HomeMy WebLinkAbout2019-04-16; City Council; Resolution 2019-052RESOLUTION NO. 2019-052
A RESOLUTION OF THE CITY COUNCIL OF THE CITY OF CARLSBAD ACCEPTING
THE NORTH SAN DIEGO COUNTY CITIES COMMUNITY CHOICE ENERGY
TECHNICAL FEASIBILITY STUDY AND AUTHORIZING THE CITY MANAGER TO
NEGOTIATE, EXECUTE AND FUND A COST SHARE AGREEMENT ALLOWING
FOR THE CITY OF CARLSBAD'S PARTICIPATION IN PROCURING JOINT LEGAL
SERVICES TO ASSIST THE CITY IN NEGOTIATING AND PREPARING
COMMUNITY CHOICE ENERGY FORMATION DOCUMENTS IN AN AMOUNT
NOT TO EXCEED $20,000
EXHIBIT 1
WHEREAS, Community Choice Energy is a mechanism that allows local governments to
purchase and supply electrical power to customers within their jurisdictions as an alternative to the
service provided by an investor-owned utility; and
WHEREAS, the terms 'Community Choice Energy' and 'Community Choice Aggregation' are used
interchangeably; and
WHEREAS, the City of Carlsbad General Plan Sustainability Element includes Policy 9-P.14 to
support a regional approach to study the feasibility of establishing Community Choice Aggregation
(CCA) or another program that increases the renewable energy supply and maintains the reliability and
sustainability of the electrical grid; and
WHEREAS, on July 11, 2017, the Carlsbad City Council approved Resolution No. 2017-141
authorizing the City of Carlsbad's participation in a Community Choice Energy Technical Feasibility
Study in an amount not to exceed $60,000; and
WHEREAS, on January 24, 2018, the City of Carlsbad joined the cities of Del Mar, Encinitas and
Oceanside in a cost share agreement to prepare a Community Choice Energy (CCE) Technical
Feasibility Study; and
WHEREAS, on February 26, 2019, the Carlsbad City Council received a presentation of the draft
North San Diego County Cities Community Choice Energy Technical Feasibility Study and approved
Resolution No. 2019-025 authorizing the City Manager to negotiate, execute and fund a cost share
agreement allowing for the City of Carlsbad's participation in an evaluation of potential Community
Choice Energy program governance options in an amount not to exceed $35,000; and
WHEREAS, the City of Carlsbad has joined the cities of Del Mar and Encinitas in a cost share
agreement to engage EES Consulting, Inc. to prepare an evaluation of Community Choice Energy
program governance options; and
April 16, 2019 Item #4 Page 6 of 132
WHEREAS, on March 19, 2019, the Carlsbad City Council adopted a resolution expressing the
City Council's intention to pursue a community choice energy program that prioritizes certain operating
principles; and
WHEREAS, on April 16, 2019, the Carlsbad City Council received the final North San Diego
County Cities Community Choice Energy Technical Feasibility Study, dated March 28, 2019 (Attachment
A); and
WHEREAS, the study determined that a Community Choice Energy program is both technically
and financially feasible, and could provide environmental and economic benefits to residents and
businesses in the City of Carlsbad; and
WHEREAS, the City of Carlsbad has been invited to join the cities of Del Mar and Encinitas in a
cost share agreement to engage Richards Watson Gershon (RWG) Law to assist the cities in negotiating
and preparing CCE formation documents, as outlined in their proposal dated March 6, 2019
(Attachment B); and
WHEREAS, adoption of this resolution in no way obligates the City of Carlsbad to participate in
any future decision to establish a Community Choice Energy program.
NOW, THEREFORE, BE IT RESOLVED by the City Council of the City of Carlsbad, California, as
follows:
1. That the above recitations are true and correct.
2. That the City Council accepts the North San Diego County Cities Community Choice
Energy Technical Feasibility Study, dated March 28, 2019 (Attachment A).
3. That the City Manager is authorized to negotiate and execute a Cost Share Agreement
among the cities of Del Mar, Encinitas and Carlsbad to assist the cities in negotiating and
preparing CCE formation documents, as outlined in the proposal from Richards Watson
Gershon (RWG) Law, dated March 6, 2019 (Attachment B).
4. That the City Manager, or his designee, is authorized to transfer and appropriate from
the City Council Contingency Fund an amount not to exceed $20,000 for the City of
Carlsbad portion of the cost to procure joint legal services to assist the city in negotiating
and preparing CCE formation documents.
April 16, 2019 Item #4 Page 7 of 132
PASSED, APPROVED AND ADOPTED at a Regular Meeting of the City Council of the City of
Carlsbad on the 16th day of April 2019, by the following vote, to wit:
AYES:
NAYS:
ABSENT:
Blackburn, Bhat-Patel, Schumacher, Hamilton.
Hall.
None.
(SEAL)
April 16, 2019 Item #4 Page 8 of 132
Contents
CONTENTS .............................................................................................................................................................. 1
EXECUTIVE SUMMARY ........................................................................................................................................... 1
INTRODUCTION ................................................................................ , ......................................................................... 1
ELECTRIC LOAD .......................................................................................................................................................... 1
FINDINGS AND CONCLUSIONS ........................................................................................................................................ 6
INTRODUCTION ..................................................................................................................................................... 8
STUDY METHODOLOGY ................................................................................................................................................ 9
STUDY ORGANIZATION ................................................................................................................................................ 9
LOAD REQUIREMENTS ........................................................... _ .............................................................................. 10
HISTORICAL CONSUMPTION ........................................................................................................................................ 10
CCE PARTICIPATION AND OPT-OUT RATES ..................................................................................................................... 12
CONCEPTUAL CCE LAUNCH ......................................................................................................................................... 13
FORECAST CONSUMPTION AND CUSTOMERS ................................................................................................................... 14
POWER SUPPLY STRATEGY AND COSTS ................................................................................................................ 16
RESOURCE STRATEGY ................................................................................................................................................ 16
PROJECTED POWER SUPPLY COSTS ............................................................................................................................... 16
RESOURCE STRATEGY ................... -.......................................................... _ ................................................................... 35
COST OF SERVICE ................................................................................................................................................. 37
COST OF SERVICE FOR CCE "BASE CASE" OPERATIONS ..................................................................................................... 37
POWER SUPPLY COSTS ............................................................................................................................................... 37
NON-POWER SUPPLY COSTS ..................................................... : ................................................................................. 38
SDG&E BILLING & METERING COSTS ...................................... .-.................................................................................... 41
UNCOLLECTIBLE COSTS ............................................................................................................................................... 42
FINANCIAL RESERVES ................................................................................................................................................. 42
FINANCING COSTS .................................................................................................................................................... 43
RATE COMPARISON ............................................................................................................................................. 48
RATES PAID BY SDG&E BUNDLED CUSTOMERS ............................................................................................................... 48
RATES PAID BY CCE CUSTOMERS ................................................................................................................................. 49
RETAIL RATE COMPARISON ......................................................................................................................................... 51
ENVIRONMENTAL AND ECONOMIC IMPACTS ...................................................................................................... 53
IMPACT OF RESOURCE PLAN ON GREENHOUSE GAS (GHG) EMISSIONS ................................................................................ 53
LOCAL RESOURCES/BEHIND THE METER CCE PROGRAMS .................................................................................................. 54
ECONOMIC IMPACTS IN THE COMMUNITY ...................................................................................................................... 57
SENSITIVITY AND RISK ANALYSIS ......................................................................................................................... 61
SDG&E RATES AND SURCHARGES ................................................................................................................................ 64
REGULATORY RISKS ................................................................................................................................................... 65
POWER SUPPLY COSTS ............................................................................................................................................... 65
SDG&E RPS PORTFOLIO ........................................................................................................................................... 68
AVAILABILITY OF RENEWABLE AND GHG-FREE RESOURCES ................................................................................................ 68
FINANCIAL RISKS ...................................................................................................................................................... 69
LOADS AND CUSTOMER PARTICIPATION RATES ................................................................................................................ 70
Community Choice Energy Technical Feasibility Study
April 16, 2019 Item #4 Page 11 of 132
SENSITIVITY RESULTS •.•..••••••..••••.•••.••.•••.•.••.••....•••••••.•.•••.•.••..••.••.•••••.••.••..•.•..•.••••••.••.•••..••••.•.•.••.•..••.•••••.•.•.•.••.•.•••..•.•. 70
CCE GOVERNANCE OPTIONS ................................................................................................................................ 73
RECOMMENDATION .................................................................................................................................................. 75
CCE ORGANIZATIONAL OPTIONS ···························································································"···································· 75
CONCLUSIONS AND RECOMMENDATIONS •...•••.•••••.•.••..•••••.•••.•..•••••••.••••••••••.••••••..••••.••••.••••.••.••.•.••.••.•.••••.•..••••.••• 76
RATE CONCLUSIONS .................................................................................................................................................. 76
RENEWABLE ENERGY CONCLUSIONS .............................................................................................................................. 77
ENERGY EFFICIENCY CONCLUSIONS ............................................................................................................................... 77
ECONOMIC DEVELOPMENT CONCLUSIONS ...................................................................................................................... 77
GREENHOUSE GAS (GHG) EMISSIONS CONCLUSIONS ....................................................................................................... 78
FINDINGS AND CONCLUSIONS ...................................................................................................................................... 78
RECOMMENDATIONS ................................................................................................................................................. 79
SUMMARY •.•••••.•.•.•••.•••••••••.••.••.•.••••.•..••••.•••••••••.•.•••••••.•••••••.•••••••••.•.••.•.•.•••••••.•.•.•••.•••.•••.•.•...•.••.•.••.•.•••••.•••••••..•••.••• 80
APPENDIX A -PROJECTED SCHEDULE .••..•••.•••••••••.•.•.•.•••••••••••••••.•.•.•..•.••••••.••.•.••.•.••.••••••••.•.•••••.•••..••••••••••••...••.•••• 81
APPENDIX B -BASE CASE PRO FORMA ANALYSES ............................................................................................... 82
APPENDIX C-RENEWABLE PPA ALTERNATIVE PRICING PROFORMA ANALYSES ................................................. 83
APPENDIX D -STAFFING AND INFRASTRUCTURE DETAIL. .................................................................................... 84
APPENDIX E -:<CE CASH FLOW ANALYSIS ............................................................................................................. 85
APPENDIX F -GLOSSARY ..................................................................................................................................... 86
APPENDIX G -POWER SUPPLY DETAIL. .......................................................... · ...................................................... 92
APPENDIX H -SEPARATE CITY RESULTS ............................................................................................................... 96
Community Choice Energy Technical Feasibility Study ii
April 16, 2019 Item #4 Page 12 of 132
Exhibit ES-2 summarizes the CCE costs for the first nine months of operation assuming customers
begin taking service in April 2021. This exhibit assumes the percent of power supply obtained
from renewable resources for the Partner cities would be equal to SDG&E's current levels. The I
operational and administrative costs for the CCE are estimated based on costs incurred by other
CCEs launched in California in recent years. Operational and administrative costs may vary
depending on the proportion of staff internal to the CCE versus contracted as consulting services.
Typically, California CCEs have kept internal staffing to a minimum and relied on consultants with
expertise in energy procurement to manage the more technical components of the CCE. Debt
service payments are included and are needed to pay back loans needed to provide start-up
capital and initial operations working capital.
Exhibit ES-2
2021 CCA Costs, SDG&E-Equivalent Renewable Portfolio
Base Case Renewable Pricing
Cost of Energy
Operating & Administrative
Billing & Data Management
SDG&E Fees
SDG&E Setup and Start-up Fees
Consulting Services
Staffing
General & Administrative Expenses
Debt Service
Tota I O&A Costs
$Millions
$71.31
$1.7
$0.4
$0.2
$1.6
$2.2
$0.2
$2.5
$8.8
Total Cost $80.1
1. Conservatively includes mostly short-term renewable contract prices as described in the Power Supply
Strategy and Cost section of this Study.
Exhibit ES-3 illustrates the 10-year financial forecast for the CCE to provide a power supply mix
with a renewable power content equal to SDG&E's renewable power content forecast (SDG&E-
Equivalent Renewable Portfolio scenario). Because that chart is only for power supply costs, it
does not provide the overall impact to customer rates. The rates faced by the customer include
the distribution component provided by the IOU in addition to the power supply component
provided by the CCE. When the full customer bill is considered, and under the base assumptions,
the CCE is able to provide an approximate 2% overall bill reduction to CCE customers. In addition,
the CCE would build reserve funds that could be used for local programs or additional rate
reductions. Each rate component illustrated in Exhibit ES-3 is described below the chart.
Community Choice Energy Technical Feasibility Study 2
April 16, 2019 Item #4 Page 14 of 132
resources are 80% GHG free and cost CCE ratepayers an average additional $0.0014/kWh. This
adder is based on forecast prices for GHG free energy starting at $0.004/kWh in 2021.
Renewable Energy -Renewable energy costs include both the energy component and the
renewable attributes. These costs increase over the study period as a higher share of renewable
energy is purchased to meet both RPS and SDG&E's projected renewable portfolio. The base case
renewable contract prices included in the Study are based on two conservative assumptions: 1)
the majority of renewable energy purchases are made at short-term, rather than long-term,
renewable contract prices and 2) the long-term renewable contract price is greater than the price
at which existing CCEs are currently transacting. An alternative scenario is included in the Study
in which the renewable energy contract prices are less conservative and more accurately reflect
the renewable resource portfolio of a functioning CCE.
Capacity -In addition to energy purchases, the CCE will need to purchase capacity and reserves
to meet reliability and resource adequacy requirements as required by the CPUC and California
Independent System Operator (CAISO). These costs are forecast to increase over the study
period.
Operating, Administrative & General -Expenses required to operate the program as detailed in
ES-2. These expenses are escalated at the inflation rate of 2%.
Debt Service/Start-Up -Repayment of start-up costs plus working capital requirements. The
repayment term is 5 years; however, the analysis shows that start-up costs can be repaid within
3 years.
Reserves -Cash reserves equal to 120 days of operating expenses are held to ensure the CCE can
operate in a changing environment. Reserves are often used as a rate stabilization measure
during periods of market instability. Reserve targets are calculated over the study period and the
reserve level increases as power supply costs and operating expenses escalate.
SDG&E Generation Rate -The SDG&E generation rate is forecast to increase at a conservative
level of 1% annually. This escalation rate is conservative considering SDG&E generation rates
have increased as much as 2-9% over the period 2006 to 2015. 4 The basis for the generation rate
forecast includes future expectations about renewable energy costs, non-renewable costs, and
RPS requirements. While costs for non-renewable resources (wholesale market prices) and
resource adequacy are expected to increase; renewable energy costs are expected to decline. If
the SDG&E generation rate increases at a rate greater than 1% annually, the CCE's financial
position would improve.
4 Average annual generation rate increases for small commercial and small agriculture are 2%, large commercial is
4.7% and residential is 9.7% over the period 2006 to 2015. Estimated based on average weighting of summer and
winter rates.
Community Choice Energy Technical Feasibility Study 4
April 16, 2019 Item #4 Page 16 of 132
Renewable Energy Portfolio Scenarios
While Exhibit ES-3 shows the results for one power supply scenario, the Study analyzed the CCE
rate under several different scenarios for renewable power content in the power supply mix.
The three scenarios are described below. The first scenario (SDG&E-Equivalent Renewables
Portfolio) was used above in Exhibit ES-3.
1) SDG&E-Equivalent Renewable Portfolio: Achieves between 46% and 59% of power supply
from Renewable Portfolio Standard (RPS)-qualifying resources in 2021 through 2029,
based on SDG&E planned renewable energy procurements. Achieves 60% RPS beginning
in 2030.
2) 100% Renewable by 2030 Portfolio: 50% of retail loads are served with RPS-qualifying
beginning in 2021 ramping up to 50% in 2025, 75% in 2029, and 100% in 2030 and after.5
3) 100% Renewables Portfolio: 100% of retail loads are served with RPS-qualifying
renewable resources in all years.6
At a minimum, the CCE would need to meet State mandated Renewable Power Supply (RPS)
requirements; however, since SDG&E will likely have higher renewable content than the RPS
requires, this minimum requirement scenario was not analyzed in the study. It was assumed that
the CCE would have a power supply mix with a renewable content that was at least equivalent to
SDG&E. This portfolio is the base case scenario.
Sensitivity Analysis
In addition to the base assumptions, uncertainties which could impact CCE rates were evaluated
under different assumptions. Uncertainties analyzed included: higher or lower PCIA costs, higher
market power costs, lower loads served by the CCE, higher loads served by the CCE, Exhibit ES-4
shows the results of the sensitivity analysis; in most cases,.the CCE could continue to offer rate
discounts. In the cases where high power costs result in CCE rates greater than SDG&E rates, the
impact could likely be mitigated by offsets in both the PCIA and SDG&E generation rates.7
5 Meets Climate Action Plan goals established by the cities of Encinitas (100% renewable by 2030) and Del Mar (100%
renewable by 2035).
6 Meets Climate Action Plan goals established by the cities of Encinitas (100% renewable by 2030) and Del Mar (100%
renewable by 2035).
7 Higher power supply costs would likely impact SDG&E at the same time as the CCE. Therefore, higher CCE power
costs would be mitigated by both lower PCIA rates and a higher SDG&E generation rate.
Community Choice Energy Technical Feasibility Study 5
April 16, 2019 Item #4 Page 17 of 132
Exhibit ES-4
Partner CCE Rate Sensitivity
10-Year Levelized Rate and Average Discount 2021-20301
SDG&E-Equivalent 100% Renewable by 100% Renewable Renewable Portfolio 2030
Sensitivity $/kWh Rate $/kWh Rate $/kWh Rate
Discount Discount Discount
Base Assumptions $0.2927 2% $0.2927 2% $0.2987 0%
High PCIA $0.2989 0% $0.2989 0% $0.3050 -2%
Low PCIA $0.2901 3% $0.2901 3% $0.2960 1%
High Power Costs2 $0.3136 -5% $0.3170 -6% $0.3180 -7%
Low Load $0.2931 2% $0.2931 2% $0.2991 0%
High Load $0.2920 2% $0.2989 0% $0.2980 0%
1Negative rate discounts indicate that the CCE retail rate is higher than the SDG&E bundled rate.
2The CCE purchases power supply at costs higher than SDG&E.
Findings and Conclusions
Based on the analysis conducted in this Study, the following findings and conclusions are made:
■ The formation of a CCE is financially feasible and could yield considerable benefits for all
participating residents and businesses.
■ Financial benefits include electric retail rates that are 2% lower compared with SDG&E rates
■ Other benefits include local control over power supply sources, rate levels and customer
programs. Specific programs such as economic development incentives, and targeted energy
efficiency and demand response programs could be implemented.
■ CCE start-up costs could be fully recovered within the first three years of CCE operations.
■ After this cost recovery, revenues that exceed costs could be used to finance a rate
stabilization fund, new local renewable resources, economic development projects and/or
lower customer electric rates.
■ The sensitivity analysis shows that the ranges of prices for different market conditions will, in
most cases, not negatively impact CCE rates compared to SDG&E rates. Where negative
impacts may exist, those risks can be mitigated.
■ The CCE could be a means to achieve local control of energy supply and for cities to meet
their respective Climate Action Plan (CAP) goals.
■ Local electric rate savings are expected to stimulate economic development for the Partner
cities.
Community Choice Energy Technical Feasibility Study 6
April 16, 2019 Item #4 Page 18 of 132
The positive impacts on the Partner cities and their citizens of forming a CCE suggest that CCE
implementation should be considered with the following next steps: consideration of Joint
Powers Authority or other governance options, Business Plan development, and Implementation
Plan development. No likely combination of sensitivities would change this recommendation
based on the detailed analysis contained in the balance of this report.
Community Choice Energy Technical Feasibility Study 7
April 16, 2019 Item #4 Page 19 of 132
Introduction
California Assembly Bill 117 allows local governments to form Community Choice Aggregations
(CCAs), which are also referred to as Community Choice Energy (CCE) programs, that offer an
alternative electric power option to constituents currently served electric power by investor
owned utilities (IOUs). Under the CCE model, local governments purchase and manage their
community's electric power supply by sourcing power from a preferred mix of traditional and
renewable generation sources, while the incumbent IOU continues to provide distribution
service. CCEs face the same requirements for renewable energy purchases as the incumbent IOU
and other public utilities; however, many CCE programs can offer power content that has a
greater share of renewable energy compared with the incumbent utility and at lower retail rates.
This Technical Feasibility Study (Study) evaluates the financial feasibility of a potential CCE for the
cities of Carlsbad, Del Mar, Encinitas and Oceanside (Partners).
While a CCE financial feasibility study typically focuses purely on the logistical and financial
feasibility of operating a CCE, this Study also includes a discussion of governance and
organizational alternatives.
As the IOU currently providing electric power to the Partners, San Diego Gas and Electric (SDG&E)
was asked to provide historic energy use data for the Partners' service areas. Using the
information provided by SDG&E, EES Consulting, Inc. (EES) estimated future power supply costs,
administrative costs, electric loads, and retail rates under various Partner CCE scenarios, and for
SDG&E service. These forecast rates were then compared to determine if the CCE could feasibly
offer competitive rates, service and lower greenhouse gas options.
The Study assumes that a CCE created among the Partner cities would directly support the cities'
Climate Action Plans (CAPs), and would generally aspire to meet the following objectives:
■ Decrease greenhouse gas (GHG) emissions from electricity generation
■ Increase the renewable energy in the power mix to exceed the baseline power mix offered
by SDG&E, including the 100% Clean Energy goals set by the Del Mar and Encinitas CAPs
■ Provide competitive rates
■ Provide local control over rate setting
■ Provide customer choice to residents and businesses
■ Reinvestment of residual revenue in local renewable power initiatives
■ Promote and incentivize community-focused CCE programs
While the Partners have not yet officially adopted these goals, they serve as the foundation for
this Study. Once the Partners' goals are refined, adopted, and prioritized, modifications to this
Study may be appropriate.
Community Choice Energy Technical Feasibility Study 8
April 16, 2019 Item #4 Page 20 of 132
Study Methodology
This Study evaluates the estimated costs and resulting rates of operating a CCE for the Partners
and compares these rates to a SDG&E rate forecast for the years 2021 through 2030. This pro
forma financial analysis models the following cost components:
■ Power Supply Costs:
• Wholesale purchases
• Renewable purchases
• Procurement of resource adequacy (RA} capacity (System, Local and Flexible capacity
products)
• Other power supply and charges
■ Non-Power Supply Costs:
• Start-up costs
• CCE staffing and administration costs
• Consulting support
• SDG&E and regulatory charges
• Financing costs
■ Pass-Through Charges from SDG&E:
• Transmission and distribution charges
• Power Charge Indifference Adjustment (PCIA}
The information above is used to determine the projected retail rates for the CCE. The CCE rates
are then compared to the SDG&E projected rates for the Partners' CCE service area. After these
rate comparisons are made, the attendant economic development and greenhouse gas (GHG}
comparisons are made. Operational and governance options are discussed, as well as a
sensitivity analysis of the key variables contained in the Study.
Study Organization
This Study is organized into the following main sections:
■ Load Requirements
■ Power Supply Strategy and Costs
■ Partners' CCE Cost of Service
■ Product, Service and Rate Comparisons
■ Environment,al/Economic Considerations
■ Sensitivity Analysis
■ CCE Governance
■ Conclusions and Recommendations
Community Choice Energy Technical Feasibility Study 9
April 16, 2019 Item #4 Page 21 of 132
Load Requirements
One indicator of the viability of a CCE for the Partners is the number of customers that participate
in the CCE as well as the quantity and timing of energy these customers consume. This section
of the Study provides an overview of these projected values and the methodology used to
estimate them.
Historical Consumption
SDG&E provided hourly historical data on energy use (kWh) for customers receiving power supply
services from SDG&E (bundled customers) in each of the four cities for the 2017 calendar year.
Bundled customers currently purchase the electric power, transmission and distribution from
SDG&E. Direct Access (DA) customers buy only the transmission and distribution service from
SDG&E and purchase power from an independent and competitive Electric Service Provider (ESP).
In California, eligibility for DA enrollment is currently limited to non-residential customers and
subject to a maximum allowable annual limit for new enrollment measured in gigawatt-hours of
new load and managed through an annual lottery. 8 Customers classified as taking service under
DA arrangements are not included in this Study, as it is assumed that these customers would
remain with their current Energy Service Provider (ESP)9• Once operating, the CCE may decide to
provide service options to DA customers with expired contracts, but our approach offers the most
conservative analysis of feasibility.
EES aggregated this data by rate class in each month for bundled (full service) customers. In total,
bundled residents and businesses within the four cities purchased 1,722 GWh of electricity in
2017 from SDG&E.
Exhibit 1 summarizes energy consumption and number of accounts for bundled customers in
2017.
8 S.B. 286 (CA, 2015-2016 Reg. Sess.)
9 CPUC rulemaking to date has not addressed how vintage would be handled to DA customers that opt to switch to
receive electric power from a CCA rather than their ESP. The most recent ruling on PCIA vintaging was issued on
10/5/2016: http://docs.cpuc.ca.gov/Published Docs/Publish ed/G000/M 167 /K7 44/1677 44142. PDF.
Community Choice Energy Technical Feasibility Study 10
April 16, 2019 Item #4 Page 22 of 132
This Study anticipates an overall customer participation rate of 85% for the Commercial and
Industrial accounts. For residential accounts, it is assumed that approximately 95% of customers
would remain with the Partners' CCE. For commercial and industria.1 accounts, the participation
rate is 85% which adjusts historic participation rates for the new cap on direct access.12 These
participation assumptions are conservative based on participation rates in other CCEs, however,
this Study's sensitivity analysis tested CCE feasibility under higher opt-out scenarios. Operating
CCEs in California have experienced overall participation rates ranging from 83% (Marin Clean
Energy) to 98% (Peninsula Clean Energy). On average, 90% of all potential customers have stayed
with their CCE. 13
Conceptual CCE Launch
The California Public Utilities Commission (CPUC) recently issued Resolution 4723, which requires
that new CCEs file their Implementation plan by January 1, resulting in the earliest possible
Partner CCE launch date of January 1 the subsequent year. Under this new requirement, the
Partners' earliest possible launch date is early 2021. This Study assumes that service would be
offered to all customers by April 2021 in one phase, at launch, as outlined in Exhibit 4.
