HomeMy WebLinkAbout2021-11-18; Clean Energy Alliance JPA; ; Adopt Resolution 2021-014 Authorizing the City of Escondido to Become a Party to the Joint Powers Agreement and a Member of the Clean Energy Alliance__ Iii
CLEAN ENERGY ALLIANCE
DATE:
TO:
FROM:
ITEM3:
Staff Report
November 18, 2021
Clean Energy Alliance Board of Directors
Barbara Boswell, Chief Executive Officer
Adopt Resolution 2021-014 Authorizing the City of Escondido to Become a Party to the
Joint Powers Agreement and a Member of the Clean Energy Alliance
RECOMMENDATION
1) Adopt Resolution No. 2021-014 Authorizing the City of Escondido to Become a Party to the Joint
Powers Agreement and a Member of the Clean Energy Alliance.
2) Direct staff to prepare an Implementation Plan Amendment reflecting a City of Escondido launch in
2023 and return to the Board for approval no later than the December 30, 2021, Board Meeting.
3) Direct staff to include the City of San Marcos in the Implementation Plan Amendment contingent on
the City of San Marcos adopting an ordinance establishing a community choice aggregation through
Clean Energy Alliance.
BACKGROUND AND DISCUSSION
The City of Escondido has been evaluating options related to bringing community choice energy to
residents and businesses within Escondido and the results of those efforts identified joining Clean
Energy Alliance (CEA) was the City's best option.
At its October 27, 2021, meeting, the Escondido City Council adopted a resolution to join CEA and
introduced an ordinance to establish a Community Choice Aggregation Program. The second reading
and adoption of the ordinance is planned for November 17, with the ordinance effective 30-days after
adoption.
As part of CEA's evaluation of Escondido joining, CEA received historical electric usage data from San
Diego Gas & Electric (SDG&E) for Escondido load. CEA's technical team at Pacific Energy Advisors
analyzed the usage, prepared a financial proforma utilizing CEA's revenue and expense assumptions,
and an assessment report (Attachment B). The assessment report concluded that CEA expansion into
Escondido would have a positive financial impact on CEA.
In anticipation of San Marcos City Council consideration of joining CEA and the desire to bring
community choice in 2023, CEA also received San Marcos electric usage data and a financial proforma
and assessment report were prepared (Attachment C). The assessment report concluded that CEA
expansion into San Marcos would have a positive financial impact on CEA.
Financial Assessment
November 18, 2021
Escondido New Member
Page 2 of3
Using a base assumption of enrolling customers in April 2023, which was determined to be the optimal
enrollment date, and serving 90% of eligible customers, the assessment concluded that with the
addition of Escondido, CEA's net operating margin would increase by approximately 85% beginning in
FYE 2024, which would be the first full fiscal year of service. The projected incremental revenues, costs,
and net operating margin are shown in Table 1 below:
Table 1: Incremental Net Margins from Expansion (in $MM) City of Escondido
__ ,, __ ----------------------------------·----··--. --7 FYE 20231 FYE 2024 FYE 2025
Revenue $10.3 $52.1 $52.4
Power Costs -$8.1 -$43.6 -$41.1 -----~ .. ------~-. --_,,,_, __ -----I-------------
Other Costs -$0.3 -$1.2 -$1.2 .
--------~ -----------· -
Reserve Contribution -$.52 -$2.61 -$2.62
Net Operating Margin $1.38 $4.69 $7.48 .. _,, _______ ---------------------... ----------------------__ ,
Using a base assumption of enrolling customers in April 2023, which was determined to be the optimal
enrollment date, and serving 90% of eligible customers, the assessment concluded that with the
addition of San Marcos, CEA's net operating margin would increase by approximately 30% beginning in
FYE 2024, which would be the first full fiscal year of service. The projected incremental revenues, costs,
and net operating margin are shown in Table 1 below
Table 2: Incremental Net Margins from Expansion (in $MM) City of Son Marcos
! FYE 20232 ' FYE 2024 FYE 2025 !
Revenue $6.9 $34.1 $34.2
Power Costs -$5.4 -$28.6 -$27.0
Other Costs -$0.2 -$0.8 -$0.8
Reserve -$.35 -$1.71 -$1.71
Net Operating Margin $1.05 $2.99 $4.69
In addition to evaluating financial impact, the assessment report reviewed impacts to energy product
procurements needed to serve the City of Escondido. These products include Renewable Energy (short-
term and long-term), Carbon Free Energy, System Energy and Resource Adequacy (RA) capacity.
I
! I
Accommodating the expansion will require careful consideration of resource availability, particularly for
RA and long-term renewable energy products. When Escondido customers transition to CEA service,
SDG&E should have surplus RA and long-term renewable energy supply. CEA will need to work closely
with SDG&E to acquire the surplus supply SDG&E holds to ensure CEA can meet its new obligations. Staff
is confident that SDG&E can work together to reach an agreement for the procurement of power supply
1 Reflects partial year of service for fiscal year ending June 30, 2023, with enrollments assumed to commence on
April 1, 2023.
2 Reflects partial year of service for fiscal year ending June 30, 2023, with enrollments assumed to commence on
April 1, 2023.
November 18, 2021
Escondido New Member
Page 3 of3
and anticipates beginning this process with SDG&E in early 2022 to allow sufficient time to negotiate the
procurements.
Based on the results of the assessments, staff recommends CEA Board approve the addition of
Escondido as a new member of CEA and direct staff to prepare the Implementation Plan Amendment
reflecting expanding service in 2023. In addition, to ensure service can be offered to San Marcos in
2023, staff recommends CEA Board to direct staff to include San Marcos in the Implementation Plan
Amendment, contingent on San Marcos City Council approving its ordinance to establish Community
Choice Aggregation service.
FISCAL IMPACT
Pursuant to CEA's policy, the cost of preparation of the Implementation Plan Amendment, up to a not to
exceed amount of $50,000, is to be split between the two cities. Escondido and San Marcos will be
eligible for reimbursement of the cost within three years of CCA service commencement.
