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HomeMy WebLinkAbout2019-04-16; City Council; ; Resolution Accepting the North San Diego County Cities Community Choice Energy Technical Feasibility Study and Authorizing Participation in a Legal Services Cost Share AgCA Review ~ ~ CITY COUNCIL • Staff Report Meeting Date: To: From: Staff Contact: Subject: April 16, 2019 Mayor and City Council Scott Chadwick, City Manager Jason Haber, Assistant to the City Manager jason.haber@carlsbadca.gov or 760-434-2958 Resolution Accepting the North San Diego County Cities Community Choice Energy Technical Feasibility Study and Authorizing Participation in a Legal Services Cost Share Agreement Recommended Action Approve a resolution accepting the North San Diego County Cities Community Choice Energy (CCE) Technical Feasibility Study and authorizing the City Manager to negotiate, execute and fund a cost share agreement for the City of Carlsbad's participation in procuring joint legal services to assist the city in negotiating and preparing CCE formation documents in an amount not to exceed $20,000 (Exhibit 1). Executive Summary California Assembly Bill 117 allows local governments to form 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. This gives CCEs the opportunity to design and potentially reduce retail rates for their constituents, promote local economic development and offer a cleaner power supply. On July 11, 2017, the City Council approved Resolution No. 2017-141 authorizing the City of Carlsbad's participation in a Community Choice Energy Technical Feasibility Study. This item presents for City Council consideration, a resolution accepting the North San Diego County CCE Technical Feasibility Study, which evaluates the financial feasibility of a potential CCE for the cities of Carlsbad, Encinitas, Del Mar and Oceanside (Partner cities). The resolution also authorizes city participation in a cost share agreement to procure joint legal services to assist the city in negotiating and preparing CCE formation documents. Discussion On July 11, 2017, the 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. On January 24, 2018, a cost share agreement was executed among the April 16, 2019 Item #4 Page 1 of 132 cities of Carlsbad, Encinitas, Del Mar and Oceanside (Partner cities) to engage EES Consulting, Inc. (EES) to prepare a CCE Technical Feasibility Study in the amount of $104,515. The City of Carlsbad's not-to-exceed cost share totaled $30,775. A draft feasibility study was presented to City Council on February 26, 2019. At that time, the City Council directed staff to work with EES and the Partner cities to achieve final acceptance of the study, to include participating in a public workshop a"nd soliciting community feedback on the draft study. The City Council also approved Resolution No. 2019-025 authorizing the City Manager to negotiate, execute and fund a cost share agreement with the Partner cities to participate in an evaluation of CCE program governance options in an amount not to exceed $35,000. A cost share agreement among the cities of Carlsbad, Encinitas and Del Mar was signed by the City Manager on March 28, 2019, with a City of Carlsbad not-to-exceed cost share in the amount of $33,995. On March 19, 2019, the City Council adopted Resolution No. 2019-036, expressing the City Council's intention to pursue a community choice energy program that prioritizes certain operating principles. A public meeting was held on March 21, 2019, at which staff from the Partner cities and EES shared the results of the feasibility study with community stakeholders, received feedback and answered questions. The meeting was attended by approximately 50 people from Carlsbad, Del Mar, Encinitas and Oceanside, including representatives ofthe Carlsbad Chamber of Commerce and Carlsbad Unified School District, among others. While the discussion covered a wide range of issues, questions and concerns regarding CCE and the draft feasibility study, it did not result in any substantive changes to the study's findings, conclusions or recommendations. EES has prepared responses to "Frequently Asked Questions Regarding the CCE Feasibility Study Prepared for the Cities of Carlsbad, Del Mar, Encinitas and Oceanside" (Exhibit 2). This document answers several of the questions raised at the March 21 public meeting, as well as those raised in the correspondence received from Mayor Hall on March 11, 2019 (Exhibit 3). North San Diego County Cities Community Choice Energy Technical Feasibility Study The North San Diego County Cities CCE Technical Feasibility Study estimates the costs of launching and operating a CCE for the Partner cities and presents a CCE retail rate forecast for the years 2021 through 2030. The projected retail rates for the CCE