Exhibit 4
CCE Load, Customers, and Revenue
Total
Retail Peak Normalized Annual
Average Load Demand Operating Revenues
Assumed Start Eligibility Customer Accounts (GWh) (MW) to the CCE
Apr2021 All Customers 145,500 1,138 322 $120 million
This launch strategy, without phasing, would enable the Partners' CCE to provide service to all
customers as soon as possible. The number of customers and projected total load is similar to
the number of customers enrolled by other CCEs launching in a single phase.14
12 Opt-out rates were increased to account for a 16% increase in the amount of non-residential load that is allowed
to move to direct access schedules. California Senate Bill 237: September 20, 2018.
https :/ /I egi nfo. legislature. ca .gov /faces/bi I IT ext Cl ie nt.xhtm I ?bi 11 _id =201720180S 8237
13 Average opt-out rate determined based on published number of customers and opt-out rates of Marin Clean
Energy, Peninsula Clean Energy, Sonoma Clean Power, Apple Valley Clean Energy, and Lancaster as found at the
following document http://www.vvdailypress.com/news/20170818/a ppl e-val I ey-choice-en ergy-prom pts-
thousa nds-of-customer-ca 11 s. Published 8/18/2017; accessed 2/15/2018.
14 For example, Silicon Valley Clean Energy enrolled 180,000 residential customers and Monterey Bay Clean Energy
enrolled 235,000 residential customers at one time.
Community Choice Energy Technical Feasibility Study 13
April 16, 2019 Item #4 Page 25 of 132
Power Supply Strategy and Costs
This section of the Study discusses the CCE's resource strategy, projected power supply costs,
and resource portfolios based on the Partners' CCE projected loads.
Long-term resource planning involves load forecasting and supply planning on a 10-to 20-year
time horizon. Prior to launch, the Partners' CCE planners would develop integrated resource
plans that meet their supply objectives and balance cost, risk, and environmental considerations.
Integrated resource planning also considers demand side energy efficiency, demand response
programs, and non-renewable supply options. The Partners' CCE would require staff or a
consultant to oversee planning even if the day-to-day supply operations are contracted to third
parties. This staff or consultant would ensure that local preferences regarding the future
composition of supply and demand side resources are planned for, developed, and implemented.
Resource Strategy
This Study assumes that the Partners' CCE would be interested in minimizing overall community
energy bills, achieving GHG emissions reductions, stimulating local economic development to
achieve CAP goals, and meeting or exceeding the State's renewable energy requirements. The
CCE can likely achieve these goals within 5 years by taking advantage of relatively low wholesale
market prices and abundant GHG-free energy. As discussed in greater detail below, the CCE's
electric portfolio would be guided by the CCE's policymakers with input from its scheduling
coordinator and other power supply experts. The scheduling coordinator would obtain sufficient
resources each hour to serve all of the CCE customer loads. The CCE policymakers would guide
the power supply acquisition philosophy to achieve the CCE's policy objectives.
Projected Power Supply Costs
This Study presents the costs of renewable and non-renewable generating resources as well as
power purchase agreements based on current and forecast wholesale market conditions,
recently transacted power supply contracts, and a review of the applicable regulatory
requirements. In summary, the CCE would need to procure market purchases, renewable
purchases, ancillary services, resource adequacy, and power management/schedule coordinator
services. The Study determines the base case assumption for each of these cost categories as
well as establishing a high and low range for each to be used for the risk analysis later in the
report.
Market Purchases
Market prices for Southern California (referred to as SPlS prices) were provided by EES's
subscription to a market price forecasting service, S&P Global. Exhibit 7 shows forecast monthly
southern California wholesale electric market prices. The levelized value of market purchase
prices over the· 20-year Study period is $0.0471/kWh (2018$) assuming a 4% discount rate.
Community Choice Energy Technical Feasibility Study 16
April 16, 2019 Item #4 Page 28 of 132
trends. First, renewable energy prices are being driven down by the rapidly declining cost of solar
and wind projects. This trend has persisted over the past several years and is expected to
continue over the Study's forecast period. However, this trend is expected to be balanced out
by the impact of increasing statewide demand for renewables as a result of California's
renewable portfolio standards (RPS) laws and changes in Federal tax laws. These assumptions
regarding renewable energy prices have been independently confirmed by current market trends
in southern California.
RPS compliance requirements are 50% in 2020 and growing again to 60% in 2030. But, at a
minimum, comparability with SDG&E's renewable energy procurement plan is recommended. To
provide information about the cost difference between renewable resource portfolios, this Study
analyzes the following 3 portfolios:
1) SDG&E-Equivalent Renewable Portfolio: Achieve between 46% and 59% renewables in
2021 through 2029, based on SDG&E planned renewable energy procurements. Achieve
60% renewables beginning in 2030.
2) 100% Renewables by 2030 Portfolio: 50% of retail loads are served with RPS-qualifying
renewable resources through 2025, 75% through 2029, and 100% in 2030 and after.
3) 100% Renewables Portfolio: 100% of retail loads are served with RPS-qualifying
renewable resources in all years.
The resource portfolios will be discussed in greater detail in the "Resource Portfolios" section
below. It should be noted that the CCE policymakers may opt for other resource portfolios but
those selected above should give the Partners a sound basis for evaluating other resource
portfolio options. The renewable energy targets of the three portfolios included in the power
cost model are shown below in Exhibit 8. For comparison, the state RPS requirement is also
presented in Exhibit 8. All power supply portfolios meet the RPS requirement (SB 100 and SB
350).
Community Choice Energy Technical Feasibility Study 18
April 16, 2019 Item #4 Page 30 of 132
■ Bucket 2: Renewable resources that cannot be delivered into a CBA without some
substitution from non-renewable resources19• This process of substitution is referred to as
"firming and shaping" the energy. The firmed and shaped energy is bundled with RECs.
■ Bucket 3: Unbundled RECs, which are sold separately from the electric energy. 20
Under the current guidelines, the amount of RECs that can be procured through Buckets 2 and 3
is limited and decreases over time. SBX1 2 (April 2011) established a 33% RPS requirement for
2020 with certain procurement targets prior to 2020. SB350 (October 2015) increased the RPS
requirement to 50% by 2030. The share of renewable power that can be sourced from Bucket 2
or 3 energy after 2020 is expected to be the same as the 2020 required share of total RPS
procurement. 21 All power supply portfolios are modeled to meet the relevant state mandates.
All load serving entities face the same mandates and resource choices.
Purchasing unbundled RECs from existing renewable resources does not increase the amount of
renewable projects in the State. In addition, the REC market is not as liquid as it once was. For
these reasons, this Study does not rely on unbundled REC purchases to meet renewable energy
purchase requirements under the RPS.
However, in practice, small quantities of unbundled RECs may be used to balance the CCE's
annual renewable energy purchase targets with the output from renewable resources. Due to
the variable size and shape of the renewable energy purchases, the annual modeled renewable
energy purchases do not typically match up perfectly with annual renewable energy purchase
targets. In some years there are small REC surpluses, and, in others, there are small REC deficits.
These surpluses and deficits can be balanced out using small unbundled REC purchases and sales.
This methodology was used in order to simplify the modeling. In reality, small REC surpluses and
deficits would most likely be handled by banking RECs between years. For the Base Case,
unbundled REC prices are assumed to increase from $17.50/REC in 2020 to $29.09 in 2039 (2.7%
annual escalation).
19 This may occur if a California entity purchases a contract for renewable power from an out of state resource. When
that resource cannot fulfill the contract, due to wind or sun intermittency for example, the missing power is
compensated with non-renewable resources.
2° For example, a small business with a solar panel has no RPS compliance obligation, so they use the power from
the solar panel, but do not "retire" the REC generated by the solar panel. They can then sell the REC, even though
they are not selling the energy associated with it.
21 California Public Utilities Commission Final Decision, 12/20/2016, accessed at:
http://docs.cpuc.ca.gov/PublishedDocs/Published/GOOO/M171/K457 /171457580.PDF, on 1/19/2017. 75% of the
RPS procurement must be Bucket 1 resources and less than 10% of the RPS procurement can come from Bucket 3
resources.
Community Choice Energy Technical Feasibility Study 20
April 16, 2019 Item #4 Page 32 of 132
Ancillary Service Costs
The CCE would need to pay the California Independent System Operator (CAISO) for transmission
congestion and ancillary services associated with its power supply purchases. Transmission
congestion occurs when there is insufficient capacity to meet the demands of all transmission
customers. Congestion is managed by the CAISO by charging congestion charges in the day-
ahead and real-time markets. The Grid Management Charge (GMC) is the vehicle through which
the CAISO recovers its administrative and capital costs from the entities that utilize the CAISO's
services.
In addition, because generation is delivered as it is produced and, particularly with respect to
renewables, can be intermittent, deliveries need to be firmed using ancillary services to meet the
CCE's load requirements. Ancillary services and products need to be purchased from the CAISO
based on the CCE's total loads requirement. Based on a survey of transmission congestion and
ancillary service costs currently paid by CAISO participants, the Partners' CCE Base Case ancillary
service costs are estimated to be approximately $.003/kWh, escalating by 20% annually through
the study period. Ancillary service costs are expected to increase significantly as California works
toward the RPS requirements over the next 10 years.
Resource Adequacy
In addition to purchasing power, the CCE would also need to demonstrate it has sufficient
physical power supply capacity to meet its projected peak demand plus a 15% planning reserve
margin. This requirement is in accordance with RA regulations administered by the CPUC, CAISO
and the CEC. In addition, the CCE must meet the local and flexible resource adequacy
requirements set by the CPUC, CAISO and CEC every year.
The CPUC undertakes annual policy changes to the RA program, so these requirements may
change by the time program launch occurs. Different types of resources have different capacity
values for RA compliance purposes, and those values can change by month. Moreover, recent
rule changes have reduced the RA values for wind and solar resources as more of these
technologies are added to the system. As such, other types of renewables, including geothermal
and biomass, could have an overall better value in the portfolio compared to relying on RA solely
from gas-fired resources.
The CPUC's resource adequacy standards applicable to a CCE require several procurement
targets. CCEs must secure the following three types of capacity and make it available to the
CAISO:
■ System capacity, which is capacity from a resource that is qualified for use in meeting system
peak demand and planning reserve margin requirements;
■ Local capacity, which is capacity from a resource that is located within a Local Capacity Area
capable of contributing to the amount of capacity required in a particular Local Capacity Area;
and
Community Choice Energy Technical Feasibility Study 21
April 16, 2019 Item #4 Page 33 of 132
■ Flexible capacity, which is capacity from a resource that is operationally able to respond to
dispatch instructions to manage variations in load and variable energy resource output.
Power Management/Schedule Coordinator
Given the likely complexity of the CCE's resource portfolio, the CCE would want to engage an
experienced scheduling coordinator to efficiently manage the CCE's power purchases and
wholesale market transactions. The CCE's resource portfolio would ultimately include market
purchases, shares of some relatively large power supply projects, as well as shares of smaller,
most likely renewable resources with intermittent output. Managing a diverse resource portfolio
with metered loads that will be heavily influenced by distributed generation may be one of the
most important and complex functions of the CCE.
The CCE should initially contract with a third party with the necessary experience (proven track
record, longevity and financial capacity) to perform most of the CCE's portfolio operation
requirements. This would include the procurement of energy and ancillary services, scheduling
coordinator services, and day-ahead and real-time trading.
Portfolio operations encompass the activities necessary for wholesale procurement of electricity
to serve end use customers. These activities include the following:
■ Electricity Procurement -assemble a portfolio of electricity resources to supply the electric
needs of the CCE customers.
■ Risk Management -standard industry risk management techniques would be employed to
reduce exposure to the volatility of energy markets and insulate customer rates from sudden
changes in wholesale market prices.
■ Load Forecasting -develop accurate load forecasts, both long-term for resource planning,
and short-term for the electricity purchases and sales needed to maintain a balance between
hourly resources and loads.
■ Scheduling Coordination-scheduling and settling electric supply transactions with the CAISO,
with related back office functions to confirm SDG&E billing to customers.
The Partners' CCE should approve and adopt a set of protocols that would serve as the risk
management tools for the CCE and any third-party involved in the CCE portfolio operations.
Protocols would define risk management policies and procedures, and a process for ensuring
compliance throughout the CCE. During the initial start-up period, the chosen electric suppliers
would bear the majority of risk and be responsible for managing those risks. The protocols that
cover electricity procurement activities should be developed before operations begin.
Based on conversations with scheduling coordinators currently working within the CAISO
footprint, the estimated cost of scheduling services is in the $0.0001 to $0.00025/kWh range for
Community Choice Energy Technical Feasibility Study 22
April 16, 2019 Item #4 Page 34 of 132
large operating CCEs. This Study very conservatively assumes a cost of $0.0005/kWh, escalating
at 2.5% annually, in all portfolios as a starting cost. Over time, as the CCE is operating, it is
expected that the scheduling costs will decline to the $0.0002/kWh range.
Resource Portfolios
Projected power supply costs were developed for three representative resource portfolios.
Portfolios are defined by two variables:
(1) the share of renewable energy in the power mix (per the "Renewable Energy" discussion
above), and
(2) the share of resources that are GHG-free in the power mix.
Renewable resources refer to resources that qualify under State and Federal RPS, such as solar
and wind power. GHG-free power refers to energy sourced from any non-GHG emitting resource,
including both the RPS-compliant sources mentioned above as well as nuclear power and large
hydroelectric power. For this Study, no nuclear resources were included in the resource portfolio
analysis.
SDG&E's resource portfolio in 2016 included 43% renewable energy resources, 42% natural gas
resources as well as 15% unspecified (market) purchases. In 2016, SDG&E's resource portfolio
was 43% GHG-free. As the amount of load served by renewable resources increases each year,
so too would the amount of load served by GHG-free resources. This is true of all three portfolios
included in the Study.
In the "RPS Portfolio"22 and "SDG&E-Renewable Equivalent" scenarios, it is assumed that the CCE
resource portfolio is 80% GHG-free in all years. In the "100% Renewable by 2030 Portfolio" it is
assumed that the CCE's resource portfolio is 80% GHG in 2021 and ramps up to 100% GHG~free
in 2030. The "100% Renewable Portfolio" assumes 100% GHG free resources in all years. The
GHG-free targets for each scenario are shown below in Exhibit 9. It is important to remember
that Exhibit 8 above shows the percentage share of renewable energy in each portfolio, while
Exhibit 9 below shows the GHG-free share of each portfolio.
It is assumed that the Partners' CCE would not modify its renewable energy or GHG-free
achievements to match unexpected or abrupt changes in SDG&E's portfolio. Exhibit 9 below
shows the GHG-free targets for the resource portfolios.
22 The RPS Portfolio is included for comparison purposes but is not included as an alternative in the financial analysis.
Community Choice Energy Technical Feasibility Study 23
April 16, 2019 Item #4 Page 35 of 132
On a $/watt basis, the cost of smaller scale solar projects is greater than the cost of large-scale
solar projects. It is expected that the cost of smaller local renewable resources is $0.065/kWh
based on information related to recent projects. The advantage of local renewable projects is
lower transmission costs and less stress on the congested .transmission grid.
The renewable energy requirements in the State's RPS are based on retail energy sales. Retail
energy refers to the amount of energy sold to customers as opposed to the amount of energy
purchased from generation sources (wholesale energy). Wholesale energy purchases must
always exceed retail energy sales to account for transmission and distribution system losses. To
be consistent, it was assumed that the renewable energy targets included in the portfolios apply
to retail energy sales.
Renewable PPA Pricing Alternative Scenario
This section of the Study considers an alternative resource portfolio in which renewable PPA
contract prices are lower than the base case prices described above. The base case renewable
contract prices included in the Study are based on two conservative assumptions: 1) the majority
of renewable energy purchases are made at short-term, rather than long-term, renewable
. contract prices and 2) the long-term renewable contract price is relatively high compared to the
price at which existing CCEs are currently transacting. These conservative assumptions are
described in greater detail below.
Short-Term Renewable Energy Contract Price
Short-term contracts have a term of one to three years. Short-term contract prices include two
components: a price for energy that is based forward wholesale market prices and a price for
Renewable Energy Credits (RECs). The Study's base case assumes that RE Cs are priced at $17 /REC
for bucket 1 RECs and $11/REC for bucket 2 RECs (1 REC= 1 MWh). Both bucket 1 and bucket 2
REC prices were assumed to escalate 1.5 percent annually. The base case also assumes that 75
percent of RECs acquired under short-term renewable contracts were bucket 1 RECs. Given these
assumptions, the short-term renewable contract price escalated from $54/MWh in 2021 to
$70/MWh by 2030. This pricing is used for short-term renewable energy contracts in all cases in
this study.
Long-Term Renewable Energy Contract Price
The Study's base case includes a long-term renewable PPA fixed contract price of $42/MWh (all
years). The $42/MWh assumption is conservative as other CC Es are currently signing PPAs for the
output of solar projects with flat contract prices of near $30/MWh.
Consistent with the base case, the alternative scenario assumes a long-term renewable PPA price
of $42/MWh in 2021 through 2026. However, the power cost model was updated to assume that
lower priced long-term renewable PPA prices are slowly layered in beginning in 2027. In 2027 the
average long-term renewable PPA price was reduced to $40/MWh. It is assumed that long-term
Community Choice Energy Technical Feasibility Study 26
April 16, 2019 Item #4 Page 38 of 132
renewable contracts with lower fixed prices continue to be layered in and decrease the average
long-term renewable PPA price to $39.5/MWh in 2028, $37.5/MWh in 2029 and $35.5/MWh in
2030. While the $2/MWh decreases in 2028 and 2029 may seem relatively large, the $35.5/MWh
price in 2030 is still $5 to $6/MWh greater than the prices at which existing CCEs are currently
executing contracts. Therefore, the updated long-term renewable PPA prices are still fairly
conservative.
The base case assumes that the majority of renewable energy purchases are made at short-term
renewable contract prices. Specifically, during the first three years of operation all renewable
energy is acquired through short-term renewable PPAs. The amount of renewable energy
sourced to long-term renewable PPAs increased to 10 percent in year 4, 20 percent in year 5 and
25 percent in years 6 through 20.
In the alternative power supply scenario, the amount of renewable energy that is sourced to
long-term renewable PPAs is increased. It is assumed that all renewable energy is acquired
through short-term PPAs in the first two years of operation. The amount of renewable energy
assumed to be acquired through long-term renewable PPAs was increased to 50 percent in year
3, 55 percent in year 4, 60 percent in year 5 and 65 percent in years 6 through 20.
The revised assumptions regarding a) the amount of renewable energy purchased through long-
term renewable energy PPAs and b) the prices at which renewable energy is purchased are
illustrated below in Exhibit 11.
Community Choice Energy Technical Feasibility Study 27
April 16, 2019 Item #4 Page 39 of 132
SDG&E-Renewable Equivalent Renewables Portfolio
In this portfolio, the renewable energy purchases match the expected SDG&E renewable share
based on recent information. 24 In Exhibit 14, the green and orange bars show renewable energy
purchases {44%). Renewable energy purchases in 2021 through 2023 are greater than the RPS
minimum requirement of 33%.
200
180
160
140
120
s ::E 100
ctl
80
60
40
20
0
Exhibit 14
SDG&E-Renewable Equivalent Renewables Portfolio (aMW)
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040
■ Market PPAs ■ GHG-Free Market PPAs ■ Solar ■ Wind ■ Local Renewables
*Average annual megawatt or a MW is equal to annual megawatt-hours divided by the number of hours in a year.
24 http://www.energy.ca.gov/pcl/labels/2016_index.html
Community Choice Energy Technical Feasibility Study 31
April 16, 2019 Item #4 Page 43 of 132
storage targets for IOUs, CCEs, and other LSEs in September 2013. The applicable CPUC decision
established an energy storage procurement target for CCEs and other LSEs equal to 1% of their
forecasted 2020 peak load. The decision requires that contracts be in place by 2020 and projects
be installed by 2024.
Community Choice Energy Technical Feasibility Study 36
April 16, 2019 Item #4 Page 48 of 132
Cost of Service
This section of the Study describes the financial pro forma analysis and cost of service for a CCE
for the Partners. It includes estimates of staffing and administrative costs, consultant costs,
power supply costs, uncollectable charges, and SDG&E charges. In addition, it provides an
estimate of start-up working capital and longer-term financial needs.
Cost of Service for CCE "Base Case" Operations
The first category of the pro forma analysis is the cost of service for a CCE for the Partners'
operations. To estimate the overall costs associated with CCE operations, the following
components have been included:
■ Power Supply Costs
■ Non-Power Supply Costs
• Staffing
• Administrative costs
• Consulting support
• SDG&E billing and metering charges
• Uncollectible costs
• Reserves
• New programs funding
• Financing costs
■ Pass-Through Charges from SDG&E
• Transmission and distribution charges
• Power Charge Indifference Adjustment (PCIA)
Once the costs of CCE operations have been determined, the total costs can be compared to
SDG&E's projected rates. A detail of the various non-power supply costs is included in Appendix
D.
Power Supply Costs
A key element of the cost of service analysis is the assumption that electricity would be procured
under a power purchase agreement (PPA) for both renewable and non-renewable power for an
initial period. Power supply would likely be obtained by the CCE's procurement consultant prior
to commencing operations. The products and services required from the third-party
procurement consultant are energy, capacity (System, Local and Flexible RA products),
renewable energy, GHG-free energy, load forecasting, CAISO charges (grid management and
congestion), and scheduling coordination.
Community Choice Energy Technical Feasibility Study 37
April 16, 2019 Item #4 Page 49 of 132
The calculated 20 year levelized cost of electric power supply, including the cost of the scheduling
coordinator and all regulatory power requirements, is estimated between$0.075 and $0.082 per
kWh as discussed in the previous chapter. This price represents the price needed to meet the
load requirements of the CCE customers while meeting required regulations (SB 350 and SB 100)
and objectives of the CCE. The variation in price is a function of the desired level of renewable
resources.
Three power supply scenarios are modeled for this Study have been discussed in previous
sections. As a reminder the scenarios are:
(1) SDG&E Renewable Equivalent
(2) 100% Renewable by 2030
(3) 100% Renewable
Non-Power Supply Costs
While power supply costs would make up the vast majority of costs associated with operating
the Partners' CCE (roughly 80-90% depending on the portfolio scenario), there are additional cost
components that must be considered in the proforma financial analysis. These additional non-
power supply costs are described below.
Estimated Staffing Costs
Staffing is a key component of operating a CCE. This Study assumes the Partners will proceed
with the JPA operating model. All staffing costs are detailed in Exhibit 17.
The Partners' CCE would have discretion to distribute operational and administrative tasks
between internal staff and external consultants in any combination. For this Study, two scenarios
are explored that are considered to be at the maximum and minimum of this spectrum. The first
option involves hiring internal staff incrementally to match workloads involved in forming the
CCE, managing contracts, and initiating customer outreach/marketing during the pre-operations
period (Full Staff Scenario). In the alternative approach, the CCE would hire just four staff
internally and contract out the remaining work to consultants (Minimum Staff Scenario).
Throughout the rest of this Study, it is assumed that the Partners' CCE will opt for the Full Staff
Scenario to be conservative in the Study's economic analysis, but both options are discussed. The
Full Staff Scenario is likely the most-costly option that the CCE could pursue and the details of the
staffing plan would be part of the JPA between partners.
Minimum Staff Scenario
To build the minimum staff possible to run the Partners' CCE, all necessary tasks would be
completed by consultants on a contract basis. It is assumed that these contracts would be
managed by the Executive Director and two in-house staff, such as the Communication Outreach
Community Choice Energy Technical Feasibility Study 38
April 16, 2019 Item #4 Page 50 of 132
Manager, a Director of Administration and Finance and a Director of Power Resources. In
addition, consultants would have to be hired to manage the tasks not managed by full-time staff.
This study focuses on the Full Staff Scenario described below, the Minimum staff scenario would
be lower cost to implement and therefore the Full Staff Scenario is more conservative.
Full Staff Scenario
Exhibit 19 provides the estimated staffing budgets for a full staff CCE scenario for the start-up
period (Pre-launch in 2020 through full operating in 2021). Staffing budgets include direct salaries
and benefits. Prior to program launch, it is assumed that an operating team would be employed
per the example of other CCEs in California thus far to implement the launch of a CCE program.
This operating team typically includes an Executive Director, a Director of Administration and
Finance, a Communication Outreach Manager and a Director of Power Resources. The remaining
functions would be filled as quickly as possible.
Exhibit 19
CCE Staffing Plan (Full Staff Scenario)
2020* 2021
CCE Staff Positions Pre-launch Launch
Executive Director 1 1
Director of Marketing and Public Affairs 0 1
Account Service Manager 0 1
Account Representative 0 1
Communication Outreach Manager 1 1
Communication Specialist 0 1
Director of Power Resources 1 1
Director of Administration and Finance 1 1
Power Resource Analyst 0 1
Power Supply Compliance Specialist 0 1
Administrative Assistant 0 1
Total Number of Employees 4 11
Total Staffing Costs $389,299 $2,204,114
*Represents only partial year (6 months).
Based on this staffing plan, the Partners' CCE would initially employ 4 staff members. Once the
CCE launches, it is anticipated that staffing would increase to approximately 11 employees within
the first year of operation.
