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Home My WebLink About2022-05-26; Clean Energy Alliance JPA; ; Receive Update and Assessment Report Related to the cities of Oceanside, San Clemente, and Vista Joining Clean Energy Alliance.... CLEAN ENERGY ALLIANCE DATE: TO: FROM: ITEM 10: Staff Report May 26, 2022 Clea n Energy Alliance Board of Directors Barbara Boswell, Chief Executive Officer Receive Update and Assessment Report Related to the cities of Oceanside, San Clemente, and Vista Joining Clean Energy Alliance RECOMMENDATION Receive update and assessment report related to the cities of Oceanside, San Clemente and Vista joining Clean Energy Alliance. BACKGROUND AND DISCUSSION Clean Energy Alliance's New Member Addition Policy states the Board will consider adding new agencies under the following conditions: 1. The analysis of the proposed member usage data results in a positive feasibility study using CEA's financial pro form a model; 2. The addition of the new member does not create an undue risk orfinancial burden to CEA; 3. Does not create an undue risk to the achievement of the goals of CEA, including the achievement of the Climate Action Plan goals of the current Members. In order to analyze the financial impact of Oceanside, San Clemente, and Vista (Cities) joining CEA for purposes of complying with condition 1 above, CEA received the 2021 usage data for the three cities. The electric usage was analyzed and input into CEA's current financial proforma model, using current approved customer rates and updated energy costs, the results of which have been summarized in the attached Assessment Report. Customer Information May 26, 2022 Assessment Report Page 2 of8 The chart above provides information on the number of accounts and annual energy usage in 2021 for the Cities, CEA's current base (Carlsbad, Del Mar and Solana Beach) and the 2023 expansion into Escondido and San Marcos. Adding the Cities in 2024 more than doubles the number of accounts that CEA services and increases energy usage by 81% (not adjusted for any opt-out assumption). Oceanside 73,295 568,725 647 124 Vista 39,593 353,719 744 74 San Clemente 34,478 253,731 613 58 Total 147,366 1,176,175 665 256 CEA Base Forecast 59,153 626,927 883 136 2023 Expansion 86,400 826,410 797 196 Forecast Total Current 145,553 1,453,337 832 332 Forecast Total Combined 292,919 2,629,512 898 % Increase 101% 81% Financial Assessment The financial assessments used the following assumptions: • Customers enrolled in April 2024 • 10% of eligible customers would opt-out • Current CEA rates • Current Forward Price Curve of Energy May 26, 2022 Assessment Report Page 3 of8 a base assumption of enrolling customers in April 2024, which was determined to be the optimal enrollment date, and serving 90% of eligible customers, the assessment concluded that with the addition of Oceanside, CEA's net operating margin would increase by approximately 85% beginning in FYE 2025, which would be the first full fiscal year of service. The projected incremental revenues, costs, and net operating margin are shown in Table 1 below: Incremental Net Margins from Expansion (in $MM) City of Oceanside FYE 20241 FYE 2025 FYE 2026 Revenue $9.86 $53.55 $53.82 Power Supply Costs -$8.88 -$50.54 -$49.50 Staffing -$0.17 -$0.17 -$0.17 Billing and Other Costs -$0.48 -$1.43 -$1.44 Net Operating Margin $0.35 $1.42 $2.72 5% Reserve Contribution $0.49 $2.68 $2.69 Reserve Shortfall/Excess -$0.14 -$1.26 $0.03 Based on the assumptions listed above, sufficient revenue related to serving Oceanside would be generated to cover operating costs, however, for Fiscal Years ending 2024 and 2025, the net operating margin falls short of the 5% reserve contribution. Fiscal year 2026 projects sufficient revenue to cover all costs and the 5% operating reserve contribution. Incremental Net Margins from Expansion (in $MM} City of San Clemente FYE 202421 FYE 2025 FYE 2026 Revenue $4.45 $23.83 $23.95 Power Supply Costs -$3.99 -$22.40 -$21.94 Staffing -$0.08 -$0.08 -$0.08 Billing and Other Costs -$0.15 -$0.59 -$0.59 Net Operating Margin $0.24 $0.75 $1.34 5% Reserve Contribution $0.22 $1.19 $1.20 Reserve Shortfall/Excess $0.02 -$0.44 $0.14 1 Reflects partial year of service for fiscal year ending June 30, 2024, with enrollments assumed to commence on April 1, 2024. 2 May 26, 2022 Assessment Report Page 4 of8 Based on the assumptions list ed above, sufficient revenue related to serving San Clemente would be generated to cove r operating costs, however, for Fiscal Year ending 2025, the net operating ma rgin falls short of t he 5% reserve contribution. Fiscal yea rs 2024 and 2026 projects sufficient revenue to cover all costs and the 5% operating reserve contribution. Incremental Net Margins from Expansion (in $MM) City of Vista FYE 202431 FYE 2025 FYE 2026 Revenue $6.19 $32.96 $33.12 Power Supply Costs -$5.62 -$31.49 -$30.85 Staffing -$0.11 -$0.11 -$0.11 Billing and Other Costs -$0.21 -$0.74 -$0. 