ATTACHMENTS
Attachment A Resolution 2021-014 Authorizing the City of Escondido to Become a Party to the Joint
Powers Agreement and a Member of the Clean Energy Alliance
Attachment B Clean Energy Alliance New Membership Assessment, City of Escondido
Attachment C Clean Energy Alliance New Membership Assessment, City of San Marcos
DocuSign Envelope ID: 3A06A6A2-7074-4A44-9EE9-E93EC8D0F0EE
RESOLUTION NO. 2021-014
A RESOLUTION OF THE BOARD OF DIRECTORS
OF THE CLEAN ENERGY ALLIANCE AUTHORIZING THE CITY OF ESCONDIDO TO BECOME A
PARTY TO THE JOINT POWERS AGREEMENT AND A MEMBER OF THE CLEAN ENERGY ALLIANCE
THE BOARD OF DIRECTORS OF THE CLEAN ENERGY ALLIANCE DOES HEREBY FIND, RESOLVE AND
ORDER AS FOLLOWS:
WHEREAS, on September 24, 2002, the Governor of California signed into law Assembly
Bill 117 (Stat. 2002, Ch. 838; see California Public Utilities Code section 366.2; hereinafter
referred to as the "Act"), which authorizes any California city or county, whose governing body
so elects, to combine the electricity load of its residents and businesses in a community-wide
electricity aggregation program known as Community Choice Aggregation ("CCA"); and
WHEREAS, the Act expressly authorizes participation in a CCA program through a joint
powers agency; and on November 4, 2019, the Clean Energy Alliance ("CEA" or "the Agency")
was formed under the Joint Exercise of Power Act, California Government Code section 6500 et
seq., among the Cities of Carlsbad, Solana Beach and Del Mar to work cooperatively to create
economies of scale and implement sustainable energy initiatives that reduce energy demand,
increase energy efficiency, and advance the use of clean, efficient, and renewable resources in
the region for the benefit of all the parties and their constituents, including, but not limited to,
establishing and operating a CCA program; and
WHEREAS, on March 16, 2020, the California Public Utilities Commission ("CPUC")
certified the "Implementation Plan" of CEA, confirming CEA's compliance with the
requirements of the Act; and
WHEREAS, Section 2.4 of the CEA Joint Powers Agreement ("Agreement") sets forth the
procedures for the addition of new member jurisdictions; and
WHEREAS, including new member jurisdictions within CEA's Joint Powers Authority can
benefit CEA communities, customers, and the general public by 1} expanding access to
competitively-priced renewable and carbon-free energy; 2) achieving greater economies of
scale while accelerating the reduction of greenhouse gas emissions; 3} enhancing CEA's
financial strength through increased revenues and reserves; 4} expanding the opportunities for
local renewable energy and decarbonization projects and programs and the creation of local
jobs; and 5} empowering local stakeholders with more direct representation before State-level
regulators and elected officials; and
DocuSign Envelope ID: 3A06A6A2-7074-4A44-9EE9-E93EC8D0F0EE
WHEREAS, on October 27, 2021, through a unanimous vote of its City Council, the City
of Escondido adopted Resolution No. 2021-169 authorizing the execution of the Joint Exercise
of Powers Agreement of the Clean Energy Alliance and authorizing staff to take other actions
necessary for the City of Escondido to join CEA, and introduced Ordinance No. 2021-12
ordaining the City Council's decision, pursuant to Public Utilities Code Section 366.2 to
implement a CCA program within the jurisdiction of the City of Escondido by participating in
CEA, under the terms and conditions of its Joint Powers Agreement; and
WHEREAS, on November 17, 2021, the City of Escondido conducted a second reading
and adopted ordinance No. 2021-12 ordaining the City Council's decision, pursuant to Public
Utilities Code Section 366.2 to implement a CCA program within the jurisdiction of the City of
Escondido by participating in CEA, under the terms and conditions of its Joint Powers
Agreement; and
WHEREAS. Pacific Energy Advisors on behalf of CEA conducted an assessment of the
financial and resource planning impacts of adding Escondido as a member of CEA and
concluded that there would be an overall positive financial effect; and
WHEREAS, per CPUC rules, prospective member jurisdictions must join CEA before the
end of calendar year 2021 in order to begin customer enrollments in CEA's service options by
2023;and
WHEREAS, Section 2.4 of the Agreement requires the Board of Directors to adopt a
resolution by a two-thirds vote of the entire Board authorizing the membership of additional
member jurisdictions, and specifying the conditions for membership, if any.
NOW, THEREFORE, THE BOARD OF DIRECTORS OF THE CLEAN ENERGY ALLIANCE DOES
HEREBY RESOLVE AS FOLLOWS:
Section 1. The City of Escondido is hereby authorized to become a party to the Agreement and
a member of CEA, subject to the following conditions:
(a) The Community Choice Aggregation ordinance adopted by the City of Escondido
becoming effective.
(b) The execution of the Agreement by the duly authorized official of the City of
Escondido.
(c) Reimbursement to CEA by City of Escondido of CEA costs incurred in connection with
adding a new agency, including, but not limited to, the cost of analysis of historical
usage data using CEA's financial proforma model to determine impact to CEA of the
proposed member; and preparation of an Amended Implementation Plan and related
activities of the expansion.
DocuSign Envelope ID: 3A06A6A2-7074-4A44-9EE9-E93EC8D0F0EE
PASSED AND ADOPTED by the Board of Directors of the Clean Energy Alliance this 18th day of
November 2021, by the following vote:
AVES: Druker, Bhat-Patel, Becker
NOES: None
ABSENT: None
ATTEST:
G~~~~,&~ilU\., bbAf't swumi
Kristi Becker, Chair
Sheila Cobian, Interim Board Secretary
SUMMARY
Clean Energy Alliance New Membership Assessment
City of Escondido
November 2021
The City of Escondido ("City") has engaged with the Clean Energy Alliance ("CEA") to explore the possibility
of joining CEA. On behalf of CEA, Pacific Energy Advisors, Inc. ("PEA") conducted an assessment of the
financial and resource planning implications associated with extending CEA service to electric customers
within the City (which are currently receiving bundled electric service from the incumbent utility, San
Diego Gas & Electric, or "SDG&E"). The assessment involved a study to understand the potential increase
in electric load and the additional energy resources that would be needed to serve the City. The study
also estimated the incremental revenues that would be derived from electricity sales to City customers,
as well as the incremental costs associated with energy resource procurement and other items/services
that would be necessary to support CCA service expansion to City customers. These factors were jointly
evaluated to determine whether any operating surpluses could be generated, on a projected basis, for
the benefit of CEA and its customers.