Community Choice Energy Technical Feasibility Study 39
April 16, 2019 Item #4 Page 51 of 132
Administrative Costs
Overhead needed to support the organization includes computers and other equipment, office
furnishings, office space, utilities and miscellaneous expenses. These expenses are estimated at
$28,000 during program pre-start-up. Office space and utilities are ongoing monthly expenses
that would begin to accrue before revenues from program operations commence, and are;
therefore, included in start-up costs that would be financed.
It is estimated that the per employee start-up cost is approximately $7,000. This expense covers
computer and furniture needs. An additional annual expense of $15,000 for office space, and
approximately $10,000 per year in office supplies and utilities costs is expected. Miscellaneous
start-up costs of $102,000 are estimated for 2021 to address the general cost of mailing
notifications, meetings, communication and other start-up activities. In addition, it is assumed
that computers would need to be replaced every 5 years. Finally, additional miscellaneous
expense budgets are estimated for general start-up costs in 2020. All administrative costs for
start-up are shown in Exhibit 20. These costs are based on other start-up CCE operations. These
costs are a very small portion of total operating costs that even a doubling of these costs from
the below assumptions would not change the Study findings.
Exhibit 20
Estimated Overhead Cost by Year (Full-Staff Scenario)
2020 2021
Infrastructure Costs
Computers $20,000 $35,700
Furnishings $8,000 $14,280
Office Space $0 $15,300
Utilities/Other Office Supplies $0 $10,200
Miscellaneous Expenses $0 $102,000
Total Infrastructure Costs $28,000 $177,480
The above costs are based on a full staff scenario. If the CCE determines in its business plan that
hiring consultants rather than staff would be more cost-effective administrative costs would be
reduced improving the feasibility of the CCE.
Outside Consultant Costs
Consultant costs would include outside assistance for legal and regulatory work, communication
and marketing, data management, financial consulting, technical consulting and implementation
support.
CCE data management providers supply customer management system software, and oversee
customer enrollment, customer service, as well as the payment processing, accounts receivable
and verification services. The cost of data management is charged on a per customer basis and
Community Choice Energy Technical Feasibility Study 40
April 16, 2019 Item #4 Page 52 of 132
has been estimated based on existing contracts for similar sized CC Es. For this Study, the cost for
data management is estimated at $1.25 per customer per month.
In addition, estimated funding for other consulting support (such as HR, legal, customer service,
etc.) is provided. These costs have been estimated based on the experience of start-up consulting
costs at other CCEs. Exhibit 21 shows the estimated consultant costs except for data management
during the first three years. Consultant fees are provided on a monthly and annual basis in
Appendix D.
Exhibit 21
Estimated Consultant Costs by Year
2020 · 2021
Legal/Regulatory* $0 $374,500
Communication 34,000 208,000
Financial Consulting** 61,200 124,800
Technical Consultant 255,000 520,200
Other Consulting/City Functions 76,500 312,100
Total Consultant Costs $426,700 $1,539,600
*Legal/regulatory consulting refers only to legal counsel regarding CPUC compliance, filings, etc.
**Financial consulting includes legal fees for counsel on CCE financing.
2022
$382,000
106,100
127,300
530,600
159,200
$1,305,200
The estimate for each of the services is based on costs experienced by other CCEs. Consultant
costs are increased by inflation every year.
SDG&E Billing & Metering Costs
SDG&E would provide billing and metering services to the CCE based on Schedule CCE:
Transportation of Electric Power to CCE Customers. The estimated costs payable to SDG&E for
services related to the Partners' CCE start-up include costs associated with initiating service with
SDG&E, processing of customer opt-out notices, customer enrollment, post enrollment opt-out
processing, and billing fees.
Customers who choose to receive service from the CCE would be automatically enrolled in the
program and have 60 days from the date of enrollment to opt-out of the program. A total of four
opt-out notices would be sent to each customer. The first notice would be mailed to customers
approximately 60 days prior to the date of automatic enrollment. A second notice would be sent
approximately 30 days later. Following automatic enrollment, two additional opt-out notices
would be provided within the 60-day period following customer enrollment.
Based on SDG&E's current rate schedules, and CCE participation assumptions, SDG&E billing
charges would be approximately $389,000 annually and initial setup costs and noticing would be
on the order of $180,000 per year for 2020 and 2021, as shown in Exhibit 22.
Community Choice Energy Technical Feasibility Study 41
April 16, 2019 Item #4 Page 53 of 132
Total SDG&E Billing Fees
Notification and Setup costs
Uncollectible Costs
Exhibit 22
Utility Transaction Fees
2020
$0
$180,000
2021
$389,000
$184,000
2022
$390,000
$0
As part of its operating costs, the CCE must account for customers that do not pay their electric
bill. While SDG&E would attempt to collect funds, approximately 0.2% of revenues are estimated
as uncollectible. 25 This cost is therefore included in the CCE operating costs, or expense budget.
Financial Reserves
The Partners' CCE is assumed to receive capital financing during its start-up through full
operation. After a successful 1,aunch, the CCE must build up a reserve fund that is available to
address contingencies, cost uncertainties, rate stabilization or other risk factors faced by the CCE.
Therefore, this Study assumes that the CCE would-begin building its reserve immediately upon
launch. After three full operating years, it is estimated that the CCE will have accumulated
enough reserves to cover three months of expenses . This level of reserves represents the
minimum industry standard for electric utilities and would provide financial stability to assist the
CCE in obtaining favorable interest rates if additional financing is needed. After that point,
revenues that exceed costs could be used to finance a rate stabilization fund, new local
renewable resources, economic development projects and/or lower rates. Exhibit 23 provides
the estimate of the reserves available for local programs or rate stabilization.
25 Based on SDG&E 2019 GRC uncollectible revenue as percent of total revenue.
Community Choice Energy Technical Feasibility Study 42
April 16, 2019 Item #4 Page 54 of 132
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
* Includes cash from financing
Exhibit 23
Estimated Reserves Under Base Scenario
Assuming 2% Rate Discount Off SDG&E Rates
Cumulative Operating Reserves
Surplus* (4 months O&M)
$1,040,834 $1,040,834
$36,426,945 $36,426,945
$51,017,476 $35,446,407
$66,821,209 $35,527,660
$79,417,870 $36,925,937
$92,520,717 $38,577,598
$103,191,391 $39,892,548
$111,642,089 $41,286,828
$118,694,926 $42,703,313
$123,331,689 $44,179,264
$125,615,569 · $45,642,936
Programs or Rate
Reduction
$0
$0
$15,571,068
$6,589,109
$11,198,385
$11,451,185
$9,355,724
$7,056,418
$5,636,352
$3,160,811
$820,208
The new program funding amount decreases over time due to the conservative 1% growth in
SDG&E generation rates and persistently high PCIA. After 2030, SDG&E stranded costs are
expected to decrease significantly as contracts expire {resulting in lower PCIA rates). It is
expected that programs and rate discounts could be provided well beyond the term of this Study.
These financial reserves are documented in Appendix B.
Financing Costs
In order to estimate financing costs, a detailed analysis of working capital needs, as well as start-
up capital, is estimated. Each component is discussed below.
Cash Flow Analysis and Working Capital
This cash flow analysis estimates the level of working capital that would be required until full
operation of the CCE is achieved. For the purposes of this Study, it is assumed that the CCE pre-
operations begin in July 2020. In general, the components of the cash flow analysis can be
summarized into two distinct categories:
1. Cost of the CCE operations, and
2. Revenues from CCE operations.
The cash flow analysis identifies and provides monthly estimates for each of these two
categories. A key aspect of the cash flow analysis is to focus primarily on the monthly costs and
revenues associated with the CCE and specifically account for the transition or "phase-in" of the
CCE customers.
Community Choice Energy Technical Feasibility Study 43
April 16, 2019 Item #4 Page 55 of 132
The cash flow analysis also provides estimates for revenues generated from the CCE operations
or from electricity sales to customers. In determining the level of revenues, the cash flow analysis
assumes all customers are enrolled at the same time, based on the assumed participation rates,
and assumes that the CCE offers rates that provide a discount compared to projected SDG&E
rates corresponding to a total bill discount of 2% for each customer class.
The results of the cash flow analysis provide an estimate of the level of working capital required
for the CCE to move through the pre-operations period. This estimated level of working capital
is determined by examining the monthly cumulative net cash flows (revenues minus cost of
operations) based on payment terms, along with the timing of customer payments.
The cash flow analysis assumes that customers will make payments within 60 days of the service
month, and that the CCE would make payments to power suppliers within 30 days of the service
month. It is assumed that payments for all non-power supply expenses would need to be paid in
the month they occur. Customer payments typically begin to come in soon after the bill is issued,
and most are received before the due date. Some customer payments are received well after
the due date. Therefore, the 30-day net lag in payment is a conservative assumption for cash
flow purposes.
For purposes of determining working capital requirements related to power purchases, the CCE
would be responsible for providing the working capital needed to support electricity
procurement unless the electricity provider can provide the working capital as part of the
contract services. In addition, the CCE would be obligated to meet working capital requirements
related to program management, the CPUC Bond of minimum $180,00026 and a potential SDG&E
program reserve. While the CCE may be able to utilize a line of credit, for this Study it is assumed
that this working capital requirement is included in the financing associated with start-up
funding.
A summary of working capital needs is presented below on Exhibit 24.
Exhibit 24
Working Capital Needs
2020 2021
Pre-Launch Launch
Bonding & Security Requirement (CPUC) $0.2 million -
SDG&E Program Reserve $0.6 million -
Start-up Costs $1.2 million -
Working Capital (Cash Flow) -$14.0 million
Total Capital Needed $ 2.0 million $14.0 million
26 CPUC Decision 18-05-022
Community Choice Energy Technical Feasibility Study 44
April 16, 2019 Item #4 Page 56 of 132
For comparison, Marin Clean Energy (MCE) started with $3.3 million in pre-launch funding27 and
is now operating with $21.7 million in working capital-28 At initial launch MCE served electrical
load roughly equivalent to 80-90% of the Partner CCE's estimated load. 29 Similarly, Sonoma Clean
Power (SCP) acquired $6.2 million in pre-launch capital, 30 and now maintains working capital
reserves of $25 million31 while serving 25% more than the Partner CCE's estimated load. 32 The
working capital needs after launch assumed in this Study are reflective of the experience of
successfully operating CCEs on a $/GWh basis.
Total Financing Requirements
The start-up of the Partners' CCE would require a significant amount of start-up capital for three
major functions: (1) staffing and consultant costs; (2) overhead costs (office space, computers,
etc.) and (3) CPUC Bond and SDG&E security deposits.
Staffing, consultant and other program initiation costs have been discussed previously. In
addition, the Public Utilities Code requires demonstration of insurance or posting of a bond
sufficient to cover reentry fees imposed on customers that are involuntarily returned to SDG&E
service under certain circumstances. SDG&E also requires a bond equivalent to the re-entry fee
for voluntary returns to the IOU. This corresponds to the fees outlined in the CCE rate schedule
from SDG&E, which are $1.12/customer for 2018. In addition, the bond must cover incremental
procurement costs. Incremental procurement costs are power supply costs incurred by the IOU
when a customer provides notice and returns to IOU bundled service.
For the Partners' CCE, the total financing requirement, including working capital, du ring the pre-
launch to full operations, are estimated to be approximately $2 million, with approximately
another $14 million following full enrollment. With more flexible power payment terms and/or
customer payments of less than 60 days, capital requirements can be reduced by up to $7 million.
Current CCE Funding Landscape
The CCE market is rapidly expanding with increasingly proven success. To date, there are twenty
operational CCEs in California and existing CCEs have demonstrated the ability to generate
positive operating results. The early sources of that funded CCE start-up capital costs were
community banks located in the CCE service territory, but now a mix of regional and large
27https ://www. mcecl ea n energy. o rg/wp-co ntent/ up I oads/2016/01/M CE-Start-Up-Tim el in e-a n d-1 n i ti a 1-F u n ding-
Sou rces-10-6-14-1. pdf
28https://www. m cecl ea nenergy. o rg/wp-co ntent/ up I oads/2016/09 /M CE-Audited-Finan ci a 1-Statem ents-2015-
2016. pdf
29https ://www. mcecl ea ne nergy. o rg/wp-conten t/ up I oa ds/2016/01/Ma ri n-CI ea n-En ergy-2015-1 ntegrated-Resou rce-
Pl an _Fl NAL -BOARD-APP ROVED. pdf
30 https:// sonoma clean power. o rg/wp-conten t/ up loa·ds/2015/01/2014-SCP A-Audited-Finan cia Is. pdf
31 https :// son oma clean power. org/wp-content/ up loa ds/2015/01/2016-05-SCP-Co mpi I ed-Fi nan cia I-Statements. pdf
32 https:// son om a clean power. o rg/wp-content/u pl oads/2015/01/2015-SCP-I m pl em entati on-Plan. pdf
Community Choice Energy Technical Feasibility Study 45
April 16, 2019 Item #4 Page 57 of 132
national banks have shown increased levels of interest evidenced by additional banks submitting
proposals to CCEs looking for financing. As such, the Partners would likely have access to an
adequate number of potential financial counterparties.
As CCEs have successfully launched across the State and a more robust data set of opt-out history
becomes available, the financial community has demonstrated an increased level of comfort in
providing credit support to CCEs. Most programs that have launched to date and those in
development have relied on a sponsoring entity to provide support for obtaining needed funds.
This support has come in varied forms, which are summarized in Exhibit 25.
Exhibit 25
Forms of Support
Pre-Launch Funding
CCE Name Date Requirement1 Funding Sources
Marin Clean $2-$5 million Start-up loan from the County of Marin, individual
Energy 2010 investors, and local community bank loan.
Sonoma Loan from Sonoma County Water Authority as well as
Clean Power 2014 $4 -$6 million loans from a local community bank secured by a
Sonoma County General Fund guarantee.
CleanPowerSF 2016 ~$s million Appropriations from the Hetch Hetchy reserve
(SFPUC).
Lancaster 2015 ~$2 million Loan from the City of Lancaster General Fund. Choice Energy
Peninsula PCE has also obtained a $12 million loan with Barclays
Clean Energy 2016 $10 -$12 million and almost $9 million with the County of San Mateo
for start-up costs and collateral.
Silicon Valley Loans from County of Santa Clara and City members
2017 $2.7 million $21 million Line of Credit with $2 million guarantee, Clean Energy otherwise no collateral.
Clean Power 2018 $41 million $10 million loan from Los Angeles County and $31
Alliance million Line of Credit from River City Bank.
Solana Clean
Energy 2018 N/A Vendor Funding
East Bay 2018 $50 million Revolving Line of Credit from Barclays. Clean Energy
1 Source: Respective entity websites and publicly available information. These funds are representative of CCE
funding at different times of start-up.
A review of the current state of options for obtaining funds for these in itial phases is detailed
below:
Direct Loan from Cities -Any of the Partner cities could loan funds from its General Fund for all
or a portion of the pre-launch through launch needs. Start-up funding provided by the cities
would be secured by the CCE revenues once launched. The cities would likely assess a risk-
appropriate rate for such a loan. This rate is estimated to be 4.0% to 6.0% per annum.
Community Choice Energy Technical Feasibility Study 46
April 16, 2019 Item #4 Page 58 of 132
Collateral Arrangement from Cities -As an alternative to a direct loan from the cities, the cities
could establish an escrow account to backstop a lender's exposure to the CCE. The cities would
agree to deposit funds in an interest-bearing escrow account, which the lender could tap should
the CCE revenues be insufficient to pay the lender directly. The cities obligations would be
secured by CCE revenues collected once the CCE achieves viability.
Loan from a Financial Institution without Support -Silicon Valley Clean Energy Authority (SVCEA}
was able to use this option to fund ongoing working capital. After member agencies funded a
total of $2.7 million in start-up funds, SVCEA obtained a $20 million line of credit without
collateral. This is the most common financing options used by emerging CCEs. This arrangement
requires a "lockbox" approach with a power provider. A lockbox arrangement requires the CCE
to post revenues into a "lockbox" which power suppliers can access in order to get paid first
before the CCE. This arrangement reduces the required reserves and collateral held by the CCE.
Vendor Funding -The CCE could negotiate with its power suppliers to eliminate or reduce the
need for supplemental start-up and operating capital. However, the vendor funding approach
can be less transparent as the vendor controls expenses and activities, and the associated cost
may outweigh the benefit of eliminating or reducing the need for bank financing. This method
was used by Solana Energy Alliance.
Revenue Bond Financing -This financing option becomes feasible only after the CCE is fully
operational and has an established credit rating.
CCE Financing Plan
While there are many options available to the CCE for financing, the initial start-up funding is
expected to be provided via short-term financing via a loan from a financial institution. The CCE
would recover the principal and interest costs associated with the start-up funding via
subsequent retail rate collections. This Study demonstrates that the CCE start-up costs would be
fully recovered within the first three years of CCE operations.
The anticipated start-up and working capital requirements for the Partners' CCE through launch
are approximately $2.2 million. Once the CCE program is operational, these costs would be
recovered through retail rate collections. Actual recovery of these costs would be dependent on
third-party electricity purchase prices and the rates set by the CCE for customers.
Based on severa.1 recent examples of CCE's obtaining financing for start-up and operating costs,
this financial analysis assumes that the CCE would be able to obtain a loan for all $16 million with
a term of 5 years at a rate of 5.5%. While the term of the loan is assumed to be 5 years, the
repayment period assumed is 3 years. This is very conservative as most CCEs will operate on a
line of credit for the majority of working capital needs.
The detail of the base case cash flow analysis is provided in Appendix B.
Community Choice Energy Technical Feasibility Study 47
April 16, 2019 Item #4 Page 59 of 132
Rate Comparison
This section provides a comparison of rates between SDG&E and the Partners' CCE. Rates are
evaluated based on the CCE's total electric bundled rates as compared to SDG&E's total bundled
rates. Total bundled electric rates include the rates charged by the CCE, including non-bypassable
charges, plus SDG&E's delivery charges.
Rates Paid by SDG&E Bundled Customers
Customers served by SDG&E will pay a bundled rate that includes SDG&E's generation and
delivery charges. SDG&E's current rates and surcharges have been applied to customer load data ·
aggregated by major rate schedules to form the basis for the SDG&E rate forecast.
The average SDG&E delivery rate, which is paid by both SDG&E bundled customers and CCE
customers, has been calculated based on the forecasted customer mix for the Partners' CCE. The
SDG&E rate forecast assumes that delivery costs will be based on SDG&E's recent General Rate
Case (GRC) filing for 2019 to 2021. Thereafter, it is assumed that the delivery costs will increase
by 2% per year based on inflation expectations.
Similarly, the average power supply rate component for SDG&E bundled customers has been
calculated based on the projected CCE customer mix. Finally, the SDG&E generation rates have
been projected to increase based on the renewable and non-renewable market price forecast,
and the state's regulatory requirement for RPS, energy storage, and resource adequacy
objectives. It is projected that SDG&E-owned resource and renewable cost escalation will be 1%
over the 10-year analysis period. SDG&E does not provide detailed cost information or power
supply price forecasts for the utility. Based on SDG&E's 2016 resource mix and RPS requirements,
50% to 60% of SDG&E's resources come from market purchases and natural gas resources for
which costs grow based on market price changes. Market costs are expected to increase at a rate
of 1% to 3% annually. The remainder of SDG&E's resources are from high priced long-term
renewable contracts. While the cost of market purchases and natural gas are expected to
increase, the cost of the renewable portfolio is expected to decrease over time as SDG&E's
current contracts expire and new lower cost renewable contracts are obtained. The Study uses
a conservative 1% growth rate for SDG&E generation costs beginning in 2020. This growth rate
is conservative compared with the growth rate utilized in the San Diego Feasibility Study (roughly
2.5%). The SDG&E generation rate forecast can be seen in Exhibit 26.
Community Choice Energy Technical Feasibility Study 48
April 16, 2019 Item #4 Page 60 of 132
Rate Class
Residential
Small Commercial
Medium Commercial
Street Lights
Agriculture
Total
Initial Rate Savings in 2021 from
SDG&E Bundled Rate
Exhibit 29
Bundled Rate Comparisons
$/kWh
SDG&E
Equivalent
2021 SDG&E * Renewable
0.3494 0.3480
0.2233 0.2317
0.2303 0.2203
0.2388 0.2390
0.1322 0.1325
0.2854 0.2797
2.00%
*SDG&E bundled average rate projections based on SDG&E's 2018 Rates.
100%
Renewable by
2030
0.3480
0.2317
0.2203
0.2390
0.1325
0.2797
2.00%
A financial proforma in support of these rates can be found in Appendix B.
Community Choice Energy Technical Feasibility Study
100%
Renewable
0.3494
0.2233
0.2303
0.2388
0.1322
0.2854
0.00%
52
April 16, 2019 Item #4 Page 64 of 132
Environmental and Economic Impacts
This section provides an overview of the potential environmental and indirect economic impacts
to the San Diego area from the implementation of a CCE in the four Cities. In addition, potential
future programs that could be offered by the CCE are outlined.
Impact of Resource Plan on Greenhouse Gas (GHG) Emissions
At this time, SDG&E's resource mix is 43%33 GHG-free due to power supply from renewable
resources. The passing of SB100 accelerates the Renewable Portfolio Standard {RPS) obligations
for retail sellers (investor-owned utilities {IOUs), CCEs, energy service providers (ESPs), and Public
Owned Utilities (POUs)) as follows:
a) from 40% to 44% by 2024;
b) from 45%t to 52% by 2027; and
c) From 50% to 60% by 2030.
The bill also establishes state policy that RPS-eligible and zero-carbon (Clean Energy) resources
supply 100% of all retail sales of electricity to California end-use customers no later than
December 31, 2045. SDG&E is therefore expected to be 60% renewable and GHG free by 2030
and 100% GHG free by 2045.
As outlined in the Resource Portfolio section above, the CCE portfolio scenarios assumed that the
CCE's resource portfolio is at least 80% GHG-free in all years. In the "SDG&E-Equivalent Portfolio"
it is assumed that the Partners' CCE resource portfolio is 80% GHG-free in all years. In the "100%
Renewable By 2030 Portfolio" it is assumed that the CCE's resource portfolio is 80% GHG-free in
2021 and that the GHG-free resources increase each year after 2021 until 2030 when GHG-free
resources are 100%. In the "100% Renewable Portfolio" it is assumed that the CCE's resource
portfolio is 100% GHG-free in 2021 and remains 100% GHG-free through 2030.
The remaining non-GHG-free energy would generate amounts of GHG emissions as outlined in
Exhibit 30. The average portfolio GHG-free percentage over the ten-year study period (88%) was
used for this calculation, to account for the higher GHG-free levels in later years. Average annual
emissions from the three portfolios for 2021-2030 are presented below. In each case, it was
assumed that the full CCE load {1,542 GWH) was in each portfolio. In other words, if, for example,
the CCE decides to offer both 100% Renewable and 50% Renewables products and some
proportion of customers fall into each product bucket, the emissions would fall somewhere
between 222,000 and 272,000 metric tons of CO2e/year.
33 http://www.energy.ca.gov/pcl/labels/2016_index.html
Community Choice Energy Technical Feasibility Study 53
April 16, 2019 Item #4 Page 65 of 132
Exhibit 30
Comparison of Average Annual GHG Emissions from Electricity, by Resource Portfolio {2021-2030}
SDG&E 100% Equivalent Renewable 100% SDG&E Renewable by 2030 Renewable
Portfolio
Avg./GHG Share 80% 89% 100% 60%
Avg. Emissions (Metric Tons CO2) 109,000 61,000 -218,000
Difference SDG&E 60% Portfolio (Metric 109,000 157,000 218,000 Tons CO2)
Savings expressed as Number of Cars Off 24,000 34,000 47,000 0 the Road1
1 Passenger cars, based on 4.6 metric tons of CO2 per year assuming 22 mpg and 11,500 miles per year.
Local Resources/Behind the Meter CCE Programs
The CCE would have the option to invest in a range of programs to expand renewable energy use
and enhance economic development in the Partner cities. Increased renewable energy use can
be accomplished by supporting customers wishing to own small renewable generation {net
energy metering), purchasing from small local for-profit renewable generators {feed-in tariffs),
purchasing renewable resources directly, or supporting electric vehicle use. Each of these
programs also yields economic development benefits by stimulating spending locally and saving
local customers money. Economic development can also be accomplished by providing additional
support for low-income customers or extra support for new or growing businesses. The following
sections discuss these programs.
Economic Development Rate Incentive
There are several programs that CCEs can offer to stimulate indirect local economic development
in their service area. One is a special economic development rate to encourage job providers to
locate within the CCE jurisdiction.
Another type of program that promotes economic development is to provide incentives for
businesses to locate in the service area, remain there, or expand. For instance, the CCE could
offer rebate programs or fund infrastructure costs for the business to target the business sectors
of interest to their service area. If, for example, a large industrial customer would like to locate
within the CCE service area, increased efficiency may result in decreased costs to all other
customers due to overhead cost sharing, thus an incentive could be paid to the new industrial
customer.
Net Energy Metering (NEM) Program
The CCE could establish a Net Energy Metering {NEM) program for qualified customers in their
service territory to encourage wider use of distributed energy resources {DER) such as rooftop
Community Choice Energy Technical Feasibility Study 54
April 16, 2019 Item #4 Page 66 of 132
solar. NEM programs allow energy customers who generate some or all of their own power to
sell excess generation to the grid and benefit from a credit for those sales when they become a
NEM consumer.
SDG&E currently offers a NEM program in which customers receive an annual "true-up"
statement at the end of every 12-month billing cycle. This allows customers to balance credit
earned in summer months (when solar energy generation is highest) with charges accrued in the
winter (when solar generation is lower, and customers rely more on SDG&E's bundled service).
Customers earn power credits at the value of electricity and the value of renewable energy
credits, though they are not paid for excess generation. Credits unused at the end of each year
expire. This policy therefore incentivizes customers to limit the size of their generation system,
as excess generation supplied to the grid will not provide a return.