74 Net Operating Margin $0.26 $0.62 $1.43 5% Reserve Contribution $0.31 $1.65 $1.66 Reserve Shortfall/Excess -$0.05 -$1.02 -$0.23 Incremental Net Margins from Expansion (in $MM) Combined FYE 202441 FYE 2025 FYE 2026 Revenue $20.51 $110.34 $110.89 Power Supply Costs -$18.48 -$104.43 -$102.29 Staffing -$0.35 -$0.35 -$0.35 Billing and Other Cost s -$0.83 -$2.76 -$2.77 Net Operating Margin $0.85 $2.79 $5.48 5% Reserve Contribution $1.03 $5.52 $5.54 Reserve Shortfall/Excess -$0.18 -$2.72 -$0.06 The co mbined financial assessment determines sufficient revenue is generated at cu rrent rates to cover operating costs but fall short of the 5% reserve contribution. The reserve contribution for FYE 2024 is projected to be 4%, 2025 2.5% and 2026 4.9%. Resource Availability The following is taken from the Assessment Report (attached ) prepared by Pacific Energy Advisors : Changes in market prices for electricity represent the single greatest uncertainty that could impact the projected benefits related to expansion. Electricity commodity, traded in a highly volatile market, and prices could materially change before CEA is ready to contract for the power supply needed to serve 3 41 Reflects partial year of service for fiscal year ending June 30, 2024, with enrollments assumed to commence on April 1, 2024. May 26, 2022 Assessment Report Page 5 of8 anticipated Cities' loads. Commodity price risk is inherent in the electric utility industry and is not unique to expansion, but expansion imposes challenges with respect to the timing of electricity purchase as well as the timing associated with a final/definitive determination regarding the expansion itself This is not unlike the challenges CEA (or any Community Choice Aggregator) faced during its initial startup period. CEA utilizes professional risk management approached and forward hedging contracts to mitigate commodity price risk for its existing customers; however, adverse price movements that may occur before CEA initiates power purchases for the Cities' load could drive up costs and result in negative margins. In addition to the impact of the volatility of the energy market, CEA must take into consideration regulatory compliance procurement as it relates to the expansion. Under existing regulation, CEA must have a certain percentage of its renewable energy requirements in long-term contracts. This requirement must be met as of the end of 2024 for the expansion load. Realistically, CEA will only be able to meet this requirement through procurement of existing contracts from San Diego Gas & Electric (SDG&E). SDG&E would have entered into long-term renewable energy contracts on behalf of the Cities' load, which would be excess at the time the energy transfers to CEA. Through California Public Utilities Commission Decision 21-05-030, CEA has access to SDG&E excess long-term renewable energy through an allocation process. To the extent CEA can arrange such as allocation related to the expansion load, the incremental obligation related to the new load is diminished. Resource adequacy (RA) is another power supply product that CEA will need to plan for in preparing for serving the expansion cities load. RA is a constrained product, and SDG&E will have been required to have 100% of the RA associated with the Cities' load in 2022. Due to constraints in RA availability, CEA will be required to work with SDG&E in procuring its excess RA capacity to meet the additional requirements. The ability of work with SDG&E successfully will be key in CEA meeting its regulatory procurement compliance. CEA will need to take this into account in determining whether a 2024 enrollment is achievable or postponing to 2025 results in less risk. Average Residential Bill Comparison Using CEA's current adopted rates and SDG&E's current rates, the following reflects the average monthly bill comparison for a residential customer on rate Schedule DR for each of the three cities. City of Oceanside Residential: DR Generation Clean Impact Plus/Green Impact Premium SDG&E PCIA+FFS -2022 Vintage Generation Related Costs SDG&E Delivery Total Average Monthly Bill Average 324 kWh Usage $ Savings to SDG&E % Savings to SDG&E City of San Clemente Residential: DR Generation Clean Impact Plus/Green Impact Premium SDG&E PCIA+FFS -2022 Vintage Generation Related Costs SDG&E Delivery Total Average Monthly Bill Average 396 kWh Usage $ Savings to SDG&E %Savings to SDG&E SDG&E 31% Renewable $ 49.86 s -s - s 49.86 s 73.08 $ 122.94 SDG&E 31% Renewable $ 60.94 s - s - $ 60.94 $ 89.32 $ 150.27 CEA May 26, 2022 Assessment Report Page 6 of8 CEA CEA Clean Impact Green 50% Plus Impact Renewable 75%Carbon 100% Clean Impact Free Renewable $ s s $ s $ s 35.80 $ -$ 9.73 $ 45.53 s 73.08 s 118.61 $ (4.33) $ -3.52% 35.80 $ 0.32 s 9.73 s 45.85 $ 73.08 $ 118.93 $ (4.01) $ -3.26% CEA CEA Clean Impact 50% Plus Renewable 75%Carbon 35.80 2.43 9.73 47.96 73.08 121.04 (l.90) -1.55% CEA Green Impact 100% Clean Impact Free Renewable