost exclusively on short-term contracts to meet energy needs. The CPUC
uses the IRP process to evaluate the state's long-term contracting requirements to meet both
its reliability and renewable procurement. Each LSE is required to file its own IRP with the
CPUC so that the CPUC can ensure the that it will meet its obligations; however, the IRP
process is relatively new and the CPUC still in the process of developing the needed
compliance tools. The Action Plan also suggests potential solutions to address reliability and
resource challenges with retail choice, including coordinated multi-party procurement and
the creation of a central procurement entity.'
The remaining topics in the Action Plan are not within the scope of SB 237 and will not be assessed
in this report, although they still need to be considered within their respective proceedings.
1.2.2 Public Input to Support Staff Report Recommendations
On January 8, 2020, staff held a workshop to solicit input from stakeholders and parties to R.19-03-
009. Parties provided informal comments in response to the discussion. Comments were provided
by the Alliance for Retail Energy Markets (AReiVI), California Large Energy Consumers Association
(CLECA), Cogeneration Association of California (CAC), Commercial Energy of California
(Commercial Energy), Direct Access Customer Coalition (DACC), Energy Producers and Users
Coalition (EPUC), Pacific Gas & Electric (PG&E), Public Advocates Office (CalPA), Renewable
Energy Buyers Alliance (REBA), Southern California Edison (SCE), The Utility Ratepayer Network
(TURN). This report was informed by the comments and analysis of the participating parties, as well
as past staff reports and decisions, which are cited below.
1.3 Potential Benefits of Expanding Direct Access
in their informal comments on the January 8th Energy Division workshop, parties discussed the
potential benefits that expanding Direct Access can provide to commercial customers.
1.3.1 Expanded Direct Access will increase Choices for C&I customers
ESP representatives point out that many commercial and industrial customers desire the retail
options that Direct Access can offer. Since caps on total participation were instituted, subscription
to the Direct Access program has always been at the cap and there have been consistent waiting lists
for the program. At the end of 2018, 6,951 GWh of customer load remained on the Direct Access
waitlist.' While SB 237 increased the maximum allowable limit for Direct Access by 4,000 GWh,
2,000 GWh of which will come from the June 2020 Direct Access Lottery, it is reasonable to expect
that demand for Direct Access service requests will increase if the cap is lifted.
7 California Customer Choice Project: Choice Action Plan and Gap Analysis, December 2018, p. 2.
8 2018 Direct Access Lottery Enrollment Report
ill Page
1.3.2 ESPs can tailor their service to customer needs
Companies seek Direct Access for various reasons. First, while the CPUC has no visibility into the
rates ESPs charge their customers, it appears that ESPs have generally been able to provide power at
a significant cost-advantage to IOUs, and many Direct Access customers choose Direct Access in
order to lower their overall energy bills. Lower rates are appealing to all customers but may be
particularly important to large commercial and industrial customers for whom energy is a major
component of overall costs. For this class of customer, particularly industrial customers with some
degree of locational freedom, the search for cheaper electricity could lead them to consider moving
energy-intensive production activities out of California. Direct Access may provide these customers
an incentive to keep production in the state.
Direct Access may also provide customers with competitive options and flexibility, allowing them to
choose procurement products and rate designs. Customers may use Direct Access in order to pursue
corporate GHG emission reduction initiatives. ESPs point out that they can provide customers with
electricity services, such as load management, that are tailored to the customer's specific needs.
Customers with multiple locations, such as large retailers, may seek Direct Access in order to
aggregate load across different service territories and buy electricity services from a single provider.
Buying from an ESP may facilitate customers who want to implement a unified energy management
plan across jurisdictional boundaries and can facilitate the pursuit of corporate or institutional GHG
goals by allowing companies to more efficiently plan and finance long-term, offsite investments in
solar, wind, storage or other renewable assets.
1.4 Challenges of Expanding Direct Access
Large-scale load migration between LSEs may create structural challenges to California's system of
electrical system planning. In recent years load migration has been driven primarily by the rapid
growth of CCAs. Reopening Direct Access would allow nearly two-thirds of existing load, including
load that has recently migrated to CCA service, to migrate between IOU, ESP and CCA service.
Modeling in the 2019-2020 IRP cycle indicates a need for nearly 25,000 megawatts (MW) of new
energy resources to be built by 2030. Accomplishing this rate of new build requires either that LSEs
make long-term contracting commitments or that another entity do so on their behalf.
ESPs currently procure much of their energy in day-ahead and real-time markets or through short-
term contracts and have little track record of signing long-term contracts. Because Direct Access
customers make short term commitments to an ESP, generally signing 1 to 2-year contracts, multi-
year contracts are risky for ESPs. However, since long-term contracts arc needed to meet system
reliability needs and develop new clean energy resources, expanding Direct Access increases the risks
for long-term procurement contracting needed to meet system reliability and GHG reduction
targets.
It is important to acknowledge that, to a certain degree, these long-term planning and contracting
challenges are caused by load migration in general, which includes load migration due to CCA
expansion. In their informal comments to the January 8th workshop, several Direct Access
12 I Page
representatives raised the concern that ESPs are held to a separate standard than CCAs. They
questioned whether this report should go beyond challenges that are specific to Direct Access
expansion and consider load migration in general. While the rapid growth of CCAs has, in fact,
made planning and procurement to meet system reliability more challenging, the current legislative
mandate under P.U. Code 366.2 does not cap the amount of load that can be served by CCAs.
A rapid expansion of Direct Access is likely to exacerbate the challenges associated with load
migration. Currently, the IOUs are experiencing a substantial amount of load departure annually
with the launch and expansion of CCAs. There is also a small amount of load returning to IOUs or
migrating to ESPs, to the extent allowed by the current cap. This migration has created planning
challenges but has generally proven manageable. However, a rapid expansion of Direct Access
would significantly increase the medium to long term planning uncertainty because customers may
freely migrate between IOUs, CCAs and Direct Access providers. This increased load migration will
make long-term procurement far more challenging for all LSEs. We describe those challenges
further in Section 2.
1.4.1 Mechanism to address market risks related to load migration may be
developed but do not currently exist
The Customer Choice Project found that a central procurement entity that procures on behalf of all
LSEs may resolve some of the procurement challenges caused load migration, since central
procurement would be indifferent to which ISE is serving load.' The CPUC has recently adopted
central procurement for local Resource Adequacy in two IOU territories—Pacific Gas & Electric
(PG&E) and Southern California Edison (SCE)—to be implemented beginning in 2023.1°
Over time, market participants may also adapt to load migration and develop new ways to organize
procurement to meet State planning requirements while also maintaining the flexibility they desire in
competitive retail markets. However, currently these market-based approaches either do not
currently exist or are in the very early stages of development.
2. Assessment of Statutory Provisions of Reopening Direct
Access
This section provides an assessment of the four statutory provisions identified in Public Utilities
Code Section Code 365.1 (f)(2) that must be met in setting a recommended schedule for reopening
of Direct Access. The statute directs the CPUC to find that the recommendations are consistent
with the State's GHG emission reduction, do not increase criteria and toxic air pollutants, ensure
system reliability, and do not cause undue cost shifting to bundled customers. These provisions are
considered below.
9 California Customer Choice: An Evaluation of Regulatory Framework Options for an Evolving Electricity
Market (August, 2018), p. 65.
Dedsion (ID.) 20-06-002 (June 11, 2020).
13 I Page
2.1 Impact of Direct Access Expansion on Greenhouse Gas
Emission Reduction Goals
Under SB 32 (Pave, 2016) the State must reduce GlIG emission to 40 percent below 1990 levels
by 2030. SB 350 (de Leon, 2015) requires the California Air Resources Board to establish emission
reduction targets for the electricity sector and for the CPUC to use those targets in developing
Integrated Resource Plans (IRP) for LSEs under its jurisdiction.
The IRP process sets an electric sector GHG reduction target" and identifies an optimal portfolio
of resources needed to meet that target and maintain system reliability at least-cost. Each of the
CPUC's jurisdictional LSEs are required to regularly submit IRP filings with the CPUC that are
consistent with this portfolio. in their 1RP filings, LSEs detail how they will meet GFIG and
reliability targets with new and existing resources. If the LSEs' IRP filings collectively show actual or
potential deficiencies, the CPUC may order additional procurement.
The Renewables Portfolio Standards (RPS) program works in conjunction with the IRP as the
primary driver to build new renewable resources. Originally adopted in 2002 and most recently
updated by SB 100 (de Leon, 2018), the RPS program requires that the LSEs procure 60 percent of
their total electricity retail sales from renewable energy resources by 2030. Additionally, SB 350
mandates that 65 percent of each LSE's RPS procurement must be derived from contracts of 10 or
more years beginning in RPS Compliance Period 4, which will run from 2021 to 2024.12 RPS
mandates drive the build-out new renewable resources, which helps meet GHG emission reduction
targets and system reliability needs set in the 1RP.