All of the CCEs currently operating in California also offer NEM programs, and three of the most
recently operational CCEs have offered them at the launch of service. 34 All of these CCE-managed
NEM programs offer greater incentives for customers in their service area to invest in more and
larger Distributed Energy Resources (DER). Higher incentives up to the full retail rate have been
offered. This has the benefit of increasing the supply of renewable resources available to these
CCEs as well as encouraging high participation rates among current and potential NEM
customers. The Partner cities would have the option to implement a similar NEM program and
the ability to stimulate local economic development in the form of new DER system investments
and associated business activity.
Feed-in Tariffs
Feed-in tariffs (FIT) offer terms by which electric service providers such as IOUs and CCEs
purchase power from small-scale renewable electritity projects within their service territory. In
contrast with NEM programs, which typically target owners of homes and small businesses who
wish to install a rooftop photovoltaic (PV) system, FIT programs target owners of larger
generation projects, in the range of 0.5-3 MW. These could be larger rooftop photovoltaic (PV)
systems located at industrial sites or ground-mounted solar shade structures in parking lots. In
developing a FIT program of its own, the Partners' CCE could incentivize customers in their service
area to develop local renewable resources.
Local Generation Resources Development
A final option to drive investment in local renewable generation resources within the CCE service
area is for the CCE itself to build or acquire generation resources. For example, Marin Clean
Energy (MCE) currently has 10.5 MW of CCE-owned local solar PV projects under development
34https://pioneercommunityenergy.ca.gov/home/nem-solar/,https://www.poweredbyprime.org/faq.
http://www.applevalley.org/home/showdocument?id=18607
Community Choice Energy Technical Feasibility Study 55
April 16, 2019 Item #4 Page 67 of 132
and is planning to develop or purchase up to 25 MW of locally constructed, utility scale renewable
generating capacity by 2021.35 This model of CCE-owned resources provides CCEs with a
guaranteed renewable power source as well as local economic stimulus.
Electric Vehicle (EV) Programs and Charging Stations
Encouraging electric vehicle use can both increase load serving entity ("LSE") total load and
simultaneously reduce greenhouse gas emissions within its service area. Many LSEs offer special
rates for electric vehicle charging. SDG&E offers two non-tiered, time-of-use (TOU) plans for
electric vehicle charging: EV-TOU-2 and EV-TOU-5 which combines the loads of vehicle charging
with the load of the residence. The two programs offer different TOU periods. EV-TOU customers
install a separate meter explicitly for vehicle charging. 36 TOU rates encourage vehicle charging at
times when energy is cheapest, or system load is lowest. MCE offers a similar program for their
customers with lower rates than the IOU. 37
In addition to targeted rate programs, CCEs can encourage electric vehicle use by investing in
local electric vehicle charging stations. Silicon Valley Power (SVP) opened the largest public
electric vehicle charging center in the State in April 2016. The facility features 48 Level 2 chargers
and one DC Fast Charger. 38 Sonoma Clean Power (SCP) also provided qualified customers with
incentives to purchase EVs in 2016 and continued the program in 2017. 39 The Partners' CCE could
invest in similar projects to promote electric vehicle use within its service area.
Low Income Programs
SDG&E offers assistance to low-income customers on both one-time and long-term bases. For
customers in need of sustained assistance, SDG&E offers rates that are up to 30% lower for
qualifying households under the California Alternate Rate Energy (CARE)40 program. The CARE
program is mandatory for IOUs per California Public Utilities Code 739.1. The program is set up
for electric corporations that have 100,000 or more customer accounts to provide 30-35%
discount on electric utility bills on households that are at or below 200% of the federal poverty
line. Funding for CARE is collected on an equal cents/kWh basis from all customer classes except
street lighting. This program, like other SDG&E low income programs, would continue to be
available to CCE customers through SDG&E.
35https://www. mcecl eanenergy .org/wp-content/u ploads/2017 /11/MCE-2018-1 ntegrated-Resou rce-Plan-FI NAL-
2017 .11.02. pdf
36 https ://www. sdge. com/ reside ntia I/ p rici ng-p I ans/ a bout-ou r-p ricing-plans/ el ectri c-veh i cl e-p I ans
37 https://www.mcecleanenergy.org/ electric-vehicles/
38 http://www.siliconvalleypower.com/Home/Components/News/News/5036/2065
39 https: / / sonomacleanpower.org/ sonoma-clean-power-launches-ev-incentive-program/
40 https://www.sdge.com/residential/pay-bill/get-payment-bill-assistance/assistance-programs
Community Choice Energy Technical Feasibility Study 56
April 16, 2019 Item #4 Page 68 of 132
In addition, the Family Electric Rate Assistance {FERA} Program can provide a monthly discount
on electric bills. This program is designed for income-qualified households of three or more
persons. Finally, the California Department of Community Services and Development {CSD}
oversees a federal program, Low-income Home Energy Assistance Program {LIHEAP}, which
offers help for heating or cooling homes and help for weatherproofing homes.
At present, most California CCEs simply match their incumbent I0U's low-income programs, as
in the case of MCE and SCP. The Partners' CCE would provide the same support to low-income
customers as does SDG&E.
Economic Impacts in the Community
The analyses contained in this Study of forming a four-city CCE has focused only on the direct
economic effects of this formation. However, in addition to direct effects, indirect
microeconomic effects are also expected.
The indirect effects of creating a CCE include the effects of increased commerce and disposable
income. Within this Study, an input-output {10} analysis is undertaken to analyze these indirect
effects. The 10 model estimated the impact in the economy of forming a CCE that .would lead to
lower energy rates for the CCE customers. Three types of indirect impacts are analyzed in the 10
model. These are described below.
Local Investment -The CCE may choose to implement programs to incentivize investments in
local distributed energy resources {DER}. Partners in the CCE may choose to invest in local DER
generation projects. These resources can be behind the meter or community projects where
several customers participate in a centrally located project {e.g. "community solar"}. This
demand for local renewable resources would lead to an increase in the manufacturing and
installation of DER, and lead to an increase in employment in the related manufacturing and
construction sectors.
Increased Disposable Income -Establishing a CCE would lead to reduced customer rates for
energy, more disposable income for individuals, and greater revenues for businesses. These cost
savings would then lead to more investment by individuals and businesses for personal or
business purposes. This increase in spending would then lead to increased employment for
multiple sectors such as retail, construction, and manufacturing.
Environmental and Health Impacts -With the creation of a CCE, other non-commerce indirect
effects would occur. These may be environmental, such as improved air quality or improved
human health due to the CCE utilizing more renewable energy sources, versus continuing use of
traditional energy sources which may have a greater GHG footprint. While a change in GHG
emissions is not modeled directly in economic development models used in this Study, the
Community Choice Energy Technical Feasibility Study 57
April 16, 2019 Item #4 Page 69 of 132
reduction of these GHG emissions are captured in indirect effects projected by the models to the
extent that carbon prices are accounted for in the input-output matrix. 41
Input-Output Modeling (10 Modeling) -County-wide electric rate savings and growth in
manufacturing jobs and other energy intensive industries are expected to spur economic
development impacts. Exhibit 30 shows the effect $9 million in rate savings could have on the
County economy as estimated in the San Diego County IMPLAN model.42 The $9 million rate
savings represents the minimum annual bill savings projected to occur once the CCE has achieved
full operation if all of the Partner cities are included (SDG&E-Equivalent Renewable portfolio}.
The IMPLAN model is an 10 model that estimates impacts to an economy due to a change to
various inputs such as industry income, supply costs, or changes to labor and household income.
Both positive and negative impacts can be measured using 10 modeling. 10 modeling produces
results broken down into several categories. Each of these is described below:
■ Direct Effects -Increased purchases of inputs used to produce final goods and services
purchased by residents. Direct effects are the input values in an 10 model, or first round
effects.
■ Indirect Effects -Value of inputs used by firms affected by direct effects (inputs}. Economic
activity that supports direct effects.
■ Induced Effects -Results of Direct and Indirect effects (calculated using multipliers}.
Represents economic activity from household spending.
■ Total Effects -Sum of Direct, Indirect, and Induced effects.
■ Total Output -Value of all goods and services produced by industries.
■ Value Added -Total Output less value of inputs, or the Net Benefit/Impact to an economy.
■ Employment -Number of additional/reduced full time employment resulting from direct
effects.
This Study uses Value Added and Employment figures to represent the total additional economic
impact of the rate savings associated with CCE formation.
The projected rate savings are modeled for residential, commercial, industrial, and agricultural
sectors. For residential, the rate savings are modeled at different household income levels to
estimate the impact on the economy from reduced bills. Estimated household income
distribution is based on the income percentiles from the statistical atlas for San Diego County.43
41 Decreased health care costs have been modeled to make a major contribution to the local economy. e.g., DT
Shindel!, Y. Lee & G. Faluvegi, Climate and health impacts of US emissions reductions consistent with 2 °C; Nature
Climate Change volume 6, pages 503-507 (2016)
42 http://www.implan.com/
· 43 Statistical Atlas. San Diego, California. Available on line: https://statisticalatlas.com/county/California/San-
Diego-County/Household-lncome data from U.S. Census Bureau.
Community Choice Energy Technical Feasibility Study 58
April 16, 2019 Item #4 Page 70 of 132
and herbs. Major commercial and industrial industries include government, healthcare, retail,
manufacturing, construction, professional and scientific services, finance, accommodation and
food services, and wholesale trade.
Exhibit 32 details the macroeconomic impacts anticipated from the 2% savings in the generation
rate after forming the CCE. The total Value Added for one year of rate savings is estimated at $7.7
million. Finally, the rate savings are estimated to produce an additional 109 full time jobs.
Exhibit 32
$9 Million Rate Savings Effects on the San Diego County Economy1
Impact Type Employment Labor Income Total Value Added Output
Direct Effect 50.7 $2,473,000 $2,508,000 $4,613,000
Indirect Effect 10.7 $641,000 $1,039,000 $1,740,000
Induced Effect 47.4 $2,273,000 $4,146,000 $6,712,000
Total Effect 108.8 $5,387,000 $7,694,000 $13,065,000
1. Full impacts to San Diego county are estimated, it can be expected that a large share of these impacts
would be realized within the 4 jurisdictions.
These savings are based on the economic construct that households would spend some share of
the increased disposable income on more goods and services. This increased spending on goods
and services would then lead to producers either increasing the wages of their current employees
or hiring additional employees to handle the increased demand. This in turn would give the
employees a larger disposable income which they spend on goods and services and thus
repeating the cycle of increased demand. In addition, reduced inputs to production for non-
residential electric customers would allow companies to invest in other areas to promote growth
such as hiring new employees, offering additional training, and purchasing upgraded equipment.
Community Choice Energy Technical Feasibility Study 60
April 16, 2019 Item #4 Page 72 of 132
Exhibit 34
Comparison of Risks, Mitigation Strategies, and Risk Severity
Potential to ..
Risk Description Problem Mitigation Strategy Likelihood of Problem Severity of Problem "Suspend"
CCE
1 SDG&E Rates SDG&E's • CCE rates • Establish Rate Stabilization Fund High -most operating Medium -CCEs have Medium-
and generation rates exceed SDG&E • Invest in a balanced energy CCEs in California have been able to buffer rate depending
Surcharges decrease or its • Increased supply portfolio to remain agile in undergone short impacts using financial on the
non-bypassable customer opt-power market periods of rate reserves, then adjust outcome of
charges out rate • Emphasize the value of competition from the power supply to regain the PCIA
(PCIA/CTC) programs, local control, and incumbent IOU. ra.te advantage. proceeding,
increase environmental impact in CCEs may
marketing become
infeasible
2 Regulatory Energy policy is • New costs • Coordination with CCE Low-existing High -a worst-case Medium-
Risks enacted _that incurred community on regulatory regulatory precedent scenario regulatory energy
compromises CCE • Reduced involvement and a growing market legislative decision policy
competitiveness authority • Hire lobbyists and regulatory share makes the limiting CCE autonomy severe
or independence representatives to advocate for likelihood of state or enforcing additional enough to
CCE policies that severely costs could hinder CCE make CCE
disadvantage CCEs low. viability. infeasible is
not likely.
3 Power Supply Power prices • CCE rates • Long-term contracts Low -market prices are Medium - a poorly Low
Costs increase at crucial exceed SDG&E • Draw on CCE reserves to unlikely to spike enough timed price spike
time for CCE • Increased stabilize rates through price spike to make CCE financially combined with poor
customer opt-infeasible prior to CCE power supply contract
out rate launch. From that point management could
on, the CCE can limit its require CCE to dig into
·. exposure through reserves or delay launch.
contract selection.
4 SDG&E RPS SDG&E's RPS or Increased • Increase renewable power Medium..:. SDG&E's Low-CCE would have Very Low-
Share GHG-free power customer opt-portfolio power portfolio is capability to increase CCE is likely
portfolio grows to out rate • Emphasize rates and local ,dynamic and could renewable energy to respond
match or exceed programs in marketing change rapidly as a purchases to match or effectively if
CCE 's result of other CCE exceed SDG&E if the th is occurs.
departures. event occurs. In
Community Choice Energy Technical Feasibility Study 62
April 16, 2019 Item #4 Page 74 of 132
Potential to
Risk Description Problem Mitigation Strategy Likelihood of Problem Severity of Problem "Suspend"
CCE
" addition, CCE would
.. promote other benefits
of its service to
customers.
5 Availability of Unexpectedly • CCE unable • Shift emphasis to GHG-free or Low-power Medium -if CCE were Low-
RPS/GHG-high market to provide RPS resources depending on procurement providers unexpectedly unable to negligible
free power demand or loss of target power availability are projecting a procure enough RPS or chance of
supply of products • Secure long-term contracts plethora of RPS and GHG-free power, it occurring.
renewable • Invest in local renewable GHG-free bids available could emphasize other
resources -on the market. program strengths to resources
retain customers until
new resources came
online.
6 Financial CCE is unable to • Slower or • Adopt gradual program roll-out Low -CCEs have Medium -in the event Low
Risks acquire desired delayed • Establish Rate Stabilization Fund become sufficiently CCE is limited in
financing or credit program • Minimize overhead costs established in California, financing options, it can
launch such that financing is adopt a more
•· Unable to almost certainly conservative program
build available. design and gradual roll-
generation out.
projects
7 Loads and Unprecedented • Excess • Increase marketing Low -as CCEs have Low -CCE would have Low
customer opt-out rate power • Reduce overhead become more common numerous viable options
participation reduces contracts • Expand to new customer in California, and CCE in the event they suffer
competitiveness • Poor margins markets marketing firms more unexpectedly low
• Consider merging with existing experienced, opt-out participation.
CCE rates have gone lower. ---
Community Choice Energy Technical Feasibility Study 63
April 16, 2019 Item #4 Page 75 of 132
SDG&E Rates and Surcharges
Sensitivity analyses were conducted for two components of SDG&E rates. The delivery rates are
paid by both CCE and SDG&E bundled customers. As such, changes in delivery rates impact all
customers equally.
Generation Rate
SDG&E generation rates are projected to increase on average by 1% per year over the next 10
years based on the projected market prices, SDG&E's resource mix and renewable resource
growth rates. To explore the impact in the case that SDG&E's generation rate changes
significantly relative to the CCE's generation cost, SDG&E's generation rates was modeled in the
high and low case by incorporating higher and lower generation growth rates. This results in
SDG&E's power supply average annual growth rate in the high case of +2% and in the low case of
-2%.
PCIA
When legislation was introduced to allow the formation of CCEs, it was recognized that the IOUs
currently serving the potential CCE customers may face stranded generation costs. The PCIA
methodology was established by the CPUC as a means for IOUs to recover those stranded costs.
The PCIA faces several issues, however, including the source and transparency of data used for
the calculation and the fact that the PCIA level is variable and contains a great amount of
uncertainty.
The level of the PCIA, or other non-bypassable charge that will potentially replace the PCIA, would
impact the cost competitiveness of the Partners' CCE . In order to be competitive, the CCE's
power supply costs plus PCIA and other surcharges must be at or lower than SDG&E's generation
rates. Many factors influence the PCIA, but primarily the PCIA is determined by the cost of power
contracts and the cost to SDG&E of the departing load. Uncertainties surrounding the PCIA
include methodology assumptions unique to SDG&E, as well as to what degree previously
acquired power contracts can be retired. The potential for the PCIA to increase sharply occurs
when SDG&E must sell previously contracted power at times when wholesale power prices are
much lower. The PCIA also has potential to decrease since it reflects SDG&E's own resources and
signed contracts obtained prior to load departure; once those contracts expire, the related PCIA
would disappear. Therefore, over time the PCIA would vary, but it is expected that it would
decline as market prices increase and grandfathered contracts expire.
Forecasting the PCIA is difficult since key inputs are heavily redacted from the rate filings and
regulatory changes can significantly impact the PCIA. The uncertainty associated with forecast
PCIA rates is modeled considering historic PCIA increases as well as the adopted methodology
used for the PCIA calculation (October 11, 2018). In addition to the base case, a low and high
PCIA forecast are modeled. The low scenario is 10% lower than the forecasted assumption . In
Community Choice Energy Technical Feasibility Study 64
April 16, 2019 Item #4 Page 76 of 132
the high scenario, the PCIA increases by the full cap of $0.005/kWh in the first 2 years then de-
escalates at an average of 5% per year.
Regulatory Risks
There are numerous factors that could impact SDG&E's rates in addition to the market price
impacts described above. Regulatory changes, plant or technology retirements or additions, and
gas prices all can impact SDG&E's rates in the future. Regulatory issues continue to arise that
may impact the competitiveness of the Partners' CCE. The impact of these factors is difficult to
assess and model quantitatively. However, California's operating CCEs have worked aggressively
to address any potentially detrimental changes through effective lobbying at the California state
legislature and at the California Public Utilities Commission.
New legislation can also impact the Partners' CCE. For example, new legislation that recently
affected CCEs is SB 350. The CCE-specific changes reflected in SB 350 are generally positive,
providing for ongoing autonomy with regard to resource planning and procurement. CCEs must
be aware, however, of this legislation's long-term contracting requirement associated with
renewable energy procurement. Specifically, CCEs are required to contract 65% of renewable
resources for 10 years or more by 2020.
In addition, there is a risk that additional capacity resource costs are pushed onto CCEs via the
Cost Allocation Mechanism (CAM). The CCE would need to continually monitor and lobby at the
Federal, State and local levels to ensure fair and equitable treatment related to CCE charges.
Finally, SDG&E has asked lawmakers to introduce legislation (AB56) that would eventually result
in the IOU leaving the power supply business. SDG&E is faced with losing half of its customers as
the City of San Diego is poised to launch its CCE program. SDG&E is asking that the legislature
pass a bill that would create a way for the utility to sell long-term power contracts to a "state-
level electrical procurement entity." This entity could then re-sell the contracts to other buyers.
Any difference in price would then become a non-bypassable charge to former SDG&E bundled
customers. The non-bypassable charge would likely be similar to the PCIA/CTC and the PCIA/CTC
would no longer be in effect. Because the state-level procurement entity would be a public
agency, and be subject to a lower cost of capital, the new exit fee mechanism could result in
lower charges to electric customers. These lower charges would benefit CCE customers.
Power Supply Costs
Ramping services are predominantly provided by natural gas-fired generating resources. These
resources are capable of ramping generation levels up and down quickly to assure that resources
are equal to load requirements. Therefore, wholesale market prices are driven largely by natural
gas prices. In addition, the CCE's power supply mix has been modeled according to different
levels of renewable energy. Renewable energy costs are forecast for the base case; however,
several factors could influence future renewable energy costs including locational factors for new
Community Choice Energy Technical Feasibility Study 65
April 16, 2019 Item #4 Page 77 of 132
/
facilities, transmission costs, technology advancements, changes in state and federal renewable
energy incentives, or changes in California or neighboring state RPS.
Since resource costs are based on forecast wholesale market and renewable market prices, it is
prudent to look at the sensitivity of the 20-year levelized cost calculations to fluctuations in
projected prices. Exhibit 35 below shows a summary of low, mid-range, and high resource costs.
Exhibit 35
Power Supply Cost Sensitivity
SDG&E-
Equivalent 100%
Renewable Renewable by 100%
Case RPS Portfolio 2030 Renewable
Low Case 0.0535 0.0537 0.0566 0.0602
Mid-range 0.0746 0.0749 0.0765 0.0819
High Case 0.0993 0.0996 0.1014 0.1052
As discussed in the "Power Supply Strategy and Costs" section of this Study, the Mid-range
renewable energy costs are conservative in that they are greater than the cost of long-term
renewable PPAs currently being executed in the region. The Low Case renewable energy costs
are based on an assumption that the costs of renewable generating projects will, as expected,
continue to decline and the CCE would, over time, layer in PPAs sourced to the lower cost
renewable resources that will be developed over the next five to ten years. The High Case
renewable energy costs are based on an assumption that the CCE is not able to secure PPAs
sourced to relatively new and lower cost renewable resources but, rather, signs PPAs sourced to
older renewable resources with higher costs. The renewable costs in this case reflect the costs
of renewable resources that were developed three to five years or more ago.
The 20-year levelized costs of each portfolio has been calculated using the range of resource costs
shown above. The base case costs are depicted by the black dots in Exhibit 36, while the range
projected between the High Case and the Low Case are depicted by the blue bar.
Community Choice Energy Technical Feasibility Study 66
April 16, 2019 Item #4 Page 78 of 132
Exhibit 36
Sensitivity of Portfolio 20-year Levelized Costs $/kWh
0.120
0.100
0.080 --• •
..c s :::..: 0.060 ----<.I}
0.040
0.020
0.000
•
SDG&E-Equivalent Renewable 100% Renewables by 2030
Portfolio
100% Renewable
The 100% Renewable portfolio, which relies on the most renewable energy purchases to serve
retail load, has the highest projected costs that range from a low of $0.060/kWh to a high of
$0.0105/kWh. There is a low likelihood that renewable project costs would increase to the point
that 20-year levelized costs of renewable purchases is near $0.0100/kWh. It is far more likely
that decreases in solar equipment costs on a $/watt basis will continue. The 20-year levelized
costs associated with the renewable PPA alternative pricing discussed in the "Power Supply
Strategy and Costs" fall below the black dots and within the blue bars shown above in Exhibit 36.
While renewable energy costs continue to decline, the potential for market PPA price$ to increase
could be material. Wholesale market prices are depende,nt on many factors, the most notable
of which is natural gas price. Natural gas prices are at historic lows, and because natural gas-
fired resources are often the marginal resource in the market, wholesale market prices have
followed. Natural gas prices are subject to a variety of local, national and international forces
that could have a large impact on the current marketplace. For example, increased regulation in
the natural gas industry with respect to the deployment of fracking technology could cause
decreases in natural gas supplies and commensurate increases in natural gas prices. Additionally,
increased costs associated with carbon taxes and/or carbon cap and trade programs could also
cause upward pressure on wholesale market prices.
Community Choice Energy Technical Feasibility Study 67
April 16, 2019 Item #4 Page 79 of 132
SDG&E RPS Portfolio
There are several factors that may impact the share of renewable energy in SDG&E's portfolio
over the next decade. Customers departing SDG&E for CCE service throughout SDG&E territory
would have the effect of shrinking SDG&E's load, thereby increasing the share of renewables
made up by SDG&E's current RPS contracts. Finally, SDG&E could further strive to compete with
CCEs in terms of the environmental impact of its pow_er portfolio. In combination, these forces
could drive up the share of renewable energy in SDG&E's power mix to match or exceed the CCE's
planned power mix. To mitigate this risk, the CCE would have the option to acquire more
renewable energy in response to changes in SDG&E's portfolio.
Availability of Renewable and GHG-Free Resources
Often one of the goals of a CCE is to offer power products that are cleaner than those provided
by the IOU. All of the portfolios developed for this Study are modeled at 80% to 100% GHG-free.
As such, they include more renewable resources and exceed the share of GHG-free resources in
SDG&E's power supply portfolio, which is in the 40% to 50% range.
SDG&E does offer additional renewable choice to customers. EcoChoice allows the customer to
sign up for "50% to 100% renewable power" as shown in Exhibit 37.45 This program is currently
closed to commercial customers. EcoChoice has a minimum 1-year enrollment term and charges
an exit fee if the customer decides to cancel participation. EcoChoice currently results in a
discount off SDG&E's standard rate, because new renewable resources are cheaper than the
existing resources committed to by SDG&E. However, the EcoChoice customer will have to pay
the PCIA as would CCE customers.
Exhibit 37
EcoChoice Rates (Updated 01/01/2018)
Small M/L Commercial Street
Residential Commercial and Industrial Agriculture Lighting
Rate Component ($/kWh) ($/kWh) ($/kWh) ($/kWh) ($/kWh)
Renewable Power Rate &
Program Costs & Transmission 0.07763 0.07763 0.07763 0.07763 0.07763
SDG&E's Average Commodity
Cost Adjustment (0.10138) (0.09934) (0.09943) (0.08293) (0.06691)
EcoChoice Differential {0.02375) (0.02171) (0.02180) (0.00530) 0.01072
PCIA 0.02267 0.02326 0.01810 0.01282 0.00000
Total Cost (0.00108) 0.00155 (0.00370) 0.00752 0.01072
For residential customers, the discount per kWh for participating in EcoChoice is $0.02375 per
kWh. However, after applying the PCIA, this discount is reduced to $0.00108 per kWh. The
45 https://www.sdge.com/residential/savings-center/solar-power-renewable-energy/ecochoice
Community Choice Energy Technical Feasibility Study 68
April 16, 2019 Item #4 Page 80 of 132
results for SDG&E's EcoChoice program over time are anticipated to be similar to the estimated
cost for the 100% renewable product from the CCE because any PCIA changes will impact both
the CCE and the EcoChoice programs. While the current estimate for the 80% renewable
program indicates that the cost will be 2% below SDG&E standard generation rate for all
customers, the 100% renewable program is at parity with the standard SDG&E rate. Changes in
the PCIA will impact the EcoChoice program and likely result in EcoChoice rates that are above
SDG&E rates for all rate classes.