s s s s s $ $ 43.75 $ -$ 11.90 $ 55.65 $ 89.32 s 144.97 $ (5.29) $ -3.52% 43.75 $ 0.40 $ 11.90 $ 56.05 $ 89.32 $ 145.37 $ (4.89) $ -3.26% 43.75 2.97 11.90 58.62 89.32 147.94 (2.32) -1.55% City of Vista Residential: DR Generation Clean Impact Plus/Green Impact Premium SDG&E PCIA+FFS -2022 Vintage Generation Related Costs SDG&E Delivery Total Average Monthly Bill Average 342 kWh Usage $ Savings t o SDG&E % Savings to SDG&E SDG&E 31% Renewable $ 52.63 $ - $ - $ 52.63 $ 77.14 $ 129.77 May 26, 2022 Assessment Report Page 7 of 8 CEA CEA CEA Clean Impact Green 50% Plus Impact Renewable 75%Carbon 100% Clean Impact $ $ $ $ $ $ $ 3 7.79 $ -$ 11.90 $ 49.69 $ 77.14 $ 126.83 $ (2.95) $ -2.27% Free Renewable 37.79 $ 0.34 $ 11.90 $ 50.03 $ 77.14 $ 127.17 $ (2.60) $ -2.01% 37.79 2.57 11.90 52.25 77.14 129.39 (0.38) -0.29% For comparison, current CEA customers are realizing the following results compared to SDG&E: 2020 PCIA Vintage 50% Renewable 75% Carbon Free 100% Renewable Carlsbad & Del Mar Clean Impact Clean Impact Plus Green Impact $ (Savings)/Premium to SDG&E -Total Bill ($1.42) ($.97) $1.64 % (Savings)/Premium to SDG&E -Total Bi ll (0.9%) (0.6%) 1.0% 2017 PCIA Vintage 50% Renewable 75% Carbon Free 100% Renewable Solana Beach Clean Impact Clean Impact Plus Green Impact $ (Savings)/Premium to SDG&E -Total Bill ($5.57) ($5.17) ($2.S_!L % (Savings)/Premium to SDG&E -Total Bill (3.64%} (3.38%} (1.64%) Staff will continue to monitor t he energy market, and its impact on the financial assessment of the service expansion and provide an update to the CEA Board in July 2022 when the next action is needed by the CEA Board related to the additions. Next Steps ACTIVITY Assessment Report Results to CEA Board Cities -Resolution to Join CEA and ist Reading of Ordinance to Establish a CCA Cities -2nd Reading of Ordinance CEA -Resolution approving Cities joining CEA/Direct preparation of Implementation Plan Amendment - Draft Implementation Plan Amendment to CEA Board ~ File Implementation Plan Amendment with CPUC FISCAL IMPACT Th ere is no fiscal impact related to this report. ATTACHMENTS May 26, 2022 Assessment Report Page 8 of8 TIMING May 26, 2022 June 2022 June/July 2022 July 2022 - October 2022 December 2022 Pacific Energy Advisors Assessment Report -Oceanside, San Clemente, Vista Expansion Item 10 Attachment Clean Energy Alliance New Membership Assessment Cities of Oceanside, San Clemente, and Vista May 2022 SUMMARY The cities of Oceanside, San Clemente, and Vista ("Cities") have engaged with the Clean Energy Alliance ("CEA") to explore the possibility of joining CEA. On behalf of CEA, Pacific Energy Advisors, Inc. ("PEA") conducted assessments of the financial and resource planning implications associated with extending CEA service to electric customers within the Cities (which are currently receiving bundled electric service from the incumbent utility, San Diego Gas & Electric, or "SDG&E"). The assessments involved studies to understand the potential increase in electric load and the additional energy resources that would be needed to serve the Cities. The studies also estimated the incremental revenues that would be derived from electricity sales to the Cities' customers, as well as the incremental costs associated with energy resource procurement and other items/services that would be necessary to support CCA service expansion to the Cities' customers. These factors were jointly evaluated to determine whether any operating surpluses could be generated, on a projected basis, for the benefit of CEA and its customers. In consideration of the prospective timing associated with amended implementation plan submittal and in accordance with existing regulatory rules, the earliest possible enrollment date for Cities customers would be January 1, 2024.1 For this assessment, PEA modeled various enrollment start times in 2024 and found that April 2024 would be optimal from a financial perspective. Thus, enrollment would be expected to occur toward the end of CEA's fiscal year ending 2024; the first full year reflecting Cities load would be CEA's fiscal year ending 2025. Under current base case assumptions, the analysis indicates that expansion would yield positive operating margins (revenue net of incremental cost) and reserve additions, but not at a level sufficient to meet CEA's targeted 5% reserve contribution. The projected incremental revenues, costs, operating margin, and net deficit (i.e., shortfall in reserve contribution) is shown in Table 1. Table 1: Incremental Net Margins from Expansion (in $MM} FYE 20242 FYE 2025 FYE 2026 Revenue $20.51 $110.34 $110.89 Power Costs -$18.48 $104.43 -$102.29 Staffing -$0.35 -$0.35 -$0.35 Other Costs -$0.83 -$2.76 -$2.77 Subtotal: Operating Margin $0.85 $2.79 $5.48 Reserves (targeted) -$1.03 -$5.52 -$5.54 Net Deficit -$0.18 -$2.72 -$0.06 1 Achieving the prospective early enrollment date for Cities customers would require submittal of an amended CCA implementation plan no later than December 31, 2022. 