are then compared to the SDG&E projected rates for the Partner cities' service area. Based on these rate comparisons, associated economic development and greenhouse gas (GHG) comparisons are made. The study also discusses a variety of operational and governance options and presents a sensitivity analysis of key market variables. The study finds that the formation of a Partner cities CCE is financially feasible and could yield considerable benefits for all participating residents and businesses. Benefits could include electric retail rates that are at least 2% lower than SDG&E rates. April 16, 2019 Item #4 Page 2 of 132 The study also assesses the feasibility of each Partner city forming its own, stand-alone CCE. The study finds that the larger cities, Oceanside and Carlsbad, could form a financially feasible CCE offering retail rates at least 2% lower than SDG&E rates and found that the City of Encinitas could feasibly form a CCE with rates at least 1% lower than SDG&E. The study determines that, of the formation scenarios evaluated, the most financially feasible option would be to form a CCE comprising all four Partner cities. The study finds that CCE start-up costs could be fully recovered within the first three years of CCE operations. After start-up cost recovery, revenues that exceed costs could be used to finance a rate stabilization fund, development of new local renewable resources, economic development initiatives and/or lower customer electric rates. Other benefits of forming a CCE are also summarized in the study and include local control over power supply, economic development stimulus, and the ability to offer enhanced customer incentive programs. The study acknowledges and provides a detailed discussion of several variables and uncertainties that could affect CCE feasibility, including: • SDG&E Rates and Surcharges • Regulatory Risks • Power Supply Costs • SDG&E RPS Share • Availability of RPS/GHG-Free Power • Financial Risks • Loads and Customer Participation The study's sensitivity analysis shows that costs projected under most combinations of variables and potential market conditions will not negatively impact CCE rates compared to SDG&E rates, and where negative impacts may exist, those risks can be mitigated. In summary, the study concludes that "the positive impacts on the Partner cities and their inhabitants of forming a CCE suggest that this effort should be considered." Joint Legal Services -Cost Share Proposal As noted in the study, several options are available to the City Council in deciding whether and how to pursue the implementation of Community Choice Energy. These include: Forming a City of Carlsbad CCE (stand-alone) Forming or Joining a CCE Joint Powers Authority (JPA) o Forming a Partner Cities/North San Diego County/South Orange County JPA o Forming a San Diego Regional JPA (including City/County of San Diego) o Joining an Existing JPA (i.e., Solana Beach, Los Angeles) April 16, 2019 Item #4 Page 3 of 132 On February 26, 2019, the City Council approved Resolution No. 2019-025 authorizing the City Manager to negotiate, execute and fund an agreement to join the Partner cities in a technical evaluation of potential CCE program governance options. On March 19, 2019, the City Council adopted Resolution No. 2019-036, expressing the City Council's intention to pursue a community choice energy program that prioritizes certain operating principles. The City of Encinitas obtained proposals from law firms interested in providing joint legal services to assist the Partnerdties in negotiating and preparing CCE formation documents, concurrent with the evaluation of potential CCE program governance options. Staff from Carlsbad, Encinitas and Del Mar are recommending that Richards Watson Gershon (RWG) Law be retained to provide such services. RWG's proposal is attached to the resolution in Exhibit 1, which authorizes the City Manager to negotiate, execute and fund a cost share agreement for the City of Carlsbad's participation in procuring joint legal services to assist the city in negotiating and preparing CCE formation documents in an amount not to exceed $20,000. Should the City Council decide to participate, staff would execute an agreement that applies the cost sharing formula that was used among the Partner cities previously. As such, costs would be apportioned on a combined fixed cost (10%) and population-based proportional cost basis, including a 5% administrative fee to be paid to the City of Encinitas for project management and contract administration services. Anticipating a three-party cost share agreement among the cities of Carlsbad, Del Mar and Encinitas, the City of Carlsbad cost share amount is estimated at $20,000. Adoption of this re~olution in no way obligates the City of