To assess the impact of Direct Access expansion to all non-residential customers on GHG
emissions, we evaluate the ESPs' current planning, procurement practices, and compliance with 1RP
and RPS requirements, and what they indicate about ESPs' likely market behavior in the future. We
also consider the implications of additional load migration and Direct Access customers' short-term
commitments to their ESP on the State's ability to accurately set and meet GHG reduction targets.
2.1.1 ESPs' Current Procurement Practices
ESPs' current energy procurement practices offer the best available indication of potential impacts
of reopening Direct Access on GHG emissions. Figure 3 (below) shows each LSE's 2018 power
content as reported to the CEC in 2018. The green wedge in Figure 3 shows the RPS eligible
resources purchased by each LSE. The dark blue represents large hydro which, like nuclear (purple),
is not RPS eligible but does qualify as GIIG-free according to Power Content Labeling rules. The
11 Electric sector GI-IG targets are set consistent with California Air Resources Board Scoping Plan ranges.
Available: https: /Avw3.arb.ca.govicc/scopingplan iscopinpplarthun
12 RPS rules measure compliance as a percentage of energy used during the entire compliance period. This
means that an LSE could fail to procure 65 percent of its RPS through 10-year or longer contracts but still
meet program requirements if 65 of the RPS it procures during the 4 year compliance period comes from 10-
year or longer contracts.
14 I Page
Utilities Average
100%
90%
SO%
70%
60%
50%
40%
30%
20%
10%
094 li o II II
dark brown represents gas generation, while the lighter beige represents California Independent
System Operator (CATS()) system power.
Figure 3 indicates that ESPs relied heavily on purchases of unspecified CATS° system power, with
the exception of 3 Phases and the University of California (UC). This contrasts with the majority of
CCAs, who procured large amounts of renewable and GHG-free resources and with the IOUs, who
also outperformed ESPs in procuring GHG free encrgy. Unspecified CAISO system power, which
includes energy from all resources including RPS eligible and gas generation, accounted for
69 percent of the ESPs' portfolio content.' Reliance on CAISO system power, which is generally
cheaper and requires no long-term contracting, has been a source of competitive advantage for E,SPs
by allowing them to avoid higher costs and commitments of long-term contracts.
Figure 3: GHG free and System Power Used by each LSE"
Energy Resource Mix by LSE
Community Choke Aggregators Energy Service Providers
d 4,,o, 0 cf."? e, <3 4- e 4,Z (*.RC^ . ck 4, 4- q t, cp.?, e ,e,% ,60 •S‘-‘ ,0 6 „..e. ,z; 6 •k .0\ ef,..c\e df c't- ,4%
cpN s,zizs 1 0
•Eligible Renewable • Coal •Large Hydro Nuclear • Natural Gas it Other ,f:Unspecified
ESP representatives have explained that the different resource mixes they procure reflect the
differing priorities of their commercial customers. Some customers prioritize GHG emission
reductions above energy prices and vice versa.' However, overall, the ESPs' general procurement
13 For a full description of each LSE's power content label report for 2018, see Appendix 2 of this report.
14 This chart is based on California Energy Commission Power Content Label data for 2018. A complete data
set for each IOU, CCA, and ESP, including total retail sales, can be found in Appendix 2 at the end of this
report.
Informal Comments of the Affiance for Retail Energy Markets on the January 8,2020 Workshop, p. 3.
15 I Page
...
50%
al 40%
5 30%
0.1 O. 20% tn Q.
strategies, including a heavy reliance on CAISO system power, appear to increase GI-IG emissions
relative to portfolios that rely on high amounts of RPS eligible resources.'
As will be further discussed in Section 2.1.4 (below) SB 350 requires all LSEs to procure a minimum
65 percent of their RPS compliance requirement with contracts of 10-years or longer starting in
2021. The ESPs' ability to comply with these requirements is untested to date. Based on past
procurement trends, CPUC staff has concerns that some ESPs may not meet the new requirements.
2.1.2 Renewable Portfolio Standard Compliance
The 2019 CalOnia Renewable: Portfolio S tandard Annual Report provides a comprehensive evaluation of
each LSE's RPS coraplia,nce.17 Figure 4 shows the trend in average RPS energy as a percentage of
load by IOUs, CCAs and ESPs from 2014 to 2018. During this period, both CCAs and IOUs, on
average, procured quantities of RPS well above mandated RPS requirements. In contrast, ESPs
generally met their RPS requirements, but RPS represented a lower percentage of their procurement
than it was for other LSE classes. The 2019 Cali firnia Renewable: Portfolio Standard Annual Rep ort
found that while one ESP exceeded its target by more than 10 percent, the remaining 11 met or
barely exceeded their RPS compliance target. 3 ESPs failed to meet RPS Period 2 (2014-16) RPS
compliance targets.'
Figure 4. Average Actual LSE RPS Percentages (2014-2018)"
60%
io%
0%
2014 2015 2016 2017 2018 . ........._....
—CCAs —ESPs -- IOUs — — Annual RPS Requirement
If the trends shown in Figure 4 are indicative of future practices, then load migration from IOUs or
16 The GHG content of CAISO system power varies from month-to-month and hour-to-hour depending on
the availability of renewable resources. Emissions information can be found at the CAISO websitc.
"RPS requirements differ from Power Content Label since large hydro and nuclear are not included under
RPS rules. Furthermore, RPS rules allow for the procurement Geothermal and Biopower, which are GHG
emitting.
18 2019 California Renewables Portfolio Stanch.rd Annual Report, P. 25.
19 From CalCCA's informal comments on Energy Division's January 8, 2020 workshop, p. 5, sent to the
R.19-03-009 service list on January 21, 2020. Source data is from 2019 California Renewables Portfolio
Standard Annual Report
16 1 Page
CCAs to ESPs will likely lead to a net decline in RPS procurement since ESPs tend to procure
proportionally less RPS resources than the CCAs and IOUs. Although RPS procurement is not
precisely correlated with GHG reductions, a decline in the procurement of RPS resources would
likely lead to an increase in GHG emissions.
2.1.3 Impact of Direct Access Expansion on setting GHG emission
reduction targets in Integrated Resource Planning
The IRP process is a critical planning tool to reduce GHG emissions. The process starts by
forecasting of long-term demand for each LSE. These LSE-specific demand forecasts are derived
from CEC analysis in the Integrated Energy Polig Report (IEPR). The forecasts are adjusted to reflect
near-term load migration, which is projected based on historical sales. However, while the IEPR sets
targets for each IOU and CCA, it does not include individual load forecasts for ESPs. This is
because ESP load data is confidential and fluctuates based on customers' commitments. Instead, the
CPUC sets an aggregate GHG planning target for all ESPs within each IOU service territory and
then requires each ESP to calculate its own confidential GHG Emissions Benchmark using its own
load forecast.
In order to account for that uncertainty while forecasting load to set ESP targets, the IRP currently
requires ESPs to utilize their most recent year-ahead load forecast submission in the CPUC
Resource Adequacy proceeding and extend it out to 2030.' Using short-term forecasts from the
Resource Adequacy proceeding for long-term planning could lead to setting inaccurate procurement
targets in electric sector planning, and increases the risk that a potentially significant portion of
Direct Access load will not be planned for in IRP.
This mismatch between short-term forecasts and long-term planning raises several potentially
significant issues when integrating ESPs into the IRP process:
•Uncertainty among ESPs. As discussed in Section 1.4, ESPs do not have long-term
customer commitments, which makes load forecasting and long-term planning highly
uncertain. Load may shift between various ESPs on a year-to-year basis, which means that
the load that an ESP plans for today may grow or shrink, potentially significantly, in the
years ahead, leaving that portion of load unplanned for when it migrates to another ESP. In
a competitive environment in which customers can always leave and seek service with a
different ESP, ESPs will face challenges holding long-term contracts for resources that the
IRP process identifies as necessary.
•Load uncertainty for CCAs and IOUs. With the expansion of Direct access, load
uncertainty for ESPs leads to load uncertainty for CCAs and IOUs. Commercial and
industrial customers currently make up about 57 percent of electric load in California. If that
load becomes less predictable—more subject to moving between Direct Access and other
LSE classes—then all LSEs will have less planning certainty. With less confidence in the load
projections that they use in their IRPs, LSEs could be less willing to procure based on
20 AU J Ruling dated January 24, 2020 describing IRP load forecasts available here:
//docs.cpuc.ca.gov/PublishedDocs/Efile/G000 /M32.5 /K033 /325033751.PDF
17 I Page
identified planning needs.
•ESP load aggregation. Each ESP provides its own load forecast in IRP. Because ESP load
is confidential, they do this without knowing the load forecast of other ESPs or how their
load forecasts contribute to achieving the Direct Access cap. This creates a risk that the sum
of individually provided ESP forecasts will not add up to the total Direct Access load cap,
which is the portion of load that they must plan for in IRP. If ESPs do procure based on
their identified TRP needs, their collective procurement may still not add up to the aggregate
ESP procurement obligation, which would cause under-procurement and jeopardize the
electric sector meeting its 2030 GHG and reliability goals. If the Legislature opens more load
to Direct Access, this problem will be amplified.