SDG&E's EcoShare program allows the customer to contract directly with a renewable project
developer and purchase the rights to a portion of the output from a new local renewable
generating facility. Customers participating in EcoShare will receive a credit on their SDG&E bill
reflecting the amount of renewable energy purchased through the developer. In addition, the
customer pays the PCIA and other program costs, such as the administrative costs.
The primary risk associated with a high renewable resource strategy is lack of sufficient
renewable resources at prices that would keep the CCE competitive with SDG&E. The current
market has sufficient renewable resources available. Utilities that submit requests for renewable
power supply receive bids that far exceed the requested amounts at prices that are very
competitive to non-renewable market resources. As RPS requirements and the share of
renewable resources in CCE portfolios are increasing, competition fqr renewable resources could
increase. However, it is important to note that the CCE movement does not change the total
load. Rather, the renewable resource timeline may just have accelerated until targets have been
reached. Increased competition would result in increased prices once supply cannot meet the
demand, resulting in increased development of renewable resources. In addition, the CCEs
would have the opportunity to aid in the development of renewable resources by fostering local
resource development.
Financial Risks
Starting a new venture carries financial risks that will have to be considered and mitigated before
proceeding with a CCE. Depending on the organization structure, a third-party may take on the
financial obligations of the CCE. These include establishing start-up financing, working capital
funding such as lines of credit, and entering into contracts with suppliers and consultants. Other
cities and counties have protected their General Funds by establishing JPAs or lockbox
arrangements with vendors.
The Partner cities could manage many of the financial risks associated with the uncertainty
surrounding a CCE start-up. While the goal is to provide clean power competitively with SDG&E,
the most important consideration to the third-party financer is that the CCE can increase rates if
needed to ensure sufficient revenues are collected to meet costs. In addition, the CCE can plan
carefully by minimizing staff initially and only growing as fast as the size of the CCE can support,
thus minimizing the fixed costs of operating the CCE.
Community Choice Energy Technical Feasibility Study 69
April 16, 2019 Item #4 Page 81 of 132
The Partners' CCE would need to manage the financial risk associated with power supply costs
by managing power market and load exposure through prudent hedging and power portfolio
management. In addition, the establishment of rate stabilization reserves and sufficient working
capital can mitigate financial risks to the third-party financer and to customers. The success of
existing CCEs in managing the financial challenges of a CCE start-up and setting rates that are
competitive with the SDG&E and the other IOUs can be a valuable guide for the Partners' CCE .
Loads and Customer Participation Rates
The Study bases the load forecasts on expected load growth, load profiles, and participation
rates. In order to evaluate the potential impact of varying loads, low, medium, and high load
forecasts have been developed for the sensitivity analysis.
Another assumption that can impact the costs of the CCE is the overall CCE customer
participation rates. This Study uses a conservative participation rate of 95% for residential
customers and 85% for non-residential customers as its base case. A higher participation rate,
such as has been experienced by all of California's operating CCEs to date, would increase energy
sales relative to the base case and decrease the fixed costs paid by each customer. On the other
hand, a reduced participation rate would increase the fixed costs to the CCE Partners. For
reference, recent CCEs have experienced participation rates in the 90-97% range.
· Sensitivity to changes in projected loads has been tested for the high and low load forecast
scenarios. For the sensitivity analysis, the high case assumes an additional 5% participation rate
for non-residential customers, while the low case assumes the participation rate is reduced by
10% for all customers. The low case assumes a 0% growth in energy and customers after 2019,
while the high scenario assumes a 1% growth in energy and customers.
The experience of existing CCEs suggest that only a small number of customers opt-out. For
example, PCE has an opt-out rate of 2%, while CPA has a current opt-out rate of 0.7%. Once a
CCE is operating, the number of customers switching back to the incumbent IOU have also been
less than 5%. In order to mitigate the potential switching of customers, it would be important
for the CCE to implement prudent power supply strategies to address potential load swings from
changes in participation and weather uncertainty, plus establish a rate stabilization fund.
Keeping rates low as well as providing excellent customer service would lead to strong customer
retention.
Sensitivity Results
Exhibit 38 provides the results of the sensitivity analysis for the SDG&E Equivalent Renewable
Portfolio (Base Case), which is the most likely portfolio for the CCE to pursue initially given its
goals.
Community Choice Energy Technical Feasibility Study 70
April 16, 2019 Item #4 Page 82 of 132
operating CCEs, which is closer to 5% overall. While there is a possibility that the Partners' CCE
does not reach the projected participation rates, careful monitoring and planning can reduce the
potential impact of low loads through flexible power supply contracts and regular monitoring of
administrative and general expenses.
The CCE should also consider implementing a rate stabilization fund so that short-term events
that result in lower SDG&E rates compared with the CCE rates can be mitigated with reserves
rather than by rate increases. Reserves would help the CCE remain competitive and would
provide rate stabilization for customers.
Community Choice Energy Technical Feasibility Study 72
April 16, 2019 Item #4 Page 84 of 132
CCE Governance Options
One indicator of the viability of a CCE for the Partners is the number of Various options for CCE
operations for each of the cities that participated in this Study are described below. The following
criteria are used to describe strengths and weaknesses of each option: Financial Viability,
Governance, Local Control, and Other Attributes.
1. Form a Joint Powers Authority (JPA) with Each of the Partners Joining
■ Financial Viability: This Study shows that a 4-member JPA is financially viable.
■ Governance: Under a JPA, likely each city would be a voting board member. Having a
limited number of board members keeps governance nimble and local/regional control
focused.
■ Local Control: Since the Partners have similar climate action goals, and collaborated on
this Study for similar purposes, decisions around the CCE's operations should be less
complicated. Decisions about wholesale power portfolio, rate designs, local distributed
generation, and customer clean energy programs should be easier to make.
■ Other Attributes: A JPA of this size is ideal for allowing other San Diego County cities that
create their own CCEs to join. Consideration of consistent goals, local programs and
operations design should be considered for new CCE cities. Operational savings on non-
power supply costs (administration, legal, regulatory, and other services) would likely
occur. A JPA provides clear financial protection of cities' general funds from CCE
obligations. A JPA could apply to the CPUC for energy efficiency program funds on behalf
of the cities.
2. Each City Forms Individual CCE
■ Financial Viability: This is likely viable for each city except Del Mar. EES has analyzed this
option and has financial pro-forma results for this including combinations of cities
operating together under a smaller JPA.
■ Governance: A single or smaller JPA creates less complicated governance.
■ Local Control: Decision-making is more locally focused.
■ Other Attributes: Solana Beach, Pico Rivera, San Jacinto, and King City are examples of
smaller city CCEs that are operating independently; although Pico Rivera and San Jacinto
participate in the California Choice Energy Authority (described below) to share non-
power costs with other individual city CCEs. Except for Del Mar, individual city CCEs are
likely feasible but net revenue margins will be smaller without sharing non-power supply
costs with others. Operating a city CCE requires special care to protect the city's general
fund from CCE obligations. Individual city CCEs may apply to the CPUC for energy
efficiency funding but the amount will be less than a CCE JPA.
Community Choice Energy Technical Feasibility Study 73
April 16, 2019 Item #4 Page 85 of 132
3. The Partners Join Another CCE
■ Financial Viability: This option would be financially viable and would benefit the net
revenue margins for the larger CCE organization.
■ Governance: Governance would be more complicated, especially if the Partners join a
CCE JPA with many members. However, there are CCEs that operate with many members
across contiguous and non-contiguous borders (Clean Power Alliance of Southern CA,
Marin Clean Energy, Sonoma Clean Power) despite having large governing boards.
■ Local Control: Local decision-making on operations (power portfolio contents, rates, local
generation, customer programs) would be diminished, especially under a CCE JPA with
many members (e.g., 20-30 or more). Boards of these types of JPAs must approve
operations policies and program decisions that could apply across differing communities:
■ Other Attributes: Net revenue margins for the organization as a whole benefit from large
memberships. How those revenues are utilized to benefit members must be determined
by many cities, likely with differing local goals regarding CCE operations. A larger JPA of
CCEs could apply for larger amounts energy efficiency funds but the design of the
programs becomes more complicated.
'
The cities could conceivably join the already operating Solana Beach CCE. Solana is a fraction of
the size of the Partners in terms of load, and this may create complications in negotiating the
roles of each of the cities, sharing of revenues and costs, and other decision-making issues.
4. The Partners Join a JPA of Individual CCEs or Create a San Diego Region JPA of Individual CCEs
■ Financial Viability: Any group of CCEs is more financially viable than operating
individually.
■ Governance: The California Choice Energy Authority (CCEA) is a JPA of individual city CCEs
(currently members are Lancaster, Pico Rivera, San Jacinto, and Palm Desert -they have
6 other cities in process of joining them including a city in Tulare County). Individual cities
need to adopt resolutions to become a CCE, then they can join CCEA. CCEA provides
centralized services such as: power procurement, power scheduling and dispatching, bill
data management and regulatory/legal services. Since each city is a CCE, decisions on
CCE operations are made by each CCE. The Partners could also create a CCEA-type JPA
for San Diego-region CCEs and provide similar, centralized services and benefits.
■ Local Control: CCEs that join CCEA (or create a San Diego-region similar organization)
retain local control over CCE operations (power portfolio mix, rates, local generation and
programs) and will see net revenue benefits by sharing centralized services. However,
the details of how these shared services are utilized and paid for need to be determined
(in the case of CCEA) and developed (in the case of a San Diego-region effort).
■ Other Attributes: Creating a San Diego-region JPA of CCEs makes it easier for San Diego-
region cities to become a CCE in that acquiring start-up and operational services support
would already be established under the JPA. Each city CCE in the JPA could apply for
energy efficiency funding at the CPUC.
Community Choice Energy Technical Feasibility Study 74
April 16, 2019 Item #4 Page 86 of 132
Recommendation
As the Partners move towards CCE adoption by their governing organizations, or after the cities
approve creating a CCE, they should further investigate each of these options. EES recommends
that the cities further discuss the options among themselves to more clearly understand all of
the pros and cons. The cities should develop a more detailed assessment of the options of joining
existing organizations or developing new, local/regional organizations. The cities could develop
a solicitation to distribute to existing CCE organizations to acquire information about costs and
other requirements for joining these organizations. That information should then be compared
to potential costs and requirements of creating a new, local/regional CCE organization. If joining
another CCE is the preferred option for the Partners, a request for proposal (RFP) should be
issued to each potential existing CCE to define the terms of joining an existing CCE.
This Study evaluates the feasibility of operating a CCE under the JPA model with the four Partner
cities. The financial sensitivity analysis provided in Appendix H also provides feasibility results for
each Partner city operating their own CCE. If the Partners join an existing JPA, the start-up
activities are simpler as the organization is already operating and programs have been developed.
However, the overall governance issues would have to be established prior to the cities joining
the existing CCE.
CCE Organizational Options
If the Partners operate as a JPA there are several staffing options available. One option would
be to operate the CCE with minimal staff, such as a General Manager, Power Supply Manager
and a Customer Service Manager, to oversee consultants that would perform all necessary tasks.
Another option is to minimize the use of outside consultants and hire sufficient staff in-house to
manage all necessary tasks. Most operating CCEs have started with minimal staffing and then
transitioned over time to additional staff in-house. A third option is to have an independent
third-party completely operate the CCE .
For this Study, it is assumed that the Partners would operate a CCE with limited staff supported
by consultants experienced in power procurement, data management and utility operations. If
the Partners decide to transition some administrative and operational responsibilities to
internally staffed positions, the CCE could reach a full-time staff of approximately 11 employees
to perform its responsibilities, primarily related to program and contract management, legal and
regulatory, finance and accounting, energy efficiency, marketing and customer service. Technical
functions associated with managing and scheduling power suppliers and those related to retail
customer billings would likely still be performed by an experienced third-party consultant.
Community Choice Energy Technical Feasibility Study 75
April 16, 2019 Item #4 Page 87 of 132
Conclusions and Recommendations
Rate Conclusions
The first impact associated with forming the Partners' CCE would be lower electricity bills for CCE
customers. CCE customers should see no obvious changes in electric service other than the lower
price and potentially more renewable power procurement, depending on the CCE's goals.
Customers would pay the power supply charges set by the CCE and no longer pay the costs of
SDG&E power supply but would still pay the costs of SDG&E distribution.
Given this Study's findings, the CCE's rate setting ca,n establish a goal of providing rates that are
equal to or lower than the equivalent rates offered by SDG&E even under the 100% Renewable
by 2030 portfolio. The projected CCE and SDG&E rates are illustrated in Exhibit 39.
Rate Class
Residential
Small Commercial
Medium Commercial
Street Lights
Agriculture
Total
Exhibit 39
Bundled Rate Comparison by Customer Class
$/kWh
SDG&E
2021 SDG&E Renewable
Bundled Equivalent 100% by 2030
Rate* Bundled Rate Bundled Rate
0.3494 0.3480 0.3480
0.2233 0.2317 0.2317
0.2303 0.2203 0.2203
0.2388 0.2390 0.2390
0.1322 0.1325 0.1325
0.2854 0.2797 0.2797
Initial Rate Savings in 2021 from 2.00% 2.00%
SDG&E Bundled Rate
*SDG&E bundled average rate projected based on SDG&E's 2019 Rates,
100%
Renewable
Bundled Rate
0.3494
0.2233
0.2303
0.2388
0.1322
0.2854
0.00%
Once the CCE gives notice to SDG&E that it will commence service, the CCE customers will not be
responsible for costs associated with SDG&E's future electricity procurement contracts or power
plant investments.46 This is an advantage to the CCE customers as they would then have local
control of power supply costs through the CCE.
46 CCAs may be liable for a share of unbundled stranded costs from new generation but would then receive
associated Resource Adequacy credits,
Community Choice Energy Technical Feasibility Study 76
April 16, 2019 Item #4 Page 88 of 132
Renewable Energy Conclusions
A second consequence of forming a CCE would be an increase in the proportion of energy
generated and supplied by renewable resources. The Study includes procurement of renewable
energy sufficient to meet 50% or more of the CCE's electricity needs {initially}. The majority of
this renewable energy would be met by new renewable resources over time. By 2030, SDG&E
must procure a minimum of 60% of its customers' annual electricity usage from renewable
resources due to the State Renewable Portfolio Standard and the Energy Action Plan
requirements of the CPUC. The CCE can decide whether to follow the same renewable goals or
to implement more aggressive targets.
Energy Efficiency Conclusions
A third consequence of forming a CCE would be an increase in energy efficiency program
investments and activities. The existing energy efficiency programs administered by SDG&E are
not expected to change as a result of forming a CCE. The CCE customers would continue to pay
the public goods charges to SDG&E which funds energy efficiency programs for all customers,
regardless of supplier. The energy efficiency programs ultimately planned for the CCE would be
in addition to the level of investmentthat would continue in the absence of a CCE. Thus, the CCE
has the potential for increased energy investment and savings with an attendant further
reduction in emissions due to expanded energy efficiency programs.
Economic Development Conclusions
The fourth consequence of forming a CCE would be enhanced local economic development. The
analyses contained in this Study has focused primarily on the direct effects of this formation.
However, in addition to direct effects, indirect economic effects are also anticipated. The indirect
effects of creating a CCE include the effects of increased local investments, increased disposable
income due to bill savings, and improved environmental and health conditions.
Exhibit 40 shows the effects $9 million in electric bill savings could have in San Diego County. The
$9 million rate savings represents the estimated {maximum} bill savings per year achievable by
the CCE once in full operation. It is estimated that the electric bill savings could create
approximately 109 additional jobs in the County with over $5.4 million in labor income. It is also
projected that the total value added could be approximately $7.7 million and output close to $13
million.
Community Choice Energy Technical Feasibility Study 77
April 16, 2019 Item #4 Page 89 of 132
Exhibit 40
$9 Million Rate Savings Effects on the San Diego County Economy1
Impact Type Employment Labor Income Total Value Added Output Jobs
Direct Effect 50.7 $2,473,000 $2,508,000 $4,613,000
Indirect Effect 10.7 $641,000 $1,039,000 $1,740,000
Induced Effect 47.4 $2,273,000 $4,146,000 $6,712,000
Total Effect 108.8 $5,387,000 $7,694,000 $13,065,000
1Full impacts to San Diego County are estimated, it can be expected that a large share of these impacts
would be realized within the 4 jurisdictions.
These savings are based on the economic assumption that households would spend some share
of the increased disposable income on more goods and services. This increased spending on
goods and services would then lead to producers either increasing the wages of their current
employees or hiring additional employees to handle the increased demand. This in turn would
give the employees a larger disposable income which they spend on goods and services and thus
repeating the cycle of increased demand.
Greenhouse Gas (GHG) Emissions Conclusions
A fifth consequence of forming a CCE may be reduced GHG emissions. The amount of renewable
power in SDG&E's power supply portfolio is 43% and will rise to 60% by 2030. Based on power
supply strategy described previously, the estimated GHG emission reductions are forecast to
range from zero to 36,000 tons C02e per year by 2030 assuming a 60% RPS target is achieved.
The baseline for comparison is the SDG&E's portfolio resource mix versus the potential CCE
resource mixes. Exhibit 41 details these reductions.
Exhibit 41
Comparison of Average Annual GHG Emissions from Electricity, by Resource Portfolio {2021-2030)
SDG&E 100% Equivalent Renewable 100% SDG&E Renewable by 2030 Renewable
Portfolio
Avg./GHG Share 80% 89% 100% 60%
Avg. Emissions (Metric Tons CO2) 109,000 61,000 -218,000 ·
Difference SDG&E 50% Portfolio (Metric Tons CO2) 109,000 157,000 218,000
Findings and Conclusions
Based on the analysis conducted in this Study, the following findings and conclusions are made:
■ The formation of a CCE is financially feasible and could yield considerable benefits for all
participating residents and businesses.
Community Choice Energy Technical Feasibility Study 78
April 16, 2019 Item #4 Page 90 of 132
■ Financial benefits include electric retail rates that are 2% lower compared with SDG&E rates.
■ Benefits are also achieved through local decision-making about power supply, rates and
customer programs. Specific programs could include economic development incentives, and
targeted energy efficiency and demand response programs. CCE start-up costs could be fully
recovered within the first three years of CCE operations.
■ After this cost recovery, revenues that exceed costs could be used to finance a rate
stabilization fund, new local renewable resources, economic development projects and/or
lower customer electric rates.
■ The sensitivity analysis shows that the ranges of prices for different market conditions will for
the most part not negatively impact CCE rates compared to SDG&E rates. Where negative
impacts may exist, those risks can be mitigated
■ The CCE could be a means to achieve local control of energy supply, and for cities to· meet
their respective Climate Action Plan (CAP) goals.
■ Local electric rate savings are expected to stimulate economic development.
The positive impacts on the Partner cities and their citizens of forming a CCE suggest that CCE
implementation should be considered with the following next steps: consideration of Joint
Powers Authority or other governance options, Business Plan development, and Implementation
Plan development. No likely combination of sensitivities would change this recommendation
based on the detailed analysis contained in the balance of this report.
Recommendations
Based on the Study results, and recent CCE experience, the following recommendations are made
pursuant of CCE formation:
■ The CCE should initially contract with a third party with the necessary experience (proven
track record, longevity and financial capacity) to perform most of the CCE's portfolio power
supply operation requirements. This would include the procurement of energy and ancillary
services, scheduling coordinator services, and day-ahead and real-time trading.
■ The Partners' CCE should approve and adopt a set of protocols that would serve as the risk
management tools for the CCE and any third-party involved in the CCE portfolio operations.
Protocols would define risk management policies and procedures, and a process for ensuring
compliance throughout the CCE. During the initial start-up period, the chosen electric
suppliers would bear the majority of risks and be responsible for their management. The
protocols that cover electricity procurement activities should be developed before
operations begin.
■ The CCE should be flexible in its approach to obtaining power supply resources necessary to
meet load requirements.
■ Additionally, it is recommended that the · Partners engage with a portfolio manager or
schedule coordinator, who has expertise in risk management and would work with the CCE
to design a comprehensive risk management strategy for long-term operations.
Community Choice Energy Technical Feasibility Study 79
April 16, 2019 Item #4 Page 91 of 132
Summary
This Study concludes that the formation of a CCE in the Partner cities is financially feasible and
could yield considerable benefits for all participating residents and businesses. These benefits
could include 2% lower rates for electricity, although higher rate reductions are possible. The
positive impacts on the Partner cities and their inhabitants of forming a CCE suggest that this
effort should be considered. No likely combination of sensitivities or launch schedules would
change this recommendation based on a detailed analysis of currently available data.
Community Choice Energy Technical Feasibility Study 80
April 16, 2019 Item #4 Page 92 of 132
Appendix A -Projected Schedule
2019 2020 2021
Task Due Date Jan Feb Mar Apr Ma~ Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr Ma1 Jun Jul Aug Sep Oct Nov Dec Jan Feb !Mar !Apr May
Feasibility Report .. _ ~inal 12.'aft Rep~~ _ _ __ --· _ 2(_1/2019 - -----. ------"-----·-------··-··---· ·---··· ·---t-----I CCA Ad Hoc Cou"!_ci~u~9mmittee ~eetin~ 2/15/2019 ----.. -Council Presentations -•----· -••·•·• ..... ,.,_. -.. --·. --· -Carlsbad 2/;5/2019 .. -. -
-Del Mar -2/15/301'} ---Encinitas 2/15/2019 --Oceanside 2/15/2019 I --->---
~··
-•· -~ulJ_lic Workshops __ _ __ ----_4/!?/20!9 --· ---··---·------1··"' ·-· ----~ ··---1--:---Ordinance Approval of Ordinance and Resolution to Create CCA 7/15/2019
FormJPA 9/1/2019 I
Organizational Setu ' I
Hire Executive Director 1/1/2020 I
Hire Staff 6/1/2020 ,;
Prepare Implementation Plan 1/1/2020
File Implementation Plan with CPUC 1/1/2020 IJim.i CPUC Registration CPUC completes review of IP 4/1/2020
Register with CPUC and submit Bond 4/1/2020 l!ill:i
CPUC confirms registration 5/1/2020 !!le.'.
File Historic load Data with CPUC/CEC 3/17/2020 :-::,, I
File Vear-Ahead load Forecast 4/20/2020 ~~-Resource Adequacy Revised Year-Ahead RA load Forecast 8/16/2020 •.•;. ;
January Month-Ahead RA load Forecast Due 10/15/2020 ,,.,. '
RFP & Contract for Scheduling Coordinator/Portfolio Mn1 7/1/2020
Power Procuremen Develop risk manaeemen.t and procurement olan 9/1/2020 -~.i.' !l<
Power Purchase and Contracting 1/1/2021 ::;._
RFP & Contract for line of Credit 8/1/2020 '
Banking & Credit Finalize financial Plan and Rates 10/1/2020 ~~i-
Transaction Testing with SDG&E 12/1/2020 r.Ja r;A!i1
RFP & Contract for Data Mgmt, Billing, Call Cntr, and Mrkt 8/1/2020 ~ I I
Systems Testing with SDG&E 10/1/2020 ;
CCA Website Finalized 11/1/2020
Call Center and CRM Operational 12/1/2020 ~ I
Pre-Enrollment Notice 1 1/1/2021 I
Customer Noticing Pre-Enrollment Notice 2 2/1/2021 ,a',:.~
Customer Program Transitions Notice 3/1/2021 1.··-.. ,il
Program Launch 4/1/2021 I t-:.:.