In consideration of the prospective timing associated with amended implementation plan submittal and
in accordance with existing regulatory rules, the earliest possible enrollment date for City customers
would be January 1, 2023.' For this assessment, PEA modeled various enrollment start times in 2023 and
found that April 2023 would be optimal from a financial perspective. Thus, enrollment would be expected
to occur toward the end of CEA's fiscal year ending 2023; the first full year reflecting City load would be
CEA's fiscal year ending 2024.
Under base case assumptions, the analysis indicates that expansion would yield a positive financial impact
for CEA: the expansion would be expected to increase CEA net operating margin by approximately 85%
per year, beginning in FYE 2024. The projected incremental revenues, costs, and net operating margin
(i.e., surplus or contribution to reserves) is shown in Table 1.
Table 1: Incremental Net Margins from Expansion (in $MM}
I ----------------------···· 1 FYE 20232 FYE 2024 FYE 2025
!--~evenue $10.3 $52.1 $52.4 '
-------------------------------------------
Power Costs -$8.1 -$43.6 -$41.1
' -----+-·· -
! Other Costs -$0.3 -$1.2 -$1.2
I Reserves -$.52 -$2.61 -$2.62
i Net Operating Margin $1.38 $4.69 $7.48
1 Achieving the prospective early enrollment date for City customers would require submittal of an amended CCA
implementation plan no later than December 31, 2021.
2 Reflects partial year of service for fiscal year ending June 30, 2023, with enrollments assumed to commence on
April 1, 2023.
Pacific Energy Advisors, Inc., November 2021 Page 1 of 9
Electric resource requirements associated with the expansion would be significant, and close coordination
between CEA and SDG&E would be important to achieve an appropriate allocation of resources needed
to serve the transferred load. Such coordination and cooperation would be especially important for
resource adequacy and long-term renewable energy supply. Without cooperation from SDG&E to sell
excess resources, or alternatively, a regulatory mechanism to ensure transfer of resources as load shifts
from SDG&E to CEA, it may not be possible for CEA to obtain the necessary resources in the near term to
meet its resource adequacy and long-term Renewable Portfolio Standards ("RPS") obligations.
ANALYSIS
PEA conducted an analysis of the City's prospective electric accounts to estimate the revenues and costs
associated with extending CEA service to the City. The analysis incorporated historical monthly electric
usage data provided by SDG&E for all current electric accounts located within the City. PEA reviewed load
data from 2017 and 2018 to formulate its load projections.
Table 2 summarizes the account and electric usage data for the major customer classifications
represented within the City. Available data indicate the potential to serve 56,348 new CEA customer
accounts, which are expected to use approximately 538,388 MWh of electric energy per year. This would
be an approximate 80% increase in size for CEA, relative to the anticipated retail sales volume associated
with CEA's current membership. The aggregate peak demand of these prospective accounts is estimated
at 125 MW.3
Table 2: 2018 City Electric Data
Classification Accounts Annual Energy (MWh) Monthly Per Account (kWh)
Residential 48,933 237,823 405
Small Commercial 6,277 92,109 1,223
Medium and Large 745 197,847 22,131
Commercial
Agricultural 154 4,688 2,537
Street Lighting 239 5,922 2,065
Total 56,348 538,388 796
*Pak Demand (MW) 125
•Estimate based on CEA customer hourly usage profiles.
As compared to the current CEA customer base, summarized in Table 3 below, t he City has a
proportionately larger residential sector and a smaller commercial sector. City residential customers tend
to be somewhat larger users of energy than those in CEA's current service area, with 9% greater average
3 These figures reflect bundled electricity customers of SDG&E and exclude customers taking service from non-utility
energy providers (namely, direct access service providers) as well as certain accounts on generation service contracts
that are not expected to transition to CEA service. These figures are unadjusted for expected customer attrition
{customer elections to "opt-out").
Pacific Energy Advisors, Inc., November 2021 Page 2 of9
monthly consumption. However, due to the smaller commercial sector, the average usage of all
customers in the City is below that of the current CEA area.
Table 3: Projected Annual CEA Electricity Data -Current Membership
Classification Accounts Annual Energy (MWh) Monthly Per Account (kWh)
Residential 50,339 224,061 371
Small Commercial 7,401 105,282 1,185
Medium and Large 871 281,830 26,964
Commercial
Agricultural 59 9,410 13,291
Street Lighting 189 3,225 1,422
Total 58,859 623,808 883
Peak Demand (MW) 127
As illustrated in Figures 1 and 2 below, electricity usage within the City shows greater seasonality relative
to the current SDCP customer base, with elevated summer peak consumption. These usage
characteristics are likely due to cooling loads driven by climate differences between the two geographic
areas.
Figure 1: 12-Month Hourly Load Profile (kW) for the City of Escondido
140,000
120.000
100,00J
80,000
40,000
20,000
■ · 20,000 • 20,(XIO · 40,000 a 40,000 -60,000 60.0XI • 80,000 ■ 80,000 · 100,000 ■ 100,000 • 120,000 ■ 120,000 · 140.000
Pacific Energy Advisors, Inc., November 2021 Page 3 of 9
Figure 2: 12-Month Hourly Load Profile (kW) of CEA's Current Customer Base
I
140,000
120,000
100,000
80,000
60,000
40,000
20,000
■ • -10,0CO ■ 20,000 40,000 ■ 40,000 60.0CO 60,000 · 80,()()) ■ 80,000 · 100,000 ■ 100,000 120,00:, ■ 120,000 140,0CX,
FISCAL IMPACTS
For purposes of the fiscal impact analysis, it was assumed that service would be initiated to the City in
April 2023 and that 90% of eligible accounts would choose to participate {with the remaining 10% electing
to opt-out, continuing to receive bundled electric service from the incumbent utility). This would equate
to an increase in annual CEA electricity sales of 500 GWh, or approximately 80% relative to pre-expansion
sales. In order to quantify anticipated financial impacts to CEA, the incremental revenues and costs
associated with the prospective service expansion were examined. More specifically, the year of
enrollment and the next two fiscal years following expanded service, i.e., the period beginning April 1,
2023 through June 30, 2025, were analyzed to determine likely fiscal impacts over a multi-year planning
period.