To the extent that Direct Access providers serve a higher share of total load, the CPUC will need a
mechanism to ensure that ESPs procure their share of resources that meet GHG emissions
reduction targets. These challenges may be manageable, but they require a clear compliance and
enforcement regime to align the incentives of ESPs and their customers with IRP objectives. CPUC
authority to enforce the IRP planning requirements is limited at this time. Staff recommends that the
Legislature consider extending the CPUC's authority to enforce compliance.
2.1.4 Impact of Direct Access Expansion on Long-term Contracting to
Meet GHG Emission Reductions
In order to meet 2030 GHG emission targets, California will need to build nearly 25,000 MW of
new GHG-free resources, including over 12,000 MW of storage. This new capacity will need to
achieve commercial operation by 2026 to replace retiring gas generation.' As major capital
investments, new renewables projects cannot generally find financing without long-term purchase
agreements.
In the past, California has required the IOUs to sign the long-term power purchase agreements
needed to finance new generation and guaranteed the IOUs cost-recovery for these purchases.
However, IOUs will only be responsible for 50 percent of load by 2021, and the IOUs' portfolios
currently include more RPS eligible resources than they need to meet RPS requirements for their
current load. Meanwhile more RPS-eligible generation is still needed statewide for the California to
reach its 2030 GHG emission reduction targets. SB 350 addressed the issue that other LSF,s will be
increasingly responsible for ensuring new RPS resources are built by requiring that all LSEs procure
at least 65 percent of their RPS requirements through contracts of 10-years or longer. This
requirement starts in the 2021-2024 RPS compliance period. The 10-year contracting requirement is
necessary to ensure that RPS contracts cover the capital costs needed to finance new renewable
projects.
In informal comments to the January 8, 2020 workshop, Direct Access representatives stated that
21 fn.` vk) 16-02-007, 2019-2020 Proposed Decision on Electric Resource Portfolios to Inform Integrated
Resource Plans and Transmission Planning, Figure 2 (p. 36), mailed Feb. 22, 2020,.
18 I Page
ESPs are able to meet long-term contracting requirements and are on a pathway to compliance in
2024. Specifically, Shell Energy has announced a new 200 MW solar project and Direct Energy
announced a 250 MW solar project. Furthermore, Shell and Commercial Energy argue that
expansion of the DA market will increase market liquidity and encourage LSEs to pursue long-term
investments.'
Nevertheless, the ESPs have a limited record of entering long-term contacts. The 2019 C4fornia
Renewable Porpeolio Standard Annual Report found that long-term contracts account for 9 percent of
their total portfolio.' While the ESPs will not need to reach compliance with the 65 percent long-
term contracting requirement until 2024, ESPs will need to make a significant investment in the near
term for projects to come online between 2021-2024 to meet the 65 percent target.
CPUC staff is concerned that ESPs' short-term customer commitments may create an impediment
to making long-term investments in GHG-reducing resources. Customers seeking lower energy
costs will have an incentive to switch to the provider with lower cost portfolio. In a competitive
market, this could also impact the CCAs' ability to hold long-term contracts. In their informal
comments to the January 8, 2020 workshop, CalCCA stated that uncertainty caused by load
migration could undermine the long-term contracts that they have entered into and leave them
locked into a fixed price contract as they lose load to lower price competitors. CCAs, who are not
guaranteed cost-recovery and risk losing non-residential customers if Direct Access is expanded,
may delay investments in renewables and storage to avoid investing on behalf of customers who
then depart their service. The risk that load may depart is likely to raise borrowing .costs for those
projects that CCAs do pursue.
In sum, reopening Direct Access to all non-residential customers, Energy Division staff is concerned
that overall levels of renewable generation investment will decline and reduce GHG emission
reductions. While the 10-year RPS contracting requirement provides a floor by requiring longer-term
investment, reporting and enforcement occur at the end of the compliance period. This means that
the CPUC will not be able to rectify the shortfall if LSEs fail to procure the long-term contracts
needed to meet their compliance requirements.
2.2 lm oact on Criteria Air Pollution and Toxic Air Contaminants
The Federal Clean Air Act requires the Environmental Protection Agency (EPA) to establish
National Ambient Air Quality Standards (NAAQS) for the maximum allowable concentrations of
six "criteria" pollutants in outdoor air to protect public health: carbon monoxide, lead, ground-level
ozone, nitrogen dioxide, particulate matter, and sulfur dioxide.
22 2018 RPS Compliance Reports filed August 1, 2019 provide detail for the amount and number of long-
term contracts in place by ESPs as of the date of those filings
23 See Workshop Comments filed by Shell Energy.
24 See 2019 CahloniaRenewable Porffolio nagdarel Amid Report, pg. 20
19 I Page
The CPUC has very limited jurisdiction over the emission of criteria pollutants and toxic air
pollutants. CPUC jurisdiction consists of setting emission standards for criteria air pollutants
related to IOU owned Biomass facilities. The CPUC minimizes the emission of criteria air pollutants
through the requirements established by SB 100, which, in addition to setting more ambitious RPS
goals, requires that the State "Reduc[e] air pollution, particularly criteria pollutant emissions and
toxic air contaminants."' Additionally, the CPUC requires that LSEs "minimize localized air
pollutants" in their Integrated Resource Plans.
The CPUC's ability to assess the impact of expansion of Direct Access on criterial and toxic
pollutants is limited by the fact that most emissions in the state's electric system occur as the result
of unspecified transactions in the CATS° energy market. These unspecified energy purchases are
not tied to a specific generator or even resource type. However, as was discussed in section 2.1.1 and
illustrated in Figure 3, unspecified purchases are the primary source of brown power in the energy
resource mix of the system. While it is not feasible to calculate the criteria air pollutants for each
ISE, it can be reasonably concluded that air pollutant levels would be higher if LSEs primarily
procure unspecified power rather than power from specified carbon-free resources through long-
term renewable contracts.
As discussed in Section 2.1.4, new RPS standards require that LSEs procure 65 percent of their RPS
through contracts of 10-years or more, and primarily from in-state resources. While the new
compliance requirements adopted in RPS and IRP will likely require ESPs to shift toward a greener
portfolio, we anticipate that ESPs will continue to rely on unspecified energy procurement to the
extent they can. If Direct Access is further opened and ESPs continue their past practice of relying
on unspecified power as a significant source of their procurement, this could lead to an increase in
criteria air pollutants.
2.3 Ensuring Reliability with Expansion of Direct Access
2.3.1 How the CPUC Ensures Reliability
The CPUC manages electric reliability through the Resource Adequacy (R. 17-09-020) and IRP
proceedings (R.16-02-007). The purpose of the Resource Adequacy program is to ensure that
existing resources needed for reliability are kept online by requiring that CPUC jurisdictional LSEs
have sufficient capacity under contract to meet their peak demand plus a 15 percent planning reserve
margin. LSEs also are subject to local and flexible capacity obligations to ensure the resources
needed for local grid reliability and renewable intc-gration are under contract.
25Clean Air Act permitting is the shared responsibility of the California Air Resources Board (CARB), its 35
air pollution control agencies (districts), and EPA Region 9. California's 35 local Air Pollution Control
Districts or Air Quality Management Districts are responsible for regional air quality planning, monitoring,
and stationary source and facility permitting. The Air Quality Management Districts are responsible for the
monitoring the criteria air pollutants emitted by California electricity generators
Public Utilities Code Section 399.11 (a) (1)
20 Page
The Resource Adequacy program began implementation in 2006 pursuant to AB 380 (Nunez, 2005).
Current Resource Adequacy requirements are meant to provide thc energy market with sufficient
forward capacity to meet peak demand, ensure local area reliability and ensure reliable integration of
renewable energy. LSEs are required to make annual and monthly showing to the CPUC reflecting
that they meet their Resource Adequacy system, local and flexible Resource Adequacy requirements.
In D. 20-06-002, the CPUC adopted a centmli7ed procurement entity (CPE) that will be charged
with procuring local RA on behalf of all LSEs in PG&E's and SCE's service territories.
Longer-run reliability is addressed through the IRP process, which identifies the mix of new and
existing resources that will be needed to ensure reliability (as well as meet GHG targets) over the
longer run. The IRP identifies long-run needs by modeling system resources ten years into the future
to determine the level of procurement needed to meet forecasted demand. If the IRP identifies a
shortfall, the CPUC may order new procurement based on those findings, as discussed in Section
2.1.
Investment in new generation benefits all customers by lowering the risks of Resource Adequacy
shortfalls for all LSEs. However, because the costs of the investing in new resources are
considerable and all LSEs receive the benefits, each LSE has a financial disincentive to invest in new
generation. This creates a tendency for an unregulated market to underinvest in reliability, creating
the potential for capacity shortages.
Beginning in 2006, California addressed this potential market failure by requiring the IOUs to
procure new generation with independent generators on behalf of all LSEs. D.06-07-029 adopted a
Cost Allocation Mechanism (CAM) to ensure that IOUs can recover the costs of these investments
from other LSEs. The CAM works by allocating the net capacity costs of investments to all
customers through a non-bypassable charge. The capacity benefits are then allocated to LSEs based
on monthly peak load-shares. The guaranteed cost recovery provided by the CAM mechanism
allows the IOUs to act as central procurement agents for the other LSEs in their service territory to
ensure that the new resource needs identified through the Commission's long-term planning
processes are built and paid for by all customers who will benefit, both bundled and unbundled.