Carlsbad to participate in any future decision to establish a Community Choice Energy program. Fiscal Analysis Funding for the CCE Technical Feasibility Study was approved by Resolution No. 2017-141, which appropriated up to $60,000 from the City Council Contingency Fund. The total cost of the study ($104,515) was shared among the Partner cities of Carlsbad, Del Mar, Encinitas and Oceanside. The City of Carlsbad's share of the total.cost was $30,775. On February 26, 2019, the City Council approved Resolution No. 2019-025 authorizing participation in an evaluation of CCE program governance options in an amount not to exceed $35,000 from the City Council Contingency Fund. A cost share agreement among the cities of Carlsbad, Encinitas and Del Mar was signed by the City Manager on March 28, 2019, with a City of Carlsbad not-to-exceed cost share in the amount of $33,995. The recommended action requires an additional transfer and appropriation from the City Council Contingency Fund in an amount not to exceed $20,000 to fund the City of Carlsbad's 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 4 of 132 Should the City Council decide to continue its evaluation of CCE, and ultimately decide to proceed toward CCE implementation, additional analysis would be required to fully understand the fiscal impacts of CCE. Next Steps Pursuant to City Council direction, staff is working with EES and the Partner cities of Del Mar and Encinitas to evaluate CCE program governance options. It is anticipated that the evaluation of CCE program governance options will be completed in August 2019. Upon receiving direction from City Council, staff will notify the City of Encinitas of the city's decision regarding the proposal to provide joint legal services. Should the City Council decide to participate, staff will enter into negotiations with the Partner cities to complete a cost share agreement. The projected schedule provided in Appendix A of the CCE Feasibility Study identifies one possible procedural pathway to accomplish the necessary legislative, regulatory, administrative and operational steps to achieve a 2021 CCE program launch, which would be the city's earliest possible opportunity to do so. Environmental Evaluation (CEQA) The project is exempt from the California Environmental Quality Act (CEQA) per State CEQA Guidelines Section 15262 -Feasibility and Planning Studies, which exempts a project involving only feasibility or planning studies for possible future actions which the agency, board, or commission has not approved, adopted, or funded. Public Notification This item was noticed in accordance with the Ralph M. Brown Act and was available for public viewing and review at least 72 hours prior to scheduled meeting date. A public meeting was held on March 21, 2019, for staff from the Partner cities and EES to share the results of the feasibility study with community stakeholders, receive feedback and answer questions. The meeting was attended by approximately 50 people from Carlsbad, Del Mar, Encinitas and Oceanside. Exhibits 1. City Council Resolution 2. Frequently Asked Questions Regarding the CCE Feasibility Study Prepared for the Cities of Carlsbad, Del Mar, Encinitas and Oceanside 3. March 11, 2019 -Correspondence from Mayor Hall April 16, 2019 Item #4 Page 5 of 132 RESOLUTION 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. 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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 Community Choice Energy Frequently Asked Questions Exhibit 2 The cities of Carlsbad, Del Mar, Encinitas and Oceanside are working together to evaluate a new approach to providing electric power in their communities. This new approach is called Community Choice Energy (CCE). An initial CCE feasibility study was completed in March 2019. 1. Is the CCE model economically feasible? What would the potential ratepayer savings be? A feasibility study shows that the CCE model is financially feasible and would save residents and businesses at least 2% a year compared to SDG&E. In addition, discretionary net proceeds of roughly $15 million could be generated annually. This net income could be used for further rate savings, investment in local distributed energy generation, enhanced energy efficiency programs, additional support for low-income customers, energy storage, electric vehicle charging and any other program related to the CCE business model. The decisions regarding utilization of discretionary net income will rest with the CCE Board of Directors. 