Post-Enrollment Notice 1 4/8/2021 "'"' Post-Enrollment Notice 2 5/10/2021
Community Choice Energy Technical Feasibility Study 81
April 16, 2019 Item #4 Page 93 of 132
Appendix B -Base Case Pro Forma Analyses
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Revenues from Operations($)
Electric Sales Revenues for CCE $0 $103,669,449 $122,617,248 $124,078,350 $125,132,767 $130,672,694 $132,248,045 $134,277,370 $137,196,482 $139,278,617 $141,386,518
less Uncollected Accounts $0 $156,443 $210,561 $211,317 $219,715 $229,652 $237,538 $245,904 $254,402 $263,259 $272,040
Total Revenues for CCE $0 $103,513,007 $122,406,687 $123,867,032 $124,913,052 $130,443,042 $132,010,508 $134,031,466 $136,942,080 $139,015,358 $141,114,479
Cost of Operations ($)
Cost of Energy $0 $71,307,923 $97,889,416 $101,399,614 $105,499,743 $110,372,197 $114,270,084 $118,369,961 $122,514,027 $126,840,341 $131,178,658
Operat;ng & Administrative
Billing & Data Management $0 $1,725,312 $2,351,577 $2,404,605 $2,458,829 $2,514,275 $2,570,972 $2,628,947 $2,688,230 $2,748,850 $2,810,836
SDG&E Fees $0 $389,033 $390,006 $390,981 $391,958 $392,938 $393,921 $394,906 $395,893 $396,883 $397,875
SDG&E Setup and Startup Fees $0 $180,308 $183,908 $0 $0 $0 $0 $0 $0 $0 $0
Consulting Services $426,700 $1,617,822 $1,411,407 $1,439,635 $1,468,427 $1,497,796 $1,527,752 $1,558,307 $1,589,473 $1,621,263 $1,653,688
Staffing $389,299 $2,204,114 $2,248,196 $2,293,160 $2,339,023 $2,385,804 $2,433,520 $2,482,190 $2,531,834 $2,582,471 $2,634,120
General & Administrative expenses $28,560 $181,030 $132,651 $135,304 $158,410 $177,184 $143,586 $146,457 $169,787 $188,788 $155,422
Debt Service Payment on Flnanci ng $114,607 $2,521,353 $3,208,995 $0 $0 $0 $0 $0 $0 $0 $0
Total O&A Costs $959,166 $8,818,973 $9,926,740 $6,663,685 $6,816,648 $6,967,997 $7,069,750 $7,210,808 $7,375,217 $7,538,254 $7,651,941
Total Cost & Reserves $959,166 $80,126,896 $107,816,156 $108,063,299 $112,316,391 $117,340,195 $121,339,834 $125,580,768 $129,889,243 $134,378,595 $138,830,598
Net Income from Opereations ($959,166) $23,386,111 $14,590,531 $15,803,733 $12,596,662 $13,102,847 $10,670,674 $8,450,698 $7,052,837 $4,636,763 $2,283,880
Cash from Operations and Financing
Net Income from Operations ($959,166) $23,386,111 $14,590,531 $15,803,733 $12,596,662 $13,102,847 $10,670,674 $8,450,698 $7,052,837 $4,636,763 $2,283,880
Cash from Financing $2,000,000 $12,000,000 $0 $0 $0 $0 $0 $0 $0 $0 $0
Total Cash Available $1,040,834 $35,386,111 $14,590,531 $15,803,733 $12,596,662 $13,102,847 $10,670,674 $8,450,698 $7,052,837 $4,636,763 $2,283,880
Net Income Allocation
Reserve Fund Contribution $1,040,834 $35,386,111 ($980,537) $81,252 $1,398,277 $1,651,662 $1,314,950 $1,394,280 $1,416,485 $1,475,951 $1,463,672
Working Capital Repayment $0 $□ $0 $9,133,372 $ □ $0 $0 $0 $0 $0 $0
Cash Available for Other Purposes $0 $0 $15,571,068 $6,589,109 $11,198,385 $11,451,185 $9,355,724 $7,056,418 $5,636,352 $3,160,811 $820,208
Total Cash Outlays $0 $0 $15,571,068 $15,722,481 $11,198,385 $11,451,185 $9,355,724 $7,056,418 $5,636,352 $3,160,811 $820,208
Rate Stabilization Reserve Balance $1,040,834 $36,426,945 $35,446,407 $35,527,660 $36,925,937 $38,577,598 $39,892,548 $41,286,828 $42,703,313 $44,179,264 $45,642,936
CCATotal Bill $0 $333,111,892 $429,074,010 $437,061,464 $445,207,892 $457,553,598 $466,078,566 $474,773,317 $483,641,397 $492,686,431 $501,912,120
SDG&ETotal Bil l $0 $339,910,094 $437,830,622 $445,981,086 $454,293,767 $466,891,426 $475,590,374 $484,462,568 $493,511,629 $502,741,256 $512,155,224
Difference $0 $6,798,202 $8,756,612 $8,919,622 $9,085,875 $9,337,829 $9,511,807 $9,689,251 $9,870,233 $10,054,825 $10,243,104
Savings 0% 2% 2% 2% 2% 2% 2% 2% 2% 2% 2%
Community Choice Energy Technical Feasibility Study 82
April 16, 2019 Item #4 Page 94 of 132
Appendix C -Renewable PPA Alternative Pricing Pro Forma Analyses
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Revenues from Operations($)
Electric Sales Revenues for CCE $0 $103,669,449 $122,617,248 $124,078,350 $125,132,767 $130,672,694 $132,248,045 $134,277,370 $137,196,482 $139,278,617 $141,386,518
Less Uncollected Accounts $0 $154,366 $210,561 $200,483 $210,206 $218,689 $223,199 $227,337 $233,100 $236,974 $240,834
Total Revenues for CCE $0 $103,515,084 $122,406,687 $123,877,866 $124,922,561 $130,454,005 $132,024,846 $134,050,033 $136,963,382 $139,041,643 $141,145,685
Cost of Operations($)
Cost of Energy $0 $70,269,484 $97,889,229 $95,982,511 $100,745,330 $104,890,559 $107,100,833 $109,086,432 $111,863,188 $113,697,630 $115,575,738
Operating & Administrative
Billing & Data Management $0 $1,725,312 $2,351,577 $2,404,605 $2,458,829 $2,514,275 $2,570,972 $2,628,947 $2,688,230 $2,748,850 $2,810,836
SDG&E Fees $0 $389,033 $390,006 $390,981 $391,958 $392,938 $393,921 $394,906 $395,893 $396,883 $397,875
SDG&ESetup and Startup Fees $0 $180,308 $183,908 $0 $0 $0 $0 $0 $0 $0 $0
Consulting Services $426,700 $1,617,822 $1,411,407 $1,439,635 $1,468,427 $1,497,796 $1,527,752 $1,558,307 $1,589,473 $1,621,263 $1,653,688
Staffing $389,299 $2,204,114 $2,248,196 $2,293,160 $2,339,023 $2,385,804 $2,433,520 $2,482,190 $2,531,834 $2,582,471 $2,634,120
General & Administrative expenses $28,560 $181,030 $132,651 $135,304 $158,410 $177,184 $143,586 $146,457 $169,787 $188,788 $155,422
Debt Service Payment on Financing $114,607 $2,521,353 $3,208,995 $0 $0 $0 $0 $0 $0 $0 $0
Total O&A Costs $959,166 $8,818,973 $9,926,740 $6,663,685 $6,816,648 $6,967,997 $7,069,750 $7,210,808 $7,375,217 $7,538,254 $7,651,941
Total Cost of Operations $959,166 $79,088,457 $107,815,969 $102,646,196 $107,561,977 $111,858,556 $114,170,583 $116,297,239 $119,238,404 $121,235,884 $123,227,679
Net Income from Opereations ($959,166) $24,426,627 $14,590,718 $21,231,671 $17,360,584 $18,595,449 $17,854,263 $17,752,794 $17,724,978 $17,805,760 $17,918,006
Cash from Operations and Financing
Net Income from Operations ($959,166) $24,426,627 $14,590,718 $21,231,671 $17,360,584 $18,595,449 $17,854,263 $17,752,794 $17,724,978 $17,805,760 $17,918,006
Cash from Financing $2,000,000 $12,000,000 $0 $0 $0 $0 $0 $0 $0 $0 $0
Total Cash Available $1,040,834 $36,426,627 $14,590,718 $21,231,671 $17,360,584 $18,595,449 $17,854,263 $17,752,794 $17,724,978 $17,805,760 $17,918,006
Net Income Allocation
Reserve Fund Contribution $0 $24,960,851 $9,444,662 $0 $0 $1,329,070 $760,118 $699,175 $966,958 $656,706 $654,837
Working Capital Repayment $0 $0 $0 $9,133,372 $0 $0 $0 $0 $0 $0 $0
Cash Available for Other Purposes $0 $11,465,776 $5,146,056 $12,098,299 $17,360,584 $17,266,380 $17,094,145 $17,053,619 $16,758,019 $17,149,054 $17,263,169
Total Cash Outlays $0 $36,426,627 $14,590,718 $21,231,671 $17,360,584 $18,595,449 $17,854,263 $17,752,794 $17,724,978 $17,805,760 $17,918,006
Rate Stabilization Reserve Balance $1,040,834 $26,001,684 $35,446,346 $35,446,346 $35,446,346 $36,775,416 $37,535,534 $38,234,709 $39,201,667 $39,858,373 $40,513,210
CCA Total Bill $0 $333,111,892 $429,074,010 $437,061,464 $445,207,892 $457,553,598 $466,078,566 $474,773,317 $483,641,397 $492,686,431 $501,912,120
SDG&E Total BI ii $0 $339,910,094 $437,830,622 $445,981,086 $454,293,767 $466,891,426 $475,590,374 $484,462,568 $493,511,629 $502,741,256 $512,155,224
Difference $0 $6,798,202 $8,756,612 $8,919,622 $9,085,875 $9,337,829 $9,511,807 $9,689,251 $9,870,233 $10,054,825 $10,243,104
Savings 0% 2% 2% 2% 2% 2% 2% 2% 2% 2% 2%
Community Choice Energy Technical Feasibility Study 8~
April 16, 2019 Item #4 Page 95 of 132
lnfr.:;tn.~ctu.!'-2
C<1!-M.p1rt-n
F~m.~.:h.irt,;:
Cff.~Sp::i..:::
lJl?.:l"~ a!l:CJ Ol~f O ff~ ~r,,r'.:e.s
fl-1~:SC€;!an-E"OouS
== ou~i-r
T-ot•1 ldr.:i..tn::ti:rc-: ·Co.:1:
C,...n,,s.u:l'tirr;
L!!J;_,I/F:·~:1.1i1t❖,Y·
A.i:1<e.,"t'",:s~n·,i::tcomma:nil<i1Con
ki.:riun-R-uoi:rci;r. Plrm
T~·,n l Coru;:uit;i r,t:
c..in M ar.:as.;-:nu~rat
F1ri:ar..i::i:ai c-on:u,t:n2
A«-:-i:n:t:r..,r. S.f:r.--k~
,t.,:'C-tA. Ann.u111 Ou=.J
othe-r constflt~n:
o tt,~r
Ott'~,_r
T,ot.J C'ar.;c . .tir.,i-C=..;t
St:iffin_;:
t.h.:!!r O.ecL<twe orr'.:!!r
<:i-!!lt!!J"III COtrr~-c'J & o:1'"K1W or G::,.,,-e:rr;.m!!::nt Affl!IC~
D,recror 01 F'O,\.'er ~!A)Lfr.oe-J:
ll:i;.,ri:l.it-=o!'"f/1.,_"!tz.la-c1'1'°' .o.\.ru:i!y:-c
..-..-o:rrum;;ttativ~ ~-;L'fr■ln.t
E.n.~,ry Pro,;r;arr-:; M• n,;i;Qr
Ci:r~or .gf Alfm~r.~r:iV-on. -:incl Fir~=-~"-=
Di!t=d,;,.~ gf Mi:nkehn: -1:1n..l f'i.•bir.:. A·ff1fr~
Fon·er ~l!:i;,p1f C,orn.p!::11n,c,,e .5p,~af~1
F011t.'€'t t.:eWv'fC!: ,,.,a,..f't:r.:: a nd P"!O! ra o,. ..:anat!l'~-t
c::or,Hi>.-i,,IL'l!o' Cl!l!E-~C:.h wi ana;;: er
Ar.~r.t Se:N.:c~ M;ir:;aac.r
A-::-~i:r;t r.~~";,;-cm.tat,v,c-;.
-Oi:-Mm11:r .. :.C:~1::m Sp=-:~:1U:t:::
EY.e-ci;t,,-....~ A:.!.i::t:tr.1/~~rt;;l Cl-erk
AC.nh::n:1:I!.ative ~na!vst:
Tot.a~ Starfll!.~ C<C>.:-lS
Appendix D -Staffing and Infrastructure Detail
Z.'PZD
~:;!.-0,l!OO
~B,lEQ ,,.
"" "" 5<>
"' ~:.li',i£>!>
:z.021
SJ-5,--1,1.<1
SU,SSE-
S1S•,e;QS
510,40:2
$1():1.,oao
"' "' Sii:1.J-030
zvz.,
...
"" SlS.Si·S:
510,e12.
5-L~,12L
"' . .,
.H.32.,651.
l.Qi.~
.. ,
.so
S:1~.~3-6
'-l0,DZ4
SlO& .. ~~!li
so
"' s;l.35.,3-04
'"""
.. n .0,-100
50
.s.1.e,se:1
~LL,0'11
~l-1.0,a.oD
"' so
£U.&14U)
,,.,.
S.31:iJ-11.4-
.5<'
$16,S'!!!Z.
$11,z..!1,Z.
su2.eu,,
"' ,o
S1.71Jii:-4-
Z026
50
50
SJ.7,?.30
~11,4"7
:\1 L4,,&t);,l
50
so
S:1..4i,Si5
zoz-r
so
so
.!-J.7.57S
S.U.,.717
~l.1.7,.l"
"' "' .S1AS,4S1
~ ~J;-.i,=-44 .S-lDZ.OJ.:• -5-J!!S',,"70 !iH0:7',"09 S:W!l-,,4UI: !i41.l . .:•27 !-4U.,7iJ
S.!4,000 ~2.0C!t,O!SO .S-l0:).1Z.L. S-1..:iD.,z.4:S .5-U.0,40!!-Sl12,,Ci1.!), .511.4,~:li? !-lL7.lC,t,
50 ,0 W ~ 50 ~ "' ,0
5;61.,200 S:1.24111:.ilB 5,t27,,3!l.S. ~12~.,&--~2. 5U214~ S:13S_.1U-5:t3.7,.lill2. $1-40~SQ~
so S1_.'.7.:tS,.3U S:!,351,!71' 52,4~,ros 5.l,-4!-&,S:lC ~:!.,SlA,:!.7.S. S.2.,!-70_.~;;2 .s.2,-~s,o..i:;
:S-2.!:s.,ooo SSl.O,l.00 .$-S.30,E'D-4, t"s.t.1,21.5 S-5-!,2,0<'IG) SSl:iiJ0&:1. 5574,~<13 .SS'-55 .• 63(1
~ ro ~ w ro • ro ~
~ !:7!!,000 _:~LO:O.lll. ==.ul!l~Z4l ~.Ll.0.40!!-:iJ.ll,,r.1."'-!::Ll.A . .B:09 Sl.U.1:.:1
S7t,,,o,o 5:SlZ, lZO ~L~?,.l!H. ~1-:,2,:,.-0,, ~1e.,,e12 510B,3l.4 ~l TZ,JO:J ~1.7:), 749
~ ~ ~ ~ ~ ~ ~ ~
~ "' ro ro "' "' ro "'
54::1.S.,700 S:1.,34.3,1.34 S-3,762;,QS.l-S:3,~41J13g SJ-,?l?',ll!S S4,0UJQ7i. 54,0~ii,r.!.4 5-411.97,2..i::..I
~l..:>J,000 ~JlZ,U:O
!i,O,, ~
S.UY,3·3 r 524-3,447
5(1 so
5.0 $itd,4.0S
s,c. SO
S1!.\.,B6"!l': S:!.-4:1,..WG
!ZQI ~2.4l-,447
:-o !l-l:!'15,0lO
So 5'19.!i,O,o
SS??.,07), ~
50
50
"" ""
51?1.,1:!::13
S114,4-0S
5171..,4-3.:!.
50
.:~::11.ll.!J:i.Z.
"" SaMB',.31>&
so
$,l16,6:lt ..,
,S.?..-1,S,::liS,
J.Z4!5.!J:1;G
SZ.O1,!:!S.O
~zo1,.a,;,o
"" .U.i:;,5,0:17
.S.1.1.6,S~l,
:!-1.74,561.
::,i'J,
SJZ~_,7.JO
.>o
S253.,2SZ ,o
!.liO}l~?'
"' Si:!!:'.:JJ;;?..S::?
Sz.5J.,Z·!!,.Z
sz0::t0lo
S2~_.m.o
>O
il:tl&J~1.?
SUO.,lu.l.71'.
$17-S):J.S.6
.so
S.lJ,l.,t~
~~
SZ.S.'8,3.::18
$0
$U1.1JOI
S<>
s.as,341
S.U.!5,.l4!)
:'.iZ.J.O,~J.
$Zl0,l!t1
"" 5·20.2,s-os
S1.l.1.,40S
Sis.1.,~:!S
50
;JJ7_,!!4S-,.,
S263-,StS
'·" SD!.,&·U: ,.,
S::!.r.3J!iJ..4.
~?t-J .. ~l.!,
!:Z..1.4,J.N.
sz1a,,~
,0
f.:!OS,t>.S.i-
51.E.,B.l-5'.
51.BS.,!i-~ -
~44,000
C<>
5:2-5,B, 185
"' ~i.l.S,U.3
50
!i2·S.S, 764
!l.Z·G!3,7Q~
:;z.u,ca1.
52.L8,-o41
'° SJ.l.1.,~2.
Si.l.5,31.3
SioS9,Z7.5
50
.5.),:f-1,4:'ll
"" ·SZ.74,161l
"' s12s,a3,::,
"' .S.1.74,lEO
S.Z.74_,U::-O
.5.2.Z.:l~oi.,;i
~Z0,.014
"' s:i.1.S,.:11...i
S1.:!B,&3P
.SUl_,061
""
"'"'
520,400
u,
517,·92,G
~ll;9:!-l
Sll1li,~?
$0
$0
S16-0o17i:7
ZOZ'91
.S-36,41-1 ,.,
.S.i9-,Z9S
5-1-2,.l ~
$1Z1,.~E'9
so ,o
S1.BS,?"iB
zo,o
s,o
so
$1SJS:S1.
S.12.,4~
~lZ,::l_,:S!IT
ro
"' S.1.5S,.'11l.
!':4.JQ,.l.J•.l :i4-J:Cl.,15jD ~7.,01.:.
Sll·J,,:03 ~l..Z.l,•1!99 .S.l.24.,!l!IT
·so se:i so
S143,,U.t s1..is,:ng >,1:.J:>>::'.!,j§.
S~,61£:,.HO S.l.174!,&50 S.21S10>ii3·~
S:5P7,.i-4 S 5-S.0~,4!)7 .S-52.1JS1i7'
.to so s,o,
!U.J:!t,.!-09 , 1.Z.1,,-B~:? S.LZ"_,JJT
S.17§1,lr&a ~l.52,.!S.1? S.l~::) .. ~0,
so "° ~
50 50 $0
Sol,:!.77',703 .S-4-,J.10,U2 S4_,454>5:!4
:..:i:,.G:,.l2B
"" S2H,-
S0
!.131,.:116
5"
5~79',Ml
!;-Z.7:!',•'44
SZ27,4'79'
:S2ZT,4T4 ,.,
s:::119,sio
tU1.,-tl5
S"'Go,'~ll
.so
!;.l-O!l-_,c,35 ,,,
SZSS,23-1
50
$U-4,0lJ
50
5.t!35,23G
~.Z.!5!!-.07
!i.z.JZ,02.J.
~l-'Z,025
"' S-::l.24,01.3
Si.34,044
52.00,650
so
.5.l-7:1.,0U. ,,,
S.Z90.,9:l1
5<)
51.'35 .. 725-
s,o
~9-DJ~1.
:~?S'D,~1.
!:~.:.J~~C·t,4.
~z,ei.~
"° .S:USJ.ll:1J-
.!i-i.3E,7:U:-
SZ.0-4)-877 ,,.
~O !UT4,l.!-9 .S.L.77.M.} Sl!Sl,1'1•!:, 5l.~,15li Sl!5!SJ~l0, 5l:9'l.,ZISO .S-L~.1!52 $Z00,0-'4 ~.Z.04.0~ ~?O!Jl.37
$.58?,c!S-;,i 5.2..ZCld,l 1a ~Z.ZA!S>l:?t-SZ,.2S:5,1~ ,z .. M,~.025 sz,5.a~J&J,:l. 5z,4,,s,,zo ~Z-~2..1:='> 5.2 .. "51,-&,4 S2,M2,47l ~Z,C54Jl 20
Community Choice Energy Technical Feasibility Study 84
April 16, 2019 Item #4 Page 96 of 132
Appendix E -CCE Cash Flow Analysis
2010 mo
feb Mar Apr M•y ""' S<p Ou Ap, M,y .,. Sop
$0 $0 $0 __ $.(I_ $0 $0 $6,712,627 $12,410,126 $12,659,898 $14,999,321 ~$15,076,410 $14,189,166 $13,644,920 $6,824,185 $7,152,097
CCAPCIARevenue $0 $0 $0 $0 SO
so
so
$0
$0
so
$0
$0
so
$0
$0
so
$0
so
so
$0
$0
So
$0
so
so
$0
so
$0
$0
$0
so
_$0
$0 $3,094,032 $3,204,545 $3,267,868 $3,886,106 $3,900,567 $3,674,739 $3,526,735 $3,159,538 $3,423,487
C~RevenunbuedonPl"(!JutedR1tu(GENtPCIA) $0 $0 •.. _$0 $0 . $0 Jo $9,80_6,659 $15,61,S,371 $15,9l7,76'i _$~,B~,42_6_ $~.~7_6,978 $17,863,905 $17,171,655 $9,913,723 $10,57S,~84
Expen,e•
Power Supply
Non-bypau~blecharge,
.T!>~.l!'J?l'.-''!r_s_uppty_
CCAProgramC01tJ
OalaManagement
COUf.,ulincludi11sB1llingJ
, Unoollectrd.a~unts
S~ffing
G11,_ne...,l&Admlt1
Debt Payment
Tcital ~eniu (net PCIA)
RHerRNeeds
Beginning Balance
Additions
Financing
Working u~t•I repayment
Reductions
BeginnlngB.alance
Additions
flnandng
ReducllonslncludlngdeblseMce
Ending Balance
so $0 so so so
$0 $0 so so so
SO S0 S0 $0 -~
so so so $0 so
so -~-~ $0 so
so so so $0 so
$0 $0 $0 $0 so
so so so $0 so
$0 $0 so $0 so
so so so so $0
SO SO _SO so SO
so so so so
$0 so so so so
$0
$0
$0
so
so
so
so
so
$0
$0
so
$0
$0
,.
$0
$0
$0
so
so
$0
,$0
so
$0
$0
$9
so
so
$0
''·
so
so so ~ so so
S65,450 S65,4SO S65,450 S65,4SO 582,450
so so ~ ~ so
S61,S68 S61,568 S61,568 S61,561 $61,568
SH,'20 So $0 SO SO
Sl9,101 $19,101 $19,101_ Sl9,101 $1':1,101
so
$0
$0
so
$0
$0
so
$0
. $0
SO $6,226,686 56,453,445 56,754,146 59,703,089 510,114,481 $9,219,451 SS,134,402 57,253,374 57,807,888
So $3,094,032 $3,204,54S $3,267,868 $3,88~,.106 $3,900,567 53,674,739 $3,526,735 Sl,159,538 $3,423,487
so 59,no,11, s~,65!,99o s10,022,014 su,sa,~19• s14;01S,048 512,894,190 s11,,,1,u1 s10,4~,912 s1µ31,31s
$0 $0 $0
$0 so so
Sll,450 $128,316 $128,316
so ,.
$128,316
$192,026
$32,48-t
$136,986
so so SO _S:O. _Sl,3,7l!i
$81,458 $183,676 $183,676 $183,676 $183,676
S7,l◄D $61,817 $10,u1_ $10,838 Slo,an
$19,101 $38,202 $38,202 $Jll,2_02 $267,416
$192,451
$31,556
$136,916
S1_4,170
$183,676
s10,u8
$267,416
$193,022
$32,653
$136,986
$192,7011 $192,751
$32,600 . S32,607
$136,986 $136,986
$14,771. $~0,6~9. $21,4':12
$183,676 $183,676 $18.3,676
$10,138 Sl0,838 _ $10,83B
$267,416 $267,416 $267,416
5192,741
$32,605
$136,986
$19,702
$183,676
$10,Bll
$267,416
$192,802
$32,615
SU6,986
$17,512
$183,676
Sl0,838
$267,416
$192,366
$32,542
$136,986
sis.no
$183,676
$}0,838
$267,416
$184,447
$31,202
$136,986
$16,876
$183,676
$10,838
$267,416
$0 $167,539 $146,119 $1~6,119 $146,119 $163,119 $190,10 $412,0U $361,0n s1,~on s,,111,102 s1,ou,01, s,,400,u, uo,Jss,213 si~.167,495 S?,110,674 sa.,n,4,s s,,100,001 sa,454,u2
$0 $1,000,000 $832,461 $686,341 $540,222 $3!14,'102 $230,983 $1,040,834 $628,822 $267,790 Sll,906,758 $11,069,616 S4,004,837 $3,424,658 $8,236,446 $10,347,489 $14,388,365 $19,403,460 S24,618,631
so $0 $0 ,, s, SO S6,712,627 SH,410,826 Sll,659,898 $14,999,321 $15,076,UO $14,189,166 513,644,920
SO SO SO $0 SO Sl,000,000
$0
so
So
so
s,
so
so
so SO Sl,000,000
so
so so Sll,000,000
so
so so so $0 $0 so $0 $0 $0
so so $0 $0 so so $0 so so so so so $0 $0
$0 so so so so SO S167,539 Sl46,119 $146,119 $146,119 $163,119 $190,149 $412,012 $361,032
so
S361,032
so so so so so so so so so
$837,142 57,064,779 s1,2,2,801 S7,599,0l8 510,548,854 $10,!ISB,44~ $10,061,316 $8,973,995 $8,084,815
SO SO $0 SO SO Sl,000,000 S832,461 $686341 $540,222 S394,102 S230,983 $1,040,834 $628,822 $267,790 $11,906,758 $11,069,616 $4004837 S3,424,658 $8236,446 $10347489 Sl4,l88365 S19,403460 $24,618,631 $30,178,737
so so so so so SO Sl,000,000 $832,461 S686,341 S540,222 $394,102 $230,983 $1,040,834 S628,812 S267,790 SU,':106,758 $11,069,616 $4,004,Bl1 $3,424,658 $8,236,446 $10,347,489 SU,388,365 Sl9,403,460 S24,618,6H
so so so so so so
SO so so so $0 $1,000,000
$0
$0
$0
$0
so
so
so ,. SO $0
SO $1,000,000
,.
so
so so
$0 $12,000,000
$0 S0 $0 so $0 So $167,539 $146,119 S146,119 S146,l19 Sl63,119 S190,149 $412,012 $361,032 S361,032
so
so
SO $6,712,627 $12,410,826 Sll,6S9,19B Sl4,999,3ll SlS,076,410 Sl4,189,166 SU,644,920
so so so so so so so so
$837,lU $7,064,779 57,292,807 $7,599,038 $10,548,854 SlD,958,445 $10,061,316 Sl,973,995 $8,084,815
$0 SO so so o $1,000000 S832,461 $686,341 $540222 Sl94102 $230,983 Sl,040,834 $628,822 S267,790 Sll,906,758 $11069,616 S4,004,837 $3,42◄,&SI $8,236,446 $10,347,489 $14,388365 $19,403,460 $24,618,631 S:W,178,737
Community Choice Energy Technical Feasibility Study 85
April 16, 2019 Item #4 Page 97 of 132
Appendix F -Glossary
Ancillary Services: Those services necessary to support the transmission of electric power from
seller to purchaser given the obligations of control areas and transmitting utilities within those
control areas to maintain reliable operations of the interconnected transmission system.
aMW: Average annual Megawatt. A unit of energy output over a year that is equal to the energy
produced by the continuous operation of one megawatt of capacity over a period of time (8,760
megawatt-hours).