D.20-06-002 adopted a more formal central procurement structure, the Central Procurement Entity
(CPE) to ensure that local Resource Adequacy needs are met in PG&E and SCE's service territories.
The CPE will procure local Resource Adequacy on behalf of all LSEs and make sure the costs are
shared equitably. Initially the IOUs will fulfill the CPE function, but this function may be fulfilled by
other entities in the future.
2.3.2 Current Reliability Shortfalls Identified in Resource Adequacy and IRP
Recent trends documented in Energy Division's 2019 State of the Resource Adequacy Market Reportr
indicate a tightening market for Resource Adequacy. The Market Report documents that for the
2019 Resource Adequacy compliance year, 11 LSEs had year ahead local deficiencies, 6 had year-
ahead system deficiencies, and 5 had year-ahead flexible deficiencies in 2019. One reason reported
for local waiver requests was that LSEs could not identify available local capacity at any price. Many
27Issueci in R.17-09-020 Assigned Commissioner's ruling on September 3, 2019
211 Page
of these deficiencies persisted through the year in 2019 month-ahead filings. These trends also
continued into 2020 Year-ahead filings, where 20 LSE requested local waivers.' While the CPE
adopted in D. 20-06-002 will procure local Resource Adequacy, system and flex Resource Adequacy
requirements will remain the responsibility of the LSEs.
Appendix A includes the list of Resource Adequacy citations issued from 2006-2019. Of the 90
citations issued since 2006, 77 have been issued to ESPs, approximately 85 percent. Compliance
with Resource Adequacy obligations is the CPUC's primary mechanism to ensure reliability. The
ESPs' poor compliance record is an indication that expanding Direct Access to all non-residential
customers could lead to shortfalls in resource adequacy.
Furthermore, the total citation penalties amounts increased sharply in 2018. Prior to 2018 the total
annual citations issued averaged $27,518 per year. The CPUC issued $2.6 million in citations in 2018
and $9.5 million in 2019, plus an additional $8.8 million in enforcement penalties. The magnitude of
this increase is an indicator of a short supply in Resource Adequacy market. The tightening Resource
Adequacy market has made it difficult and more expensive to procure Resource Adequacy contracts,
particularly for newer LSEs. LSEs will only pay Resource Adequacy citations if there is no available
Resource Adequacy capacity to procure, or the needed Resource Adequacy costs more than the
citations themselves. Either way, the LSE's failure to procure Resource Adequacy contracts creates a
capacity shortfall for the entire system, which drives up energy prices for all customers and puts
system reliability at risk.
The system capacity shortfall identified in the Resource Adequacy proceeding is being addressed in
the IRP proceeding. D.19-11-016 ordered that 3,300 MW of additional capacity be procured by
Summer 2021 and assigned each LSE a share of the procurement obligation based on their
proportion of the total load.' D.19-11-016 further required that 50 percent of the required
resources come online by August 1, 2021, 75 percent by August 1, 2022, and 100 percent by August
1, 2023. As a stopgap measure to ensure reliability until the new generation is online, the decision
recommended to the State Water Board that generation contracts for several large Once Through
Cooling generators that were slated to retire by December 31, 2020, be extended through 2022.3°
CCAs and ESPs may choose to self-procure resources to meet their procurement obligations or may
elect to have the IOU procure on their behalf. However, D.19-11-016 directed CPUC staff to
develop a mechanism similar to CAM to address cost allocation associated with both LSEs that
choose to opt out of self-procurement and with LSEs that opt in (to self-provide) but fail to meet
their obligations.' This mechanism is still being developed in the IRP proceeding.'
28September 2020 Revised State of the Resource Adequacy Market Report.
29 D. 19-11 -016, Finding of Fact 5, p.68 and Ordering Paragraph 3, pp. 80-81.
30 D. 19-11-016, Ordering Paragraph 1, pp. 79-80.
31 D. 19-11-016, Ordering Paragraph 5, p. 82.
32.R. 16-02-007
22 I Page
2.3.3 Challenges to Meeting Resource Adequacy Shortfall in a
Disaggregated Market
D.19-11-016 is the first time that the CPUC has ordered non-IOU LSEs to direcdy procure new
generation capacity. It represents a test of whether individual LSEs in a competitive, disaggregated
market can effectively procure the resources needed to meet their long-term reliability obligations.
As stated in D.19-11-016 "[t]his is also an appropriate place to test how well the obligated LSEs
perform when given a procurement requirement for system reliability and renewable integration
resources in the context of IRP."33
There are several challenges to addressing the reliability challenges identified in D.19-11-016. There
are now over 40 LSEs that must build new generation. Even if each LSF, is each able to meet its
resource obligations, it is uncertain whether the state will obtain the most cost-effective mix of
energy resources from up to 40 independent procurements that can meet GHG targets while
meeting local and flexible resource adequacy.
As explained in Section 2.1.3, load migration makes it challenging for ESPs to accurately forecast
load and therefore to sign the long-term contracts needed to finance new resource development.
Staff acknowledges that several of the challenges with meeting reliability are not isolated to Direct.
Access but are also created by load migration from CCA formation. However, as stated in previous
sections, reopening Direct Access will exacerbate these challenges since it creates planning and
procurement uncertainty for CCAs.
Finally, the ESPs' procurement processes lack transparency when compared to IOUs' and CCAs'
procurement processes. IOUs receive up-front authorization from the CPUC for their bundled
procurement plans and submit all procurement contracts to the CPUC for review and approval. The
CPUC does not approve CCA procurements, but the CCAs' procurement plans are reviewed by
their boards at public meetings and agenda packets containing details of procurement transactions
are published on their public websites. In contrast, ESPs generally do not make information about
their procurement practices available to the public and claim privilege and confidentiality to avoid
disclosing information to the CPUC. This lack of transparency means that the CPUC cannot check
on the progress of ESP procurement activities towards compliance targets and propose remedies if
it seems likely that an ESP will fail to meet its obligations.
While P.U. Code 394.25 provides the grounds for the CPUC to suspend or revoke an ESP's
registration under certain conditions, it does not the CPUC the authority to revoke licenses of ESPs
due to repeated failure to comply with procurement requirements. Staff recommends that the
Legislature consider extending the authority provided by P.U. Code 394.25 to ensure that a few
ESPs who are out of compliance do not undermine the competitive market and put system
reliability at risk.
33 D.19-11-016 at 39
23 I Page
2.3.4 Mechanisms Under Development to Address Reliability in a More
Fragmented Retail Market
The CPUC is currently considering new procurement and cost allocation mechanisms in the TRP
•and Resource Adequacy proceedings that could solve the challenges of meeting reliability
requirements in a fragmented energy market. As discussed in Section 2.3.2, D.19-11-016 allows
LSEs to self-procure to meet IRP requirements, while also directing thc development a CAM-like
mechanism for LSEs that opt out or fail to meet their procurement obligation. D.19-11-016 also
creates a backstop procurement mechanism to be conducted by the IOU on behalf of LSEs that fail
to self-provide may come at a higher cost. However, it remains to be seen whether a backstop
procurement mechanism can deliver generation resources quickly enough to avoid near-term system
reliability issues.
The CPUC is also considering new structures to ensure reliability despite the load uncertainty that
characterizes the current market in the RA proceeding (R. 17-09-020). D.18-06-030 determined that
multi-year local Resource Adequacy should be procured through a central buyer that will purchase
all local Resource Adequacy contracts on behalf of all LSEs. D.20-02-006 directed PG&E and SCE
to act as centralized procurements entities for Local Resource Adequacy in their respective service
territories.
While central procurement has only been adopted for local Resource Adequacy,' a broader use of
centrali7ed procurement might be an effective way to overcome the challenges identified above
related to load migration as these affect other kinds of procurement as well.
2.4 Ensuring Direct Access Expansion Does Not Result in Cost
Shifting to Bundled Customers
P.U. Code Sections 366.1 and 366.2 require that customers leaving IOU bundled service do not
burden remaining customers with stranded costs that were incurred to serve them. To ensure that
bundled customers remain indifferent to the cost of load departures, CCA and Direct Access
customers are required to pay the Power Charge Indifference Adjustment (PCIA) for the "stranded"
or above market costs of resources procured by the IOUs on their behalf before they departed. The
PCIA. is intended to capture the largest potential cost-shifts between bundled and u-nbundled
customers.
In 2018 and 2019, the CPUC refined the PCIA methodology,' adding mechanisms to cap the
annual increase of the PCIA charge and to adjust the PCIA charge to reflect actual market prices for
Resource Adequacy and RPS resources. The CPUC continues to consider further methods to fairly
allocate costs and resources through Phase 2 of the PCIA Rulemaking (R.17-06-026). If Direct
Access is expanded to more nonresidential customers, the PCIA refinements that the CPUC has
already adopted and is still considering should address most of the cost-shifting concerns related to
34 D.20-06-002, Ordering Paragraph 3, p. 91.
35 See D.18-10-019 and D.19-10-001.
24 I Page
stranded investments in resources. However, in Settions 2.4.1 and 2.4.2 below, we consider other
classes of potential cost shifts that are not addressed by the PCIA.