2 Reflects partial year of service for fiscal year ending June 30, 2024, with enrollments assumed to commence on April 1, 2024. Pacific Energy Advisors, Inc., May 2022 Page 1 of9 Electric resource requirements associated with the expansion would be significant, and close coordination between CEA and SDG&E would be important to achieve an appropriate allocation of resources needed to serve the transferred load. Such coordination and cooperation would be es pecially important for resource adequacy and long-term renewable energy supply. Without cooperation from SDG&E to sell excess resources, or alternatively, a regulatory mechanism to ensure transfer of resources as load shifts from SDG&E to CEA, it may not be possible for CEA to obtain the necessary resources in the near term to meet its resource adequacy and long-term Renewable Portfolio Standards ("RPS") obligations. ANALYSIS PEA conducted three individual analyses of the Cities' prospective electric accounts, as well as an aggregate outlook, to estimate the revenues and costs associated with extending CEA service to the Cities. The analyses incorporated historical monthly electric usage data provided by SDG&E for all current electric accounts located within the Cities. PEA reviewed load data from 2019 and 2021 to formulate its load projections.3 Table 2 summarizes the account and electric usage data for the major customer classifications represented within the Cities. Available data indicate the potential to serve 147,366 new CEA customer accounts, which are expected to use approximately 1,176,175 MWh of electric energy per year. This would be an approximate 81% increase in size for CEA, relative to the anticipated retail sales volume associated with CEA's current membership. The aggregate peak demand of these prospective accounts is estimated at 256 MW.4 Table 2: 2021 Cities' Electric Data Classification Accounts Annual Energy (MWh) Monthly Per Account (kWh) Residential 132,398 549,373 346 Com mercia 1/1 ndustria I 14,333 610,171 3,548 Agricultural 115 7,937 5,751 Street Lighting 520 8,695 1,393 Total 147,366 1,176,175 665 •Peak Demand (MW) 256 *Estimate based on CEA customer hourly usage profiles. As compared to the current CEA customer base, summarized in Table 3 below, the Cities have a slightly larger residential sector and a smaller commercial sector. The Cities' residential customers tend to be 3 2020 data were excluded due to customer usage anomalies introduced by the Covid-19 pandem ic. 4 These figures reflect bundled electric customers of SDG&E and exclude customers taking service from non-utility energy providers (namely, direct access service providers) as well as certain accounts on generation service contracts that are not expected to transition to CEA service. These figures are unadjusted for expected customer attrition (customer elections to "opt-out"). Pacific Energy Advisors, Inc., May 2022 Page 2 of9 lesser users of energy than those in CEA's current service area, with 13% lower average monthly consumption, whereas the commercial customers are similar in total average consumption. Table 3: Projected Annual CEA Electricity Data -Current Membership Classification Accounts Annual Energy (MWh) Monthly Per Account (kWh) Residential 125,372 597,177 397 Commercial/Industrial 19,382 827,998 3,560 Agricu ltu ra I 280 18,147 5,401 Street Lighting 519 10,015 1,608 Total 145,553 1,453,337 832 Peak Demand (MW) 332 As illustrated in Figures 1 and 2 below, electricity usage within the Cities shows slightly less seasonality relative to the current CEA customer base, with a flatter shape of overall consumption across the year. These usage characteristics are likely due to cooling loads driven by climate differences between the two geographic areas. Figure 1: 12-Month Hourly Load Profile (kW) for the Cities 300,000 250,000 200,000 150,0<XI 100,000 S0,000 ■ • • 50,000 ■ 50.000-100,0'JO ■ 100.000 • lS0.000 ■ 150,000 • 200,000 ■ 200.000 • 250.000 ■ 250,000-300,<XK> Pacific Energy Advisors, Inc., May 2022 Page 3 of 9 Figure 2: 12-Month Hourly load Profile (kW) of CEA 's Current Customer Base 350,000 300.000 250.000 200,000 150,000 100,000 50,000 ■ --50.000 • S0.000 · 100,000 • 100,000 • 150,000 l S0,000 · 200,000 ■ 200,000 · 250.000 ■ 250,000 -300,000 ■ 300,000 -350.000 FISCAL IMPACTS For purposes of the fiscal impact analysis, it was assumed that service would be initiated to the Cities in April 2024 and that 90% of eligible accounts would choose to participate (with the remaining 10% electing to opt-out, continuing to receive bundled electric service from the incumbent utility). The exception to this opt-out assumption is reflected in the Street Lighting class, which is assumed at a 100% enrollment rate. This would equate to an increase in annual CEA electricity sales of 1,070 GWh, or approximately 74% relative to pre-2024 expansion sa les. In order to quantify anticipated financial impacts to CEA, the