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Home My WebLink AboutStaff Report 2401-2474Item No. 4. Page 1 of 15 3 7 7 9 Utilities Advisory Commission Staff Report From: Dean Batchelor, Director Utilities Lead Department: Utilities Meeting Date: March 6, 2024 Staff Report: 2401-2474 TITLE Staff Recommends the Utilities Advisory Commission Recommend that the City Council Adopt a Resolution: 1) Approving the Fiscal Year (FY) 2025 Electric Financial Plan and Accepting the 2024 City of Palo Alto Electric Cost of Service and Rate Study, and 2) Amending E-1 (Residential Electric Service), E-2 (Residential Master-Metered and Small Non-Residential Electric Service), E-2-G (Residential Master-Metered and Small Non-Residential Green Power Electric Service), E-4 (Medium Non-Residential Electric Service), E-4-G (Medium Non-Residential Green Power Electric Service), E-4 TOU (Medium Non-Residential Time of Use Electric Service), E-7 (Large Non- Residential Electric Service), E-7-G (Large Non-Residential Green Power Electric Service), E-7 TOU (Large Non-Residential Time of Use Electric Service), E-NSE (Net Metering Net Surplus Electricity Compensation), and E-EEC (Export Electricity Compensation) RECOMMENDATION Staff recommends that the Utilities Advisory Commission (UAC) recommend the City Council Adopt a Resolution (Attachment A): 1. Accepting the 2024 City of Palo Alto Electric Cost of Service and Rate Study (Exhibit 1) 2. Approving the FY 2025 Electric Financial Plan (Exhibit 2), which includes the following actions: a. Amending the Electric Utility Reserves Management Practices (Attachment B), to direct staff to transfer to the CIP reserve, at the end of each fiscal year, any budgeted capital investment that remains unspent, uncommitted, and which is not proposed for reappropriation to the following fiscal year and to clarify how the Cap and Trade Program Reserve is adjusted each year. b. Approving the following transfers at the end of FY 2024: i. Up to $20 million from the Electric Special Projects Reserve to the Supply Operations Reserve; ii. Up to $17 million from the Supply Operations Reserve to the Hydroelectric Stabilization Reserve; iii. Up to $58 million from the Supply Operations Reserve to the Distribution Operations Reserve; and c. Approving the following transfers in FY 2025: Item No. 4. Page 2 of 15 3 7 7 9 i. Up to $26 million from the Distribution Operations Reserve to the Supply Operations Reserve; ii. Up to $30 million from the Supply Operations Reserve to the Electric Special Projects Reserve; and iii. Up to $5 million from the Distribution Operations Reserve to the CIP Reserve; 3. Amending the following rate schedules effective July 1, 2024 (FY 2025), (Exhibit 3): a. Changing retail electric rates E-1 (Residential Electric Service), E-2 (Small Non- Residential Electric Service), E-4 (Medium Non-Residential Electric Service), E-4 TOU (Medium Non-Residential Time of Use Electric Service), E-7 (Large Non- Residential Electric Service), and E-7 TOU (Large Non-Residential Time of Use Electric Service) by varying percentages depending on rate schedule and consumption with an overall revenue increase of 0.5% effective July 1, 2024; b. Decreasing the Net Surplus Electricity Compensation (E-NSE-1) rate to reflect 2023 avoided cost, effective July 1, 2024; and c. Decreasing the Export Electricity Compensation (E-EEC-1) rate to reflect current projections of FY 2025 avoided cost, effective July 1, 2024; d. Updating the Residential Master-Metered and Small Non-Residential Green Power Electric Service (E-2-G), the Medium Non-Residential Green Power Electric Service (E-4-G), and the Large Non-Residential Green Power Electric Service (E-7-G) rate schedules to reflect modified distribution and commodity components, effective July 1, 2024. EXECUTIVE SUMMARY The FY 2025 Electric Utility Financial Plan includes projections of the utility’s costs and revenues through FY 2028. Staff is seeking rate changes that vary significantly by customer class but that in aggregate result in little change (around an 0.5% increase) to total electric utility revenue in FY 2025. To ensure that electric rates continue to represent the Utility’s cost to serve customers, the City engaged the services of a consultant to prepare a cost of service analysis (COSA), which was completed in February 2024 (Attachment A, Exhibit 2) The COSA showed the need for different changes by customer class ranging from a 6% decrease for small non-residential customers (E-2) to a 2% increase for the residential class as a whole. However, recommended changes to the tier structure and the addition of a fixed charge result in a range of changes for residential customers depending on usage, with the median residential customer seeing an 8% increase. As of the drafting of this report, precipitation for the 2023/2024 water year was still below average. However, reservoir conditions are good as a result of last year’s rains, so staff is forecasting hydroelectric generation for FY 2025 and FY 2026 that is slightly higher than the baseline level staff assumes in its long-term projections. Staff is also projecting high one-time energy supply cost savings and surplus energy sales for FY 2024 related to higher late summer 2023 hydroelectric generation resulting from the 2022/2023 winter rains. Other one-time revenues include higher than average sales revenue for resource adequacy and renewable energy credits (RECs) in FY 2024 through FY 2026 due to favorable market conditions. Some of these revenues are being used to replenish the hydroelectric stabilization reserve, reducing the Item No. 4. Page 3 of 15 3 7 7 9 chance that the City would need to activate the hydroelectric rate adjuster in the next few years, even if there is less snow and rain. These one-time revenues are offset by significant capital investment costs associated with grid modernization ($50 million in FY 2024 and FY 2025), a rebuild of the Hanover substation ($15 million in FY 2024), and a new dark fiber backbone for the electric utility that will require some contribution from the electric utility ($13 million in FY 2026). Staff anticipates offsetting these capital investments by issuing municipal bonds. However, reserves will need to absorb some of the costs in FY 2024 until the first bonds can be issued in FY 2025. This is leading to large reserve transfers in FY 2024 and FY 2025 to manage this short-term cash flow issue. Staff projects total costs for the Electric Utility to increase steadily through the forecast period. The largest contributors to these cost increases are increasing transmission costs, reduced sales revenue from surplus RECs and resource adequacy rights, and increasing debt service associated with grid modernization. Staff is projecting the need for 5% per year rate increases through the forecast period. However, the electricity consumption projections in this report are conservative and increased load from electrification and any new large customer loads could reduce these projections. On the other hand, if the costs for grid modernization or other capital investment end up being higher than forecasted, as often occurs, those costs could offset the benefit of new customer loads. BACKGROUND Every year staff presents the UAC with Financial Plans for its Electric, Gas, Water, and Wastewater Collection Utilities and recommends any rate adjustments required to maintain their financial health. These Financial Plans include a comprehensive overview of the utility’s operations, both retrospective and prospective, and are intended to be a reference for UAC and Council members as they review the budget and staff’s rate recommendations. Each Financial Plan also contains a set of Reserves Management Practices describing the reserves for each utility and the management practices for those reserves. ANALYSIS Staff’s annual assessment of the financial position of the City’s Electric Utility is completed in compliance with cost of service requirements set forth in the California Constitution and applicable statutory law. The assessment includes making long-term projections of market conditions, of costs associated with the physical condition of infrastructure, and of other factors that could affect utility costs. Rates are then proposed that will move towards adequate cost recovery. This year’s proposed rates are based on the models developed in the attached February 8 2024 City of Palo Alto Electric Cost of Service and Rate Study by EES Consulting (Exhibit 2 to the attached resolution). Proposed Actions for FY 2024 and FY 2025: The FY 2025 Electric Utility Financial Plan (Exhibit 1 to the attached resolution) includes the following proposed actions: 1. Staff proposes amending the Electric Utility Reserves Management Practices (Appendix B to the Financial Plan) to direct staff to transfer to the CIP reserve, at the end of each fiscal Item No. 4. Page 4 of 15 3 7 7 9 year, any budgeted capital investment that remains unspent, uncommitted, and which is not proposed for reappropriation to the following fiscal year, and to clarify how the Cap and Trade Program Reserve is adjusted each year . 2. Staff proposes the following reserve transfers for the Electric Utility for FY 2024: a. Up to $20 million from the Electric Special Projects Reserve to the Supply Operations Reserve; b. Up to $17 million from the Supply Operations Reserve to the Hydroelectric Stabilization Reserve; c. Up to $58 million from the Supply Operations Reserve to the Distribution Operations Reserve; and 3. Staff proposes the following reserve actions for the Electric Utility for FY 2025: a. Up to $26 million from the Distribution Operations Reserve to the Supply Operations Reserve b. Up to $30 million from the Supply Operations Reserve to the Electric Special Projects Reserve, and c. Up to $5 million from the Distribution Operations Reserve to the CIP Reserve 4. Staff proposes the following rate actions effective July 1, 2024 (FY 2025): a. Changing retail electric rates E-1 (Residential Electric Service), E-2 (Small Non- Residential Electric Service), E-4 (Medium Non-Residential Electric Service), E-4 TOU (Medium Non-Residential Time of Use Electric Service), E-7 (Large Non- Residential Electric Service), and E-7 TOU (Large Non-Residential Time of Use Electric Service) by varying percentages depending on rate schedule and consumption resulting in an overall revenue increase of 0.5% effective July 1, 2024; b. An increase to the Export Electricity Compensation (E-EEC-1) rate to reflect 2023 avoided cost, effective July 1, 2024; c. An increase to the Net Surplus Electricity Compensation (E-NSE-1) rate to reflect current projections of FY 2024 avoided cost, effective July 1, 2024; and d. An update to the Residential Master-Metered and Small Non-Residential Green Power Electric Service (E-2-G), the Medium Non-Residential Green Power Electric Service (E-4-G), and the Large Non-Residential Green Power Electric Service (E-7-G) rate schedules to reflect modified distribution and commodity components, effective July 1, 2024. The Hydroelectric Stabilization Reserve will