2.4.1 Failure to meet Procurement Obligations will lead to Cost Shifting
Procurement costs will be equitably allocated to customers if all LSEs meet their own procurement
obligations. if LSEs request waivers to meeting their Resource Adequacy requirements, then
backstop procurement will be needed, which drives up the overall market cost. In the event the
LSE's failure to procure sufficient resources to ensure reliability, the CAISO may procure additional
resources under its "Reliability Must Run" program. These CAISO out-of-market procurements are
based on a "cost of service" rate that often times is much more expensive than competitive
procurements. These costs are allocated to all customers and can lead to cost shifting. To minimize
the need to rely on this costly mechanism, the CPUC has developed a backstop procurement
mechanism to order procurement through the Resource Adequacy program when one or more LSE
fails to meet its procurement obligations. As discussed in the Section 2.3, the CPUC backstop
mechanism's costs are allocated to the LSE that is short on its obligation. Reliance on backstop
procurement to meet system need will further tighten the market for all LSEs and continue to drive
up energy prices, which would also drive up rates for bundled customers. California has experienced
a significant increase in energy prices due to the tightening of the market since 2018, which will be
exacerbated if LSEs fail to secure procurement for new generation.
The cost allocation accounting of new mechanisms such as backstop procurement is extremely
complex, and it is not clear how these costs should be reallocated if an LSE goes bankrupt or its
customers migrate to a new LSE. Staff is uncertain that these many different mechanisms will
continue to function as designed if there are several different types of allocation mechanism layered
in the IOU billing systems. If they do not function as designed, there is the potential for additional
cost shifting.
2.4.2 Load Migration May Lead to Cost Shifting within Customer Classes
IOU tariffs group customers into different rate classes based on similar characteristics to serve that
class. Despite recent reforms to rate structures such as the limited adoption of time-of-use rates,
tariffs do not perfectly reflect the cost of serving each individual customer in that rate class. Rather,
each IOU tariff class includes customers that have more attractive load-profiles, and thus are less
expensive to serve, and other customers with load-profiles that are more costly to serve. When
customers with a different cost to serve all pay the same rate, the low cost of service customers are
essentially subsidizing those who are more expensive to serve.
Direct Access expansion could lead to cost shifting by changing the composition of customers
within each rate class. This could occur because customers with a lower cost of service have an
economic incentive to depart IOU service, leaving the IOUs with customers with a higher average
cost-of-service. Under competitive market conditions we can expect that the customers with a lower
cost-of-service will be more likely to choose ESP service since they can reap the greatest benefit in
25 I Page
terms of cost savings. This migration would change the composition of IOU tariff classes, leaving
the IOUs with a pool of higher cost customers. To cover the higher average cost of serving the
remaining pool of customers, IOUs would need to increase their rates for affected rate classes.
2.4.3 CCAs Have No Mechanism to Recover Stranded Costs
While SB 237 is focused on the potential undue cost shifting between bundled customers and Direct
Access customers, there is also the potential cost shifting impacts to CCA customers. With the long-
term procurement obligations established in 1RP and RPS, a rapid or unforeseeable departure of
load departure from CCAs could leave them with significant stranded costs that they cannot fully
recover through market transactions. If these stranded costs are significant enough that a CCA. fails,
residential customers of a CCA, including low-income customers, would be returned to either the
IOU or the otherwise designated Provider of Last Resort (POLR).
At this this time, the legislature has not asked the CPUC to consider potential exit fees or negotiated
compensation for the CCAs load obligations. However, Staff recommends that the Legislature
consider the CPUC's authority in allowing CCAs to recover the costs of investments that are
stranded because of unforeseen load departure to address these potential impacts.
26 I Page
3. Recommendations on the Schedule to Reopen Direct
Access
The Staff recommendations below identify the key conditions and requirements that ESPs should
meet prior to reopening any Direct Access services to nonresidential customers. Staff
recommendations also address timing parameters that should be taken into account if the
Legislature elects to reopen Direct Access. Should the Legislature enact an expansion of Direct
Access to all non-residential customers, staff recommends that the expansion should proceed on a
gradual basis to minimize planning disruptions associated with load departure.
Conditions and Demonstrations for Reopening Direct Access:
Determination of reopening Direct Access should be made no earlier than 2024, after the first phase
of Direct Access expansion mandated by P.U. Code Section 365.1(f) is completed. This schedule
will also allow the IRP procurement ordered by D.19-11-016 to be completed, and the ESPs to
demonstrate that they will meet the RPS 10-year contracting requirements. This schedule also allows
time for the CPUC to develop, adopt, and implement the procurement mechanisms, such as
backstop procurement, that are needed in the event that LSEs fall short of fulfilling any of their
procurement obligations.
If the Legislature chooses to open Direct Access, we recommend that reopening be conditioned on
ESPs' demonstrated compliance with the following obligations:
›- Integrated Resource Planning
o ESPs submit robust, transparent IRPs that:
•provide more certainty about individual ESP planning and forecasting over a
10-year time horizon, AND
•can be meaningfully aggregated with plans from other LSEs to form an
integrated resource plan for all CPUC-jurisdictional LSEs without causing
reliability or renewable integration issues; AND
o ESPs either:
•meet all procurement requirements pursuant to D.19-11-016; OR
•participate in successful cost allocation of their procurement obligation using
the modified CAM and backstop procurement mechanism directed by 0.19-
11-016: AND
•demonstrate a track record of procuring new resources in line with their
submitted IRP portfolios.
>Renewable Portfolio Standard
o ESPs meet their RPS obligations for 2021-2024 compliance period; AND
o ESPs meet 10-year contracting obligations in RPS
•Resource Adequacy (RA)
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o ESPs comply with all Resource Adequacy requirements including multi-year year ahead
flexible and system, and month ahead system and flexible obligations.
Table 3 (below) provides a timeline for these various compliance obligations.
Table 3: Timeline of compliance obligations for IRP, Resource Adequacy, and RPS.
2020 2021 2022 2023 2024
Phase One
SB 237
4,000 GW11
increase to the
Direct Access
Cap
IRP Filing
Requirements
July 1 I.SEs must
file long-term
procurement and
implementation
plans
•
ISTis must file
long-term
procurement and
implementation
plans if IRP
remains on a
two-year cycle
IRP
Procurement
(D.19-11-016)
CPUC develops
and approves a
modified CAM
mechanism.
50 % of
obligations by
Aug, 2021
75 % of
obligations by
Au Zea, 2022
100% of
obligations by
Aug, 2023
Resource
Adequacy
Requirements
Annual and
Monthly local,
system and flex
obligations.
Multi-year local
RA obligations.
Annual and
Monthly local,
system and flex
obligations.
Multi-year local
RA obligations.
Annual and
Monthly local,
system and flex
obligations.
Multi-year local
RA obligations.
Annual and
Monthly local,
system and flex
obligations.
Multi-year local
RA obligations.
Annual and
Monthly local,
system and flex
obligations.
Multi-year local
RA obligations.
RPS
Compliance
End of the
second RPS
Compliance
Period.
End of the third
RPS Compliance
Period.
Recommended Direct Access Reopening Schedule:
Should the above conditions and demonstration be met and the Legislature choose to reopen direct
access to non-residential customers, the CPUC Energy Division Staff recommends that the
Legislature follow historical precedents from SB 695 and SB 237 and phase-in additional Direct
Access load incrementally. Incremental phase-in will enable LSEs to better plan for potential load-
departures and thus create fewer potential cost-shift and reliability issues. Additionally, a phased-in
approach provides consistency and a planning horizon for customers and avoids snap decisions
28 I Page
from customers rushing into Direct Access to take advantage of a one-time opportunity. We
recommend the following phase-in schedule and conditions:
>Set an initial re-opening schedule of increments equal to 10 percent of eligible non-
residential load per year.
>Condition each annual expansion on CPUC review and approval of compliance with IRP,
Resource Adequacy and RPS requirements, as subject to CPUC approval.
>Order annual expansion to take place on a schedule that will allow Load Serving Entities
(LSEs) the ability to fully comply with Resource Adequacy requirements.
>ESPs must comply with the requirements of D.18-06-030 requiring all LSEs (including ESPs)
to participate in all aspects of the year-ahead Resource Adequacy process for load they plan to
serve in the following year and the "binding load forecast process" adopted in D.19-06-026.
The migration of 10 percent of non-residential load per year will minimize the planning disruptions
associated with load departure identified in this report and allow the CPUC and the market
sufficient time to develop the structures needed for long-term resource development in a
fragmented market
Recommendations for Legislative Action:
The CPUC recommends that the following legislative action is considered in order to ensure that
GHG emissions, reliability and cost shifting provisions are met:
>Provide CPUC clear authority to enforce compliance for MP GHG goals for all LSEs subject
to P.U. Code Section 454.52 (b).