2. What assumptions were made about purchasing renewable energy? The feasibility study assumes and evaluates three different CCE power supply portfolios: • Option 1-Same renewable portfolio used by SDG&E -increases from 46% renewable energy in 2021 to 60% in 2030. • Option 2 -100% renewable energy by 2030 -increases from 50% renewable energy in 2021 to 100% in 2030. • Option 3 -100% renewable energy throughout the study period (2021-2030). CCEs face the same requirements for renewable energy purchases as the investor-owned utilities (such as SDG&E) and public utilities and are required to comply with all applicable state laws (including SB 350 and SB 100). The feasibility study also assumes all renewable resources are located in California, and no unbundled renewable energy credit utilization. 3. Would the CCE model help reduce greenhouse gas emissions? Yes, all three options evaluated in the feasibility study would reduce greenhouse gas emissions at various levels during the study period (2021-2030). • The Option 1 portfolio is 80% greenhouse gas free throughout the study period. • The Option 2 portfolio is 80% greenhouse gas free in 2021, ramping up to 100% greenhouse gas free in 2030. • The Option 3 portfolio is 100% greenhouse gas free throughout the study period. For comparison, SDG&E's portfolio is expected to be 46% greenhouse gas free in 2021, ramping up to 60% greenhouse gas free in 2030. April 16, 2019 Item #4 Page 128 of 132 8. Does the feasibility study assess the risk of a potential increase in customers buying their electricity directly from electric service providers (Direct Access)? California Senate Bill 237, Electricity: direct transactions (adopted in 2018) provides for a 16% increase in the amount of nonresidential load that can move to direct access schedules. For commercial and industrial accounts, the feasibility study assumes a participation rate of 85%, which adjusts historic participation rates to account for the newly expanded cap on direct access. 9. Will grid reliability change under the CCE business model? Maintaining grid reliability is the function and responsibility of the California Independent System Operator. The California Independent System Operator will continue to perform this function under the CCE business model, therefore grid reliability will remain unchanged. 10. Will the growth in CCEs adversely impact the financial stability of the incumbent investor- owned utilities? The power charge indifference adjustment was implemented to ensure that the investor- owned utilities were held harmless from load loss resulting from the growth in CCE programs or direct access . 11. SDG&E pays local, state and federal taxes. Will the recipients of these tax payments be negatively impacted? The primary taxes that SDG&E pays are property, state and federal income taxes. Under the CCE business model, all SDG&E tax recipients will not be impacted. SDG&E will maintain the same asset base if a CCE is formed so property tax payments will be unchanged. Income tax is paid based upon profitability. SDG&E makes its profits on delivery facilities which will remain with SDG&E so profitability and income taxes payable will remain unchanged. The only function the CCE will assume from SDG&E is power procurement. SD&GE is prohibited by law from earning a profit on the power procurement function. 12. How will the formation of a CCE program for the four cities impact the local economy? A CCE program could save customers in Carlsbad, Del Mar, Encinitas and Oceanside approximately $9 million annually in electricity costs. This increase in disposable income could result in the creation of approximately 100 new local jobs and $13 million in new annual local economic activity. The CC E's economic impact could be greater if the CCE invests in local distributed energy resources. Through incentive programs and direct investments CCEs can create new demand for manufacturing, construction and installation of local distributed energy resources, leading to an increase in employment in those sectors. Decisions concerning investments in distributed energy resources, such as the construction of new community solar or battery storage projects, would be made by the CCE Board of Directors. Frequently Asked Questions -Community Choice Energy 3 April 16, 2019 Item #4 Page 130 of 132 Exhibit 3 (Correspondence from Mayor Hall -Received March 11, 2019) Has this been updated in the study? Does EES still conclude this is economically feasible? If not, shouldn't we update the study before we take this show on the road? Further the EES study indicates that the purchases of renewable energy costs were based on buying this energy on the short term basis. I'd like to know what the study contemplated the City buying? More specifically, what is this short term product? Is this from new renewable energy resources? If so, I'd like to know how many new jobs this will create and the timelines for these jobs. If not, what are we buying? Is this hydro, solar or wind energy from existing