incremental revenues and costs associated with the prospective service expansion were examined. More specifically, the year of enrollment and the next two fiscal years following expanded service, i.e., the period beginning April 1, 2024, through June 30, 2026, were analyzed to determine likely fiscal impacts over a multi-year planning period. The incremental revenue surplus -based on the difference between projected revenues and costs directly related to the addition of the Cities' accounts -represents the expected fiscal benefit related to expansion. Incremental revenues were projected based on forecasted electricity sales and current CEA rates. The incremental cost analysis accounts for requisite power supplies that would be required to serve accounts within the Cities, increased customer billing charges, customer service support (call center), additional CEA staffing, SDG&E service fees, and required customer notices associated with serving additional customers. Pacific Energy Advisors, Inc., May 2022 Page 4 of 9 Table 4 reflect s the estimated incremental fiscal impact during each of the first three fiscal years commencing with (and immediately following) enrollment of the Cities' accounts. Table 4: Incremental Fiscal Impact Related to Prospective Expansion FYE 20245 FYE 2025 FYE 2026 Revenue ($MM) $20.51 $110.34 $110.89 Power Costs ($MM) -$18.48 -$104.43 -$102.29 Staffing ($MM) -$0.35 -$0.35 -$0.35 Other Costs ($MM) -$0.83 -$2.76 -$2.77 Subtotal: Operating Margin $0.85 $2.79 $5.48 Reserves (targeted) -$1.03 -$5.52 -$5.54 Net Deficit ($MM) -$0.18 -$2.72 -$0.06 Incremental Sales Volume 204,081 1,072,587 1,077,950 (MWh) In consideration of current market conditions and assuming continuation of current CEA rates, adding the Cities accounts to CEA's current customer base is projected to generate a revenue surplus when compared to anticipated operating expenses; however, the operating margin would not be at a level that meets CEA's current 5% reserve contribution targets. It is estimated that expanding CEA service to the Cities would increase reserves by $9.12 million across the first three fisca l years impacted by the expansion, equivalent to a 3.8% reserve contribution. It is worth noting that power supply costs and CEA rates may change over time, and to the extent such changes occur, actual net revenues could materially differ from the net revenue projections reflected in Table 4 (above). WHOLESALE POWER PRICE SENSITIVITY Changes in market prices for electricity represent the single greatest uncertainty that could impact the projected benefits related to expansion. Electricity is a commodity, traded in a highly volatile market, and prices could materially change before CEA is ready to contract for the power supply needed to serve anticipated Cities' electric loads. Commodity price risk is inherent in the electric utility industry and is not unique to expansion, but expansion imposes challenges with respect to the timing of electricity purchases as well as the timing associated with a final/definitive determination regarding the expansion itself. This is not unlike the challenges CEA (or any Community Choice Aggregator) faced during its initial startup period. CEA utilizes professional risk manage ment approaches and forward hedging contracts to mitigate commodity price risk for its existing customers; however, adverse price movements that may occur before CEA initiates power purchases for the Cities' load, could drive up costs and result in negative margins. Utilizing historical volatility in wholesale power market prices, a likely range of potential power supply costs and resulting net margins can be calculated. Figure 3 shows the base case operating margins and error bars representing one standard deviation in power supply costs, assuming CEA does not initiate procurement until March 2023, the month during which the CPUC would be expected to certify CEA's Implementation Plan amendment addressing expansion to the Cities. Over this eleven-month period 5 Reflects partial year of service for fiscal year ending June 20, 2024, with enrollments assumed to commence on April 1, 2024. Pacific Energy Advisors, Inc., May 2022 Page 5 of9 (between the date of this Expansion Assessment and March 2023), the estimated change in market prices at one standard deviation of variation is approximately 10% relative to base case assumptions. As reflected in Figure 3 (below), the likely range of operating margin outcomes is wide, ranging from negative $9 million to positive $17 million. Figure 3: Net Surplus Sensitivity to Chonges is Power Prices Change in Operating Margin $20.0 $15.0 $10.0 $ .5 ~ $5.0 $ .8 ~ si s ,(/). $0.0 .L t 'T' 2024 -$5.0 -$10.0 -$15.0 Fiscal Year Ending RESOURCE IMPACTS Similar to the procurement approach used to support CEA's current customers, CEA would need to acquire various energy products to serve the Cities -it is assumed that the proportionate acquisition of such resources would