The incremental revenue surplus -based on the difference between projected revenues and costs directly
related to the addition of City accounts -represents the expected fiscal benefit related to expansion.
Incremental revenues were projected based on forecasted electricity sales and projected CEA rates. The
incremental cost analysis accounts for requisite power supplies that would be required to serve accounts
within the City, increased customer billing charges, customer service support (call center), SDG&E service
fees, and required customer notices associated with serving additional customers.
Pacific Energy Advisors, Inc., November 2021 Page 4 of 9
Table 4 reflects the estimated incremental fiscal impact during each of the first three fiscal years
commencing with (and immediately following) enrollment of City accounts.
Table 4: Incremental Fiscal Impact Related to Prospective City Expansion
FYE 20234 ~ FYE 2024 FYE 2025
.. R.evenue ($MIi/i) $10.3 T $52.1 $52.4
Power Costs ($MM) -$8.1 i -$43.6 -$41.1
Other Costs ($MM) -$0.3 ! -$1.2 -$1.2 --·-
Reserves -$.52 -$2.61 -$2.62
Net Operating Margin $1.38 $4.69 $7.48
($MM)
!
Incremental Sales 108,316 497,908 500,397
Volume (MWh)
In consideration of current market conditions, the incremental fiscal impact analysis indicates that adding
the City accounts to CEA's current customer base would provide benefits to CEA in the form or incremental
surplus revenues that could be used to augment reserves or be applied to other uses. It is estimated that
expanding CEA service to the City would increase net program margins by approximately $4.69 million
and $7.48 million in FYE 2024 and FYE 2025, respectively. This benefit accrues due to the margins
generated by increased retail electricity sales relative to anticipated costs, including certain economies of
scale that will result from various fixed administrative cost components (that will be spread over a larger
sales base). It is worth noting that power supply costs may change over time, and to the extent such
changes occur, actual net revenues could materially differ from the net revenue projections reflected in
Table 4 (above).
WHOLESALE POWER PRICE SENSITIVITY
Changes in market prices for electricity represent the single greatest uncertainty that could impact the
projected benefits related to expansion. Electricity is a commodity, traded in a highly volatile market, and
prices could materially change before CEA is ready to contract for the power supply needed to serve
anticipated City electric loads. Commodity price risk is inherent in the electric utility industry and is not
unique to expansion, but expansion imposes challenges with respect to the timing of electricity purchases
as well as the timing associated with a final/definitive determination regarding the expansion itself. This
is not unlike the challenges CEA (or any Community Choice Aggregator) faced during its initial startup
period. CEA utilizes professional risk management approaches and forward hedging contracts to mitigate
commodity price risk for its existing customers; however, adverse price movements that may occur before
CEA initiates power purchases for the City load could drive up costs and result in negative margins.
Utilizing historical volatility in wholesale power market prices, a likely range of potential power supply
costs and resulting net margins can be calculated. Figure 3 shows the base case operating margins and
error bars representing one standard deviation in power supply costs, assuming CEA does not initiate
procurement until March 2022, the month during which the CPUC would be expected to certify CEA's
4 Reflects partial year of service for fiscal year ending June 20, 2023, with enrollments assumed to commence on
April 1, 2023.
Pacific Energy Advisors, Inc., November 2021 Page 5 of 9
Implementation Plan amendment addressing expansion to the City. Over this four-month period
{between the date of t his Expansion Assessment and March 2022), the estimated change in market prices
at one standard deviation of variation is approximately 10% relative to base case assumptions. As
reflected in Figure 3 (below), the likely range of net margin outcomes is wide, but consistently positive
under this range of power price variability.
Figure 3: Net Surplus Sensitivity to Changes is Power Prices
Change in Operating Margin
$16.0
$14.0
$12.0
$1 .1
$10.0
~ ~ $8.0
~
$6.0
$4.0
$2.0 -$0.0
2023 2024 2025
Fiscal Year Ending
RESOURCE IM PACTS
Similar to the procurement approach used to support CEA's current customers, CEA would need to acquire
various energy products to serve the City -it is assumed that the proportionate acquisition of such
resources would occur over time through the application of a laddered hedging strategy, as followed
under CEA's risk management program. These energy products include Renewable Energy, Other Carbon
Free Energy (e.g., large hydro-electric), System Energy, and Resource Adequacy capacity. The quantities
will vary over time and are summarized in Table 5 below for a representative year.
Table 5: Summary of Resources Needed to Serve Escondido
Product Quantity Units Notes
Renewable 320 GWh Per Approx. half must be from long-term commitments (>= 10
Energy GWh Year years) per RPS rules
Other 50 to 90 GWh Per Higher end of range would be needed to offset emissions
Carbon GWh Year attributed to PCC2 renewable energy products; lower use
Free of PCC2 products will reduce need for Other Carbon Free
volumes
Resource lOSMW MW per
Adequacy, Month,
System September
Peak
Pacific Energy Advisors, Inc., November 2021 Page 6 of 9
Product I Quantity Units Notes
Resource 90MW MW Per
Adequacy, Month
Local .....
Put into more concrete terms, the 320 GWh of annual renewable energy shown above is generally
equivalent to the energy produced by a 120 MW solar or wind generation facility or a 40 MW Geothermal
facility.
Under California's RPS rules, a significant portion of renewable energy purchases must be secured through
contractual commitments of at least ten years in duration. Compliance with the RPS program is measured
over multi-year compliance periods, and the expansion would occur during Compliance Period 4 (2021-
2024). As shown below, RPS compliance would require an increase in renewable energy purchases during
Compliance Period 4 of 376 GWh, of which 245 GWh would have to be associated with long-term
commitments. Note that CEA has voluntarily adopted higher renewable energy targets than required by
the RPS program, so the total renewable energy needed to meet CEA policy is greater than the figures
shown below.