receive a $17 million transfer, increasing its current balance from $400,000 to $17.4 million, approaching the reserve's target level of $19 million. This transfer is possible due to one-time revenues related to high hydroelectric generation in FY 2024, receipt of a $24 million judgment in a lawsuit related to Federal hydropower, and unusually high sales revenue from sales of surplus resource adequacy rights and RECs. The $58 million interfund transfer from the Supply Operations Reserve to the Distribution Operations Reserve in FY 2024, followed by the return of $26 million in FY 2025 is related to the timing of debt issuance associated with major capital expenses, as described in the Executive Summary and in Section 3D (Proposed Reserve Transfers) of the attached FY 2025 Electric Utility Financial Plan. This will require a one-year $20 million additional loan from the Electric Special Item No. 4. Page 5 of 15 3 7 7 9 Projects Reserve in FY 2024 rather than the $10 million repayment of a previous loan that was approved in the FY 2024 Electric Utility Financial Plan. However, this Financial Plan includes repayment of the total $30 million in outstanding Electric Special Projects Reserve loans in FY 2025. The amendments to the Electric Utility Reserves Management Practices (Appendix B to the Financial Plan) will simplify the administration of the CIP Reserve and Cap and Trade Program Reserves. Table 1 below shows the effects of the proposed Council-approved transfers above on reserve funds as well as other planned or projected reserve transfers per the Council-approved Electric Utility Reserves Management Practices. Item No. 4. Page 6 of 15 3 7 7 9 Table 1: Reserves Starting and Ending Balances, Revenues, Expenses, Transfers To/(From) Reserves, Operations and Capital (CIP) Reserve Guideline Levels for FY 2024 to FY 2029 ($000) Table 2 shows the proposed and projected electric rates for FY 2025 through FY 2029. As noted above staff is proposing a set of rate changes consistent with the attached February 8 2024 City of Palo Alto Electric Cost of Service and Rate Study by EES Consulting (GDS Associates) that result in an approximately 0.5% increase in revenue for FY 2025. The rate changes by customer class and customer usage are discussed further in this report. FY 2024 FY 2025 FY 2026 FY 2027 FY 2028 FY 2029 Starting Reserve Balances 1 Supply Operations 44,463 15,601 27,652 26,757 26,337 25,855 2 Distribution Operation (5,581)6,921 12,020 14,317 14,429 15,362 3 CIP Reserve 880 880 5,880 5,880 5,880 5,880 4 Electric Special Projects 20,149 149 30,149 32,149 34,149 36,149 5 Hydro Stabilization 400 17,400 17,400 17,400 17,400 17,400 6 Cap and Trade Program 2,231 3,231 4,941 6,151 7,231 8,141 7 Public Benefits 5,673 7,431 9,033 10,569 12,032 13,422 8 Low Carbon Fuel Standard (LCFS)6,713 4,053 1,486 --- 9 Electrification Reserve 4,500 4,500 4,500 4,500 4,500 4,500 Revenues 10 Supply 145,323 142,902 133,822 133,976 136,567 139,122 11 Distribution 71,803 69,511 75,545 82,068 88,469 92,046 12 Cap and Trade Revenues 3,016 2,992 2,999 3,024 3,013 3,039 13 Public Benefits Revenues 4,780 4,690 4,584 4,551 4,520 4,488 14 LCFS Revenues 1,100 1,120 1,232 1,355 1,400 1,400 15 Electrification Reserve Repayments ------ Transfers from Supply Operations Reserve to Other Reserves or to Distribution Fund 16 From/(To)Distribution Operation (58,000)26,000 -2,000 2,000 2,000 17 From/(To)Electric Special Projects 20,000 (30,000)(2,000)(2,000)(2,000)(2,000) 18 From/(To)Hydro Stabilization (17,000)----- 19 From/(To)Cap and Trade ------ 20: =16+17+18+19 Supply Operations Total (55,000)(4,000)(2,000)--- Transfers from Distribution Operations Reserve to Other Reserves or to Supply Fund 21 From/(To)Supply Operations 58,000 (26,000)-(2,000)(2,000)(2,000) 22 From/(To)CIP Reserve -(5,000)---- 23 From/(To)LCFS ------ 24: =21+22+23 Distribution Operations Total 58,000 (31,000)-(2,000)(2,000)(2,000) Expenses 25 Supply Funded Expenses (119,185)(126,851)(132,717)(134,396)(137,049)(139,289) 26 Distribution Non-CIP Expenses (50,482)(52,153)(58,105)(65,285)(72,848)(74,969) 27 Distribution Planned CIP Expense (66,884)18,655 (15,143)(14,671)(12,688)(13,089) 28 Cap and Trade Expenses (2,016)(1,282)(1,789)(1,944)(2,103)(2,309) 29 Public Benefits Expenses (2,956)(3,003)(3,049)(3,088)(3,130)(3,177) 30 LCFS Expenses (3,759)(3,687)(2,718)(1,355)(1,400)(1,400) 31 Electrification Reserve Expenditures ------ Ending Reserve Balance 32: =1+10+20+25 Supply Operations 15,601 27,652 26,757 26,337 25,855 25,687 33: =2+11+24+26+27 Distribution Operation 6,856 11,934 14,317 14,429 15,362 17,350 34: =3+22 CIP Reserve 880 5,880 5,880 5,880 5,880 5,880 35: =4+17 Electric Special Projects 149 30,149 32,149 34,149 36,149 38,149 36: =5+18 Hydro Stabilization 17,400 17,400 17,400 17,400 17,400 17,400 37: =6+12+19+28 Cap and Trade Program 3,231 4,941 6,151 7,231 8,141 8,871 38: =7+13+29 Public Benefits 7,497 9,119 10,569 12,032 13,422 14,733 39: =8+14+23+30 Low Carbon Fuel Standard 4,053 1,486 ---- 40: =9+15+31 Electrification Reserve 4,500 4,500 4,500 4,500 4,500 4,500 Operations Reserve Guidelines (Supply) Minimum 21,063 22,111 22,412 22,874 23,149 23,601 Maximum 42,126 44,221 44,824 45,749 46,297 47,202 Operations Reserve Guidelines (Distribution) Minimum 10,800 11,701 12,742 14,084 14,526 14,763 Maximum 17,736 19,382 21,303 23,821 24,530 24,824 CIP Reserve Guidelines Minimum 1,192 2,489 2,412 2,086 2,152 2,223 Maximum 5,962 13,898 13,494 13,494 13,494 13,494 Item No. 4. Page 7 of 15 3 7 7 9 Table 1: Projected Electric Rates, FY 2024 to FY 2029 Projection FY 2025 FY 2026 FY 2027 FY 2028 FY 2029 Current -6% to +8%1 5%5%5%5% Last Year 5%5%5%5%N/A FY 2025 Financial Plan Projected Rate Adjustments for the Next Five Fiscal Years Table 3 shows the impact on the annual median residential electric bill (453 kwh per month in winter, 365 kwh per month in summer). Customers experienced a rate reduction in FY 2024 as the hydroelectric rate adjuster was deactivated. The proposed rate changes in FY 2025 are expected to increase the median residential bill by 5%. Future year increases of 5% per year are also projected. Table 3: Actual/Proposed/Projected Residential Bill Impacts, FY 2023 to FY 2029 Current Proposed Projected Mid- year FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028 FY 2029 Estimated Bill Impact ($/mo) * Base Bill Only $63.73 $76.82 $80.66 $85.02 $89.63 $94.49 $99.62 With Hydro Rate Adjuster $83.37 $76.82 No Hydro Rate Adjuster forecasted * Estimated impact on median monthly residential electric bill Figure 1 shows the overall Electric Utility’s costs (net of surplus sales revenues) in FY 2020, FY 2025, and FY 2029. Since FY 2025 is projected to have lower than usual electric supply costs, the rate of increase for the electric supply portfolio from FY 2020 to FY 2025 is minimal. Both FY 2024 and FY 2025 have unusually low electric supply costs, but if the comparison were done to FY 2023 or FY 2026 it would show a significant increase from FY 2020 levels, on the order of 4% to 5% per year on average, and a similar rate of increase is expected through FY 2029 as transmission and related electric supply costs continue to increase. The distribution costs for FY 2025 in Figure 1 are also unusual due to the timing of various capital investments and related debt issuances in FY 2024 and FY 2025. If a more representative year were shown (such as FY 2026) it would show operational and capital investment costs increasing at a rate of 5% to 6% per year from FY 2020 through today with a similar rate forecasted for the next five years. The forecasted increases in distribution cost relate primarily to debt service for the grid modernization project as well as continuing construction inflation and other inflation. Combined, the utility’s costs 4% to 5% per year on average for the last few years (after adjusting for the unusually low FY 2025 expenses) and are forecasted to increase at a similar rate for the next five years, necessitating ongoing 5% per year rate increases. 1 Rates for individual customers may vary significantly from this projection based on their consumption patterns. Item No. 4. Page 8 of 15 3 7 7 9 Figure 1: Electric Utility Costs, FY 2020 Actual vs. FY 2025 and FY 2029 Projections Figure 2 shows distribution costs. Operational costs increased about 6% per year from FY 2020 to FY 2025. Due to higher than anticipated staff vacancies, more expensive external contracts have been needed to complete necessary electric system maintenance. Salary and benefit costs have increased, and inflation has increased operating costs. There is greater spending on sustainability and energy efficiency initiatives to achieve S/CAP goals, though much of this is funded by dedicated funding sources not reflected in the chart below. Operational costs are projected to increase at a lower rate, 3% to 4% per year, over the forecast period. Capital costs for FY 2025 are unusual, showing a net refund as planned bond issuance debt proceeds are used to fund significant capital expenses, allowing the utility to replenish reserves. Future capital investment rates are expected to stay fairly stable as most of the electric utility capital investment activity is focused on grid modernization. The debt service for this effort is shown in Figure 2. With growth in debt service included capital-related expenses are expected to grow 7% per year on average, leading to an overall growth rate for distribution costs of 5% to 6% per year. Item No. 4. Page 9 of 15 3 7 7 9 Figure 2: Electric Distribution Costs, FY 2020 vs. FY 2025 and FY 2029 Projections Figure 3 shows commodity costs did not increase significantly from FY 2020 to FY 2025 but as noted above, this is because FY 2025 generation expenses are projected to be lower than usual due to surplus resource adequacy and REC sales revenues that are not expected to continue through the forecast period. Excluding these one-time revenues generation costs have increased 2% to 3% per year since FY 2020 and are expected to increase at a similar rate through FY 2025. Transmission costs increased by 6% annually in the same timeframe and are projected to increase by about 5% annually in future years. These increases are due to rehabilitation and replacement of the statewide electric transmission system as well as expansion of that system to accommodate new generation, mostly renewable. Staff works to contain transmission costs through partner agencies, including the Transmission Agency of Northern California (TANC) and Northern California Power Agency (NCPA), and through direct partnerships with other local utilities (the Bay Area Municipal Transmission group, BAMx). These groups intervene in transmission proceedings at the Federal Energy Regulatory Commission (FERC) and the California Independent System Operator (CAISO), and have achieved some reductions in long-term transmission costs. Staff also seeks to achieve cost savings in electric supply and overhead wherever feasible. Item No. 4. Page 10 of 15 3 7 7 9 Figure 3: Electric Supply Costs, FY 2019 Actual vs. FY 2024 and FY 2028 Projections Staff