generation facilities? Here's why I ask. If the EES study contemplated our CCA buying in the short market from existing renewable energy resources, I believe we ought to ask our consultant to explain how this buying from renewable energy projects incrementally reduces our greenhouse gas emission and actually benefits the environment. Recently, the Sierra Club sued San Diego's County's Climate Action Plan (CAP) for relying on carbon tax reductions outside of California. I believe the Sierra Club's concern was that this didn't actually result in GHG reductions and left room for abuse. If our CCA study is based on purchases on the short term market from existing renewable projects, I would like to know how we can take credit for incremental GHG reductions. I understand that the California public utilities are required to buy renewable energy exclusively from newly built renewable projects. This is important because the only way to actually reduce GHG emissions and to create new jobs is to build new renewable energy projects. If I'm wrong, please educate me. Did the study account for the State law requirement (S8350) that 65% of our energy contracts come from long term agreement by 2021? I did not see this in the study. Please point where in the study it addresses this upcoming State requirement. How does the environment benefit from us buying hydro or solar power that is already running? Don't we have to build new renewable energy projects so we can stop fossil fuel plants from running? Did the study actually study apples to apples? In other words, if the utilities are building new renewable energy projects, should our study compare the costs of a CCA building new renewable energy projects? Also, how does the consultants study help us by comparing percentages of renewable energy between the CCA and the Utility when it compares apples to oranges? April 16, 2019 Item #4 Page 131 of 132 I believe the study should compare the costs to build new generation facilities. If it doesn't perhaps we ought to start all over again. Our environment is too important to allow someone to represent that facts. I'd like to also know when we plan to build new renewable energy projects and the jobs we'll create through this program. More specifically, please provide the timelines for new projects (when will these projects be built, Megawatt size of project and estimated jobs created). The CCA study should not be a comparison of percentages of renewable energy if we're not comparing the same product . Also, since the State of California passed SB 100 during the last legislative session, how will Carlsbad beat that goal when the State will require that we get to the 100% goal anyway? The State of California passed a new law that will reopen direct access to customers. This law was passed and signed into law after the CCA was completed. This new law, which was opposed by the CCA industry, will now allow customers to one again purchase their electricity outside of the utility or CCA. This means that customers could leave a CCA and purchase energy on their own. This could create enormous risk to a CCA. Did the EES study . evaluate this risk? If so, please point this out to the City Council. Lastly, the study indicates that the utility rates will go up 2-9% through the course of the study. Is this just the energy component of the bill? Please provide back up detail how this projection was arrived at. According to the staff report, the recommendation is to now join the Partner cities in a technical evaluation of potential CCA program governance options. Are we ready to do this now when the financial picture may have changed? I recommend we get answers to my questions and we have an independent third party review these answers. I recommend we have a well-known and reputable CPA firm analyze the study. As stated above, I can support this new venture if it will truthfully reduce costs, create jobs and actually benefit the environment. However, this is a complicated and risky industry. We witnessed this when California tried to de regulate the energy industry in 2000. We need to be very careful and prudent with our constituent's tax dollars before we get into the energy commodity business. I realize that CCA's have been in operation for about 7-8 years in California but much has changed in the last year both at the CPUC and Legislature. Keep in mind, customers always have the option of leaving our CCA and returning to SDGE. This could leave us in a bad financial situation. April 16, 2019 Item #4 Page 132 of 132 To the members ofth~: CITY COUNCIL Date 4\uol ll\ CA ✓ cc ✓ cM_rmo-_coo..i_ocM(3) J April 16, 2019 Council Memorandum · To: Honorable MaycirHall<af¼~"81.R-'1ers of the City Council From: Scott Chadwick, City M na {c1tyof Carlsbad Re: Responses to