Current CEA Membership
Compliance 2021 2022 2023 2024 Total Period 4
Retail Sales 394 624 624 627 2,268 (GWh)
Gross RPS% 35.8% 38.5% 41.3% 44.0% 40.8%
Required RPS 141 240 258 276 915 (GWh)
Gross RPS LT 65.0% 65.0% 65.0% 65.0% 65.0% %
Gross LT RPS 92 156 167 179 594
Pacific Energy Advisors, Inc., November 2021 Page 7 of9
Current CEA Membership Plus City
Compliance 2021 2022 2023 2024 Total Period 4
Retail Sales 394 624 1,004 1,126 3,148 (GWh)
Gross RPS% 35.8% 38.5% 41.3% 44.0% 40.8%
Required RPS 141 240 415 496 1,291 (GWh)
Gross RPS LT 65.0% 65.0% 65.0% 65.0% 65.0% %
Gross LT RPS 92 156 270 322 839
RESOURCE AVAILABILITY
Accommodating City expansion will require careful consideration of resource availability, particularly for
resource adequacy and long-term renewable energy products. An important element of resource
procurement will be the ability to access resources currently held by SDG&E for the benefit of City
customers. When City customers transition to CEA service, SDG&E should have surplus resource adequacy
and long-term renewable energy supply, so CEA will need to arrange for the acquisition of such supply to
facilitate applicable compliance mandates. If no transfer of resources occurs, either by sale or some form
of allocation, CEA would risk being unable to meet its regulatory obligations associated with the increased
load associated with City expansion.
Under existing regulation, SDG&E is required to have 100% of the local resource adequacy capacity
associated with its current customer base two years forward and 50% in the third year. With the well-
known shortages of local resource adequacy capacity in the San Diego/Imperial Valley area, this virtually
assures that accessing local RA resources held by SDG&E will be required if CEA is to meet its increased
local RA obligations associated with the City load.
With respect to renewable energy availability, the resource constraint would primarily relate to the long-
term renewable energy requirement for Compliance Period 4. PEA understands that CEA will soon have
an opportunity to pursue an allocation of SDG&E's existing RPS portfolio, as described in Commission
Decision 21-05-030, which was adopted on May 20, 2021. Participation in this allocation process is
voluntary and certain volumes would be eligible to satisfy long-term renewable energy procurement
mandates pertaining to CEA. Additional details related to this process are forthcoming with initial
allocations expected to occur during the 2023 calendar year. To the extent that CEA can arrange such an
allocation to address the increased renewable energy requirements relating to City expansion,
incremental procurement obligations would be somewhat diminished. If CEA chooses to forgo the
aforementioned allocation opportunity, CEA would need to enter into long-term contracts for renewable
energy starting in 2023, coincident with (or shortly after) the enrollment of City customers. Development
timelines for new renewable generating projects, however, would likely extend a minimum of 24 to 36
months following the administration of a related solicitation for such supply. Depending on how early
CEA begins its procurement efforts, this could mean that new-build renewable projects may not
Pacific Energy Advisors, Inc., November 2021 Page 8 of 9
commence operation until the 2024 or 2025 calendar years (if CEA waited until it received the CPUC's
implementation plan certification before pursuing long-term renewable energy solicitation efforts related
to City expansion). If long-term renewable deliveries were to commence in 2024, CEA would require the
full 245 GWh incremental Compliance Period 4 long-term renewable energy obligation to be delivered in
that year, and that commitment would extend for the next nine (or more) years. This may result in a
higher proportion of renewable energy under long-term contracts than CEA would normally desire; it is
generally beneficial to have a mix of short-, medium-, and long-term contract commitments to diversify
risk. Of course, if the earliest delivery for new long-term contracts occurs after 2024, associated
renewable energy deliveries could not be used in Compliance Period 4. The RPS program makes no
accommodations for significant load increases, and there are severe penalties for not meeting the long-
term contracting obligation.
In light of the resource availability issues described above, it would be advisable to engage with SDG&E
early in the process to ensure that appropriate resource transfers and/or the previously described
renewable energy allocation process can be timely accommodated.
CAPITAL AND LIQUIDITY IMPACTS
Although relatively minimal, additional costs related to the prospective expansion would be incurred
during the fiscal year preceding enrollment of City accounts. These costs would relate to marketing and
outreach activities, customer noticing, regulatory and legal representation, internal operations, resource
planning and electric procurement activities that would be necessary to successfuHy integrate the City
and its customers in CEA's organization. There would also be increased working capital requirements to
address changes in cash flow. CEA is projected to have sufficient cash liquidity to internally fund pertinent
activities related to the prospective expansion.
CONCLUSIONS
This assessment concludes that under base case assumptions extending service to the City would have an
overall positive financial benefit to CEA in the form of additional net surpluses that could be used to
augment reserves or applied to other purposes. Due to wholesale market volatility, the likely range of
outcomes is wide, but margins are expected to be positive for scenarios reflecting typical power price
variability. Extending service to the City would increase CEA's sales volume by approximately 80% and
would require a meaningful increase in CEA resource acquisition. Advance coordination with SDG&E for
resource adequacy and long-term renewable energy resource transfers would be strongly advised to
ensure CEA has the resources necessary to meet its regulatory obligations associated with an increase in
load. Among other resource implications, the expansion would increase CEA's long-term RPS compliance
obligations, and meeting these heightened obligations during Compliance Period 4, which spans 2021-
2024, would be of immediate importance. It is highly likely that local resource adequacy and long-term
renewable energy would need to be obtained from SDG&E to facilitate the transfer of customers to CEA.