Baseload Resources: Base load power generation resources are resources such as coal, nuclear,
hydropower, and geothermal heat that are cheapest to operate when they generate
approximately the same output every hour.
Basis Difference (Natural Gas): The difference between the price of natural gas at the Henry Hub
natural gas distribution point in Erath, Louisiana, which serves as a central pricing point for
natural gas futures, and the natural gas price at another hub location (such as for Southern
California).
Buckets: Buckets 1-3 refer to different types of renewable energy contracts according to the
Renewable Portfolio Standards requirements. Bucket 1 are traditional contracts for delivery of
electricity directly from a generator within or immediately connected to California. These are the
most valuable and make up the majority of the RECS that are required for LSEs to be RPS
compliant. Buckets 2 arid 3 have different levels of intermediation between the generation and
delivery of the energy from the generating resources.
Bundled Customers: Electricity customers who receive all their services (transmission,
distribution and supply) from the Investor-Owned Utility.
Bundled and Unbundled Renewable RECs: Unbundled Renewable Energy Credits (RECs) are
those that have been disassociated from the electricity production originally represented and are
sold separately from energy. Bundled RECs are delivered with the associated energy.
California Independent System Operator (CAISO): The organization responsible for managing
the electricity grid and system reliability within the former service territories of the three
California IOUs.
California Balancing Authority: A balancing authority is responsible for operating a transmission
control area. It matches generation with load and maintains consistent electric frequency of the
grid, even during extreme weather conditions or natural disasters. California has 8 balancing
authorities. SDG&E is in CAISO.
California Clean Power (CCP): A private company providing wholesale supply and other services
to CCEs.
California Energy Commission (CEC): The state regulatory agency with primary responsibility for
enforcing the Renewable Portfolio Standards law as well as a number of other, electric-industry
related rules and policies.
California Public Utilities Commission (CPUC): The state agency with primary responsibility for
regulating IOUs, as well as Direct Access (ESP) and CCE entities.
Community Choice Energy Technical Feasibility Study 86
April 16, 2019 Item #4 Page 98 of 132
Capacity Factor: The ratio of an electricity generating resource's actual output over a period of
time to its potential output if it were possible to operate at full nameplate capacity continuously
over the same period. Intermittent renewable resources, like wind and solar, typically have lower
capacity factors than traditional fossil fuel plants because the wind and sun do not blow or shine
consistently.
CleanPowerSF: CCE program serving customers within the City of San Francisco. CleanPowerSF
began service to 7,800 "Phase 1" customers in May 2016.
Climate Zone: A geographic area with distinct climate patterns necessitating varied energy
demands for heating and cooling.
Coincident Peak: Demand for electricity among a group of customers that coincides with peak
total de_mand on the system.
Community Choice Aggregation (CCA): Method available through California law to allow cities
and Counties to aggregate their citizens and become their electric generation provider.
Community Choice Energy: A City, County or Joint Powers Agency procuring wholesale power to
supply to retail customers.
Community Choice Partners: A private company providing services to CCEs in California.
Congestion Charges: When there is transmission congestion, i.e. more users of the transmission
path than capacity, the Ca ISO charges all users of the congested transmission path a "Usage
Charge".
Congestion Revenue Rights (CRRs): Financial rights that are allocated to Load Serving Entities to
offset differences between the prices where their generation is located and the price that they
pay to serve their load. These rights may also be bought and sold through an auction process.
CRRs are part of the CAISO market design.
Demand Side Resources: Energy efficiency and load management programs that reduce the
amount of energy that would otherwise be consumed by a customer of an electric utility.
Demand Response (DR): Electric customers who have a contract to modify their electricity usage
in response to requests from a utility or other electric entity. Typically, will be used to lower
demand during peak energy periods, but may be used to raise demand during periods of excess
supply.
Direct Access: Large power consumers which have opted to procure their wholesale supply
independently of the IOUs through an Electricity Service Provider.
EEi (Edison Electric Institute) Agreement: A commonly used enabling agreement for transacting
in wholesale power markets.
Electric Service Providers (ESP): An alternative to traditional utilities. They provide electric
services to retail customers in electricity markets that have opened their retail electricity markets
to competition. In California the Direct Access program allows large electricity customers to opt-
out of utility-supplied power in favor of ESP-provided power. However, there is a cap on the
amount of Direct Access load permitted in the state.
Electric Tariffs: The rates and terms applied to customers by electric utilities. Typically have
different tariffs for different classes of customers and possibly for different supply mixes.
Community Choice Energy Technical Feasibility Study 87
April 16, 2019 Item #4 Page 99 of 132
Enterprise Model: When a City or County establish a CCE by themselves as an enterprise within
the municipal government.
Federal Tax Incentives: There are two Federal tax incentive programs. The Investment Tax Credit
(ITC) provides payments to solar generators. The Production Tax Credit (PTC} provides payments
to wind generators.
Feed-in Tariff (FIT): A tariff that specifies what generators who are connected to the distribution
system are paid.
Firming: Firm capacity is the amount of energy available for production or transmission which
can be (and in many cases must be} guaranteed to be available at a given time. Firm energy refers
to the actual energy guaranteed to be available. Firming refers to the financial instrument to
change non-firm power to form power.
Flexible Resource Adequacy: Flexible capacity need is defined as the quantity of economically
dispatched resources needed by the California ISO to manage grid reliability during the greatest
three-hour continuous ramp in each month.
Forward Prices: Prices for contracts that specify a future delivery date for a commodity or other
security. There are active, liquid forward markets for electricity to be delivered at a number of
Western electricity trading hubs, including SPlS which corresponds closely to the price location
which the City of Davis will pay to supply its load.
Implied Heat Rate: A calculation of the day-ahead electric price divided by the day-ahead natural
gas price. Implied heat rate is also known as the 'break-even natural gas market heat rate,'
because only a natural gas generator with an operating heat rate (measure of unit efficiency}
below the implied heat rate value can make money by burning natural gas to generate power.
Natural gas plants with a higher operating heat rate cannot make money at the prevailing
e!ectricity and natural gas prices.
Integrated Resource Plan: A utility's plan for future generation supply needs.
Investor-Owned Utility (IOU): For profit regulated utilities. Within California there are three IOUs
-Pacific Gas and Electric, Southern California Edison and San Diego Gas and Electric.
ISDA (International Swaps and Derivatives Association): Popular form of bilateral contract to
facilitate wholesale electricity trading.
Joint Powers Agency (JPA): A legal entity comprising two or more public entities. The JPA
provides a separation of financial and legal responsibility from its member entities.
Lancaster Choice Energy (LCE): A single-jurisdiction CCE serving residents of the City of Lancaster
in Southern California. LCE launched service in October 2015 and served 51,000 customers.
LEAN Energy (Local Energy Aggregation Network): A not-for-profit organization dedicated to
expanding Community Choice Aggregation nationwide.
Load Forecast: A forecast of expected load over some future time horizon. Short-term load
forecasts are used to determine what supply sources are needed'. Longer-term load forecasts are
used for budgeting and long-term resource planning.
Local Resource Adequacy: Local requirements are determined based on an annual CAISO study
using a 1-10 weather year and an N-1-1 contingency
Community Choice Energy Technical Feasibility Study 88
April 16, 2019 Item #4 Page 100 of 132
Marginal Unit: An additional unit of power generation to what is currently being produced. At
and electric power plant, the cost to produce a marginal unit is used to determine the cost of
increasing power generation at that source.
Marin Clean Energy (MCE}: The first CCE in California now serving residents and businesses in
the Counties of Marin and Napa, and the cities of Richmond, Benicia, El Cerrito, San Pablo, Walnut
Creek, and Lafayette.
Market Redesign and Technology Upgrade (MRTU}: CAISO's redesigned, nodal (as opposed to
zonal) market that went live in April of 2009.
Net Energy Metering (NEM): The program and rates that pertain to electricity customers who
also generate electricity, typically from rooftop solar panels.
Non-bypassable Charges: Charges applied to all customers receiving service from Investor-
Owned Utilities in California, but which are separated into a separate charge for departing load
customers, such as Community Choice Aggregation and Direct Access Customers. These charges
include charges for the Public Purpose Programs (PPP), Nuclear Decommissioning (ND), California
Department of Water Resources Bond (CDWR), Power Charge Indifference Adjustment (PCIA),
Energy Cost Recovery Amount (ECRA), Competition Transition Charge (CTC), Cost Allocation
Mechanism (CAM).
Non-Coincident Peak: Energy demand by a customer during periods that do not coincide with
maximum total system load.
Non-Renewable Power: Electricity generated from non-renewable sources or a source that does
not come with a Renewable Energy Credit (REC):
On-Bill Repayment (OBR): Allows electric customers to pay for financed improvements such as
energy efficiency measures through monthly payments on their electricity bills.
Operate on the Margin: Operation of a business or resource at the limit of where it is profitable.
Opt-Out: Community Choice Aggregation is, by law, an opt-out program. Customers within the
borders of a CCE are automatically enrolled within the CCE unless they proactively opt-out of the
program.
Peninsula Clean Energy (PCE): Community Choice Aggregation program serving residents and
businesses of San Mateo County. PCE launched in October of 2016.
Pricing Nodes: The ISO wholesale power market prices electricity based on the cost of generating
and delivering it from particular grid locations called nodes.
Power Cost Indifference Adjustment (PCIA}: A charge applied to customers who leave IOU
service to become Direct Access or CCE customers. The charge is meant to compensate the IOU
for costs that it has previously incurred to serve those customers.
Power Purchase Agreement (PPA}: The standard term for bilateral supply contracts in the
electricity industry.
Portfolio Content Category: California's RPS program defines all renewable procurement
acquired from contracts executed after June 1, 2010 into three portfolio content categories,
commonly referred to as "buckets."
Renewable Energy Credits (RECs}: The renewable attributes from RPS-qualified resources which
must be registered and retired to comply with RPS standards.
Community Choice Energy Technical Feasibility Study 89
April 16, 2019 Item #4 Page 101 of 132
Resource Adequacy (RA): The requirement that a Load-Serving Entity own or procure sufficient
generating capacity to_meet its peak load plus a contingency amount (15% in California) for each
month.
Renewable Portfolio Standard (RPS): The state-based requirement to procure a certain
percentage of load from RPS-certified renewable resources.
Scheduling Coordinator: An entity that is approved to interact directly with CAISO to schedule
load and generation. All CAISO participants must be or have an SC. A scheduling coordinator
provides day-ahead and real-time power and transmission scheduling services.
Scheduling Agent: A person or service that forecasts and monitors short term system load
requirements and meets these demands by scheduling power resource to meet that demand.
Shaping: Function that facilitate and support the delivery of energy generation to periods when
it is needed most.
Silicon Valley Clean Energy (SVCE): CCE serving customers in twelve communities within Santa
Clara County including the cities of Campbell, Cupertino, Gilroy, Los Altos, Los Altos Hills, Los
Gatos, Monte Sereno, Morgan Hill, Mountain View, Saratoga, Sunnyvale, and the County of Santa
Clara. As of the date of completion of this Study, SVCE had not yet launched service.
Sonoma Clean Power (SCP): A CCE serving Sonoma County and Sonoma County cities. On
December 29th, SCP received approval of their implementation plan from the California Public
Utilities Commission to extend service into Mendocino County.
SPlS: Refers to a wholesale electricity pricing hub -South of Path 15 -which roughly corresponds
to SCE and SDG&E's service territory. Forward and Day-Ahead power contracts for Northern
California typically provide for delivery at SPlS. It is not a single location, but an aggregate based
on the locations of all the generators in the region.
Spark Spread: The theoretical grow margin of a gas-fired power plant from selling a unit of
electricity, having bought the fuel required to produce this unit of electricity. All other costs
(capital, operation and maintenance, etc.) must be covered from the spark spread.
Supply Stack: Refers to the generators within a region, stacked up according to their marginal
cost to supply energy. Renewables are on the bottom of the stack and peaking gas generators on
the top. Used to provide insights into how the price of electricity is likely to change as the load
changes.
System Resource Adequacy: System requirements are determined based on each LSEs CEC
adjusted forecast plus a 15% planning reserve margin.
Vintage: The vintage of CRS applicable to a CCE customer is determined based on when the CCE
commits to begin providing generation services to the customer. CCEs may formally commit to
become the generation service provider for a group of customers
Weather Adjusted: Normalizing energy use data based on differences in the weather during the
time of use. For instance, energy use is expected to be higher on extremely hot days when air
conditioning is in higher demand than on days with comfortable temperature. Weather
adjustment normalizes for this variation.
Western Electric Coordinating Council (WECC): The organization responsible for coordinating
planning and operation on the Western electric grid.
Community Choice Energy Technical Feasibility Study 90
April 16, 2019 Item #4 Page 102 of 132
Wholesale Power: Large amounts of electricity that are bought and sold by utilities and other
electric companies in bulk at specific trading hubs. Quantities are measured in MWs, and a
standard wholesale contract is for 25 MW for a morith during heavy-load or peak hours (7am to
10 pm, Mon-Sat), or light-load or off-peak hours (all the other hours).
Western States Power Pool (WSPP) Agreement: Common, standardized enabling agreement to
transact in the wholesale power markets.
Community Choice Energy Technical Feasibility Study 91
April 16, 2019 Item #4 Page 103 of 132
Ancillary and Congestion Costs
The CCE would pay the CAISO for transmission congestion and ancillary services. Transmission
congestion occurs when there is insufficient capacity to meet the demands of all transmission
customers. Congestion refers to a shortage of transmission capacity to supply a waiting market
and is marked by systems running at full capacity and still being unable to serve the needs of all
customers. The transmission system is not allowed to run above its rated capacities. Congestion
is managed by the CAISO by charging congestion charges in the day-ahead market. Congestion
charges can be managed through the use of Congestion Revenue Rights {CRR}. CRRs are financial
instruments made available through a CRR allocation, a CRR auction, and a secondary registration
system. CRR holders manage variability in congestion costs. The CCE's congestion charges would
depend on the transmission paths used to bring resources to load. As such, the loc.ation of
generating resources used to serve the CCE load would impact these congestion costs.
The Grid Management Charge {GMC} is the vehicle through which the CAISO recovers its
administrative and capital costs from the entities that utilize the CAISO's services. Based on a
survey of GMC costs currently paid by CAISO participants, the CCE's GMC costs are expected to
be near $0.5/MWh.
The CAISO performs annual studies to identify the minimum local resource capacity required in
each local area to meet established reliability criteria. Load serving entities receive a proportional
allocation of the minimum required local resource capacity by transmission access charge area
and submit resource adequacy plans to show that they have procured the necessary capacity.
Depending on these results of the annual studies, there may be costs associated with local
capacity requirements for the CCE.
Because generation is delivered as it is produced and, particularly with respect to renewables
which can be intermittent, deliveries need to be firmed using ancillary services to meet the CCE's
load requirements. Ancillary services would need to be purchased from the CAISO. Regulation
and operating reserves are described below.
■ Regulation Service: Regulation service is necessary to provide for the continuous balancing
of resources with load and for maintaining scheduled interconnection frequency at 60 cycles
per second {60 Hertz}. Regulation and frequency response service is accomplished by
committing on-line generation whose output is raised or lowered (predominantly through
the use of automatic generating control equipment} and by other non-generation resources
capable of providing this service as necessary to follow the moment-by-moment changes in
load.
■ Operating Reserves -Spinning Reserve Service: Spinning reserve service is needed to serve
load immediately in the event of a system contingency. Spinning reserve service may be
provided by generating units that are on-line and loaded at less than maximum output and
by non-generation resources capable of providing this service.
Community Choice Energy Technical Feasibility Study 93
April 16, 2019 Item #4 Page 105 of 132
■ Operating Reserves-Non-Spinning Reserve Service: Non-spinning reserve service is available
within a short period of time to serve load in the event of a system contingency. Non-spinning
reserve service may be provided by generating units that are on-line but not providing power,
by quick-start generation or by interruptible load or other non-generation resources capable
of providing this service.
Based on a survey of ancillary service costs currently paid by CAISO participants, the CCE's
ancillary service costs are estimated to be near $0.003/kWh. The Study's base case assumes
ancillary service costs are $0.003/kWh in 2020, escalating by 20% annually thereafter. Serving a
greater percentage of load, 60% to 100% as is modeled in The Study, with renewables would
likely result in increased grid congestion and higher ancillary service costs. The scenarios included
· in this Study as shown below in Exhibit G-2.
Exhibit G-2
Base Case Ancillary Service Costs in Resource Portfolios
Portfolio
1-SDG&E Equivalent
2-100% renewable by 2030
3-100% Renewable
Scheduling Coordinator Services
2020 Ancillary
Service Costs
($/kWh)
$0.003
$0.003
$0.003
Annual Escalation
Factor
20%
20%
20%
A scheduling coordinator provides day-ahead and real-time power and transmission scheduling
services. Scheduling coordinators bear the responsibility for accurate and timely load forecasting
and resource scheduling including wholesale power purchases and sales required to maintain
hourly load/resource balances. A scheduling coordinator needs to provide the marketing
expertise and analytical tools required to optimally dispatch the CCE's surplus resources on a
monthly, daily, and hourly basis.
The CCE's scheduling coordinator would need to forecast the CCE's hourly loads as well as the
CCE's hourly resources including shares of any hydro, wind, solar, and other resources in which
the CCE is a participant/purchaser. Forecasting the output of hydro, wind, and solar projects
involves more variables than forecasting loads. Scheduling coordinators already have models set
up to accurately forecast hourly hydro, wind, and solar generation. Accurate load and resource
forecasting would be a key element in assuring the Partners' CCE power supply costs are
minimized.
A scheduling coordinator also provides monthly checkout and after-the-fact reconciliation
services. This requires scheduling coordinators to agree on the amount of energy purchased
and/or sold and the purchase costs and/or sales revenue associated with each counterparty with
which the CCE transacted in a given month.
Community Choice Energy Technical Feasibility Study 94
April 16, 2019 Item #4 Page 106 of 132
A scheduling coordinator provides day-ahead and real-time power and transmission scheduling
services. Scheduling coordinators bear the responsibility for accurate and timely load forecasting
and resource scheduling including wholesale power purchases and sales required to maintain
hourly load/resource balances. A scheduling coordinator needs to provide the marketing
expertise and analytical tools required to optimally dispatch the CCE's surplus and deficit
resources on a monthly, daily and hourly basis.
Inside each hour, the CAISO Energy Imbalance Market (EIM) takes over load/resource balancing
duties. The EIM automatically balances loads and resources every fifteen minutes and dispatches
least-cost resources every 5-minutes. The EIM allows balancing authorities to share reserves,
and more reliably and efficiently integrate renewable resources across a larger geographic
region.
Within a given hour, metered energy (i.e., actual usage) may differ from supplied power due to
hourly variations in resource output or unexpected load deviations. Deviations between metered
energy and supplied power are accounted for by the EIM . The imbalance market is used to
resolve imbalances between supply and demand. The EIM deals only with energy, not ancillary
services or reserves.
The EIM optimally dispatches participating resources to maintain load/resource balance in real-
time. The EIM uses the CAISO's real-time market, which uses Security Constrained Economic
Dispatch (SCED). SCED finds the lowest cost generation to serve the load taking into account
operational constraints such as limits on generators or transmission facilities. The five-minute
market automatically procures generation needed to meet future imbalances. The purpose of
the five-minute market is to meet the very short-term load forecast. Dispatch instructions are
effectuated through the Automated Dispatch System (ADS).
The CAISO is the market operator and runs and settles EIM transactions. The CCE's scheduling
coordinator would submit the CCE's load and resource information to the market operator. EIM
processes are running continuously for every fifteen-minute and five-minute interval, producing
. dispatch instructions and prices.
Participating resource scheduling coordinators submit energy bids to let the market operator
know that they are available to participate in the real-time market to help resolve energy
imbalances. Resource schedulers may also submit an energy bid to declare that resources will
increase or decrease generation if a certain price is struck. An energy bid is comprised of a
megawatt value and a price. For every increase in megawatt level, the settlement price also
increases.
The CAISO calculates financial settlements based on the difference between schedules and actual
meter data and bid prices during each hour. Locational Marginal Prices (LMP) are used in
settlement calculations. The LMP is the price of a unit of energy at a particular location at a given
time. LMPs are influenced by nearby generation, load level, and transmission constraints and
losses.
Community Choice Energy Technical Feasibility Study 95
April 16, 2019 Item #4 Page 107 of 132
Appendix H -Separate City Results
Introduction
A jurisdiction participation case was developed to present the impacts of designing a CCE with
only one of the four jurisdictions. The base case includes all four cities; however, a single
jurisdiction can individually establish and operate a CCE. The benefit of a single city CCE is that
the city can make all policy decisions on revenues, power mix, and programs. However, all risk
and liability associated with the CCE fall solely on this single jurisdiction. In this structure, it is
recommended that the Partners develop contractual language to minimize risk to general funds,
maintain adequate operating reserves, proactively track regulatory activities, and manage its
energy portfolio. Solana Energy Alliance, Apple Valley Choice Energy, Lancaster Choice Energy,
and CleanPowerSF are examples of single jurisdiction governance models.
The feasibility analysis found that the larger cities of Carlsbad and Oceanside can establish a
single jurisdiction CCEs and still provide 2% rate discounts to ratepayers. Encinitas can also
establish a CCE, but the projected rate savings are only 1% and several costs were reduced to
ensure reserve requirements are met by the end of the analysis period. To operate a financially
stable CCE in Encinitas, costs would have to be reduced further to ensure sufficient reserves are
collected during the first 3-4 years. Finally, the analysis shows that a single jurisdiction CCE in Del
Mar is not likely to be cost effective.
Analysis
The financial proforma model was developed for each city based on the 50% Renewable power
offering. Power supply, data management, billing, SDG&E charges, and non~bypassable charges
were reduced to reflect the lower load and number of customers. For the remaining costs, the
assumptions were modified to meet the expected requirement for each city based on the
potential number of customers.
Carlsbad
The City of Carlsbad has about 50,000 accounts or about 34% of the four-city total. If the City of
Carlsbad decides to establish a standalone CCE, it was assumed that the staffing, consulting, and
administrative costs would be approximately the same as a four-city CCE. The only change in
costs assumed were related to power supply, data management and SDG&E charges. In addition,
the working capital needs were reduced to $7 million. Based on this analysis, Carlsbad can offer
2% discount to SDG&E bills and collect up to $18 million in reserves by 2030.
Community Choice Energy Technical Feasibility Study 96
April 16, 2019 Item #4 Page 108 of 132
Del Mar
The City of Del Mar has approximately 2,900 accounts or about 2% of the four-city total. If the
City of Del Mar decides to establish a standalone CCE, the costs other than those relatedto power
supply, data management and SDG&E charges would need to be below $200,000 per year. To
model the scenario for Del Mar, it was assumed that the CCE would only spend $100,000 per year
in staffing costs, $150,000 in consulting costs, and $10,000 in A&G. For the analysis, the working
capital needs were reduced to $800,000 and it was assumed that it would be paid off over 10
years. Based on this conservative analysis, if Del Mar offers 1% discount to SDG&E rates, Del Mar
would not be able to collect sufficient reserves. It can therefore be concluded that Del Mar is too
small to operate a CCE.
Encinitas
The City of Encinitas has approximately 26,000 accounts or about 20% of the four-city total. If
the City of Encinitas decides to establish a standalone CCE, the costs other than those related to
power supply, data management and SDG&E charges would need to be below $2 million per
year. To model the scenario for Encinitas, it was assumed that the CCE would spend
approximately $1,100,000 per year in staffing costs, another $330,000 in consulting costs, and
$10,000 in A&G. For the analysis, the working capital needs were reduced to $4.1 million and it
was assumed that it would be paid off over three years. Based on this analysis, if Encinitas offers
1% discount to SDG&E bills then the reserve level by 2030 would only be $1.7 million. It can
therefore be concluded that while Encinitas could operate a standalone CCE, the costs other than
those related to power supply, data management and SDG&E charges would need to be
significantly below $2 million per year in order for sufficient reserves to be accumulated during
the first three years.
Oceanside
The City of Oceanside has about 70,000 accounts or about 46% of the four-city total. If the City
of Oceanside decides to establish a standalone CCE, it was assumed that the staffing, consulting,
and administrative costs would be approximately the same as a four-city CCE. The only change
in costs assumed were related to power supply, data management and SDG&E charges. In
addition, the working capital needs were reduced to $8.7 million. Based on this analysis,
Oceanside can offer 2% discount to SDG&E rates and collect up to $16.7 million in reserves by
2030.
Results
The base case analysis demonstrates that a four-city CCE could offer 2% rate savings for a 50%
renewable product. Under the separate city results, the proformas on the following pages
demonstrate that the same level of savings could potentially be offered by Oceanside and
Carlsbad, while Encinitas would only be able to reduce rates by 1% although additional cost
reductions would be needed to ensure robust financial performance of the CCE. Finally, the
results show that Del Mar is likely too small to operate as a separate CCE.