occur over time t hrough the application of a laddered hedging strategy, as followed under CEA's risk management program. These energy products include Renewable Energy, Other Carbon Free Energy (e.g., large hydro-electric), System Energy, and Resource Adequacy capacity. The quantities will vary over time and are summarized in Table 5 below for a representative year. Pacific Energy Advisors, Inc., May 2022 Page 6 of9 Table 5: Summary of Resources Needed to Serve the Cities Product Quantity Units Notes Renewable 630 GWh GWh Per Approx. half must be from long-term commitments(>= 10 Energy Year years) per RPS rules Other llOto GWh Per Higher end of range would be needed to offset emissions Carbon 200 GWh Year attributed to PCC2 renewable energy products; lower use Free of PCC2 products will reduce need for Other Carbon Free volumes Resource 195MW MW per Adequacy, Month, System September Peak Resource 160MW MW Per Adequacy, Month Local Under California's RPS rules, a significant portion of renewable energy purchases must be secured through contractual commitments of at least ten years in duration. Compliance with the RPS program is measured over multi-year compliance periods, and the earliest the expansion could occur would be during Compliance Period 4 (2021-2024). As shown below, RPS compliance would require an increase in renewable energy purchases during Compliance Period 4 of 337 GWh, of which 219 GWh would have to be associated with long-term commitments. Note that CEA has voluntarily adopted higher renewable energy targets than required by the RPS program, so the total renewable energy needed to meet CEA policy is greater than the figures shown below. Current CEA Membership Compliance 2021 2022 2023 2024 Total Period 4 Retail Sales 399 662 1,267 1,489 3,816 (GWh) Gross RPS% 35.8% 38.5% 41.3% 44.0% 41.3% Required RPS 143 255 523 655 1,576 (GWh) Gross RPS LT 65.0% 65.0% 65.0% 65.0% 65.0% % Gross LT RPS 93 166 340 426 1,024 Pacific Energy Advisors, Inc., May 2022 Page 7 of9 Current CEA Membership Plus the Cities Compliance 2021 2022 2023 2024 Total Period 4 Retail Sales 399 662 1,267 2,255 3,816 (GWh) Gross RPS% 35.8% 38.5% 41.3% 44.0% 41.7% Required RPS 143 255 523 992 1,913 (GWh) Gross RPS LT 65.0% 65.0% 65.0% 65.0% 65.0% % Gross LT RPS 93 166 340 645 1,243 RESOURCE AVAILABILITY Accommodating the Cities' expansion will require careful consideration of resource availability, particularly for resource adequacy and long-term renewable energy products. An important element of resource procurement will be the ability to access resources currently held by SDG&E for the benefit of the Cities' customers. When Cities customers transition to CEA service, SDG&E should have surplus resource adequacy and long-term renewable energy supply, so CEA will need to arrange for the acquisition of such supply to facilitate applicable compliance mandates. If no transfer of resources occurs, either by sale or some form of allocation, CEA would risk being unable to meet its regulatory obligations associated with the increased load associated with Cities' expansion. Under existing regulation, SDG&E is required to have 100% of the local resource adequacy capacity associated with its current customer base two years forward and 50% in the third year. With the well- known shortages of local resource adequacy capacity in the San Diego/Imperial Valley area, this virtually assures that accessing local RA resources held by SDG&E will be required if CEA is to meet its increased local RA obligations associated with the Cities' load. With respect to renewable energy availability, the resource constraint would primarily relate to the long- term renewable energy requirement for Compliance Period 4. PEA understands that CEA will soon have an opportunity to pursue an allocation of SDG&E's existing RPS portfolio, as described in Commission Decision 21-05-030, which was adopted on May 20, 2021. Participation in this allocation process is voluntary and certain volumes would be eligible to satisfy long-term renewable energy procurement mandates pertaining to CEA. Additional details related to this process are forthcoming with initial allocations expected to occur during the 2023 calendar year. To the extent that CEA can arrange such an allocation to address the increased renewable energy requirements relating to the Cities' expansion, incremental procurement obligations would be somewhat diminished. If CEA chooses to forgo the aforementioned allocation opportunity, CEA would need to enter into long-term contracts for renewable energy starting in 2024, coincident with (or shortly after) the enrollment of Cities customers. Development timelines for new renewable generating projects, however, would likely extend a minimum of 24 to 36 months following the administration of a related solicitation for such supply. Depending on how early CEA begins its procurement efforts, this cou ld mean that new-build renewable projects may Pacific