Pacific Energy Advisors, Inc., November 2021 Page 9 of 9
SUMMARY
Clean Energy Alliance New Membership Assessment
City of San Marcos
November 2021
The City of San Marcos ("City") has engaged with the Clean Energy Alliance ("CEA") to explore the
possibility of joining CEA. On behalf of CEA, Pacific Energy Advisors, Inc. ("PEA") conducted an assessment
of the financial and resource planning implications associated with extending CEA service to electric
customers within the City (which are currently receiving bundled electric service from the incumbent
utility, San Diego Gas & Electric, or "SDG&E"). The assessment involved a study to understand the
potential increase in electric load and the additional energy resources that would be needed to serve the
City. The study also estimated the incremental revenues that would be derived from electricity sales to
City customers, as well as the incremental costs associated with energy resource procurement and other
items/services that would be necessary to support CCA service expansion to City customers. These factors
were jointly evaluated to determine whether any operating surpluses could be generated, on a projected
basis, for the benefit of CEA and its customers.
In consideration of the prospective timing associated with amended implementation plan submittal and
in accordance with existing regulatory rules, the earliest possible enrollment date for City customers
would be January 1, 2023.1 For this assessment, PEA modeled various enrollment start times in 2023 and
found that April 2023 would be optimal from a financial perspective. Thus, enrollment would be expected
to occur toward the end of CEA's fiscal year ending 2023; the first full year reflecting City load would be
CEA's fiscal year ending 2024.
Under base case assumptions, the analysis indicates that expansion would yield a positive financial impact
for CEA: the expansion would be expected to increase CEA net operating margin by approximately 30%
per year, beginning in FYE 2024. The projected incremental revenues, costs, and net operating margin
(i.e., surplus or contribution to reserves) is shown in Table 1.
Table 1: Incremental Net Margins from Expansion (in $MM)
---------------------------------------------------------l FYE 20232 FYE 2024 FYE 2025
Revenue $6.9 $34.1 $34.2 ---------------------------------------------
Power Costs -$5.4 -$28.6 -$27.0
Other Costs -$0.2 i -$0.8 -$0.8 ----· I Reserve -$.35 i -$1.71 -$1.71
Net Operating Margin $1.05 $2.99 $4.69 ~
1 Achieving the prospective early enrollment date for City customers would require submittal of an amended CCA
implementation plan no later than December 31, 2021.
2 Reflects partial year of service for fiscal year ending June 30, 2023, with enrollments assumed to commence on
April 1, 2023.
Pacific Energy Advisors, Inc., November 2021 Page 1 of 10
Electric resource requirements associated with the expansion would be significant, and close coordination
between CEA and SDG&E would be important to achieve an appropriate allocation of resources needed
to serve the transferred load. Such coordination and cooperation would be especially important for
resource adequacy and long-term renewable energy supply. Without cooperation from SDG&E to sell
excess resources, or alternatively, a regulatory mechanism to ensure transfer of resources as load shifts
from SDG&E to CEA, it may not be possible for CEA to obtain the necessary resources in the near term to
meet its resource adequacy and long-term Renewable Portfolio Standards ("RPS") obligations.
ANALYSIS
PEA conducted an analysis of the City's prospective electric accounts to estimate the revenues and costs
associated with extending CEA service to the City. The analysis incorporated historical monthly electric
usage data provided by SDG&E for all current electric accounts located within the City. PEA reviewed load
data from 2017 and 2018 to formulate its load projections.
Table 2 summarizes the account and electric usage data for the major customer classifications
represented within the City. Available data indicate the potential to serve 36,820 new CEA customer
accounts, which are expected to use approximately 352,773 MWh of electric energy per year. This would
be an approximate 52% increase in size for CEA, relative to the anticipated retail sales volume associated
with CEA's current membership. The aggregate peak demand of these prospective accounts is estimated
at 80 MW.3
Table 2: 2018 City Electric Data
Classification Accounts Annual Energy (MWh) Monthly Per Account (kWh)
Residential 31,708 163,320 429
Small Commercial 4,480 62,809 1,168
Medium and Large 433 120,580 23,215
Commercial
Agricultural 83 4,682 4,690
Street Lighting 117 1,382 988
Total 36,820 352,773 798
*Pule Demand (MW) 80
*Estimate based on CEA customer hourly usage profiles.
As compared to the current CEA customer base, summarized in Table 3 below, the City has a
proportionately larger residential sector and a smaller commercial sector. City residential customers tend
to be somewhat larger users of energy than those in CEA's current service area, with 15% greater average
3 The figures inf Table 2 reflect bundled electricity customers of SDG&E and exclude customers taking service from
non-utility energy providers (namely, direct access service providers) as well as certain accounts on generation
service contracts that are not expected to transition to CEA service. These figures are unadjust ed for expected
customer attrition (customer elections to "opt-out").
Pacific Energy Advisors, Inc., November 2021 Page 2 of 10
monthly consumption. However, due to the smaller commercial sector, the average usage of all
customers in the City is below that of the current CEA area.
Table 3: Projected Annual CEA Electricity Data -Current Membership
Classification Accounts Annual Energy (MWh) Monthly Per Account (kWh)
Residential 50,339 224,061 371
Small Commercial 7,401 105,282 1,185
Medium and Large 871 281,830 26,964
Commercial
Agricultural 59 9,410 13,291
Street Lighting 189 3,225 1,422
Total 58,859 623,808 883
Peak Demand (MW) 127
As illustrated in Figures 1 and 2 below, electricity usage within the City shows greater seasonality relative
to the cu rrent SDCP customer base, with elevated summer peak consumption. These usage
characteristics are likely due to cooling loads driven by climate differences between the two geographic
areas.
Pacific Ene rgy Advisors, Inc., November 2021 Page 3 of 10
Figure 1: 12-Month Hourly Load Profile (kW) for the City of San Marcos
90,000
110.000
10,000
60,000
so.mo
40,000
J0,000
20.000
10.000
■ 10.000 ■ 10.000 20,000 • 10.C.OO 30,000 • 30,C00,40,()(X) ■ 40,000-50.000
■ SO.CD> 60,000 ■ 60,000 • 10,000 ■ 70.0CIO · (1),000 ■ 80,000 . 90,000
Figure 2: 12-Month Hourly Load Profile (kW) of CEA's Current Customer Base
1<00,000
120,000
100.000
80,000
60,000
40,000
>Q,000
■ 20,000 ■ 10,000 • 40,000 ■ 40,000 60,000 &0,000 80,0CX> ■ 80.000 100.000 ■ 100,000 · ll0.000 ■ I 20,000 140,000
Pacific Energy Advisors, Inc., November 2021 Page 4 of 10
FISCAL IMPACTS
For purposes of the fiscal impact analysis, it was assumed that service would be initiated to the City in
April 2023 and that 90% of eligible accounts would choose to participate (with the remaining 10% electing
to opt-out, continuing to receive bundled electric service from the incumbent utility). This would equate
to an increase in annual CEA electricity sales of 325 GWh, or approximately 52% relative to pre-expansion
sales. In order to quantify anticipated financial impacts to CEA, the incremental revenues and costs
associated with the prospective service expansion were examined. More specifically, the year of
enrollment and the next two fiscal years following expanded service, i.e., the period beginning April 1,
2023 through June 30, 2025, were analyzed to determine likely fiscal impacts over a multi-year planning
period.