recognizes the importance of managing operating costs and maximizing efficiency to minimize rate increases. As discussed above, staff is working on cost containment measures related to transmission and renewable energy costs. As reflected in the Utilities Strategic Plan, staff regularly explores additional ways to effectively use available resources, particularly across divisions. Electric Bill Comparison with Surrounding Cities For the median consumption level, the annual CPAU residential electric bill for calendar year 2023 was $964, which was $667 (41%) lower than the annual bill for a PG&E customer with the same consumption ($1,632) and approximately $136 (34%) higher than the annual bill for a City of Santa Clara customer ($718). However, both PG&E and Santa Clara increased rates significantly on January 1, 2024. As shown in Table 8, below, the Palo Alto winter and summer median residential bills are only 18% and 11% higher than Santa Clara, which is about the same as the historical difference between the two, so the high difference for CY 2023 only reflects the fact that the City acted earlier than Santa Clara in recognizing increasing long-term commodity costs. This was something the City had to implement due to low reserves resulting in part from avoiding rate increases through the COVID-19 pandemic to help residents manage the pandemic’s economic impact. The PG&E bills based on the January 1, 2024 rates are 50% to 60% higher than Palo Alto, reflecting an increasing cost advantage for Palo Altans over utility customers in PG&E territory. The bill calculations for PG&E customers are based on PG&E Climate Zone X, which includes most surrounding comparison communities. Item No. 4. Page 11 of 15 3 7 7 9 Table 4 presents sample median residential bills for Palo Alto, PG&E, and the City of Santa Clara (Silicon Valley Power) for several usage levels. Rates used to calculate the monthly bills shown below were in effect as of January 1, 2024. Table 4: Residential Monthly Electric Bill Comparison (Effective 1/1/2024, $/mo.) Season Usage (kwh)Palo Alto PG&E Santa Clara 300 52.56 126.03 49.02 453 (Median)88.16 191.88 74.93 650 136.75 295.44 108.29Winter 1200 274.41 584.55 201.42 300 52.56 130.78 49.02 (Median) 365 66.45 153.33 60.03 650 136.75 314.76 108.29Summer 1200 282.18 603.87 161.54 Staff is updating its methodology for commercial customer rate comparisons and will provide an update at a later date. Proposed Rate Changes Staff engaged the services of a consultant to review and revise the Electric Utility’s Cost of Service study and rates. This study, the February 8, 2024 City of Palo Alto Electric Cost of Service and Rate Study by EES Consulting (GDS Associates), examined how the City’s costs are allocated among the residential and commercial classes and recommended some realignments. In general costs increased more for residential than non-residential customer classes due to changes in consumption patterns compared to those reflected in the current rates. In addition, increased usage in the residential class led to some recommended changes to the current tiered rate design, increasing the Tier 1 allowance and narrowing the difference between the tiers. Lastly, the minimum bill included in the current rate schedules is recommended to be replaced with a modest fixed charge. The community’s electric use has been changing over time due to the economic disruptions of the pandemic, gradual relocation of industrial users from Palo Alto, adoption of electric vehicles, solar, and building electrification, and may shift more in the future as the pace of vehicle and building electrification picks up and if new commercial loads come online. Rate design changes will be needed to take advantage of new technologies, particularly advanced metering infrastructure. Due to these changes staff intends to update the COSA model more frequently in the coming years and adjust rate designs and cost allocations among classes as needed. Item No. 4. Page 12 of 15 3 7 7 9 The current rates and proposed FY 2025 rates are reflected in Table 5 below: Table 5: Current and Proposed Electric Rates Table 6 shows the impact of the proposed July 1, 2024 rate changes on the residential and non- residential bills for various consumption levels. The rate changes vary by customer class due to the completion of a cost of service analysis as noted above. The rate change for the median residential customer is 8%. Because of the addition of a customer charge and the changes in the design of the tiers for the E-1 customer class usage in this class varies widely depending on consumption, generally increasing for customers who use less electricity and decreasing for those who use more. This trend is expected to continue when the utility moves to time of use rates, which provides prices that vary by time of day rather than by how much electricity a customer uses in a month. It is worth noting, however, that increases among low users, while Item No. 4. Page 13 of 15 3 7 7 9 large in percentage terms, are arguably nominal in absolute dollar terms (not more than $10.63 per month, most low users will see lower increases). Table 6: Impact of Proposed Electric Rate Changes on Customer Bills Bill under Change Rate Schedule Usage (kWh/mo) Peak Demand (kW-mo) Current Rates ($/mo) Bill Under Rates Proposed 7/1/24 ($/mo)$/mo % 300 N/A $52.57 $62.65 $10.08 19% (Summer Median) 365 N/A $66.46 $75.22 $8.76 13% (Winter Median) 453 N/A $88.16 $92.24 $4.07 5% 650 N/A $136.75 $135.61 ($1.14)-1% E-1 (Residential) 1200 N/A $272.42 $257.34 ($15.07)-6% E-2 (Small Non- Residential) 1,000 N/A $225.93 $213.73 ($12.20)-5% 160,000 274 $31,580 $30,693 ($887)-3%E-4 (Medium Non- Residential)500,000 856 $98,680 $95,667 ($3,014)-3% E-7 (Large Non- Residential 2,000,000 3,424 $348,247 $340,864 ($7,383)-2% Net Energy Metering Buyback Rates The City operates two Net Energy Metering (NEM) programs. Solar customers served by the CPAU’s original NEM program, NEM 1, are compensated at retail rates for net electricity they export to the grid, and solar customers served by the NEM successor program, or NEM 2 (effective after the City reached its NEM 1 cap at the end of 2017), are compensated at the Export Electricity Compensation (E-EEC-1) rate for exported electricity. Customers on the NEM 1 program who have chosen to have the value of any annual net generation they produced over the past 12 months credited back to their account do so under the Net Metering Net Surplus Electricity Compensation (E-NSE-1) rate. Both surplus compensation rates are based on the City’s renewable energy costs, but the calculation methodologies differ slightly to reflect the different characteristics of the NEM programs they are used for and the different regulations applicable to Item No. 4. Page 14 of 15 3 7 7 9 those programs. More detail on these rates is included in Section 3B (Current and Proposed Rates) of the FY 2025 Electric Utility Financial Plan. Staff proposes to change the E-NSE-1 rate to $0.1427/kWh based on updated cost calculations reflecting the current electricity market prices. Staff proposes to change the Export Electricity Compensation (E-EEC-1) compensation rate to $0.1420/kWh based on projected market prices. Table 8: NEM Compensation Rates – Current vs. Proposed Rate Current $/kWh Proposed $/kWh Net Surplus Electricity (E-NSE)$0.1535 $0.1427 Export Electricity (E-EEC)$0.1685 $0.1420 Palo Alto Green (PAG) Program The Palo Alto Green (PAG) program provides CPAU’s commercial customers an opportunity to voluntarily pay a premium to receive renewable electricity credits to match their energy usage. Under this program, CPAU staff purchase and retire Green-e certified RECs in the wholesale market on behalf of PAG customers. This enables participating commercial customers to claim credit for the REC purchases in order to satisfy their corporate sustainability goals and meet federal “green certification” requirements. In the past year the wholesale cost of Green-e certified RECs in the Western US market has remained relatively flat at around $7.00/REC. As such, the PAG rate premium should remain at $7.5 per 1,000 kWh block (.75 cents/kWh), which includes both the price of the RECs and the administrative overhead. TIMELINE The Finance Committee is scheduled to review the FY 2025 Electric Financial Plan2 in April 2024. The City Council will consider adopting the Financial Plan and rate amendments as part of the FY 2025 budget review and adoption process. FISCAL/RESOURCE IMPACT FY 2025 revenues are projected to remain very close to FY 2024 levels if Council adopts this report’s recommendations. The City is a non-residential utility customer and can expect a decrease in estimated City utility expenses of about $160,000, approximately $85,000 of that being in the General Fund. Street light expenses (which are paid from the General Fund) are projected to decrease by about $180,000. Resource impacts to City departments and funds of the recommended rate adjustments are programmed in the FY 2025 Proposed Operating Budget. If the final rates adopted by Council in June differ from those proposed in this report, further adjustments may be brought forward as part of the annual budget process. STAKEHOLDER ENGAGEMENT 2FY 2025 Electric Financial Plan https://www.cityofpaloalto.org/files/assets/public/v/2/agendas-minutes- reports/reports/city-manager-reports-cmrs/attachments/03-01-2023-id-2301-0844-fy24-electric-utility-financial- plan.pdf Item No. 4. Page 15 of 15 3 7 7 9 Stakeholder engagement for the rate adoption process includes review by the UAC, Finance Committee, and City Council, as well as outreach to residents via the website and social media. ENVIRONMENTAL REVIEW The UAC’s review and recommendation to the City Council on the FY 2024 Electric Financial Plans and rate adjustments does not meet the California Environmental Quality Act’s definition of a project, pursuant to Public Resources Code Section 21065, thus no environmental review is required. ATTACHMENTS Attachment A: Resolution of the Council of the City of Palo Alto Approving the Fiscal Year 2025 Electric Utility Financial Plan and Reserve Transfers, Amending the Electric Utility Reserves Management Practices, and Amending Utility Rates Attachment A, Exhibit 1: February 8, 2024 City of Palo Alto Electric Cost of Service and Rate Study by EES Consulting (GDS Associates) Attachment A, Exhibit 2: Proposed FY 2025 Electric Utility Financial Plan Attachment A, Exhibit 3: Proposed Electric Rate Schedules Attachment B: Proposed Amended Electric Utility Reserves Management Practices Attachment C: Presentation AUTHOR/TITLE: Dean Batchelor, Director of Utilities Jonathan Abendschein, Assistant Director, Utilities Attachment A 6056815 Utility Electric Rate Schedules FY25 Electric Financial Plan *Yet to be Passed* Resolution No. Resolution of the Council of the City of Palo Alto Approving the Fiscal Year 2025 Electric Utility Financial Plan and Accepting the 2024 City of Palo Alto Electric Cost of Service and Rate Study, and Amending Utility Rate Schedules E-1 (Residential Electric Service), E-2 (Residential Master-Metered and Small Non-Residential Electric Service), E-2-G (Residential Master- Metered and Small Non-Residential Green Power Electric Service), E-4 (Medium Non-Residential Electric Service), E-4-G (Medium Non-Residential Green Power Electric Service), E-4 TOU (Medium Non-Residential Time of Use Electric Service), E-7 (Large Non-Residential Electric Service), E-7-G (Large Non- Residential Green Power Electric Service), E-7 TOU (Large Non- Residential Time of Use Electric Service), E-NSE (Net Surplus Electricity Compensation Rate), and E-EEC (Export Electricity Compensation) R E C I T A L S A. Each year the City of Palo Alto (“City”) regularly assesses the financial position of its utilities with the goal of ensuring adequate revenue to fund operations. This includes making long-term projections of market conditions, the physical condition of the system, and other factors that could affect utility costs, and setting rates adequate to recover these costs. It does this with the goal of providing safe, reliable, and sustainable utility services at competitive rates. The City adopts Financial Plans to summarize these projections. B. The City uses reserves to protect against contingencies and to manage other aspects of its operations, and regularly assesses the adequacy of these reserves and the management practices governing their operation. The status of utility reserves and their management practices are included in Reserves Management Practices attached to and made part of the Financial Plans. C. Pursuant to Chapter 12.20.010 of the Palo Alto Municipal Code, the Council of the City of Palo Alto may by resolution adopt rules and regulations governing utility services, fees and charges. D. On June 17, 2024, the City Council heard and approved the proposed rate increase at a noticed public hearing. The Council of the City of Palo Alto does hereby RESOLVE as follows: SECTION 1. The Council hereby approves the FY 2025 Electric Utility Financial Plan (Exhibit A), including the Attachment A 6056815 Utility Electric Rate Schedules FY25 Electric Financial Plan amended Electric Utility Reserves Management Practices in Appendix B of the Financial Plan. SECTION 2. The Council hereby approves the following transfers to be made by the end of FY 2024, as described in the FY 2025 Electric Utility Financial Plan: a. A transfer of up to $20 million from the Electric Special Projects Reserve to the Supply Operations Reserve; and b. A transfer of up to $17 million from the Supply Operations Reserve to the Hydroelectric Stabilization Reserve; and c. A transfer of up to $58 million from the Supply Operations Reserve to the Distribution Operations Reserve SECTION 3. The Council hereby approves the following transfers to be made by the end of FY 2025, as described in the FY 2025 Electric Utility Financial Plan: a. A transfer of up to $26 million from the Distribution Operations Reserve to the Supply Operations Reserve; and b. A transfer of up to $30 million from the Supply Operations Reserve to the Electric Special Projects Reserve; and c. A transfer of up to $5 million from the Distribution Operations Reserve to the CIP Reserve SECTION 4. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-1 (Residential Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-1, as amended, shall become effective July 1, 2024. SECTION 5. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-2 (Residential Master-Metered and Small Non-Residential Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-2, as amended, shall become effective July 1, 2024. SECTION 6. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-2-G (Residential Master-Metered and Small Non-Residential Green Power Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-2-G, as amended, shall become effective July 1, 2024. SECTION 7. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-4 (Medium Non-Residential Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-4, as amended, shall become effective July 1, 2024. SECTION 8. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-4-G (Medium Non-Residential Green Power Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-4-G, as amended, shall Attachment A 6056815 Utility Electric Rate Schedules FY25 Electric Financial Plan become effective July 1, 2024. SECTION 9. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-4 TOU (Medium Non-Residential Time of Use Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-4 TOU, as amended, shall become effective July 1, 2024. SECTION 10. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-7 (Large Non-Residential Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-7, as amended, shall become effective July 1, 2024. SECTION 11. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-7-G (Large Non-Residential Green Power Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-7-G, as amended, shall become effective July 1, 2024. SECTION 12. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-7 TOU (Large Non-Residential Time of Use Electric Service) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-7 TOU, as amended, shall become effective July 1, 2024. SECTION 13. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-NSE (Net Surplus Electricity Compensation Rate) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-NSE-1, as amended, shall become effective July 1, 2024. SECTION 14. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate Schedule E-EEC-1 (Export Electricity Compensation) is hereby amended to read as attached and incorporated. Utility Rate Schedule E-EEC-1, as amended, shall become effective July 1, 2024. SECTION 15. The Council makes the following findings: a. The revenue derived from the adoption of this resolution shall be used only for the purpose set forth in Article VII, Section 2, of the Charter of the City of Palo Alto. b. The fees and charges adopted by this resolution are charges imposed for a specific government service or product provided directly to the payor that are not provided to those not charged, and do not exceed the reasonable costs to the City of providing the service or product. Attachment A 6056815 Utility Electric Rate Schedules FY25 Electric Financial Plan SECTION 16. The Council finds that approving the Financial Plan and Reserve transfers does not meet the California Environmental Quality Act’s (CEQA) definition of a project under Public Resources Code Section 21065 and CEQA Guidelines Section 15378(b)(5), because it is an administrative governmental activity which will not cause a direct or indirect physical change in the environment, and therefore, no environmental assessment is required. The Council finds that changing electric rates to meet operating expenses, purchase supplies and materials, meet financial reserve needs and obtain funds for capital improvements necessary to maintain service is not subject to the California Environmental Quality Act (CEQA), pursuant to California Public Resources Code Sec. 21080(b)(8) and CEQA Guidelines Sec. 15273(a). After reviewing the staff report and all attachments presented to Council, the Council incorporates these documents herein and finds that sufficient evidence has been presented setting forth with specificity the basis for this claim of CEQA exemption. INTRODUCED AND PASSED: AYES: NOES: ABSENT: ABSTENTIONS: ATTEST: City Clerk Mayor APPROVED AS TO FORM: APPROVED: Assistant City Attorney City Manager Director of Utilities Director of Administrative Services Date: February 8, 2024 Version: 3rd Draft Test Period: FY: 2025 Production Peak Allocation Method: Average and Excess Method (AE) Transmission Peak Allocation Method: Average and Excess Method (AE) Distribution System Allocation Method: 100% Demand 16701 NE 80th St Suite 102 Redmond, Washington 98052 Telephone: 425 889-2700 Facsimile: 425 889-2725 For questions about this model: amber.gschwend@gdsassociates.com CITY OF PALO ALTO Cost of Service Schedules February 2024 Prepared By EES Consulting, Inc. City of Palo Alto - 100% Demand Forecast Year: 2025 Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Revenues - Present Rate $168,321,326 $27,309,759 $11,784,676 $67,707,023 $59,295,683 $2,224,184 Less Allocated Revenue Requirement $164,587,138 $27,852,514 $11,067,556 $65,186,601 $58,473,708 $2,006,759 Difference $4,034,187 -$242,755 $717,121 $2,520,422 $821,975 $217,425 Revenue To Cost Ratio 102.3%98.1%106.5%103.9%101.4%110.8% 16.9%6.7%39.6%35.5%1.2% % Increase Retail Rates to Equal Allocated Cost -2.22%2.0%-6.1%-3.7%-1.4%-9.8% Rate Base $247,977,170 $40,100,933 $16,740,604 $108,987,533 $74,010,673 $8,137,426 Rate Of Return, %1.6%-0.6%4.3%2.3%1.1%2.7% Rate Of Return, $$4,034,187 -$242,755 $717,121 $2,520,422 $821,975 $217,425 Modified Debt Service Coverage Ratio Unit Cost: Present Rates ($/kWh)$0.202 $0.20526 $0.221 $0.229 $0.170 $1.175 Unit Cost Summary Unit Cost: Present Rates ($/kWh)$0.202 $0.2053 $0.2214 $0.2293 $0.1701 $1.1748 Unit Cost: COSA Rates ($/kWh)$0.198 $0.2093 $0.2079 $0.2208 $0.1678 $1.0600 Difference from Present Rates -2.22%1.99%-6.09%-3.72%-1.39%-9.78% SUMMARY OF PRESENT AND PROPOSED RATE REVENUE BY CUSTOMER CLASS Schedule 1.1 Schedule 1.1 to 1.9 Page 1 of 10February 2024 Prepared By EES Consulting, Inc. City of Palo Alto - 100% Demand Forecast Year: 2025 Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Power Supply Demand (PD)$12,059,111 $1,525,512 $853,735 $5,178,050 $4,481,269 $20,546 Energy (PE)$85,775,612 $13,664,488 $5,622,166 $30,235,026 $36,079,503 $174,429 Direct Assignment (PDA)$0 $0 $0 $0 $0 $0 Distribution Demand (DD)$48,672,424 $7,211,559 $3,827,858 $21,189,930 $16,221,785 $221,292 Energy (DE)$0 $0 $0 $0 $0 $0 Customer (DC)$16,489,682 $5,450,955 $763,798 $8,583,596 $1,691,151 $182 Direct Assignment (DDA)$1,590,310 $0 $0 $0 $0 $1,590,310 Total $164,587,138 $27,852,514 $11,067,556 $65,186,601 $58,473,708 $2,006,759 Total Cost / Function Production $97,834,723 $15,190,000 $6,475,900 $35,413,076 $40,560,772 $194,975 Transmission $0 $0 $0 $0 $0 $0 Distribution $66,752,416 $12,662,515 $4,591,655 $29,773,526 $17,912,936 $1,811,784 Total Cost / Function $164,587,138 $27,852,514 $11,067,556 $65,186,601 $58,473,708 $2,006,759 Total Cost / Classifier Demand $60,731,534 $8,737,071 $4,681,592 $26,367,979 $20,703,054 $241,837 Energy $85,775,612 $13,664,488 $5,622,166 $30,235,026 $36,079,503 $174,429 Customer $16,489,682 $5,450,955 $763,798 $8,583,596 $1,691,151 $182 Direct Assignment $1,590,310 $0 $0 $0 $0 $1,590,310 Total Cost / Classifier $164,587,138 $27,852,514 $11,067,556 $65,186,601 $58,473,708 $2,006,759 check 0 0 0 0 0 0 FUNCTIONALIZATION AND CLASSIFICATION OF REVENUE REQUIREMENT SUMMARY BY CUSTOMER CLASS Schedule 1.2 Schedule 1.1 to 1.9 Page 2 of 10February 2024 Prepared By EES Consulting, Inc. City of Palo Alto - 100% Demand Historic Year: 2021 Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Power Supply Demand (PD)$2,837,950 $358,268 $200,664 $1,218,428 $1,055,861 $4,729 Energy (PE)$27,397,411 $4,370,785 $1,780,313 $9,681,321 $11,506,983 $58,008 Direct Assignment (PDA)$0 $0 $0 $0 $0 $0 Transmission Demand (TD)$0 $0 $0 $0 $0 $0 Energy (TE)$0 $0 $0 $0 $0 $0 Direct Assignment (TDA)$0 $0 $0 $0 $0 $0 Distribution Demand (DD)$169,721,240 $24,953,594 $13,477,543 $74,374,253 $56,268,738 $647,113 Energy (DE)$0 $0 $0 $0 $0 $0 Customer (DC)$40,593,025 $10,418,286 $1,282,084 $23,713,532 $5,179,090 $32 Direct Assignment (DDA)$7,427,544 $0 $0 $0 $0 $7,427,544 Total $247,977,170 $40,100,933 $16,740,604 $108,987,533 $74,010,673 $8,137,426 Total Cost / Function Production $30,235,360 $4,729,053 $1,980,977 $10,899,749 $12,562,844 $62,737 Transmission $0 $0 $0 $0 $0 $0 Distribution $217,741,809 $35,371,880 $14,759,627 $98,087,785 $61,447,829 $8,074,689 Total Cost / Function $247,977,170 $40,100,933 $16,740,604 $108,987,533 $74,010,673 $8,137,426 Total Cost / Classifier Demand $172,559,190 $25,311,861 $13,678,207 $75,592,680 $57,324,599 $651,842 Energy $27,397,411 $4,370,785 $1,780,313 $9,681,321 $11,506,983 $58,008 Customer $40,593,025 $10,418,286 $1,282,084 $23,713,532 $5,179,090 $32 Direct Assignment $7,427,544 $0 $0 $0 $0 $7,427,544 Total Cost / Classifier $247,977,170 $40,100,933 $16,740,604 $108,987,533 $74,010,673 $8,137,426 check 0 0 0 0 0 0 FUNCTIONALIZATION AND CLASSIFICATION OF RATE BASE SUMMARY BY CUSTOMER CLASS Schedule 1.3 Schedule 1.1 to 1.9 Page 3 of 10February 2024 Prepared By EES Consulting, Inc. City of Palo Alto - 100% Demand Forecast Year: 2025 Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Power Purchases $77,938,853 $12,076,773 $5,064,877 $28,518,196 $32,109,436 $169,570 Transmission/Ancillary Services Purchases $28,377,775 $4,538,512 $1,815,971 $10,071,340 $11,887,704 $64,248 Other -$4,111,816 -$657,611 -$263,126 -$1,459,293 -$1,722,476 -$9,309 Total Production $115,533,652 $18,089,382 $7,470,671 $41,860,681 $47,858,233 $254,685 Total Distribution $28,005,465 $4,890,155 $1,850,538 $12,549,763 $7,458,839 $1,256,169 Total Operation & Maintenance $143,539,117 $22,979,538 $9,321,209 $54,410,444 $55,317,072 $1,510,854 Total O&M w/o Purchased Power Supply & A&G $40,614,187 $7,715,792 $2,785,933 $17,280,750 $11,539,837 $1,291,875 Total Customer Service, Accounts & Sales $12,608,722 $2,825,637 $935,395 $4,730,987 $4,080,998 $35,706 Total Administrative & General $7,698,473 $1,455,847 $527,903 $3,281,415 $2,187,225 $246,083 Total O&M plus A&G $163,846,313 $27,261,021 $10,784,507 $62,422,846 $61,585,295 $1,792,643 Total Taxes $0 $0 $0 $0 $0 $0 Total Interest / Debt Service Expense $4,770,582 $767,840 $323,639 $2,150,357 $1,352,040 $176,706 Total Capital Projects Funded From Rates $6,500,000 $1,056,184 $519,787 $2,792,253 $2,107,800 $23,976 Revenue Requirement Before Other Revenues $215,571,473 $36,012,298 $14,344,364 $83,466,601 $79,583,924 $2,164,286 Revenue Req. Before Taxes and Other Revenues $215,571,473 $36,012,298 $14,344,364 $83,466,601 $79,583,924 $2,164,286 Total Other Revenues $50,984,335 $8,159,783 $3,276,809 $18,279,999 $21,110,216 $157,528 REVENUE REQUIREMENT for COST ALLOCATION $164,587,138 $27,852,514 $11,067,556 $65,186,601 $58,473,708 $2,006,759 SUMMARY OF REVENUE REQUIREMENT COST ALLOCATION Schedule 1.4 Schedule 1.1 to 1.9 Page 4 of 10February 2024 Prepared By EES Consulting, Inc. City of Palo Alto - 100% Demand Historic Year: 2021 Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Total Transmission Plant $0 $0 $0 $0 $0 $0 Total Distribution Plant $350,285,324 $55,478,957 $22,215,541 $153,581,897 $92,838,756 $26,170,173 Total Transmission & Distribution $350,285,324 $55,478,957 $22,215,541 $153,581,897 $92,838,756 $26,170,173 Total General Plant $47,223,629 $7,479,382 $2,994,983 $20,705,105 $12,516,034 $3,528,125 Total Plant Before General Plant & Intangible $350,285,324 $55,478,957 $22,215,541 $153,581,897 $92,838,756 $26,170,173 Total Gross Plant in Service $397,508,952 $62,958,339 $25,210,523 $174,287,002 $105,354,790 $29,698,298 Total Accumulated Depreciation $188,823,622 $29,369,777 $11,053,181 $80,221,345 $46,210,884 $21,968,435 Total Net Plant $208,685,330 $33,588,562 $14,157,342 $94,065,657 $59,143,905 $7,729,863 Total Working Capital $39,291,839 $6,512,371 $2,583,262 $14,921,877 $14,866,767 $407,563 TOTAL RATE BASE $247,977,170 $40,100,933 $16,740,604 $108,987,533 $74,010,673 $8,137,426 SUMMARY OF RATE BASE COST ALLOCATIONS Schedule 1.5 Schedule 1.1 to 1.9 Page 6 of 10February 2024 Prepared By EES Consulting, Inc. City of Palo Alto - 100% Demand Historic Year: 2021 Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Recorded Load Data Energy Sales (kWh)815,778,523 161,545,337 45,675,813 242,402,726 364,257,301 1,897,346 Total Billing Capacity (kW)1,297,123 0 0 669,694 627,429 0 Avg. Monthly Billing Capacity (kW)108,094 0 0 55,808 52,286 0 Number of Customers 29,647 25,600 3,147 828 70 2 Ratio of NCP to Avg. Billing Capacity 0%0%0%101%96%0% Rate Classes NCP Demand at Meter 143,946 26,353 9,983 56,601 50,402 607 Estimates Based on Recorded Data Annual NCP Load Factor 65%70%52%49%82%36% Rate Classes CP Demand at Input Voltage 129,587 21,580 6,696 48,905 52,406 0 Annual CP Load Factor 72%85%78%57%79%0% Average On-Peak kWh as a % of Total kWh 0%59%59%59%59%59% Average Off-Peak kWh as a % of Total kWh 0%41%41%41%41%41% SUMMARY OF HISTORIC LOAD DATA Schedule 1.6 Schedule 1.1 to 1.9 Page 7 of 10February 2024 Prepared By EES Consulting, Inc. City of Palo Alto - 100% Demand Forecast Year: 2025 Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Forecast Load Data Energy Sales (kWh)831,943,836 133,052,833 53,237,722 295,255,415 348,504,639 1,893,227 Total Billing Capacity (kVa)1,371,408 0 0 764,019 607,389 0 Avg. Monthly Billing Capacity (kVa)114,284 0 0 63,668 50,616 0 Number of Customers 30,193 26,100 3,183 837 71 2 Ratio of NCP to Avg. Billing 192%0%0%98%94%0% Rate Classes NCP Demand at Meter 144,419 22,568 11,434 62,252 47,558 606 Forecast Based on Recorded and Forecast Data Annual NCP Load Factor 294%67%53%54%84%36% Rate Classes CP Demand at Input Voltage 137,082 16,462 9,311 61,491 49,449 367 Annual CP Load Factor 352%92%65%55%80%59% On-Peak kWh as a % of Total kWh 297%59%59%59%59%59% Off-Peak kWh as a % of Total kWh 203%41%41%41%41%41% Schedule 1.7 SUMMARY OF FORECAST LOAD DATA Schedule 1.1 to 1.9 Page 8 of 10February 2024 Prepared By EES Consulting, Inc. City of Palo Alto - 100% Demand Forecast Year: 2025 Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Forecast Power Supply Power Purchases NCPA Pooling $10,148,225 $1,623,025 $649,412 $3,601,629 $4,251,182 $22,976 NCPA Facilities $2,542,371 $406,606 $162,693 $902,294 $1,065,022 $5,756 Local Capacity Purchase $7,486,559 $945,117 $529,355 $3,214,232 $2,785,379 $12,476 Load Advance $0 $0 $0 $0 $0 $0 Carbon Neutral Purchases (REC)$9,741 $1,558 $623 $3,457 $4,081 $22 Market Power Purchases $8,892,531 $1,422,200 $569,057 $3,155,981 $3,725,161 $20,133 PA Green Comm Purch $0 $0 $0 $0 $0 $0 Transmission/Ancillary Services Purchases Transmission Purchases $28,377,775 $4,538,512 $1,815,971 $10,071,340 $11,887,704 $64,248 Open $0 $0 $0 $0 $0 $0 Open $0 $0 $0 $0 $0 $0 Low Carbon Fuel G&A -$4,111,816 -$657,611 -$263,126 -$1,459,293 -$1,722,476 -$9,309 Total Power Supply $66,674,227 $10,411,115 $4,316,935 $24,220,078 $27,579,622 $146,478 SUMMARY OF POWER SUPPLY COSTS Schedule 1.8 Schedule 1.1 to 1.9 Page 9 of 10February 2024 Prepared By EES Consulting, Inc. City of Palo Alto - 100% Demand Forecast Year: 2025 Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Revenues: Customer Charge Revenues $0 $0 $0 $0 $0 $0 Energy Revenues $123,566,578 $27,309,759 $11,784,676 $43,647,477 $40,824,665 $0 Demand Revenues $42,530,564 $0 $0 $24,059,546 $18,471,018 $0 Surcharge $2,224,184 $0 $0 $0 $0 $2,224,184 Total Revenues $168,321,326 $27,309,759 $11,784,676 $67,707,023 $59,295,683 $2,224,184 Average Charge: Customer Charge $ / Per Customer / Month $0.00 $0.00 $0.00 $0.00 $0.00 Average Energy + Demand Charge $ / kWh $0.205 $0.221 $0.229 $0.170 $0.000 Average Energy Charge $ / kWh $0.205 $0.221 $0.148 $0.117 $0.000 Demand Charge $ / kVa or kW $0.00 $0.00 $31.49 $30.41 $0.00 SUMMARY OF REVENUES AT PRESENT RATES Schedule 1.9 Schedule 1.1 to 1.9 Page 10 of 10February 2024 Prepared By EES Consulting, Inc. City of Palo Alto - 100% Demand Forecast Year: 2025 Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Billing Determinants Total kW 1,371,408 0 0 764,019 607,389 0 Total Demand (kW)1,785,322 264,621 143,933 764,019 607,389 5,359 Total Energy (kWh)831,943,836 133,052,833 53,237,722 295,255,415 348,504,639 1,893,227 Average Monthly Customers 30,193 26,100 3,183 837 71 2 Functional Cost Total Cost Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Power Supply Demand (PD)$12,059,111 $1,525,512 $853,735 $5,178,050 $4,481,269 $20,546 $/kW $6.75 $5.76 $5.93 $6.78 $7.38 $3.83 Energy (PE)$85,775,612 $13,664,488 $5,622,166 $30,235,026 $36,079,503 $174,429 $/kWh $0.103 $0.103 $0.106 $0.102 $0.104 $0.092 Direct Assignment (PDA)$0 $0 $0 $0 $0 $0 $/kW $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $/kWh $0.000 $0.000 $0.000 $0.000 $0.000 $0.000 Distribution Demand (DD)$48,672,424 $7,211,559 $3,827,858 $21,189,930 $16,221,785 $221,292 $/kW $27.26 $27.25 $26.59 $27.73 $26.71 $41.29 Energy (DE)$0 $0 $0 $0 $0 $0 $/kWh $0.000 $0.000 $0.000 $0.000 $0.000 $0.000 Customer (DC)$16,489,682 $5,450,955 $763,798 $8,583,596 $1,691,151 $182 $/Customer/Month $46 $17 $20 $855 $1,989 $8 Direct Assignment (DDA)$1,590,310 $0 $0 $0 $0 $1,590,310 $/kW $0.89 $0.00 $0.00 $0.00 $0.00 $296.74 $/kWh $0.002 $0.000 $0.000 $0.000 $0.000 $0.840 Total $164,587,138 $27,852,514 $11,067,556 $65,186,601 $58,473,708 $2,006,759 Total $/kW $34.91 $33.02 $32.53 $34.51 $34.09 $341.87 $/kWh $0.10501 $0.10270 $0.10560 $0.10240 $0.10353 $0.93213 $/Customer/Month $45.51 $17.40 $20.00 $854.60 $1,989.31 $7.54 Melded kW/kWh in $/kWh 0.1780 0.1684 0.1935 0.1917 0.1629 1.0599 Melded kW/Cust in $/Cust/M $217.52 $45.30 $142.56 $3,479.85 $26,342.39 $75,817.26 SUMMARY OF REVENUE REQUIREMENT UNIT COSTS BY CUSTOMER CLASS Schedule 2.1 Schedule 2.1 Page 1 of 2February 2024 Prepared By EES Consulting, Inc. City of Palo Alto - 100% Demand Forecast Year: 2025 Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Billing Determinants Total kVa 1,371,408 0 0 764,019 607,389 0 Total Demand (kW)1,785,322 264,621 143,933 764,019 607,389 5,359 Total Energy (kWh)831,943,836 133,052,833 53,237,722 295,255,415 348,504,639 1,893,227 Average Monthly Customers 30,193 26,100 3,183 837 71 2 Functional Cost Total Cost Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Power Supply Demand (PD)$2,837,950 $358,268 $200,664 $1,218,428 $1,055,861 $4,729 $/kW $1.35 $1.39 $1.59 $1.74 $0.88 Energy (PE)$27,397,411 $4,370,785 $1,780,313 $9,681,321 $11,506,983 $58,008 $/kWh $0.033 $0.033 $0.033 $0.033 $0.033 $0.031 Direct Assignment (PDA)$0 $0 $0 $0 $0 $0 $/kW $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $/kWh $0.000 $0.000 $0.000 $0.000 $0.000 $0.000 Distribution Demand (DD)$169,721,240 $24,953,594 $13,477,543 $74,374,253 $56,268,738 $647,113 $/kW $94.30 $93.64 $97.35 $92.64 $120.75 Energy (DE)$0 $0 $0 $0 $0 $0 $/kWh $0.000 $0.000 $0.000 $0.000 $0.000 $0.000 Customer (DC)$40,593,025 $10,418,286 $1,282,084 $23,713,532 $5,179,090 $32 $/Customer/Month $33 $34 $2,361 $6,092 $1 Direct Assignment (DDA)$7,427,544 $0 $0 $0 $0 $7,427,544 $/kW $0.00 $0.00 $0.00 $0.00 $1,385.93 $/kWh $0.000 $0.000 $0.000 $0.000 $3.923 Total $247,977,170 $40,100,933 $16,740,604 $108,987,533 $74,010,673 $8,137,426 SUMMARY OF RATE BASE UNIT COST BY CUSTOMER CLASS Schedule 2.2 Schedule 2.2 Page 2 of 2February 2024 Prepared By EES Consulting, Inc. City of Palo Alto INPUT REVENUE REQUIREMENT Schedule 3.1 Year Classification 2025 & Allocation Cost, $Function Factor Classification & Allocation Method FERC Account Operation & Maintenance Expense Power Purchases 555.70 Western Power Purchases $7,903,405 P WEST Western Cost (84% E, 16% D) 555.71 Contra Surplus Energy -$13,328,841 P kWh Annual Energy (kWh) 555.72 NCPA Pooling $10,148,225 P kWh Annual Energy (kWh) 555.73 NCPA Facilities $2,542,371 P kWh Annual Energy (kWh) 555.74 Local Capacity Purchase $7,486,559 P CP12 12 Coincident Utility Peak 555.75 Load Advance $0 P kWh Annual Energy (kWh) 555.76 Renewable Energy $37,130,836 P REN Renewable (92% E, 3% D) 555.77 Carbon Neutral Purchases (REC)$9,741 P kWh Annual Energy (kWh) 555.78 Market Power Purchases $8,892,531 P kWh Annual Energy (kWh) 555.79 PA Green Comm Purch $0 P kWh Annual Energy (kWh) 555.80 TANC & Calveras O&M $6,816,709 P CALA Calaveras Cost (93% E, 7% D) 555.90 CVP O&M $7,000,000 P WEST Western Cost (84% E, 16% D) 555.791 EMA Purchases $0 P kWh Annual Energy (kWh) 556.00 Energy Risk Mgmt $0 P kWh Annual Energy (kWh) X555 Budget True-up $0 P kWh Annual Energy (kWh) 555.15 Resource Management Admin $3,337,316 P kWh Annual Energy (kWh) Transmission/Ancillary Services Purchases XXXX Transmission Purchases $28,377,775 P kWh Annual Energy (kWh) Other 555.10 Surplus Energy $13,328,841 P kWh Annual Energy (kWh) 555.20 Low Carbon Fuel G&A $0 P kWh Annual Energy (kWh) 555.30 Carbon Allowance Revenues -$4,111,816 P kWh Annual Energy (kWh) 555.40 open $0 P kWh Annual Energy (kWh) 555.45 Allocated G&A $0 P kWh Annual Energy (kWh) 555.50 Renewable Energy Salaries & General $0 P DSRE Demand-Side Renewable Energy Allocator Total Purchased Power $115,533,652 Total Production $115,533,652 Schedule 3.1 Page 1 of 5 February 2024 Prepared By EES Consulting, Inc. City of Palo Alto INPUT REVENUE REQUIREMENT Schedule 3.1 Year Classification 2025 & Allocation Cost, $Function Factor Classification & Allocation Method FERC Account Operation & Maintenance Expense Distribution 580.00 Op. Supervision & Engineering $11,890,278 D RBD On the Basis of Distribution Rate Base 581.00 Load Dispatching $0 D RBSE On the Basis of Station Equipment Rate Base 582.00 Line and Station Expenses $0 D RBSE On the Basis of Station Equipment Rate Base 583.00 Overhead Lines $0 D RBOH On the Basis of all Overhead Rate Base 584.00 Underground Lines $0 D RBUG On the Basis of all Underground Rate Base 585.00 Street Lighting & Signal System $0 D DA1 Direct Assignment for Streetlights 586.00 Meters $7,396 D CUSTW Customers Weighted for Accounting/Metering 587.00 Customer Installations $1,153,617 D CUSTW Customers Weighted for Accounting/Metering 588.00 Misc. Distribution $1,889,789 D RBD-noDA As Distribution Ratebase without DA Street Lighting 589.00 Rents $6,733,141 D RBD-noDA As Distribution Ratebase without DA Street Lighting 590.00 Maint. Supervision & Engineering $4,769,435 D RBD-noDA As Distribution Ratebase without DA Street Lighting 591.00 Maint. of Structures $0 D RBSE On the Basis of Station Equipment Rate Base 592.00 Maint. of Station Equipment $0 D RBSE On the Basis of Station Equipment Rate Base XXXX Maint. of Structures and Equipment $0 D RBSE On the Basis of Station Equipment Rate Base 593.00 Maint. of Overhead Lines $4,538,857 D RBOH On the Basis of all Overhead Rate Base 594.00 Maint. Of Underground Lines $80,123 D RBUG On the Basis of all Underground Rate Base XXXX Maint. of Lines $0 D RBUG On the Basis of all Underground Rate Base 595.00 Maint. of Line Transformers $0 D RBTR On the Basis of all Transformer Rate Base XXXX Maint. of Line Transformers - Underground $0 D RBTR On the Basis of all Transformer Rate Base 596.00 Maint. of Street Lighting & Signal System $603,558 D DA1 Direct Assignment for Streetlights 597.00 Maint. of Meters $0 D CUSTM Customers Weighted for Meters and Services 598.00 Maint. of Misc. Distribution Plant -$3,882,192 D RBD On the Basis of Distribution Rate Base 598.10 Communications $221,461 D RBD-noDA As Distribution Ratebase without DA Street Lighting Total Distribution $28,005,465 Total Operation & Maintenance $143,539,117 Schedule 3.1 Page 2 of 5 February 2024 Prepared By EES Consulting, Inc. City of Palo Alto INPUT REVENUE REQUIREMENT Schedule 3.1 Year Classification 2025 & Allocation Cost, $Function Factor Classification & Allocation Method FERC Account Operation & Maintenance Expense Customer Service, Accounts, & Sales 901.00 Supervision $2,584,782 D CUSTW Customers Weighted for Accounting/Metering 902.00 Meter Reading $694,215 D CUSTMR Customers Weighted for Meter Reading 903.00 Customer Records Collection $968,331 D REV On The Basis of Revenue 904.00 Uncollectable Accounts $1,727,779 D REV On The Basis of Revenue 905.00 Misc. Customer Accounts (Customer Deposits)$0 D CUST Actual Customers 906.00 Customer Service & Information -$744,743 D CUST Actual Customers 907.00 Customer Communication & Education $122,716 D CUST Actual Customers 908.00 Customer Assistance $0 D CUST Actual Customers 910.00 Misc. Customer Service & Information $270,056 D CUST Actual Customers 912.00 Demonstrating & Selling $0 D CUST Actual Customers 913.00 Advertising $0 D CUST Actual Customers 916.00 Misc. Sales Expenses $295,823 D CUSTW Customers Weighted for Accounting/Metering 917.00 Sales Expenses $0 D OM On the Basis of All O&M 906.10 Key Accounts $0 D OM On the Basis of All O&M 906.20 Energy Efficiency, DSM& Low Income Program $6,689,764 D DSMEE DSM / EE Allocator: 906.30 Low Income Residential Energy Assistance Program $0 D DSMEE DSM / EE Allocator: Total Customer Service, Accounts & Sales $12,608,722 Total O&M w/o Purchased Power Supply & A&G $40,614,187 Administrative & General 920.00 Administrative & General Salaries $2,840,007 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 921.00 Office Supplies $110,579 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 922.00 Administrative Transfer - Credit $0 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 923.00 Outside Services & Pension Credit $637,787 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 924.00 Property Insurance $230,547 SS NETPLT On the Basis of Net Plant 925.00 Injuries and Damages $179,837 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 926.00 Employee Pension & Benefits $2,346,975 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 927.00 Franchise Requirements $23,187 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 928.00 Regulatory Expense $0 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 929.00 Duplicate Charge - Credit $0 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) XXXX General Advertising $0 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 930.00 Misc. General Expense $0 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 930.10 General Advertising $0 SS OM On the Basis of All O&M 930.20 Misc. General Expense $111,099 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 930.30 Environmental $2,034 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 931.00 COVID Expenses $0 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 932.00 Maint. of General Plant & Communication Equipment $7,022 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 933.00 Transportation $0 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 935.00 Cost Plan Charges $1,209,398 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) Total Administrative & General $7,698,473 Total O&M plus A&G $163,846,313 Schedule 3.1 Page 3 of 5 February 2024 Prepared By EES Consulting, Inc. City of Palo Alto INPUT REVENUE REQUIREMENT Schedule 3.1 Year Classification 2025 & Allocation Cost, $Function Factor Classification & Allocation Method FERC Account Operation & Maintenance Expense Depreciation 403.00 Generation Plant $0 P RBG On the Basis of Generation Rate Base 403.44 Transmission Plant $0 T RBT On the Basis of Transmission Rate Base 403.45 Distribution Plant $0 D RBD On the Basis of Distribution Rate Base 403.46 General Plant $0 SS RBGP On the Basis of General Plant Rate Base 403.80 Amortization of Plant $0 D RBD On the Basis of Distribution Rate Base XXXX Amortization of Loss on Refunding $0 D RBD On the Basis of Distribution Rate Base XXXX Miscellaneous Intangible Plant $0 SS RBIG On the Basis of Intangible Plant Rate Base Total Depreciation $0 Interest and Debt Service Expense 427.00 Interest and Debt Service Electric $4,770,582 D NETPLT On the Basis of Net Plant 428.00 Amortization of Debt Discount $0 SS NETPLT On the Basis of Net Plant 429.00 Other Interest Expense $0 SS NETPLT On the Basis of Net Plant XXXX Annual LT Debt Service $0 SS GPLT Intangible) XXXX Annual ST Debt Service (AMI)$0 SS NETPLT On the Basis of Net Plant XXXX Accelerated Debt Reduction - LT Debt $0 SS GPLT Intangible) XXXX Ind A Interest Expense $0 T DA3 Direct Assignment for Ind A__________________________ Total Interest / Debt Service Expense $4,770,582 Capital Projects Funded From Rates Production $0 P RBG On the Basis of Generation Rate Base Transmission $0 T RBT On the Basis of Transmission Rate Base Distribution $6,500,000 D RBD-noDA Services Services General $0 SS GPLT Intangible) Retirements $0 SS NETPLT On the Basis of Net Plant Open $0 SS NETPLT On the Basis of Net Plant Total Capital Projects Funded From Rates $6,500,000 Other Contributions General Fund Transfer to/(from)$15,121,000 SS GF General Fund transfer based on other Revenues Reserves $23,800,000 SS Rcontr Based on production and delivery split Debt Service Coverage Requirement $0 SS NETPLT On the Basis of Net Plant Other transfers out $1,533,578 SS NETPLT On the Basis of Net Plant Transfers In $0 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) Reserve Alloc Reapp $0 D OMP On the Basis of Purchased Power O&M Margin Requirement $0 SS OM On the Basis of All O&M Total Other Contributions $40,454,578 Revenue Requirement Before Other Revenues $215,571,473 Revenue Req. Before Taxes and Other Revenues $215,571,473 Schedule 3.1 Page 4 of 5 February 2024 Prepared By EES Consulting, Inc. City of Palo Alto INPUT REVENUE REQUIREMENT Schedule 3.1 Year Classification 2025 & Allocation Cost, $Function Factor Classification & Allocation Method FERC Account Operation & Maintenance Expense Other Revenues 450.00 Late Charges $0 SS OM On the Basis of All O&M 451.00 Connect / Re-Connect Fees $1,447,561 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 453.00 Misc Revenue $0 SS OM On the Basis of All O&M 454.00 Joint Use Pole Attachment Income $0 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 456.00 Misc Revenue (Other)$0 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 457.00 Transfer Credits $0 SS OM On the Basis of All O&M 458.00 Hydro Adjuster $0 SS OM On the Basis of All O&M 419&424 Dividends from Affiliates, Interest $7,000,000 P WEST Western