Energy Advisors, Inc., May 2022 Page 8 of9 not commence operation until the 2025 or 2026 calendar years (if CEA waited until it received the CPUC's implementation plan certification before pursuing long-term renewable energy solicitation efforts related to Cities expansion). If the earliest delivery for new long-term contracts occurs after 2024, associated renewable energy deliveries could not be used in Compliance Period 4. The RPS program makes no accommodations for significant load increases, and there are severe penalties for not meeting the long- term contracting obligation. In light of the resource availability issues described above, it would be advisable to engage with SDG&E early in the process to ensure that appropriate resource transfers and/or the previously described renewable energy allocation process can be timely accommodated. Postponing mass enrollment of the Cities customers into the early timeframe of Compliance Period 5 (2025-2027) would be advised if it is deemed that sufficient resources would not be available for CEA to achieve its Compliance Period 4 requirements. CAPITAL AND LIQUIDITY IMPACTS Although relatively minimal, additional costs related to the prospective expansion would be incurred during the fiscal year preceding enrollment of the Cities' accounts. These costs would relate to marketing and outreach activities, customer noticing, regulatory and legal representation, internal operations, resource planning and electric procurement activities that would be necessary to successfully integrate the Cities and their customers in CEA's organization. There would also be increased working capital requirements to address changes in cash flow. It is currently projected that CEA will not have sufficient cash liquidity to internally fund pertinent activities related to the prospective expansion; the current analysis projects a minimum of $7.6 million in additional funding would be needed. CONCLUSIONS This assessment concludes that under current base case assumptions the expansion would yield positive operating margins and reserve contributions, but at a level below CEA's 5% reserve contribution target. Due to wholesale market volatility, the likely range of outcomes is wide under scenarios reflecting typical power price variability. Extending service to the Cities could increase CEA's sales volume by over 80% and would require a meaningful increase in CEA resource acquisition. Advance coordination with SDG&E for resource adequacy and long-term renewable energy resource transfers would be strongly advised to ensure CEA has the resources necessary to meet its regulatory obligations associated with an increase in load. Among other resource implications, the expansion would increase CEA's long-term RPS compliance obligations, and meeting these heightened obligations during Compliance Period 4, which spans 2021- 2024, would be of immediate importance. Postponing mass enrollment of the Cities customers into the early timeframe of Compliance Period 5 (2025-2027) shou ld be considered to reduce the risk that sufficient resources might not be available for CEA to achieve its Compliance Period 4 requirements. It is highly likely that local resource adequacy and long-term renewable energy would need to be obtained from SDG&E to facilitate the transfer of customers to CEA. Pacific Energy Advisors, Inc., May 2022 Page 9 of9 Item 10: Assessment Report • Recommendation: 5/26/22 • Receive Update and Assessment Report related to the ci t ies of Oceanside, San Clemente and Vista Joining CEA. CLEAN ENERGY -ALLIANCE 18 Item 10: Assessment Report • New Member Policy: 5/26/22 • Analysis of proposed member usage data results in a positive financial result using CEA's proforma model; • Addition of new member does not create an undue risk or financial burden to CEA • Does not create an undue risk to the achievement of the goals of CEA, including the achievement of the Climate Action Plan goals of the current Members. CLEAN ENERGY Ill ALLIANCE 19 Item 10: Assessment Report • Analysis • Usage data for calendar year 2021 input into CEA's current pro forma model • April 2024 Enrollment • Current CEA adopted rates used • go% Participation Rate • CEA's current cost of power supply 5/26/22 CLEAN ENERGY ~ ALLIANCE 20 Item 10: Assessment Report 5/26/22 Revenue Power Supply Costs Staffing Billing and Other Costs Net Operating Margin --- 5% Reserve Contribution Reserve Shortfall/Excess Reserve by year: 2024-4% 2025-2.5% 2026-4.9% FYE 2024 $20.51 -$18.48 -$0.35 -$0.83 $0.85 $1.03 I -so.is I FYE 2025 FYE 2026 $110.34 $110.89 -$104.43 -$102.29 -$0.35 -$0.35 -$2.76 -$2.77 $2.79 $5.48 $5.52 $5.54 I -s2.12 -$0.06 Rates would need to be increased 2.5% to achieve a minimum 5% reserve contribution in each year. CLEAN ENERGY ~=-"' ALLIANCE 21 Item 10: Assessment Report Bill Comparison -Current Rates Bill Comparison -2.5% Rate Increase City of Oceanside Residential: DR Generation Clean Impact Plus/Green Impact Premium SDG&E PCIA+FFS -2022 Vintage Generation Related Costs SDG&E Delivery Total Average Monthly Bill Average 324 kWh Usage $Savings to SDG& E % Savings to SDG&E 5/26/22 SDG&E 31% Renewable $ 49.86 $ - $ - $ 49.86 $ 73.08 $ 122.94 CEA CEA City of Oceanside CEA Clean Impact Green 50% Plus Impact Renewable 7S%Carbon 100% Clean Impact Free Renewable Residential: DR $ $ $ $ $ $ $ 35.80 $ -$ 9.73 $. 