The incremental revenue surplus -based on the difference between projected revenues and costs directly
related to the addition of City accounts -represents the expected fiscal benefit related to expansion.
Incremental revenues were projected based on forecasted electricity sales and projected CEA rates. The
incremental cost analysis accounts for requisite power supplies that would be required to serve accounts
within the City, increased customer billing charges, customer service support (call center), SDG&E service
fees, and required customer notices associated with serving additional customers.
Pacific Energy Advisors, Inc., November 2021 Page 5 of 10
Table 4 reflects the estimated incremental fiscal impact during each of the first three fiscal years
commencing with (and immediately following) enrollment of City accounts.
Table 4: Incremental Fiscal Impact Related ta Prospective City Expansion
FYE 20234 FYE 2024 FYE 2025
. RevenueJ$1\-1rv1) $6.9 $34.1 $34.2 --------------------
Power Costs ($MM) -$5.4 -$28.6 -$27.0
Other Costs ($MM) -$0.2 -$0.8 -$0.8
Reserves -$.35 -$1.71 -$1.71
Net Operating Margin $1.05
i
$2.99 $4.69
($MM)
I
Incremental Sales 71,901 I 326,255 327,886
Volume (MWh) I
In consideration of current market conditions, the incremental fiscal impact analysis indicates that adding
the City accounts to CEA's current customer base would provide benefits to CEA in the form or incremental
surplus revenues that could be used to augment reserves or be applied to other uses. It is estimated that
expanding CEA service to the City would increase net program margins by approximately $4.7 million and
$6.4 million in FYE 2024 and FYE 2025, respectively. This benefit accrues due to the margins generated
by increased retail electricity sales relative to anticipated costs, including certain economies of scale that
will result from various fixed administrative cost components (that will be spread over a larger sales base).
It is worth noting that power supply costs may change over time, and to the extent such changes occur,
actual net revenues could materially differ from the net revenue projections reflected in Table 4 (above).
WHOLESALE POWER PRICE SENSITIVITY
Changes in market prices for electricity represent the single greatest uncertainty that could impact the
projected benefits related to expansion. Electricity is a commodity, traded in a highly volatile market, and
prices could materially change before CEA is ready to contract for the power supply needed to serve
anticipated City electric loads. Commodity price risk is inherent in the electric utility industry and is not
unique to expansion, but expansion imposes challenges with respect to the timing of electricity purchases
as well as the timing associated with a final/definitive determination regarding the expansion itself. This
is not unlike the challenges CEA (or any Community Choice Aggregator) faced during its initial startup
period. CEA utilizes professional risk management approaches and forward hedging contracts to mitigate
commodity price risk for its existing customers; however, adverse price movements that may occur before
CEA initiates power purchases for the City load could drive up costs and result in negative margins.
Utilizing historical volatility in wholesale power market prices, a likely range of potential power supply
costs and resulting net margins can be calculated. Figure 3 shows the base case operating margins and
error bars representing one standard deviation in power supply costs, assuming CEA does not initiate
procurement until March 2022, the month during which the CPUC would be expected to certify CEA's
Implementation Plan amendment addressing expansion to the City. Over this four-month period
4 Reflects partial year of service for fiscal year ending June 20, 2023, with enrollments assumed to commence on
April 1, 2023.
Pacific Energy Advisors, Inc., November 2021 Page 6 of 10
(between the date of this Expansion Assessment and March 2022), the estimated change in market prices
at one standard deviation of variation is approximately 10% relative to base case assumptions. As
reflected in Figure 3 (below), the likely range of net margin outcomes is wide, but consistently positive
under this range of power price variability.
Figure 3: Net Surplus Sensitivity to Changes is Power Prices
Change in Operating Margin
$10.0
$9.0
$8.0
$7.0 $ .4
$6.0 ~ ~ $5.0 $ .7
~ $4.0
$3.0
$2.0 iii $1.0
$0.0
2023 2024 2025
Fiscal Year Ending
RESOURCE IMPACTS
Similar to the procurement approach used to support CEA's current customers, CEA would need to acquire
various energy products to serve the City -it is assumed that the proportionate acquisition of such
resources would occur over time through the application of a laddered hedging strategy, as followed
under CEA's risk management program. These energy products include Renewable Energy, Other Carbon
Free Energy (e.g., large hydro-electric), System Energy, and Resource Adequacy capacity. The quantities
will vary over time and are summarized in Table 5 below for a representative year.
Table 5: Summary of Resources Needed to Serve San Marcos
Product Quantity Units Notes
Renewable 200 GWh Per Approx. half must be from long-term commitments(>= 10
Energy GWh Year years) per RPS rules
Other 45 to 85 GWh Per Higher end of range would be needed to offset emissions
Carbon GWh Year attributed to PCC2 renewable energy products; lower use
Free of PCC2 products will reduce need for Other Carbon Free
volumes
Resource 70MW MW per
Adequacy, Month,
System September
Peak
Pacific Energy Advisors, Inc., November 2021 Page 7 of 10
! Product Quantity Units Notes
Resource 65MW MW Per
Adequacy, Month
local . ·""""""""
Put into more concrete terms, the 200 GWh of annual renewable energy shown above is generally
equivalent to the energy produced by a 75 MW solar or wind generation facility or a 25 MW Geothermal
facility.