Questions rom April 15, 2019 City Council Briefings Agenda Item No. 1-REPORT ON CITY INVESTMENTS ~ Question 1: '~All pooled investments have been made in accordance 'Nith the city's Investment Policy adopted January 2, 1985 and last revised January 8, 2019." Can you ple_ase confirm that the City Treasurer makes recommendations only, and will be bringing the policy back to Council for concurrence in regard to divestment from fossil fuels? Answer: City Council has.the final authority in matters of investment decisions within the constraints of the investment policy. Although the City Treasurer annually revises the City's Investment Policy, the City Council majority has to approve all changes to the Investment . Policy. . Question 2: Regarding Exhibit 8, can you please expand on how the Park Development Fund is · used? Answer: These funds are used to acquire park land and develop dty parks, in-lieu of a developer building a park themselves. There are four funds broken out by quadrant within the city with an addition~! fund for Zone 5. These five funds equal the $7,738,237 shown in Exhibit 8 to the staff report. Question 3: Are the Gas Tax funds already allocated for specific mobility projects? Answer: A majority of the Gas Tax funds (including SBl) have been allocated/programmed for specific projects. There is some flexibility for re-programming projects or adding new projects. There are specific rules that govern the spending of Gas Tax funds (including SBl). These projects are identified in the city's adopted capital improvement program budget for FY 2018- 19 on page J-2 of the capital improvement summary by fund section. Agenda Item No. 4-COMMUNITY CHOICE ENERGY TECHNICAL FEASIBILITY STUDY , Question 1: How is the Coun.cil Contingency Fund used here, and in general how has it been used· by Council? Answer: Per the-staff report dated 7/11/2017, Council authorized staff to spend up to $60,000 for the city's share of a regional Community Choice Energy Technical Feasibility Study. This is City Manager's Office City Hall 1200 Carlsbad Village Drive I Carlsbad, CA 92008 I 760-434-4820 t Honorable Mayor Hall and Members of the City Council April 16, 2019 Page 2 being led by the City of Encinitas. See the staff report for additional information: http://edocweb/HPRMWebClient/HPRMServiceApi/Record/477095/File/Document. Staff presented a report to Council on the use of Council contingency funds on 1/29/19. Exhibit 4 of that staff report provides a detailed list of how the Council contingency has been used since Fiscal Year 2012-13. See the staff report for additional information: http :lj edocweb/H PRMWebCI ient/H P RMServiceApi/Record/528800/Fi le/Document. Question 2: What is the current balance in the Fund? Are there already other specified allocations earmarked from this balance? Answer: The balance as of March 31, 2019 in the Council contingency fund is $1,162,490. At this time, no other specified allocations have been earmarked from this balance. Only Council and the grant approvals authorized in Council Policy No. 51 have the ability to use these funds. Question 3: Are we differentiating between "renewable" and "GHG-free" in our CCE goal? From the agenda item, it looks like the two are used interchangeably, but they are not the same. Answer: Yes, the power supply portfolios analyzed in the feasibility study (and as discussed in questions 2 and 3 of the FAQ provided in Exhibit 2 to the staff report) do differentiate between "renewable" and "GHG-free" resources, as defined by state law. Agenda Item No. 5-PRIORITY STATE LEGISLATIVE REPORT AND CONSIDER CREATION OF A LEGISLATIVE COMMITTEE Question 1: Regarding AB 847, what would 85% of our regional housing needs be, and would that be assessable for us to achieve in order to receive funding as a result of this bill? Does the bill eliminate incentives which would otherwise be available for affordable housing? -Answer: The AB 847 Fact Sheet provided as part of the April 16, 2019, City Council packet (see item 5, exhibit 4) notes local jurisdictions under the proposed bill would receive a direct allocation of transportation funding if they "issue completed entitlements, building permits, or certificates of occupancy for 85% or more of their share of regional housing needs for their low and very-low income housing categories." However, it appears this provision has been deleted from the bill text. · Based on the latest Annual Housing Progress Report (AHPR), prepared for 2013-2018. and presented to City Council last month, Carlsbad has completed 16.5% of its very low and low- income regional housing need (265 of 1,605 units). The city would need to complete 1,100 more units in this income category in the remaining three years of the reporting period to meet the 85% threshold. The