>Ensure that the CPUC continues to have dear authority to enforce the state's Resource
Adequacy goals defined in P.U. Code Section 380.
> Amend P.U. Code Section 949.25 to provide the CPUC with the authority to revoke ESP
licenses and CCA registration for repeated non-compliance with Resource Adequacy, RPS or
IRP requirements.
>Ensure that provisions to ensure that there is no cost shifting as the result of customer moving
between different LSE (Electric Corporations, CCAs, and ESPs) are applied equitable to all
customers.
29 I Page
Consumer Protection Enforcement Division Resource Adequacy Citations
Compliance
Year
Citations
Issued
Citations
Issued on
ESPs
LSE,s Cited Total
Citation
Penalties
Enforcement
Cases
Enforcement
Cases on
ESPs
LSEs
Enforced
Total
Enforcement
Penalties
2006 1 1 Commerce Energy $1,500 0 0
0
2007 3 3 3Phascs; Commerce Energy; Amer. Util. Network $5,000 1 1 CNE $107,500
2008 7 7 3Phases (2); Commerce Energy (2); Corona DWP;
Sempra Energy; Shell Energy $17,000 1 1 Calpine $225,000
2009 4 4 Commerce Energy (3); CNE $26,500 1 1 CNE $300,000
2010 5 4 Commerce Energy; Pilot Power Group (2), Direct
Energy Business, SDG&E $25,500
0
0
2011 2 2 Liberty Power; Tiger Nat Gas $7,000 1 0 PG&E $215,000
2012 4 3 Glacial Energy of CA, Shell Energy, SDG&E, Direct
Energy Business $14,600 0 (.)
0
2013 5 4 SDG&E, Commerce Energy, 3 Phases, Liberty Power (2) $26,500
2014 1 1 3 Phases $5,000 0 0
0
2015 6 6 3 Phases (2), Commerce Energy (2), EDF Industrial,
Glacial Energy $38,000 0 0
0
2016 3 3 Tiger Natural Gas, Glacial Energy, Shell Energy $13,500 0 0
0
2017 6 4 Commercial Energy of Montana (2), CleanPowerSF,
Southern California Edison, Direct Energy Business,
Tiger Natural Gas
$150,110 0 0
0
2018 10 8 AmericanPol.verNet Management, Just Energy Solutions
(5), Direct Energy Business, Pilot Power Group, Pioneer
Community Energy (2)
$2,593,439 0
2019 33 27
Just Energy Solutions (12), Commercial Energy (8),
Agera Energy (6), San Jose Clean Energy (3), East Bay
Community Energy (2), Valley Clean Energy (2), Pioneer
Community Energy
$9,549,716 21 18
$2,758,560
Total 90 77
$12,473,365 25 21
$3,606,061
30 I P age
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October 1, 2020
Sent Via Email
Mr. Ed Randolph
Director, Energy Division
California. Public Utilities Commission
505 Van Ness Avenue, Room 4004
San Francisco, CA 94102
RE: San Diego Community Power and Clean Energy Alliance's Protest of San Diego
Gas & Electric Company's Advice Letter 3605-E Requesting Approval of System
Reliability Contracts Resulting from San Diego Gas & Electric Company's Request
for Offers Under D. 19-11-016
Dear Mr. Randolph:
Pursuant to General Order ("GO") 96-B, San Diego Community Power ("SDCP") and
Clean Energy Alliance ("CEA") file this protest to San Diego Gas & Electric Company's
("SDG&E") Advice Letter ("AL") 3605-E titled Request for Approval of System Reliability
contracts Resulting from SDG&E 's Request for Qffers Under D. 19-11-01e To fulfill its
incremental procurement obligation ordered by Decision ("D.") 19-11-016, SDG&E seeks
approval of two resources adequacy ("RA") purchase agreements and one power purchase
agreement ("PPA") with a third-party owned battery energy storage system (together, the
"Contracts"), as well as two battery energy storage systems to be constructed by a third-party and
owned and operated by SDG&E (the "EPC Agreements").2 SDG&E also seeks Commission
authorization to recover the cost of the Contracts and the EPC Agreements through customer
rates and to track and record net costs related to incremental procurement in a Resource
Adequacy Procurement Memorandum Account ("RAPMA") until a modified Cost Allocation
Mechanism ("CAM") is adopted in Rulemaking ("R.") 20-05-003.3
SDCP and CEA take issue with SDG&E choosing to procure from costly resources for
extended terms despite the fact that a majority of SDG&E's bundled service customers will be
departing for Community Choice Aggregation ("CCA") programs, like SDCP and CEA, next
year.4 While D. 19-11-016 required SDG&E to conduct an all-source solicitation, it required
AL-3605-E was submitted on September 11, 2020.
2 AL-3605 at 1.
3 Id.; Appendix A.
4 AL-3605 at Appendix C, SDG&E Independent Evaluator Report — 2021-2023 1RP Reliability RFO,
Tranche 1, Sep. 11, 2020 at 37.
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consideration of existing as well as new resources and storage.5 Contracts for existing resources
are required to be of at least three years in length, while contracts for new resources were
required to be at least ten years.' Given impending bundled customer departures beginning in
2021, SDG&E's solicitation should have given priority to existing, shorter-term resources.
Instead, SDG&E used its incremental procurement obligation as an opportunity to invest in
costly, long-term, lithium ion battery energy storage projects at ratepayer expense. Since these
costs will be allocated to ratepayers, a majority of which will be soon departing from bundled
service, on a non-bypassable basis, SDG&E will effectively shift these costs to its competitors
while retaining the resources' long-term benefits.7
Accordingly, to prevent SDG&E from imposing unnecessarily high non-bypassable
charges ("NBCs") on CCA customers, the Commission should deny AL-3605 and direct
SDG&E to revise its solicitation methodology to prioritize existing, shorter term resources.
Alternatively, in recognition of the unique circumstances around the application of D. 19-11-
016's requirement that at least 50 percent of the new incremental capacity be delivered by
August 1, 2021 in the San Diego region, SDCP and CEA request that SDG&E clarify whether
the proposed contracts will be accessible to SDCP and CEA through allocation, assignment, or
some other mechanism. For example, SDG&E should clarify whether the contracts contain a
provision allowing for the assignment of the resources from the utility's portfolio to the newly
formed CCA programs that had no chance to self-procure. 8 An assignment provision of this
nature would permit SDCP, CEA and SDG&E to negotiate on a voluntary basis, or subject to a
later Commission-approved process, for the orderly transfer of resources for fair value. SDG&E
would retain the right to enter into any assignment and would not be prejudiced or otherwise
harmed.
BACKGROUND
SDCP was formed by the participating cities of San Diego, Chula Vista, Encinitas,
Imperial Beach and La Mesa in December 2019, one month after the Commission issued D. 19-
11-016.9 The CCA program will launch and begin serving load in 2021, and at full enrollment,
5 D. 19-11-016, Decision Requiring Electric System Reliability Procurement for 2027-2023, Rulemaking
("R.") 16-02-007, Nov. 7, 2019 at Ordering Paragraph ("OP") 7.
6 D. 19-11-016 at OP 10.
7 Id. at 67. "We also clarify that the capacity procured by the IOUs in response to this decision will be
allocated on a non-bypassable basis through a modified earn mechanism and no PC1A. In other words, we
will not reduce the cost allocation amounts to be recovered by the IOUs after load migrates."
8 D. 19-11-016 at OP 3.
9 See San Diego Community Power Community Choice Aggregation Implementation Plan and Statement
of Intent ("SDCP Implementation Plan"), December 9, 2019.
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SDCP will serve a total of approximately 740,000 customer accounts currently served by
SDG&E.1° CEA was formed in November 2019 and plans to initiate CCA customer service in
early 2021, providing electric generation service to approximately 58,000 service accounts
located within the member cities of Carlsbad, Del Mar and Solana Beach.11 Both SDCP and
CEA are actively engaged in a number of steps to develop their respective programs, including
resource planning and rate structure finalization.
In D. 19-11-016, the Commission imposed an additional 3,300 megawatt ("MW") system
resource adequacy ("RA") procurement obligation on all load serving entities ("LSE") to be met
by August 2023.12 Each LSEs' share of the 3,300 MW was allocated on a pro-rata basis using
the 2018 Integrated Energy Policy Report ("IEPR") load forecast, adopted by the California
Energy Commission ("CEC") in February 2019, with the 2021 projected load shares identi fied in
Form 1.1c, "California Energy Demand Update Forecast 2018-2030, Mid Demand Baseline
Case, Mid Additional Achievable Energy Efficiency and Additional Achievable
Photovoltaics." 13
With regard to LSE obligations in the SDG&E service territory, the Commission
allocated 292.9 MW of capacity to SDG&E's bundled customers, 52.7 MW to SDG&E Direct
Access ("DA"), and 1.1 MW to the Solana Energy Alliance.14 Because this decision was issued
prior to the formation of SDCP and CEA, no obligation was allocated to either CCA program.