Cost (84% E, 16% D) 448.00 Interdepartmental Sales $0 SS OM On the Basis of All O&M 415&416 Income (Loss) from Equity Investments $699,559 P kwh Annual Energy (kWh) XXXX Open $0 SS OMAG On the Basis of O&M (w/o Power Supply and A&G) 449.00 Other Revenues $274,394 P kwh Annual Energy (kWh) 456.20 Investment Income $0 SS OM On the Basis of All O&M 421.00 Misc Income (RA Sales & Surplus Sales)$37,045,073 P kwh Annual Energy (kWh) 421.10 Public Benefits Revenue $4,517,748 P kwh Annual Energy (kWh) Total Other Revenues $50,984,335 REVENUE REQUIREMENT for COST ALLOCATION $164,587,138 Schedule 3.1 Page 5 of 5 February 2024 Prepared By EES Consulting, Inc. City of Palo Alto Total 2021 Expenses 2022 2023 2024 2025 2026 Operation & Maintenance Expense Power Purchases Western Power Purchases $6,687,852 $9,394,901 $8,394,847 $9,285,966 $7,903,405 $9,701,222 Contra Surplus Energy -$5,205,273 $0 -$1,475,608 -$13,328,841 -$12,853,694 NCPA Pooling $10,320,035 $4,132,334 $5,415,717 $5,440,093 $10,148,225 $10,111,288 NCPA Facilities $2,312,749 $2,388,368 $2,436,135 $2,484,858 $2,542,371 $2,595,329 Local Capacity Purchase $3,028,409 $5,906,575 $5,286,310 $6,544,573 $7,486,559 $9,462,041 Load Advance Renewable Energy $38,702,755 $35,700,546 $34,990,114 $35,427,070 $37,130,836 $38,650,038 Carbon Neutral Purchases (REC)$1,108,277 $0 $492,577 $128,608 $9,741 $20,331 Market Power Purchases $0 $13,137,319 $22,769,940 $18,163,843 $8,892,531 $8,490,473 PA Green Comm Purch $0 TANC & Calveras O&M $3,842,277 $5,483,163 $5,616,183 $6,263,875 $6,816,709 $6,398,793 CVP O&M $807,716 $7,000,000 $7,000,000 $7,000,000 $7,000,000 $7,000,000 EMA Purchases $3,822,940 Energy Risk Mgmt $20,064 Budget True-up $8,984,011 Resource Management Admin $1,922,591 $2,824,303 $2,991,189 $3,100,525 $3,337,316 $3,474,146 Transmission/Ancillary Services Purchases Transmission Purchases $23,199,086 $20,397,767 $25,498,017 $27,280,567 $28,377,775 $29,964,562 Other Surplus Energy $2,994,684 $5,205,273 $0 $1,475,608 $13,328,841 $12,853,694 Low Carbon Fuel G&A $0 Carbon Allowance Revenues $0 -$6,118,830 -$5,285,256 -$5,700,281 -$4,111,816 -$4,231,477 open $0 Allocated G&A $6,843,179 Renewable Energy Salaries & General $466,530 Total Purchased Power $106,079,144 $109,230,458 $115,605,773 $115,419,697 $115,533,652 $121,636,745 Total Production $106,079,144 $109,230,458 $115,605,773 $115,419,697 $115,533,652 $121,636,745 PROJECTED REVENUE REQUIREMENTS Schedule 3.2 Schedule 3.2 Page 1 of 5 February 2024 Prepared By EES Consulting, Inc. City of Palo Alto Total 2021 Expenses 2022 2023 2024 2025 2026 Operation & Maintenance Expense PROJECTED REVENUE REQUIREMENTS Schedule 3.2 Distribution Op. Supervision & Engineering $10,003,968 $7,776,271 $11,253,181 $11,612,313 $11,890,278 $12,187,535 Load Dispatching $0 $0 $0 Line and Station Expenses $0 $0 $0 Overhead Lines $0 $0 $0 Underground Lines $0 $0 $0 Street Lighting & Signal System $112,680 $0 $0 $0 Meters $0 $7,000 $7,000 $7,223 $7,396 $7,581 Customer Installations -$940,288 $1,038,229 $1,091,805 $1,126,648 $1,153,617 $1,182,457 Misc. Distribution $565,477 $1,596,973 $1,788,532 $1,845,611 $1,889,789 $1,937,034 Rents $6,137,322 $6,069,000 $6,182,562 $6,329,377 $6,733,141 $7,002,466 Maint. Supervision & Engineering $3,492,774 $4,444,812 $4,513,883 $4,657,938 $4,769,435 $4,888,671 Maint. of Structures $0 $0 $0 $0 $0 $0 Maint. of Station Equipment $0 $0 $0 Maint. of Structures and Equipment $0 $0 $0 Maint. of Overhead Lines $2,360,521 $1,581,321 $4,295,659 $4,432,750 $4,538,857 $4,652,328 Maint. Of Underground Lines $16,644 $75,171 $75,830 $78,250 $80,123 $82,126 Maint. of Lines $0 $0 $0 Maint. of Line Transformers $0 $0 $0 Maint. of Line Transformers - Underground $0 $0 $0 Maint. of Street Lighting & Signal System $0 $310,880 $571,219 $589,449 $603,558 $618,647 Maint. of Meters $0 $0 $0 Maint. of Misc. Distribution Plant $1,163,077 -$926,128 -$3,892,006 -$3,882,192 -$3,932,002 Communications $167,606 $388,899 $209,595 $216,284 $221,461 $226,998 Total Distribution $21,916,704 $24,451,633 $29,063,136 $27,003,837 $28,005,465 $28,853,843 Total Operation & Maintenance $127,995,848 $133,682,092 $144,668,909 $142,423,534 $143,539,117 $150,490,587 Schedule 3.2 Page 2 of 5 February 2024 Prepared By EES Consulting, Inc. City of Palo Alto Total 2021 Expenses 2022 2023 2024 2025 2026 Operation & Maintenance Expense PROJECTED REVENUE REQUIREMENTS Schedule 3.2 Customer Service, Accounts, & Sales Supervision $1,261,028 $1,834,721 $1,939,798 $2,009,325 $2,584,782 $2,688,174 Meter Reading $415,884 $492,765 $520,986 $539,660 $694,215 $721,983 Customer Records Collection $585,885 $687,337 $726,702 $752,748 $968,331 $1,007,064 Uncollectable Accounts $625,505 $757,029 $757,029 $757,029 $1,727,779 $1,727,779 Misc. Customer Accounts (Customer Deposits)$0 $0 $0 $0 $0 $0 Customer Service & Information -$296,500 -$528,631 -$558,906 -$578,939 -$744,743 -$774,533 Customer Communication & Education $0 $87,106 $92,095 $95,396 $122,716 $127,625 Customer Assistance $0 $0 $0 $0 $0 $0 Misc. Customer Service & Information $191,690 $202,668 $209,932 $270,056 $280,858 Demonstrating & Selling $0 $0 $0 $0 $0 Advertising $0 $0 $0 $0 $0 Misc. Sales Expenses $114,500 $209,980 $222,006 $229,963 $295,823 $307,656 Sales Expenses $0 $0 $0 $0 $0 Key Accounts $0 $0 $0 $0 $0 Energy Efficiency, DSM& Low Income Program $4,086,083 $6,179,462 $6,693,931 $6,689,764 $5,766,493 Low Income Residential Energy Assistance Program $0 $0 $0 $0 $0 Total Customer Service, Accounts & Sales $2,706,301 $7,818,080 $10,081,840 $10,709,045 $12,608,722 $11,853,099 Total O&M w/o Purchased Power Supply & A&G $24,623,005 $32,269,713 $39,144,976 $37,712,882 $40,614,187 $28,853,843 Administrative & General Administrative & General Salaries $1,261,556 $1,848,292 $2,143,425 $2,207,728 $2,840,007 $2,953,607 Office Supplies $200,741 $82,457 $83,457 $85,961 $110,579 $115,003 Administrative Transfer - Credit $0 $0 $0 $0 $0 $0 Outside Services & Pension Credit $311,036 $431,250 $481,354 $495,795 $637,787 $663,299 Property Insurance $163,810 $167,000 $174,000 $179,220 $230,547 $239,769 Injuries and Damages $45,187 $81,310 $135,727 $139,799 $179,837 $187,030 Employee Pension & Benefits $1,645,824 $1,495,593 $1,771,322 $1,824,461 $2,346,975 $2,440,854 Franchise Requirements $20,077 $17,500 $17,500 $18,025 $23,187 $24,115 Regulatory Expense $0 $0 $0 $0 $0 $0 Duplicate Charge - Credit $0 $0 $0 $0 $0 $0 General Advertising $0 $0 $0 $0 Misc. General Expense $0 $0 $0 $0 $0 $0 General Advertising $1,332 $0 $0 $0 Misc. General Expense $25,454 $83,849 $83,849 $86,364 $111,099 $115,543 Environmental $5,390 $1,535 $1,535 $1,581 $2,034 $2,115 COVID Expenses $0 $0 $0 $0 $0 $0 Maintenance of General Plant $31,830 $2,033 $5,300 $5,459 $7,022 $7,303 Transportation $0 $0 $0 Cost Plan Charges $1,521,278 $1,121,467 $1,173,264 $1,209,398 $1,271,312 Total Administrative & General $3,712,238 $5,732,098 $6,018,937 $6,217,658 $7,698,473 $8,019,950 Total O&M plus A&G $134,414,387 $147,232,270 $160,769,685 $159,350,237 $163,846,313 $170,363,636 Schedule 3.2 Page 3 of 5 February 2024 Prepared By EES Consulting, Inc. City of Palo Alto Total 2021 Expenses 2022 2023 2024 2025 2026 Operation & Maintenance Expense PROJECTED REVENUE REQUIREMENTS Schedule 3.2 Depreciation Generation Plant $0 $0 $0 Transmission Plant $0 $0 $0 Distribution Plant $6,403,152 $0 $0 $0 General Plant $2,233,509 $0 $0 $0 Amortization of Plant $0 $0 $0 Amortization of Loss on Refunding $0 $0 $0 Miscellaneous Intangible Plant $0 $0 $0 Total Depreciation $8,636,661 $0 $0 $0 $0 $0 Interest and Debt Service Expense Interest and Debt Service Electric $8,068,219 $8,068,219 $8,502,737 $8,275,943 $4,770,582 $7,873,314 Amortization of Debt Discount $0 $0 $0 Other Interest Expense $0 $0 $0 Annual LT Debt Service $0 $0 $0 Annual ST Debt Service (AMI)$0 $0 $0 Accelerated Debt Reduction - LT Debt $0 $0 $0 Ind A Interest Expense $0 $0 $0 Total Interest / Debt Service Expense $8,068,219 $8,068,219 $8,502,737 $8,275,943 $4,770,582 $7,873,314 Capital Projects Funded From Rates Production $0 $0 $0 $0 $0 $0 Transmission $0 $0 $0 $0 $0 $0 Distribution -$2,080 $22,508,996 $21,991,316 $25,508,299 $6,500,000 $25,643,701 General $0 $0 $0 $0 $0 $0 Retirements $0 $0 $0 $0 $0 $0 Open $0 $0 $0 $0 $0 $0 Total Capital Projects Funded From Rates -$2,080 $22,508,996 $21,991,316 $25,508,299 $6,500,000 $25,643,701 Other Contributions General Fund Transfer to/(from)-$367,473 $14,138,000 $14,221,000 $15,119,000 $15,121,000 $15,550,000 Reserves $7,443,994 -$4,500,000 $23,800,000 Debt Service Coverage Requirement Other transfers out $334,713 $351,449 $363,046 $1,533,578 $14,594,921 Transfers In Reserve Alloc Reapp -$6,200,000 Margin Requirement -$661,616 -$568,039 -$587,742 Total Other Contributions $7,076,521 $13,811,097 $14,004,410 $4,194,305 $40,454,578 $30,144,921 Revenue Requirement Before Other Revenues $158,193,708 $191,620,582 $205,268,147 $197,328,783 $215,571,473 $234,025,573 Revenue Req. Before Taxes and Other Revenues $158,193,708 $191,620,582 $205,268,147 $197,328,783 $215,571,473 $234,025,573 Schedule 3.2 Page 4 of 5 February 2024 Prepared By EES Consulting, Inc. City of Palo Alto Total 2021 Expenses 2022 2023 2024 2025 2026 Operation & Maintenance Expense PROJECTED REVENUE REQUIREMENTS Schedule 3.2 Other Revenues Late Charges $1,658 $0 $0 $0 Connect / Re-Connect Fees $170,799 $853,087 $1,850,000 $1,850,000 $1,447,561 $1,447,561 Misc Revenue $465,178 $0 $0 $0 Joint Use Pole Attachment Income $0 $0 $0 Misc Revenue (Other)$51,580 Transfer Credits $6,183,933 Hydro Adjuster $1,288,015 $23,979,772 Dividends from Affiliates, Interest -$307,000 $7,000,000 $7,000,000 $7,000,000 $7,000,000 $7,000,000 Interdepartmental Sales $4,035,716 Income (Loss) from Equity Investments $682,703 $1,619,919 $1,323,004 $1,741,050 $699,559 $801,144 Open Other Revenues $357,575 $488,778 $500,975 $274,394 $281,313 Investment Income $561,981 Misc Income (RA Sales & Surplus Sales)$0 $18,529,188 $17,751,851 $18,801,694 $37,045,073 $23,470,737 Public Benefits Revenue $4,279,271 $4,086,083 $6,179,462 $4,902,000 $4,517,748 $4,583,987 Total Other Revenues $16,483,393 $33,865,070 $58,585,063 $34,294,744 $50,984,335 $37,584,742 REVENUE REQUIREMENT for COST ALLOCATION $141,710,315 $157,755,512 $146,683,084 $163,034,040 $164,587,138 $196,440,831 Schedule 3.2 Page 5 of 5 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto - 100% Demand Allocation Date 2025 Direct Direct Direct Total Demand Energy Assignment Demand Energy Assignment Demand Energy Customer Assignment Expenses PD PE PDA TD TE TDA DD DE DC DDA Operation & Maintenance Expense Power Purchases $0 Western Power Purchases $7,903,405 $1,264,545 $6,638,860 $0 $0 $0 $0 $0 $0 $0 $0 Contra Surplus Energy -$13,328,841 $0 -$13,328,841 $0 $0 $0 $0 $0 $0 $0 $0 NCPA Pooling $10,148,225 $0 $10,148,225 $0 $0 $0 $0 $0 $0 $0 $0 NCPA Facilities $2,542,371 $0 $2,542,371 $0 $0 $0 $0 $0 $0 $0 $0 Local Capacity Purchase $7,486,559 $7,486,559 $0 $0 $0 $0 $0 $0 $0 $0 $0 Load Advance $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Renewable Energy $37,130,836 $1,172,553 $35,958,283 $0 $0 $0 $0 $0 $0 $0 $0 Carbon Neutral