Under California's RPS rules, a significant portion of renewable energy purchases must be secured through
contractual commitments of at least ten years in duration. Compliance with the RPS program is measured
over multi-year compliance periods, and the expansion would occur during Compliance Period 4 (2021-
2024). As shown below, RPS compliance would require an increase in renewable energy purchases during
Compliance Period 4 of 246 GWh, of which 161 GWh would have to be associated with long-term
commitments. Note that CEA has voluntarily adopted higher renewable energy targets than required by
the RPS program, so the total renewable energy needed to meet CEA policy is greater than the figures
shown below.
Current CEA Membership
Compliance 2021 2022 2023 2024 Total Period 4
Retail Sales 394 624 624 627 2,268 (GWh)
Gross RPS% 35.8% 38.5% 41.3% 44.0% 40.8%
Required RPS 141 240 258 276 915 (GWh)
Gross RPS LT 65.0% 65.0% % 65.0% 65.0% 65.0%
Gross LT RPS 92 156 167 179 594
Pacific Energy Advisors, Inc., November 2021 Page 8 of 10
Current CEA Membership Plus City
Compliance 2021 2022 2023 2024 Total Period 4
Retail Sales 394 624 873 954 2,844 (GWh)
Gross RPS% 35.8% 38.5% 41.3% 44.0% 40.8%
Required RPS 141 240 360 420 1,161 (GWh)
Gross RPS LT 65.0% 65.0% 65.0% 65.0% 65.0% %
Gross LT RPS 92 156 234 273 755
RESOURCE AVAILABILITY
Accommodating City expansion will require careful consideration of resource availability, particularly for
resource adequacy and long-term renewable energy products. An important element of resource
procurement will be the ability to access resources currently held by SDG&E for the benefit of City
customers. When City customers transition to CEA service, SDG&E should have surplus resource adequacy
and long-term renewable energy supply, so CEA will need to arrange for the acquisition of such supply to
facilitate applicable compliance mandates. If no transfer of resources occurs, either by sale or some form
of allocation, CEA would risk being unable to meet its regulatory obligations associated with the increased
load associated with City expansion.
Under existing regulation, SDG&E is required to have 100% of the local resource adequacy capacity
associated with its current customer base two years forward and 50% in the third year. With the well-
known shortages of local resource adequacy capacity in the San Diego/Imperial Valley area, this virtually
assures that accessing local RA resources held by SDG&E will be required if CEA is to meet its increased
local RA obligations associated with the City load.
With respect to renewable energy availability, the resource constraint would primarily relate to the long-
term renewable energy requirement for Compliance Period 4. PEA understands that CEA will soon have
an opportunity to pursue an allocation of SDG&E's existing RPS portfolio, as described in Commission
Decision 21-05-030, which was adopted on May 20, 2021. Participation in this allocation process is
voluntary and certain volumes would be eligible to satisfy long-term renewable energy procurement
mandates pertaining to CEA. Additional details related to this process are forthcoming with initial
allocations expected to occur during the 2023 calendar year. To the extent that CEA can arrange such an
allocation to address the increased renewable energy requirements relating to City expansion,
incremental procurement obligations would be somewhat diminished. If CEA chooses to forgo the
aforementioned allocation opportunity, CEA would need to enter into long-term contracts for renewable
energy starting in 2023, coincident with (or shortly after) the enrollment of City customers. Development
timelines for new renewable generating projects, however, would likely extend a minimum of 24 to 36
months following the administration of a related solicitation for such supply. Depending on how early
CEA begins its procurement efforts, this could mean that new-build renewable projects may not
Pacific Energy Advisors, Inc., November 2021 Page 9 of 10
commence operation until the 2024 or 2025 calendar years (if CEA waited until it received the CPUC's
implementation plan certification before pursuing long-term renewable energy solicitation efforts related
to City expansion). If long-term renewable deliveries were to commence in 2024, CEA would require the
full 161 GWh incremental Compliance Period 4 long-term renewable energy obligation to be delivered in
that year, and that commitment would extend for the next nine (or more) years. This may result in a
higher proportion of renewable energy under long-term contracts than CEA would normally desire; it is
generally beneficial to have a mix of short-, medium-, and long-term contract commitments to diversify
risk. Of course, if the earliest delivery for new long-term contracts occurs after 2024, associated
renewable energy deliveries could not be used in Compliance Period 4. The RPS program makes no
accommodations for significant load increases, and there are severe penalties for not meeting the long-
term contracting obligation.
In light of the resource availability issues described above, it would be advisable to engage with SDG&E
early in the process to ensure that appropriate resource transfers and/or the previously described
renewable energy allocation process can be timely accommodated.
CAPITAL AND LIQUIDITY IMPACTS
Although relatively minimal, additional costs related to the prospective expansion would be incurred
during the fiscal year preceding enrollment of City accounts. These costs would relate to marketing and
outreach activities, customer noticing, regulatory and legal representation, internal operations, resource
planning and electric procurement activities that would be necessary to successfully integrate the City
and its customers in CEA's organization. There would also be increased working capital requirements to
address changes in cash flow. CEA is projected to have sufficient cash liquidity to internally fund pertinent
activities related to the prospective expansion.
CONCLUSIONS
This assessment concludes that under base case assumptions extending service to the City would have an
overall positive financial benefit to CEA in the form of additional net surpluses that could be used to
augment reserves or applied to other purposes. Due to wholesale market volatility, the likely range of
outcomes is wide, but margins are expected to be positive for scenarios reflecting typical power price
variability. Extending service to the City would increase CEA's sales volume by approximately 52% and
would require a meaningful increase in CEA resource acquisition. Advance coordination with SDG&E for
resource adequacy and long-term renewable energy resource transfers would be strongly advised to
ensure CEA has the resources necessary to meet its regulatory obligations associated with an increase in
load. Among other resource implications, the expansion would increase CEA's long-term RPS compliance
obligations, and meeting these heightened obligations during Compliance Period 4, which spans 2021-
2024, would be of immediate importance. It is highly likely that local resource adequacy and long-term
renewable energy would need to be obtained from SDG&E to facilitate the transfer of customers to CEA.
Pacific Energy Advisors, Inc., November 2021 Page 10 of 10