Investor-owned utilities ("IOUs") were required to conduct an all-source solicitation to
meet the incremental system RA obligation, and to consider existing as well as new resources,
demand-side resources, combined heat and power, and storage. 15 The decision also set a ten year
minimum for new resource procurement contracts, a five year minimum for energy efficiency
resources, and a three year minimum for existing resources.16
In the event that a CCA or electric service provider ("ESP") declines or fails to fully
procure their allocated obligation, the IOUs are required to procure on the LSE's behalf and
allocate capacity to the LSE's customers on a non-bypassable basis through a modified Cost
SDCP implementation Plan at 22.
See https://www.thecleanenergyalliance.org/studies-reports
'2 D. 19-11-016 atOP 3.
13 Id. at Conclusion of Law 18, OP 3.
14 Id. at OP 3.
'Id. at OP 7.
16 Id. at OP 10.
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Allocation Mechanism ("CAM").17 The Commission clarified that, since the CAM, and not the
Power Charge Indifference Adjustment ("PCIA"), will be used, an IOU's cost allocation
amounts will not be reduced due to load migration.18 As such, while neither SDCP nor CEA
have the right to self-procure under D. 19-11-016, SDCP and CEA customers will be continue to
be charged for their share of SDG&E's incremental procurement costs on a non-bypassable basis
even after departing for CCA service.
The decision requires 50% of each LSE's portion to be online by August 1, 2021, 75% by
August 1, 2022, and 100% by August 1, 2023.19 Due to opt-out decisions by SEA and certain
DA providers, SDG&E must procure an additional 8.4 MW of capacity, resulting in a total
procurement obligation of 301.3 MW, with at least 150.65 MW to be put online by August 1,
2021.20
To fulfill its 301.3 MW obligation, SDG&E, conducted a single all-source solicitation to
procure resources for all three online delivery dates and provided specific protocols for offers
from various preferred resources including Energy Efficiency, Demand Response, Renewable
Generation, Combined Heat and Power, and Energy Storage.21 In AL-3605, SDG&E proposes to
procure from five lithium ion battery energy storage systems, two of which will be owned and
operated by SDG&E.22 The remaining three Contracts would be for a term of 15 years each. 23
Altogether, SDG&E's proposed transactions would provide 164 MW, approximately 13 MW
more than the 50 percent target, of total capacity by August 1, 2021.24
PROTEST
SDCP and CEA file this protest against AL 3605-E on the grounds that the relief
requested is unjust, unreasonable, or disctiminatory.25 SDCP and CEA customers will be forced
to pay non-bypassable charges ("NBCs") to cover the cost of SDG&E's procurement even
though SDCP and CEA had no ability to self-procure for the resources. SDG&E's decision to
17 Id. at OP 5.
181d. at 67.
19 Id. at OP 3.
2° AL-3605 at 2.
21 AL-3605 at Appendix C, SDG&E Independent Evaluator Report — 2021-2023 1RP Reliability RFO,
Tranche 1, Sep. 11, 2020 at 1.
22 Id. at 9.
23 Id.
24 AL-3605 at 2.
25 See GO-96B, General Rule 7.4.2.
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ENERGY & ENVIRONMENTAL LAW
meet its procurement obligation through long-term new battery storage projects, rather than
through short-term existing resources, will essentially require SDCP and CEA customers to
assume the risk of SDG&E's investment. To prevent this unjust, unreasonable, and
discriminatory outcome, the Commission should deny SDG&E's proposal and instruct SDG&E
to procure shorter-term resources. Separately, SDG&E should be required to clarify whether the
Contracts and the utility owned resources secured under the EPC Agreements are accessible to
CCA programs through allocation, assignment or other mechanism.
A. SDCP and CEA Ratepayers will be Forced to Cover a Majority of SDG&E's
Procurement Costs
The Commission issued D. 19-11-016 in recognition of a need for system RA and
renewable integration resources beginning in 2021 and extending through at least 2023.26
SDG&E's 292.9 IVEW capacity allocation represented load forecasts at the time showing that
SDG&E would be serving the majority of the region's load in 2021.27 Circumstances have
changed, however, and a majority of SDG&E's bundled service customers will be departing for
CCA service beginning in 2021. Despite this shift, SDG&E's obligation remains the same, and
SDG&E will be required to procure incremental capacity on behalf of SDCP and CEA customers
even after they depart. As with capacity procured for customers of opt-out LSEs, capacity
procured in response to this decision and the resulting costs will be allocated on a non-
bypassable basis to SDCP and CEA customers.
The Commission should not allow SDG&E to incur unnecessarily high procurement
costs and pass a majority of the costs on to its competitor's customers without providing SDCP
and CEA an opportunity to access the resources that are ultimately approved. After D.19-11-016
was issued, two new CCA programs, SDCP and CEA, were formed and plan to begin serving
load in SDG&E service territory beginning in 2021.28 The recent load forecast issued in the
previous IRP proceeding reflected that approximately 61.60% of SDG&E's 2020 bundled
service load will shift to new CCA or DA programs in the SDG&E Planning Area by 2022.29
The forecast further reflects that a majority of that load departure is attributable to SDCP and
26 D. 19-11-016 at Finding of Fact 17.
27 Id. at Finding of Fact 24.
28 See San Die:zo Community Power Community Choice Aggregation Implementation Plan and Statement
of Intent December 9, 2019; Clean Energy Alliance Community Choice Aggregation Implementation
Plan and Statement of Intent, December 19, 2019.
29 See Administrative Law Judge's Ruling Correcting April 15, 2020 Ruling Finalizing Load Forecasts
and Greenhouse Gas Benchmarks for Individual 2020 _Integrated Resource Plan Filings', R. 16-02-007,
dated May 20, 2020, Attachment A at 2. (The load forecast table shows that SDG&E's estimated load
will fall from 13,959-Gigawatt Hours ("GWh") in 2020 to 5,359 GWh in 2022).
5
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ENERGY& ENVIRONMENTAL LAW
CEA as they begin serving customers in 2021.30 As such, the majority of incremental capacity
that SDG&E procures for 2021-2023 will be attributed to and paid for by SDCP and CEA
customers while SDG&E—not SDCP or CEA—retains control over the contracts. This leaves
SDCP and CEA in a position similar to an LSE that opts-out or fails to meet its obligation,
despite SDCP and CEA having had no opportunity to self-procure. Such an outcome leaves
SDCP and CEA powerless over SDG&E's procurement decisions and forces SDCP and CEA
customers to pay the price.
B.The Solicitation Process was Unreasonable
SDG&E was imprudent in failing to take impending customer departures into account
during the solicitation process. SDG&E's solicitation should have given priority to short-term
contracts with existing resources because of impending bundled customer departures beginning
in 2021. Instead, SDG&E set the minimum contract terms for all bids at 10 years, thus
precluding the consideration of any short-term existing rcsources.31 SDG&E also gave the same
priority to energy efficiency projects, which were allowed to be set for five years, and energy
storage projects.' Given SDG&E's forecast demand reduction over the next three years, it was
unreasonable to not place a priority on shorter term contracts during the solicitation process or to
even allow for existing resource bids to be set at the minimum allowed by D. 19-11-016. Though
bids were set at a minimum of ten years, SDG&E's proposed Contracts are for terms of 15 years
each.33 Since these costs will be allocated to ratepayers, a majority of which will be soon
departing from bundled service, on a non-bypassable basis, the Commission should not authorize
SDG&E to enter into contracts for terms greater than the minimum required.
Further, despite its obligation to procure system RA, SDG&E inexplicably added RA
value to offers with points of interconnection within the SD-IV Local Resource Area.34 It
appears as though such preferential treatment, not required by the Commission, further limited
SDG&E's choices over projects.
C.Resources Under the Proposed Contracts Should be Accessible to SDCP and CEA
through Allocation or Assignment
3° See Id. (By 2022, SDCP will serve 7,407 GWh, CEA will serve 929 GWh, and DA programs will
serve 3,940 GWh).
31 AL-3605, Appendix B.1 at 2. ("The minimum contract term for all bids was 10 years, except for energy
efficiency bids, which had a minimum term of 5 years.")
32 Id. at 6.
33 AI-3605 at 9.
34 Id.
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Since SDCP and CEA customers will be liable for SDG&E's procured capacity and
associated costs despite SDCP and CEA's inability to self-procure, the Commission should
ensure that the proposed Contracts are accessible and can be assigned to SDCP or CEA, or
resources can be allocated to SDCP and CEA at a later date. The Independent Evaluator's report
that was included as Attachment C to AL-3605 indicates that SDG&E's model RA confirm
would have allowed free assignment to a central procurement entity, California CCA, or Joint
Powers Authority.35 Since the remainder of that section is redacted, the AL is unclear as to
whether SDG&E's proposed Contracts will allow for free assignment to SDCP and CEA. Given
the circumstances described above, the Commission should not authorize SDG&E to enter into a
contract that prevents SDG&E from assigning to a CCA.