45.53 $ 73.08 $ 118.61 $ {4.33) $ -3.52% 35.80 $ 0 .32 $ 9.73 $ 45.85 $ 73 .08 $ 118.93 $ (4.01) $ -3.26% 35.80 Generation Clean Impact Plus/Green Impact 2.43 Premium 9.73 SDG& E PCIA+FFS -2022 Vintage 47.96 Generation Related Costs 73.08 SDG&E Delivery 121.04 Total Average Monthly Bill Average 324 kWh Usage {1.90) $ Savings to SDG&E -1.55% % Savings to SDG&E SDG&E 31% Renewable $ 49.86 $ - $ - $ 49.86 $ 73.08 $ 122.94 CEA CEA CEA Clean Impact Green 50% Plus Impact Renewable 75%Carbon 100% Clean Impact $ $ $ $ $ $ $ 36.70 $ -$ 9.73 $ 46.43 $ 73.08 $ 119.51 $ {3.44) $ -2.79% Free Renewable 36.70 $ 36.70 0.32 $ 2.43 9.73 $ 9.73 46.75 $ 48.86 73.08 $ 73.08 119.83 $ 121.94 (3.11) $ (1.00) -2.53% --0.81 % CLEAN ENERGY ---· . ALLIANCE 22 Item 10: Assessment Report Bill Comparison -Current Rates Bill Comparison -2.5% Rate Increase City of San Clemente Residential: DR Generation Clean Impact Plus/Green Impact Premium SDG&E PCIA+FFS -2022 Vintage Generation Related Costs SDG&E Delivery Total Average Monthly Bill Average 396 kWh Usage $ Savings to SDG& E %Savi ngs to SDG&E 5/26/22 SDG&E 31% Renewable s 60.94 s - s - s 60.94 s 89.32 $ 150.27 CEA CEA City of San Clemente CEA Clean Impact Green 50% Plus Impact Renewable 75%Carbon 100% Clean Impact Free Renewable Residential: DR s s s s s $ s 43.75 s -s 11.90 s 55.65 s 89.32 s 144.97 $ (5.29) $ -3.52% 43.75 s 0.40 s 11.90 s 56.05 s 89.32 s 145.37 $ (4.89) $ -3.26% 43.75 Generation Clean Impact Plus/Green Impact 2.97 Premium 11.90 SDG&E PCIA+FFS-2022 Vintage 58.62 Generation Related Costs 89.32 SDG&E Delivery 147.94 Total Average Monthly Bill Average 396 kWh Usage (2.32) $ Savings to SDG&E -1.55% %Savingsto5DG&E SDG&E 31% Renewable s 60.94 s - s - s 60.94 s 89.32 $ 150.27 CEA CEA CEA Clean Impact Green SO% Plus Impact Renewable 75%Carbon 100% Clean Impact s s s s s $ s 44.85 s -s 11.90 s 56.74 s 89.32 s 146.07 $ (4.20) $ -2.80% Free Renewable 44.85 s 0.40 s 11.90 s 57.14 s 89.32 s 146.47 $ (3.80) $ -2.53% 44.85 2.97 11.90 59.71 89.32 149.04 (1.23) --0.82% CLEAN ENERGY -__.; ALLIANCE 23 Item 10: Assessment Report Bill Comparison -Current Rates City of Vista Residential: DR Generation Clean Impact Plus/Green Impact Premium SDG&E PCIA+FFS-2022 Vintage Generation Related Costs SDG&E Delivery Total Average Monthly Bill Average 342 kWh Usage $ Savings to SDG&E % Savings to SDG&E 5/26/22 SDG&E 31% Renewable $ 52.63 $ - s - s 52.63 s 77.14 $ 129.77 CEA CEA CEA Clean Impact Green SO% Plus Impact Renewable 7S%Carbon 100% Clean Impact Free Renewable $ $ s $ $ $ $ 37.79 $ -$ 10.26 s 48.05 s 77.14 $ 125.19 $ (4.58} $ -3.53% 37.79 $ 0.34 $ 10.26 s 48.39 $ 77.14 $ 125.53 $ (4.24) $ -3.27% 37.79 2.57 10.26 50.62 77.14 127.76 {2.02) -1.55% Bill Comparison -2.5% Rate Increase City of Vista Residential: DR Generation Clean Impact Plus/Green Impact Premium SDG&E PCIA+FFS-2022 Vintage Generation Related Costs SDG&E Delivery Total Average Monthly Bill Average 342 kWh Usage $ Savings to SDG& E % Savings to SDG&E SDG&E 31% Renewable $ 52.63 $ - $ - $ 52.63 $ 77.14 $ 129.77 CEA CEA CEA Clean Impact Green 50% Plus Impact Renewable 75%Carbon 100% Clean Impact $ $ s $ $ $ $ 38.73 $ -$ 10.26 $ 48.99 $ 77.14 $ 126.13 $ (3.64) $ -2.80% Free Renewable 38.73 $ 0.34 $ 10.26 $ 49.34 $ 77.14 $ 126.48 $ (3.29) $ -2.54% 38.73 2.57 10.26 51.56 77.14 128.70 (1.07) -0.83% CLEAN ENERGY -~ ALLIANCE 24 Item 10: Assessment Report • Procurement Considerations • Resource Adequacy • Requires working closely with SDG&E to acquire excess RA related to the departures of the new members from SDG&E to CEA • Risk of non-compliance to CEA if unable to reach agreement with SDG&E • Long-Term Renewable Energy • Long-Term Renewable Energy contracts required for existing generating facilities immediately upon service establishment • Cooperation with SDG&E to acquire excess long-term renewable energy supply related to the departures of the new members • Risk to non-compliance to CEA if unable to reach agreement with SDG&~LEAN ~NERGY -►-:: ALLIANCE 5/26/22 25 Item 10: Assessment Report • Next Steps 5/26/22 ACTIVITY Assessment Report Results to CEA Board Cities -Resolution to Join CEA and 1st Reading of Ordinance to Establish a CCA Cities -2nd Reading of Ordinance CEA -Resolution approving Cities joining CEA/Direct preparation of Implementation Plan Amendment - Review Updated Financial Impact Draft Implementation Plan Amendment to CEA Board Review Updated Financial Impact File Implementation Plan Amendment with CPUC TIMING May 26, 2022 June 2022 June/July 2022 July 2022 October 2022 December 2022 CLEAN ENERGY ALLIANCE 26