Community Choice Energy Technical Feasibility Study 97
April 16, 2019 Item #4 Page 109 of 132
Exhibit H-1
City of Carlsbad
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Revenues from Operations($)
Electric Sales Revenues $0 $43,627,456 $51,982,455 $52,603,359 $53,059,934 $55,252,451 $55,919,725 $56,771,213 $57,983,415 $58,857,041 $59,741,485
Less Uncollected Accounts $0 $70,965 $93,271 $93,162 $96,802 $101,085 $104,447 $108,056 $111,745 $115,582 $119,328
Total Revenues $0 $43,556,490 $51,889,184 $52,510,197 $52,963,133 $55,151,366 $55,815,277 $56,663,158 $57,871,669 $58,741,459 $59,622,157
Cost of Operations ($)
Cost of Energy $0 $30,031,812 $41,108,302 $42,582,397 $44,304,231 $46,350,400 $47,987,303 $49,709,031 $51,449,317 $53,266,137 $55,087,997
Operating & Administrative
Billing & Data Management $0 $574,746 $785,207 $802,913 $821,019 $839,533 $858,464 $877,822 $897,617 $917,859 $938,556
SDG&E Fees $0 $129,901 $130,226 $130,551 $130,877 . $131,205 $131,533 $131,861 $132,191 $132,522 $132,853
SDG&E Setup and Startup Fees $0 $80,189 $83,789 $0 $0 $0 $0 $0 $0 $0 $0
Consulting Services $426,700 $1,617,822 $1,411,407 $1,439,635 $1,468,427 $1,497,796 $1,527,752 $1,558,307 $1,589,473 $1,621,263 $1,653,688
Staffing $389,299 $2,204,114 $2,248,196 $2,293,160 $2,339,023 $2,385,804 $2,433,520 $2,482,190 $2,531,834 $2,582,471 $2,634,120
General & Administrative expenses $28,560 $181,030 $132,651 $135,304 $158,410 $177,184 $143,586 $146,457 $169,787 $188,788 $155,422
Debt Service $114,607 · $1,317,980 $1,604,498 $0 $0 $0 $0 $0 $0 $0 $0
Tota I O&A Costs $959,166 $6,105,781 $6,395,972 $4,801,563 $4,917,757 $5,031,521 $5,094,854 $5,196,638 $5,320,902 $5,442,902 $5,514,639
Total Cost & Reserves $959,166 $36,137,593 $47,504,274 $47,383,960 $49,221,987 $51,381,921 $53,082,157 $54,905,670 $56,770,219 $58,709,039 $60,602,636
CCE Program Surplus/(Deficit) ($959,166) $7,418,897 $4,384,910 $5,126,237 $3,741,145 $3,769,445 $2,733,120 $1,757,488 $1,101,451 $32,421 ($980,478)
CCE Cumulative Reserves From Operations ($959,166) $6,459,731 $10,844,641 $15,970,878 $19,712,023 $23,481,468 $26,214,588 $27,972,076 $29,073,526 $29,105,947 $28,125,469
Reserve Additions
Operating Reserve Contributions ($959,166) $7,418,897 $4,384,910 $5,126,237 $3,741,145 $3,769,445 $2,733,120 $1,757,488 $1,101,451 $32,421 ($980,478)
Cash from Financing $2,000,000 $5,000,000 $0 $0 $0 $0 $0 $0 $0 $0 $0
Total Additions $1,040,834 $12,418,897 $4,384,910 $5,126,237 $3,741,145 $3,769,445 $2,733,120 $1,757,488 $1,101,451 $32,421 ($980,478)
Reserve Targets $315,342 $11,880,853 $15,617,844 $15,578,288 $16,182,571 $16,892,686 $17,451,668 $18,051,179 $18,664,182 $19,301,602 $19,924,154
Reserve Outlays
Start-up Funding Payments+ Bonds+ Collateral $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Working Capital Repayment (Remainder) $0 $0 $0 $4,469,404 $0 $0 $0 $0 $0 $0 $0
New Programs/Additional Rate Savings $0 $0 $0 $2,923,187 $0 $6,196,191 $0 $3,332,115 $0 $0 $0
Total Reserve Outlays $0 $0 $0 $7,392,590 $0 $6,196,191 $0 $3,332,115 $0 $0 $0
Rate Stabilization Reserve Balance $1,040,834 $13,459,731 $17,844,641 $15,578,288 $19,319,433 $16,892,686 $19,625,806 $18,051,179 $19,152,630 $19,185,050 $18,204,572
CCETotal Bill $0 $136,619,121 $175,755,600 $179,011,980 $182,332,936 $187,273,745 $190,747,384 $194,289,967 $197,902,933 $201,587,748 $205,345,912
SDG&E Total Bill $0 $139,407,266 $179,342,449 $182,665,285 $186,054,016 $191,095,658 $194,640,188 $198,255,069 $201,941,768 $205,701,783 $209,536,645
Difference $0 $2,788,145 $3,586,849 $3,653,306 $3,721,080 $3,821,913 $3,892,804 $3,965,101 $4,038,835 $4,114,036 $4,190,733
Savings 0% 2% 2% 2% 2% 2% 2% 2% 2% 2% 2%
Community Choice Energy Technical Feasibility Study 98
April 16, 2019 Item #4 Page 110 of 132
Exhibit H-2
City of Del Mar
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Revenues from Operations($)
Electric Sales Revenues $0 $1,808,337 $2,122,109 $2,147,767 $2,165,818 $2,273,118 $2,300,950 $2,337,254 $2,390,172 $2,427,446 $2,465,193
Less Uncollected Accounts $0 $3,758 $4,734 $4,509 $4,682 $4,862 $5,019 $5,183 $5,359 $5,521 $5,695
Total Revenues $0 $1,804,579 $2,117,376 $2,143,259 $2,161,136 $2,268,256 $2,295,931 $2,332,071 $2,384,814 $2,421,925 $2,459,498
Cost of Operations ($)
Cost of Energy $0 $1,245,497 $1,724,643 $1,786,487 $1,858,724 $1,944,568 $2,013,243 $2,085,475 $2,158,487 $2,234,709 $2,311,143
Operating & Administrative
Billing & Data Management $0 $34,281 $46,706 $47,759 $48,836 $49,938 $51,064 $52,215 $53,393 $54,597 $55,828
SDG&E Fees $0 $7,727 $7,746 $7,766 $7,785 $7,804 $7,824 $7,843 $7,863 $7,883 $7,902
SDG&E Setup and StartUp Fees $0 $32,985 $36,585 $0 $0 $0 $0 $0 $0 $0 $0
Consulting Services $76,500 $156,060 $159,181 $162,365 $165,612 $168,924 $172,303 $175,749 $179,264 $182,849 $186,506
Staffing $76,500 $156,060 $159,181 $162,365 $165,612 $168,924 $172,303 $175,749 $179,264 $182,849 $186,506
General & Administrative expenses $7,140 $130,050 $132,651 $135,304 $143,110 $140,770 $143,586 $146,457 $154,487 $152,374 $155,422
Debt Service $91,686 $183,371 $183,371 $0 $0 $0 $0 $0 $0 $0 $0
Total O&A Costs $251,826 $700,534 $725,422 $515,559 $530,956 $536,361 $547,079 $558,014 $574,270 $580,552 $592,164
Total Cost & Reserves $251,826 $1,946,031 $2,450,066 $2,302,045 $2,389,680 $2,480,929 $2,560,322 $2,643,489 $2,732,757 $2,815,261 $2,903,307
CCE Program Surplus/(Deficit) ($251,826) ($141,452) ($332,690) ($158,787) ($228,544) ($212,673) ($264,390) ($311,418) ($347,943) ($393,336} ($443,808)
CCE Cumulative Reserves From Operations ($251,826) ($393,278) ($725,967) ($884,754) ($1,113,298) ($1,325,971) ($1,590,361) ($1,901,779) ($2,249,722) ($2,643,058) ($3,086,866}
Reserve Additions
Operating Reserve Contributions ($251,826) ($141,452) ($332,690) ($158,787) ($228,544) ($212,673) ($264,390) ($311,418) ($347,943) ($393,336) ($443,808)
Cash from Financing $800,000 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Total Additions $548,174 ($141,452) ($332,690) ($158,787) ($228,544) ($212,673) ($264,390) ($311,418) ($347,943) ($393,336) ($443,808)
Reserve Targets $82,792 $639,791 $805,501 $756,837 $785,648 $815,648 $841,750 $869,092 $898,441 $925,565 $954,512
Reserve Outlays
Start-up Funding Payments + Bonds +"Collateral $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Working Capital Repayment (Remainder) $0 $0 $0 $415,887 $0 $0 $0 $0 $0 $0 $0
New Programs/Additional Rate Savings $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Total Reserve Outlays $0 $0 $0 $415,887 $0 $0 $0 $0 $0 $0 $0
Rate Stabilization Reserve Balance $548,174 $406,722 $74,033 ($500,641) ($729,185) ($941,858) ($1,206,248) ($1,517,666) ($1,865,609) ($2,258,945) ($2,702,754)
CCE Total Bill $0 $6,226,877 $8,091,861 $8,244,958 $8,401,140 $8,641,352 $8,804,912 $8,971,768 $9,141,990 $9,315,648 $9,492,815
SDG&ETotal Bill $0 $6,289,775 $8,173,597 $8,328,241 $8,486,000 $8,728,638 $8,893,850 $9,062,392 $9,234,333 $9,409,746 $9,588,702
Difference $0 $62,898 $81,736 $83,282 $84,860 $87,286 $88,939 $90,624 $92,343 $94,097 $95,887
Savings 0% 1% 1% 1% 1% 1% 1% 1% 1% 1% 1%
Community Choice Energy Technical Feasibility Study 99
April 16, 2019 Item #4 Page 111 of 132
Exhibit H-3
City of Encinitas
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Revenues from Operations($)
Electric Sales Revenues $0 $15,560,386 $18,265,099 $18,485,981 $18,641,093 $19,575,940 $19,815,685 $20,128,660 $20,585,245 $20,906,585 $21,232,090
Less Uncollected Accounts $0 $26,719 $35,085 $34,335 $35,655 $37,190 $38,441 $39,755 $41,095 $42,470 $43,861
Total Revenues $0 $15,533,667 $18,230,015 $18,451,646 $18,605,437 $19,538,750 $19,777,244 $20,088,904 $20,544,150 $20,864,116 $21,188,229
Cost of Operations ($)
Cost of Energy $0 $10,653,682 $14,775,949 $15,305,797 $15,924,692 $16,660,166 $17,248,534 $17,867,391 $18,492,919 $19,145,956 $19,800,804
Operating & Administrative
Billing & Data Management $0 $311,181 $424,074 $433,637 $443,416 $453,415 $463,639 $474,094 $484,785 $495,717 $506,896
SDG&E Fees $0 $70,157 $70,332 $70,508 $70,684 $70,861 $71,038 $71,216 $71,394 $71,572 $71,751
SDG&E Setup and Startup Fees $0 $57,106 $60,706 $0 $0 $0 $0 $0 $0 $0 $0
Consulting Services $168,300 $421,362 $456,319 $465,446 $474,755 $484,250 $493,935 $503,814 $513,890 $524,168 $534,651
Staffing $561,000 $1,144,440 $1,167,329 $1,190,675 $1,214,489 $1,238,779 $1,263,554 $1,288,825 $1,314,602 $1,340,894 $1,367,712
General & Administrative expenses $7,140 $130,050 $132,651 $135,304 $143,110 $140,770 $143,586 $146,457 $154,487 $152,374 $155,422
Debt Service $114,607 $939,777 $939,777 $0 $0 $0 $0 $0 $0 $0 $0
Total O&A Costs $851,047 $3,074,073 $3,251,189 $2,295,571 $2,346,454 $2,388,075 $2,435,752 $2,484,406 $2,539,157 $2,584,725 $2,636,431
Total Cost & Reserves $851,047 $13,727,755 $18,027,138 $17,601,368 $18,271,146 $19,048,241 $19,684,286 $20,351,798 $21,032,076 $21,730,681 $22,437,235
CCE Program Surplus/(Deficit) ($851,047) $1,805,912 $202,877 $850,278 $334,291 $490,509 $92,957 ($262,893) ($487,926) ($866,565) ($1,249,006)
CCE Cumulative Reserves From Operations ($851,047) $954,865 $1,157,742 $2,008,020 $2,342,311 $2,832,820 $2,925,777 $2,662,884 $2,174,958 $1,308,393 $59,387
Reserve Additions
Operating Reserve Contributions ($851,047) $1,805,912 $202,877 $850,278 $334,291 $490,509 $92,957 ($262,893) ($487,926) ($866,565) ($1,249,006)
Cash from Financing $4,100,000 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Total Additions $3,248,953 · $1,805,912 $202,877 $850,278 $334,291 $490,509 $92,957 ($262,893) ($487,926) ($866,565) ($1,249,006)
Reserve Targets $279,796 $4,513,235 $5,926,730 $5,786,751 $6,006,952 $6,262,435 $6,471,546 $6,691,002 $6,914,655 $7,144,333 $7,376,625
Reserve Outlays
Start-up Funding Payments + Bonds + Collateral $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Working Capital Repayment (Remainder) $0 $0 $0 $2,436,089 $0 $0 $0 $0 $0 $0 $0
New Programs/Additional Rate Savings $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Total Reserve Outlays $0 $0 $0 $2,436,089 $0 $0 $0 $0 $0 $0 $0
Rate Stabilization Reserve Balance $3,248,953 $5,054,865 $5,257,742 $3,671,931 $4,006,222 $4,496,731 $4,589,688 $4,326,795 $3,838,869 $2,972,304 $1,723,298
CCETotal Bill $0 $53,128,364 $69,101,269 $70,406,455 $71,737,902 $73,803,562 $75,198,065 $76,620,634 $78,071,862 $79,552,350 $81,062,798
SDG&E Total Bill $0 $53,665,014 $69,799,262 $71,117,631 $72,462,528 $74,549,053 $75,957,641 $77,394,580 $78,860,466 $80,355,909 $81,881,532
Difference $0 $536,650 $697,993 $711,176 $724,625 $745,491 $759,576 $773,946 $788,605 $803,559 $818,733
Savings 0% 1% 1% 1% 1% 1% 1% 1% 1% 1% 1%
Community Choice Energy Technical Feasibility Study 100
April 16, 2019 Item #4 Page 112 of 132
Exhibit H-4
City of Oceanside
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Revenues from Operations($)
Electric Sales Revenues $0 $42,496,299 $50,108,857 $SO, 706,301 $51,138,293 $53,424,355 $54,068,784 $54,898,185 $56,090,096 $56,941,092 $57,802,625
Less Uncollected Accounts $0 $70,035 $91,023 $90,024 $93,533 $97,661 $100,899 $104,377 $107,934 $111,634 $115,242
Total Revenues $0 $42,426,264 $50,017,834 $50,616,277 $51,044,760 $53,326,695 $53,967,885 $54,793,808 $55,982,161 $56,829,458 $57,687,383
Cost of Operations($)
Cost of Energy $0 $28,842,815 $39,547,303 $40,965,422 $42,621,873 $44,590,344 $46,165,089 $47,821,438 $49,495,640 $51,243,470 $52,996,149
$59.88 $62. 70 $64.79 $67.24 $70.17 $72.47 $74.88 $77.31 $79.84 82.36493438
Operating & Administrative
Billing & Data Management $0 $787,958 $1,072,220 $1,096,399 $1,121,122 $1,146,404 $1,172,255 $1,198,689 $1,225,720 $1,253,360 $1,281,623
SDG&E Fees $0 $177,383 $177,826 $178,271 $178,717 $179,163 $179,611 $180,060 $180,510 $180,962 $181,414
SDG&E Setup and Startup Fees $0 $98,534 $102,134 $0 $0 $0 $0 $0 $0 $0 $0
Consulting Services $426,700 $1,617,822 $1,411,407 $1,439,635 $1,468,427 $1,497,796 $1,527,752 $1,558,307 $1,589,473 $1,621,263 $1,653,688
Staffing $389,299 $2,204,114 $2,248,196 $2,293,160 $2,339,023 $2,385,804 $2,433,520 $2,482,190 $2,531,834 $2,582,471 $2,634,120
General & Administrative expenses $28,560 $181,030 $132,651 $135,304 $158,410 $177,184 $143,586 $146,457 $169,787 $188,788 $155,422
Debt Service $114,607 $1,994,161 $1,994,161 $0 $0 $0 $0 $0 $0 $0 $0
Total O&A Costs $959,166 $7,061,002 $7,138,S96 $S,142,768 $5,265,700 $5,386,351 $5,456,724 $5,565,704 $S,697,324 $5,826,843 $5,906,267
Total Cost & Reserves $959,166 $35,903,818 $46,685,898 $46,108,190 $47,887,573 $49,976,695 $51,621,813 $53,387,143 $55,192,964 $57,070,313 $58,902,416
CCE Program Surplus/(Deficit) ($959,166) $6,522,446 $3,331,936 $4,508,087 $3,157,187 $3,350,000 $2,346,072 $1,406,665 $789,197 ($240,856) ($1,215,033)
CCE Cumulative Reserves From Operations ($959,166) $5,563,280 $8,895,216 $13,403,303 $16,560,490 $19,910,490 $22,256,562 $23,663,227 $24,452,424 $24,211,569 $22,996,536
Reserve Additions
Operating Reserve Contributions ($959,166) $6,522,446 $3,331,936 $4,508,087 $3,157,187 $3,350,000 $2,346,072 $1,406,665 $789,197 ($240,856) ($1,215,033)
Cash from Financing $8,700,000 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Total Additions $7,740,834 $6,522,446 $3,331,936 $4,508,087 $3,157,187 $3,350,000 $2,346,072 $1,406,665 $789,197 ($240,856) ($1,215,033)
Reserve Targets $315,342 $11,803,995 $15,348, 789 $15,158,857 $15,743,860 $16,430,694 $16,971,555 $17,551,937 $18,145,632 $18,762,843 $19,365,178
Reserve Outlays
Start-up Funding Payments + Bonds + Collateral $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Working Capital Repayment (Remainder) $0 $0 $0 $5,279,527 $0 $0 $0 $0 $0 $0 $0
New Programs/Additional Rate Savings $0 $0 $0 $1,664,918 $0 $5,235,350 $0 $2,631,494 $0 $0 $0
Total Reserve Outlays $0 $0 $0 $6,944,446 $0 $5,235,350 $0 $2,631,494 $0 $0 $0
Rate Stabilization Reserve Balance $7,740,834 $14,263,280 $17,595,216 $15,158,857 $18,316,045 $16,430,694 $18,776,766 $17,551,937 $18,341,135 $18,100,279 $16,885,246
CCETotal Bill $0 $135,242,074 $173,691,247 $176,918,945 $180,210,981 $185,239,832 $188,684,975 $192,198,638 $195,782,250 $199,437,273 $203,165,200
SDG&ETotal Bill $0 $138,002,116 $177,235,967 $180,529,536 $183,888,568 $189,020,237 $192,535,689 $196,121,059 $199,777,806 $203,507,422 $207,311,429
Difference $0 $2,760,042 $3,544,719 $3,610,591 $3,677,587 $3,780,405 $3,850,714 $3,922,421 $3,995,556 $4,070,148 $4,146,229
Savings 0% 2% 2% 2% 2% 2% 2% 2% 2% 2% 2%
Community Choice Energy Technical Feasibility Study 101
April 16, 2019 Item #4 Page 113 of 132
//RWG
LAW
March 6, 2019
Crystal Najera
Climate Action Plan Program Administrator
Gregory W. Stepanicich
T 415.421.8484
F 415.421.8486
E gstepanicich@rwglaw.com
City of Encinitas I City Manager's Office I Environmental
Services
505 S Vulcan Ave
City of Encinitas, CA 92024
Re: Proposal for CCA Legal Services
Dear Crystal:
Attachment B
44 Montgomery Street, Suite 3800
San Francisco, CA 94104-4811
rwglaw.com
Thank you very much for asking Richards Watson Gershon ("RWG") to submit a proposal to
provide legal services to the City of Encinitas (Encinitas) in connection with its consideration of
participating in a Community Choice Aggregation (CCA) program. We understand that
Encinitas currently is exploring the formation of a Joint Powers Authority to conduct this
program with the Cities of Carlsbad, Del Mar, and Oceanside. The City of Encinitas also is
exploring whether it would join the Joint Powers Authority that the City of San Diego is
proposing.
Long Term Experience in Forming CCA's Using the JPA Model
With my Firm, I have been involved in the formation of Joint Powers Authorities for the
operation of CCA programs from the beginning in 2008. I drafted the CCA JPA Agreement for
Marin Clean Energy (MCE) in 2008. This was a collaborative effort by the County of Marin and
the Marin cities and towns. This effort met very aggressive opposition from the incumbent
utility PG&E, but CCA service was launched in 2010 and MCE has been very successful with
expansion to Napa, Solano and Contra Costa Counties. I was MCE's first General Counsel until
in-house General Counsel was hired. RWG continues to serve as special counsel to MCE. The
MCE form of JPA Agreement has been the model for all subsequent CCA's that were formed as
JPA's.
In 2016, I assisted in the formation of Silicon Valley Clean Energy (SVCE) including preparing all
of its formation and start up documents. This also was a collaborative effort with an initial
San Francisco Los Angeles Orange County Temecula Central Coast RICHARDS WATSON GERSHON April 16, 2019 Item #4 Page 114 of 132
Crystal Najera
March 6, 2019 Page I 2
formation committee made up of four agencies which led to a Joint Powers Authority made up
of the County of Santa Clara and 12 cities and towns. I continue to serve as SVCE's General
Counsel.
My partner lnder Khalsa and I were involved in the formation of East Bay Community Energy
(EBCE) and lnder served as the interim General Counsel before they hired in-house General
Counsel. We continue to serve EBCE as special counsel. lnder currently serves as General
Counsel to San Francisco LAFCO which oversees San Francisco's CCA program, called
CleanPowerSF.
This past year, I worked with the City of San Luis Obispo in the formation of Central Coast
Community Energy (CCCE) along with the City of Morro Bay, including drafting the JPA
Agreement and a comprehensive agreement with the Energy Authority, Inc. for technical
services and energy purchasing. Due to the significant increase in the PCIA this past October,
San Luis Obispo and Morro Bay decided to dissolve CCCE and join Monterey Bay Community
Power (MBCP), an existing JPA. I assisted both of these cities in becoming members of MBCP,
including drafting a necessary amendment to MBCP's JPA Agreement.
In our experience, every effort to form a CCA is fast-paced. We have the necessary expertise
and resources to meet the deadlines required for the formation of a CCA.
Proposed Legal Services
. We have a team of attorneys in our Firm working regularly on CCA matters. In addition to lnder
and myself, this team includes David Snow and Casey Strong. Dave has worked with MCE on
CEQA compliance questions. His work with other types of joint powers authorities includes
environmental and governance issues for the Burbank-Glendale-Pasadena Airport Authority.
Casey is the Assistant General Counsel for SVCE and provides special counsel services to MCE,
EBCE and San Francisco LAFCO. The biographies of each of these attorneys who all specialize in
representing cities and other local public agencies are attached.
Based on our initial conversation and your subsequent input, we are proposing the following
legal services:
• Review of CCA governance analysis prepared by your consultant EES.
• If requested, provide our recommendations on the preferred governance option or
options.
• Review, evaluate and provide advice on draft JPA Agreements prepared by other
entities that are given to us for our review, advice and recommendations.
: ) /." ·-;•,t1 ~:t>:Jt;i.·fr~~·:~;e~.~. ', ,),~~{f•,❖ 4"; ;~t?l!fJ;-'1:.'-:+'::-••~;;: ~~-""i:f . ;~/: < rt1.;,'; }t ){~~}
.i: '· :,:,Ri,68 AR 6s:,WA·TS o N': G0
E Rs H o'f\r"\{ .£-i".. ~--.,:,,. ;.::.,,_h :'.:, ,. t,.,q ',',,:rt;i/ :?~-~~-..1<.J•...,,1:~..!.;:....~;,,,.,;,;;~ .t;~:·,._:; -:"J,?, 'm~:.~.,,..} ,_ ,..:';., 1::i-~: ~,1 ~.,;1 April 16, 2019 Item #4 Page 115 of 132
Member, California City Management Foundation Board ofTrustees (2010-2018)
American Bar Association
Marin County Bar Association
San Francisco Bar Association
Member, Urban Land Institute
EXPERIENCE
HIGHLIGHTED PROJECTS
► Marin Clean Energy Formation. Greg provided legal guidance and drafted the formation documents for the
establishment of Marin Clean Energy, the first community choice energy program for electricity service in
California. The key concern in forming this joint powers authority was whether its individual members could be
liable for the significant contractual obligations of the authority under its power purchase agreements. Greg
developed multiple layers of liability protection to insulate the members of the authority from the authority's
debts, liabilities, and obligations in conducting its community choice aggregation program. The legal structure of
Marin Clean Energy has become the model for other community choice energy programs conducted by joint
powers authorities in California.
► Silicon Valley Clean Energy Formation. Greg assisted in the formation of the Silicon Valley Clean Energy
Authority, another community choice energy program, which is made up of the County of Santa Clara and eleven
cities in this county and continues to serve the authority as General Counsel.
► San Francisquito Creek Flood Control and Creek Restoration Project. Greg has been providing on-going advice
to San Fransciquito Creek Joint Powers Authority on the planning, environmental review and construction of
major flood control and creek restoration projects, including working with member agency legal counsel and
staff on the preparation of local funding agreements made necessary by the delays and uncertainty in federal
funding. Greg also assisted the authority on a very contentious permitting process for its initial project with the
San Francisco Bay Regional Water Quality Control Board.
► Marin Telecommunications Agency Cable Franchise Agreement. After negotiating many cable franchise
agreements for cities dating back to the early 198o's1 Greg negotiated one of the last local cable television
franchises in California for the Marin Telecommunications Agency, made up of ten cities and towns and the
County of Marin. The negotiation of this franchise agreement extended over six years with multiple cable
franchisees. The final agreement with Comcast featured a very advantageous and unusual provision providing
Stepanicich 2
April 16, 2019 Item #4 Page 118 of 132