CONCLUSION
While SDCP and CEA recognize that D. 19-11-016 provides a short procurement
timcframe, SDG&E cannot be allowed to invest in costly energy storage systems at the expense
of CCA customers without a means of accessing the resources. SDG&E engaged in a
solicitation process that favored longer-term projects with full knowledge that the bulk of its
customer load would be departing beginning in 2021 and that those customers would be
allocated the capacity and costs on a non-bypassable basis. To prevent SDG&E from unjustly
shifting imprudently incurred costs on CCA customers, the Commission should deny the
proposed transactions or, in the very least, ensure that the procurement contracts contain
provisions making the resources accessible to SDCP and CEA such as a reasonable assignment
provision allowing customers of newly formed CCAs that were excluded from D. 19-11-016 to
benefit from the power and capacity that was for all practical purposes purchased on their behalf.
Respectfully,
/s/ Ty Tosdal
Ty Tosdal
Tosdal, APC
777 S. Highway 101, Suite 215
Solana Beach, CA 92075
(858) 252-6416
ty@tosdalapc.com
35 Attachment C at 27.
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Attorney for San Diego Community Power
and Clean Energy Alliance
Copy (via e-mail): CPUC Energy Division (EDTariffUnit@cpuc.ca.gov)
Gregory Anderson, SDG&E (ganderson@sdge.com)
SDOETariffs@sdge.corn
8
CCA
ADVANCING LOCAL ENERGY CHOICE
September 29, 2020
CPUC Energy Division
Attn: Tariff Unit and Edward Randolph, Director
505 Van Ness Avenue
San Francisco, CA 94102
By email: EDTariffUnitAcpuc.ca.gov
Re CalCCA Protest to Southern California Edison's and San Diego Gas and Electric's
AMP Advice Letters in response to Decision 20-06-003
Dear Tariff Unit and Mr. Randolph:
Pursuant to General Order 96-B, CalCCAI submits this protest to Southern California
Edison Advice Letter 4287-E and San Diego Gas and Electric Advice Letter 3602-E / 2902-G
("Advice Letters").
Southern California Edison (SCE) and San Diego Gas and Electric (SDG&E) filed their
Advice Letters on September 9, 2020 in response to Decision ("D") 20-06-003, Ordering
Paragraph ("OP") 83 and OP 87.
OP 83: To implement the arrearage management payment (AMP) plan, Pacific
Gas and Electric Company, San Diego Gas & Electric Company, Southern
California Edison Company, and Southern California Gas Company must each
file a Tier 2 Advice Letter within 90 days of this decision to implement the AMP
plan.
OP 87: The issue of concern raised by CalCCA as it relates to the allocation of
proportional recovery shall be discussed in the AMP working group and a
proposed resolution shall be set forth in the Tier 2 Advice Letters that Pacific Gas
and Electric Company, San Diego Gas & Electric Company, Southern California
Edison Company, and Southern California Gas Company file.
1 CalCCA was formed in 2016 as a trade organization to facilitate joint participation in certain
regulatory and legislative matters in which members share common interests. CalCCA's voting
membership includes CCAs serving load and others in the process of implementing new service,
including: Apple Valley Choice Energy, Baldwin Park Resident Owned Utility District, Central Coast
Community Energy, CleanPowerSE, Clean Energy Alliance, Clean Power Alliance, Desert Community
Energy, East Bay Community Energy, Lancaster Choice Energy, MCE, Peninsula Clean Energy, Pioneer
Community Energy, Pico Rivera Innovative Municipal Energy, Pomona Choice Energy, Rancho Mirage
Energy Authority, Redwood Coast Energy Authority, San Diego Community Power, San Jacinto Power,
San Jose Clean Energy, Silicon Valley Clean Energy, Solana Energy Alliance, Sonoma Clean Power,
Valley Clean Energy, and Western Community Energy.
ADVANCING LOCAL ENERGY CHOICE
While the Advice Letters adequately addresses the requirements established in D.20-06-
003, certain provisions require further clarification.
1.The Advice Letters should clarify how often SCE and SDG&E plan to remit
amounts recovered for generation-related arrears to the CCA.
CalCCA is supportive of SCE and SDG&E's proposals to have all debt forgiven through
the AMP, including third-party charges, tracked in the residential uncollectibles balancing
account and then recovered through the public purpose programs charge.2 Additionally, SCE
states that it "will render amounts recovered for CCAs' generation-related AMP subsidies to the
CCA"3 but does not clarify how often (e.g., on a monthly basis or quarterly basis) the amounts
recovered would be transmitted to the CCA. SCE's Advice Letter should be re-filed to clarify
this detail.
Furthermore, CalCCA is concerned that SDG&E does not make any statement that it
plans to render amounts recovered for forgiven CCA arrears to CCAs in its Advice Letter. Thus,
the Advice Letter should be re-filed to clarify SDG&E intends to render all amounts recovered
for third-party charges that are forgiven to the third party to which they were owed, and clarify
the frequency and process through which such amounts will be rendered. Specifically, SDG&E
should clarify whether it plans to remit funds collected to recover debt-forgiveness costs to CCA
programs using the same process and with the same frequency, i.e., daily, that it uses to process
CCA program charges under SDG&E Rule 27. To the extent that the remittance process
deviates from the process described in Rule 27, SDG&E should provide a detailed explanation
regarding how its plan differs from that process.
2.SCE and SDG&E should be required to provide program information at the
intervals requested by the CCAs, and SDG&E should clarify what information it
will provide CCAs that notify it that they intend to participate in the AMP.
As described in the Advice Letters, SCE and SDG&E's proposals for additional
information to-be reported to CCAs about the AMP differ significantly. SCE correctly describes
that CalCCA requested the following information to-be able to track the status of unbundled
customer who are enrolled in the AMP:
1.AMP Eligibility / Ineligibility Flag (requested weekly)
2.AMP Enrollment Flag (requested weekly)
3.AMP Start / End Date (requested weekly)
4.Missed Payments Tracking (requested daily)
5.Total Expected AMP Dollar Amount (requested daily)
a. Total Expected Generation Dollar Amount
2 SDG&E Advice Letter at pp. 6-7 and SCE Advice Letter at p. 12.
3 SCE Advice Letter at p. 12.
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LC CA
ADVANCING LOCAL ENERGY MICE
b. Total Expected Distribution Dollar Amount
6. Processed AMP Dollar Amount (requested daily)
a.Processed Generation Dollar Amount
b.Processed Distribution Dollar Amount.'
Although CalCCA requested the information on a daily or weekly basis, CalCCA understands
that both SCE and SDG&E will be implementing AMP through manual processes until SCE can
automate the AMP in its customer service system and SDG&E completes deployment of its
customer information system ("CIS"). SCE and SDG&E should clarify when they plan to
automate the AMP program in their customer service systems, and provide the requested
information at frequencies requested as much as possible.5 The information described above
should be regularly provided to CCA programs on at least a weekly basis to provide timely
information about AMP participation and avoid costly and time consuming account
reconciliations that would be required if the data is provided on a.less frequent basis.
Furthermore, SDG&E states that it "does not intend to deviate from any of the reports
currently provided to its CCAs" and that it "will work with its current CCA, Solana Energy
Alliance, to accommodate data requests prior to implementation of the new CIS system."6
CalCCA fmd this troublesome because having to formally data request information for an
ongoing program is not only slow and inefficient but also does not allow a CCA to have any
visibility into which of its customers are eligible for or enrolled in the AMP because eligibility is
determined based on both IOU and third-party arrears. Additionally, the dollar value of arrears
that are expected to be forgiven, the value of forgiven amounts that have been processed, and
whether a customer has made the monthly payment it was supposed to make and is still in good
standing in the program must be communicated to the CCAs that participate in the program. It is
essential for a CCA to have access to data about the an-earage amounts it is owed that will be
forgiven in order to update its billing system logic and billing system reporting to coordinate the
third-party billing side of an unbundled customer's bill.
3. SCE should clarify whether a CCAs notice of intent to participate in the AMP is
requested 45 days from the date of approval of the Advice Letters.
SCE states that it "requests that the CCAs notify SCE within 45 days of this AL submittal
regarding their intent to participate" in the AMP.7 CalCCA requests that SCE modify the Advice
Letter to state that it requests notification 45 days after the approval of the Advice Letter.
CalCCA finds it unreasonable that CCAs are being asked to determine whether or not they will
participate in the AMP without knowing exactly what the final Advice Letters that are approved
by the Commission will state about the how the AMP will be implemented.
4 SCE Advice Letter at p. 13.
5 SCE Advice Letter at p. 13.
6 SDG&E Advice Letter at p. 7.
7 SCE Advice Letter at p. 13.
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14CALCCA
ADVANCING LOCAL ENERGY CHOICE
We thank the Commission for its consideration of this protest and urge the Commission
to require SCE and SDG&E to re-file their Advice Letters to clarify the abovementioned issues.
Respectfully submitted,
Evelyn Kahl
General Counsel to the
California Community Choice Association
cc: AdviceTariffManager@sce.com
Karvn.Ganseckisce.com
SDG&ETariffs(cilsdge.com
GAndersonsdge.com
Service List R. 18-07-005
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