Fact Sheet also describes a "10-percent selection priority bonus" for certain agency funding applications if the agency has issued permits for at least 85% of its mo~erate-income housing need. Per the latest AHPR, the city has completed 24% of its moderate-income regional housing Honorable Mayor Hall and Members of the City Council April 16, 2019 Page 3 need (257 of 1,062 units) and would need to complete 650 more units in the next three years to meet 85%. Since 2013, the city has annually completed an average 474 homes. About 84% are homes affordable to above moderate-income households. Regarding the bill's elimination of any incentives, the proposed bill text is minimal. It would establish a competitive grant program to cities to offset transportation impact fees. The text does not discuss potential funding sources for the grant program or loss of incentives that might otherwise be available to affordable housing. The bill does note transit-oriented development projects would have preference in a competitive grant program. While this development type is not defined, it may exclude affordable housing development in Carlsbad not located near the train stations. Question 2: Regarding SB 50, what is Carlsbad's current jobs to housing ratio? How does the Housing Accountability Act (HAA) restrict demolition of existing housing? Answer: Carlsbad's current jobs-to-housing ratio is 1.6:1. We have 1.6 jobs to each housing unit. J The HAA does not contain any restrictions on demolition of existing housing. As currently proposed, SB SO contains the following restriction: in order for a developer to request the development incentives in SB 50, the project cannot be located on a site that is occupied by tenants, or has been occupied by tenants in the past 7 years. Question 3: Regarding AB 11, SB 5, SB 15, what are the essential differences between these bills focused on making up the affordable housing gap since the end of RDAs? Answer: Because there is not a lot of detail with any of these bills yet and the expectation is that they all may be revised significantly over coming weeks, staff has completed a higher-level analysis which indicates the following differences as we understand the bills today. ABll has an unspecified state commitment for funding. The bill provides economic development tools similar to the old redevelopment program, and is primarily for infrastructure development. It has a requirement for 30% of funds to be used for affordable housing. It has a unique condition that formation of an infrastructure and affordable housing agency could not be created if it has a negative impact on the state. It relies on an award offunding from the state based on review of a resolution of intention for a proposed project plan. The new agency can use affected taxing entity's share of property tax if the affected taxing entity consents. This may prove to be difficult to obtain the financing for this program. SBS allows for the creation of new redevelopment programs for affordable housing and investment for neighborhood revitalization, using post redevelopment tools. It will have less flexibility than previous redevelopment programs, and less resources for economic Honorable Mayor Hall and Members of the City Council April 16, 2019 Page4 development. It is proposed to have an appropriation of funding from the State to back fill lost revenue to school districts, but also has a "rainy day" clause that can be invoked by the State if the provision of financial support must be suspended by the state. It will require a 30% · inclusionary requirement for affordable housing. It also will have a State Oversight Board that will be established to review and approve all proposed projects. SB15 is primarily a funding program through the Department of Finance for certain infrastructure projects. Cities would apply to the Department of Finance for funding for certain purposes and affordable housing. It requires an appropriation of property tax revenues by the State. Question 4: Regarding SB 532, does Carlsbad also still have funds left over from RDA? A successor agency? Answer: Neither the Carlsbad Redevelopment Agency nor its Successor Agency had tax increment funds or bond proceeds left over to be expended on eligible projects at the time that the State moved forward to dissolve all redevelopment agencies. We have two debts to be repaid -tax increment bonds and city loans to the Agency. The loan repayment from Agency to City requires 20% to be set-aside for affordable housing for low income households. We have approximately $2.8 million available for expenditure. Question 5: Regarding AB 392, SB 230, what are the major differences in these two bills? Answer: AB 392 revises the legal standard for use of deadly force by peace officers, by limiting it to those situations where it is necessary to defend against a threat of imminent serious bodily injury or death to the officer or to another person. SB 230 requires law enforcement agencies to have a policy on the minimum standard on the use of force. It also calls for more and standardizes police training, documenting departmental policies, and an emphasis on utilizing . de-escalation techniques or other alternatives to force when feasible. cc: Celia Brewer, City Attorney Gary Barberio, Deputy City Manager Paz Gomez, Deputy City Manager Laura Rocha, Deputy City Manager Jason Haber, Assistant to the City Manager Debbie Fountain, Community & Economic Development Director Jason Haber, Assistant to the City Manager April 16, 2019 Community Choice Energy Technical Feasibility Study and Legal Services Cost Share Recommended Action Approve a resolution: 1.Accepting CCE Technical Feasibility Study 2.Authorizing CM to negotiate, execute & fund a cost share agreement to procure joint legal services to assist in negotiating and preparing CCE formation documents –NTE $20,000 Background •July 11, 2017 –Approved participation in CCE feasibility study (NTE $60,000) •February 26, 2019 –Received & provided feedback on DRAFT study –Directed staff to conduct public workshop & finalize study –Approved participation in CCE governance study (NTE $35,000) Background •March 19, 2019 –Approved resolution expressing intention to pursue CCE –Identified priority operating principles •March 21, 2019 –Joint public meeting held at Carlsbad Senior Center –50 attendees –Carlsbad, Del Mar, Encinitas, Oceanside {city of Carlsbad Ca l i for n ia Howur -help, ~ngFun,n(,11r1~ C.ett,tagAroood ""''" Mport~ter~n ComtrA1n tyC.Ploocef.l'ltrgy Cont~tl/s Related Topics Beaches New Resident Resources City Nl!M. Water. Shi-er & Trash a, ng Carhbad Pubhc Optnion Sunoeys Onl e Serv1tes 0 11 ■■■1111 Community Choice Energy Homf! • ReSldMts • Commun,ty ChOKl' Energy A new study shows the Commur ,ty (hOl(I! Energy modl!I Is techn1CaUyleu1ble and would save Carlsbad ratepayers a oll ye,n comp.ired to SOG&E But'd on the~ draft hndmgs. the Carlsb.Jd City Council voted on Feb 26 to explore how a '"lew locally con11ol energy utility could be g0Ye1ned The City Council al~ voted to d11e<:t city stall to returl" to the C,ty Coone ii 111,th a st,llement ol tent 10 pursue Commulllly (ho,ce Ene1gy The cities ofCa,hb.Jd, Ori Mar. Encm,t•sand Ckean~de held a ,omt ~~10 p,e~nt the Mdings ol lM lus1b,l1ty study arn:I hear IJ'lptll lrom commu1111y l'!"embea The C,tyol C.11lsti.d III coop,ffallon w,th the c,tin of Ori Moir and Enon tas a,@ dewlopmg • Geta,IKI as'.teument ol .iva11Ia~ ga.,e,nante op1ionsas lhe next eaploratory pha!>e ol lormlflg .t Commun,ty (h(ll(:e Energy prog,am. As p,irl ol 1h15. dl!!l.t,led U!>eument, these cities .tie \OhCJt,ng 1nterest from other Cities, counties. third p,irly oper.ttors/Yendors and u,st<r,g Commun,tyChOlte Energy programs tor potential partnerships Ple.t)e re"tlew the Bf:g~ and consider respond,ng Sobm,1 any questlOI s related to the Bm~ More information 0YC>IIOD\ & Answm ~g~g [C)Q{J/1100 lor IC#)lhnltv llY..lb, July 11. 2017 (Item 17) Qrt]I) (gmmun1IY ChOKC EOC1gy_flil1.IW.11Y..S.1Wh'., Feb 26. 2019 ~ Feb 27. 2019 2littHQQU.March 19. 2019 (begms page 14n ~~gy Public PmrnlilltPO. Mil/Ch 21. 2019 Feasibility Study Overview •Can the North San Diego County Cities and Specifically Carlsbad, Form a CCE that is Financially Feasible Under a Range of Likely Future Conditions? •Methodology: Conservatively Estimate CCE Revenues and Costs and Compare to Comparable Rates of SDG&E •Also Review Options for Operational Structures and Governance Choices •Identify and Evaluate Risks of Forming a CCE Feasibility Study Findings •A North San Diego County Cities CCE is Financially Feasible Under a Wide Range of Sensitivities •Renewable content of power supply •Lower or higher than expected participation rates •Changes in PCIA or power supply costs •At least 2% savings below SDG&E rates •Repayment of start-up capital within 2-3 years very likely 23 Feasibility Study Findings •$8 -$9 Million in Bill Savings Annually •Participants Gain Greater Control Over Rates, Programs, Power Supply •Green House Gas Reduction Potential up to 218,000 MTCO2e •Increased Local Economic Development of 100 New Jobs and $13M in Local Economic Activity Each Year for Change in Disposable Income Only •No substantive changes from DRAFT study –typos & clean-up edits 23 Joint Legal Services •Encinitas solicitation for legal support •During Governance Study •Negotiate and Prepare CCE Formation Documents •Partners -Carlsbad, Del Mar, Encinitas •RWG Proposal •Carlsbad cost share - $20,000 April 16, 2019 Community Choice Energy Technical Feasibility Study and Legal Services Cost Share