Purchases (REC)$9,741 $0 $9,741 $0 $0 $0 $0 $0 $0 $0 $0 Market Power Purchases $8,892,531 $0 $8,892,531 $0 $0 $0 $0 $0 $0 $0 $0 PA Green Comm Purch $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 TANC & Calveras O&M $6,816,709 $477,170 $6,339,539 $0 $0 $0 $0 $0 $0 $0 $0 CVP O&M $7,000,000 $1,120,000 $5,880,000 $0 $0 $0 $0 $0 $0 $0 $0 EMA Purchases $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Energy Risk Mgmt $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Budget True-up $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Resource Management Admin $3,337,316 $0 $3,337,316 $0 $0 $0 $0 $0 $0 $0 $0 Transmission/Ancillary Services Purchases $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Transmission Purchases $28,377,775 $0 $28,377,775 $0 $0 $0 $0 $0 $0 $0 $0 Other $0 Surplus Energy $13,328,841 $0 $13,328,841 $0 $0 $0 $0 $0 $0 $0 $0 Low Carbon Fuel G&A $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Carbon Allowance Revenues -$4,111,816 $0 -$4,111,816 $0 $0 $0 $0 $0 $0 $0 $0 open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Allocated G&A $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Renewable Energy Salaries & General $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Total Purchased Power $115,533,652 $11,520,826 $104,012,826 $0 $0 $0 $0 $0 $0 $0 $0 Total Production $115,533,652 $11,520,826 $104,012,826 $0 $0 $0 $0 $0 $0 $0 $0 Power Supply Transmission Distribution FUNCTIONALIZATION AND CLASSIFICATION Schedule 3.3 REVENUE REQUIREMENT COST ALLOCATION Schedule 3.3 Page 1 of 5 February 2024 Prepared By EES Consulting, Inc. Allocation Date 2025 Direct Direct Direct Total Demand Energy Assignment Demand Energy Assignment Demand Energy Customer Assignment Expenses PD PE PDA TD TE TDA DD DE DC DDA Operation & Maintenance Expense Power Supply Transmission Distribution FUNCTIONALIZATION AND CLASSIFICATION Schedule 3.3 REVENUE REQUIREMENT COST ALLOCATION Distribution Op. Supervision & Engineering $11,890,278 $0 $0 $0 $0 $0 $0 $8,530,111 $0 $2,504,017 $856,151 Load Dispatching $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Line and Station Expenses $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Overhead Lines $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Underground Lines $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Street Lighting & Signal System $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Meters $7,396 $0 $0 $0 $0 $0 $0 $0 $0 $7,396 $0 Customer Installations $1,153,617 $0 $0 $0 $0 $0 $0 $0 $0 $1,153,617 $0 Misc. Distribution $1,889,789 $0 $0 $0 $0 $0 $0 $1,355,739 $0 $534,050 $0 Rents $6,733,141 $0 $0 $0 $0 $0 $0 $4,830,370 $0 $1,902,771 $0 Maint. Supervision & Engineering $4,769,435 $0 $0 $0 $0 $0 $0 $3,421,603 $0 $1,347,832 $0 Maint. of Structures $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Maint. of Station Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Maint. of Structures and Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Maint. of Overhead Lines $4,538,857 $0 $0 $0 $0 $0 $0 $4,538,857 $0 $0 $0 Maint. Of Underground Lines $80,123 $0 $0 $0 $0 $0 $0 $80,123 $0 $0 $0 Maint. of Lines $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Maint. of Line Transformers $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Maint. of Line Transformers - Underground $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Maint. of Street Lighting & Signal System $603,558 $0 $0 $0 $0 $0 $0 $0 $0 $0 $603,558 Maint. of Meters $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Maint. of Misc. Distribution Plant -$3,882,192 $0 $0 $0 $0 $0 $0 -$2,785,093 $0 -$817,565 -$279,534 Communications $221,461 $0 $0 $0 $0 $0 $0 $158,877 $0 $62,584 $0 Total Distribution $28,005,465 $0 $0 $0 $0 $0 $0 $20,130,587 $0 $6,694,703 $1,180,175 Total Operation & Maintenance $143,539,117 $11,520,826 $104,012,826 $0 $0 $0 $0 $20,130,587 $0 $6,694,703 $1,180,175 Schedule 3.3 Page 2 of 5 February 2024 Prepared By EES Consulting, Inc. Allocation Date 2025 Direct Direct Direct Total Demand Energy Assignment Demand Energy Assignment Demand Energy Customer Assignment Expenses PD PE PDA TD TE TDA DD DE DC DDA Operation & Maintenance Expense Power Supply Transmission Distribution FUNCTIONALIZATION AND CLASSIFICATION Schedule 3.3 REVENUE REQUIREMENT COST ALLOCATION Customer Service, Accounts, & Sales Supervision $2,584,782 $0 $0 $0 $0 $0 $0 $0 $0 $2,584,782 $0 Meter Reading $694,215 $0 $0 $0 $0 $0 $0 $0 $0 $694,215 $0 Customer Records Collection $968,331 $0 $0 $0 $0 $0 $0 $968,331 $0 $0 $0 Uncollectable Accounts $1,727,779 $0 $0 $0 $0 $0 $0 $1,727,779 $0 $0 $0 Misc. Customer Accounts (Customer Deposits)$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Customer Service & Information -$744,743 $0 $0 $0 $0 $0 $0 $0 $0 -$744,743 $0 Customer Communication & Education $122,716 $0 $0 $0 $0 $0 $0 $0 $0 $122,716 $0 Customer Assistance $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Misc. Customer Service & Information $270,056 $0 $0 $0 $0 $0 $0 $0 $0 $270,056 $0 Demonstrating & Selling $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Advertising $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Misc. Sales Expenses $295,823 $0 $0 $0 $0 $0 $0 $0 $0 $295,823 $0 Sales Expenses $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Key Accounts $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Energy Efficiency, DSM& Low Income Program $6,689,764 $0 $6,689,764 $0 $0 $0 $0 $0 $0 $0 $0 Low Income Residential Energy Assistance Program $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Total Customer Service, Accounts & Sales $12,608,722 $0 $6,689,764 $0 $0 $0 $0 $2,696,110 $0 $3,222,849 $0 Total O&M w/o Purchased Power Supply & A&G $40,614,187 $0 $6,689,764 $0 $0 $0 $0 $22,826,696 $0 $9,917,552 $1,180,175 Administrative & General Administrative & General Salaries $2,840,007 $0 $467,792 $0 $0 $0 $0 $1,596,191 $0 $693,500 $82,525 Office Supplies $110,579 $0 $18,214 $0 $0 $0 $0 $62,150 $0 $27,002 $3,213 Administrative Transfer - Credit $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Outside Services & Pension Credit $637,787 $0 $105,053 $0 $0 $0 $0 $358,460 $0 $155,741 $18,533 Property Insurance $230,547 $0 $0 $0 $0 $0 $0 $180,763 $0 $41,927 $7,858 Injuries and Damages $179,837 $0 $29,622 $0 $0 $0 $0 $101,075 $0 $43,914 $5,226 Employee Pension & Benefits $2,346,975 $0 $386,582 $0 $0 $0 $0 $1,319,088 $0 $573,106 $68,199 Franchise Requirements $23,187 $0 $3,819 $0 $0 $0 $0 $13,032 $0 $5,662 $674 Regulatory Expense $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Duplicate Charge - Credit $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 General Advertising $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Misc. General Expense $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 General Advertising $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Misc. General Expense $111,099 $0 $18,300 $0 $0 $0 $0 $62,442 $0 $27,129 $3,228 Environmental $2,034 $0 $335 $0 $0 $0 $0 $1,143 $0 $497 $59 COVID Expenses $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Maint. of General Plant & Communication Equipment $7,022 $0 $1,157 $0 $0 $0 $0 $3,947 $0 $1,715 $204 Transportation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Cost Plan Charges $1,209,398 $0 $199,206 $0 $0 $0 $0 $679,727 $0 $295,322 $35,143 Total Administrative & General $7,698,473 $0 $1,230,079 $0 $0 $0 $0 $4,378,017 $0 $1,865,515 $224,862 Total O&M plus A&G $163,846,313 $11,520,826 $111,932,669 $0 $0 $0 $0 $27,204,714 $0 $11,783,067 $1,405,037 Schedule 3.3 Page 3 of 5 February 2024 Prepared By EES Consulting, Inc. Allocation Date 2025 Direct Direct Direct Total Demand Energy Assignment Demand Energy Assignment Demand Energy Customer Assignment Expenses PD PE PDA TD TE TDA DD DE DC DDA Operation & Maintenance Expense Power Supply Transmission Distribution FUNCTIONALIZATION AND CLASSIFICATION Schedule 3.3 REVENUE REQUIREMENT COST ALLOCATION Depreciation Generation Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Transmission Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Distribution Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 General Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Amortization of Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Amortization of Loss on Refunding $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Miscellaneous Intangible Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Total Depreciation $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Interest and Debt Service Expense $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Interest and Debt Service Electric $4,770,582 $0 $0 $0 $0 $0 $0 $3,740,419 $0 $867,570 $162,593 Amortization of Debt Discount $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Other Interest Expense $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Annual LT Debt Service $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Annual ST Debt Service (AMI)$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Accelerated Debt Reduction - LT Debt $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Ind A Interest Expense $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Total Interest / Debt Service Expense $4,770,582 $0 $0 $0 $0 $0 $0 $3,740,419 $0 $867,570 $162,593 Capital Projects Funded From Rates $0 $0 $0 $0 $0 $0 $0 $0 $0 Production $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Transmission $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Distribution $6,500,000 $0 $0 $0 $0 $0 $0 $6,354,628 $0 $145,372 $0 General $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Retirements $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Total Capital Projects Funded From Rates $6,500,000 $0 $0 $0 $0 $0 $0 $6,354,628 $0 $145,372 $0 Other Contributions $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 General Fund Transfer to/(from)$15,121,000 $332,171 $14,430,225 $0 $0 $0 $0 $241,294 $0 $104,835 $12,475 Reserves $23,800,000 $1,326,114 $8,067,926 $0 $0 $0 $0 $10,742,536 $0 $3,663,424 $0 Debt Service Coverage Requirement $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Other transfers out $1,533,578 $0 $0 $0 $0 $0 $0 $1,202,416 $0 $278,894 $52,268 Transfers In $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Reserve Alloc Reapp $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Margin Requirement $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Total Other Contributions $40,454,578 $1,658,285 $22,498,151 $0 $0 $0 $0 $12,186,246 $0 $4,047,153 $64,743 Revenue Requirement Before Other Revenues $215,571,473 $13,179,111 $134,430,820 $0 $0 $0 $0 $49,486,007 $0 $16,843,161 $1,632,374 Revenue Req. Before Taxes and Other Revenues $215,571,473 $13,179,111 $134,430,820 $0 $0 $0 $0 $49,486,007 $0 $16,843,161 $1,632,374 Schedule 3.3 Page 4 of 5 February 2024 Prepared By EES Consulting, Inc. Allocation Date 2025 Direct Direct Direct Total Demand Energy Assignment Demand Energy Assignment Demand Energy Customer Assignment Expenses PD PE PDA TD TE TDA DD DE DC DDA Operation & Maintenance Expense Power Supply Transmission Distribution FUNCTIONALIZATION AND CLASSIFICATION Schedule 3.3 REVENUE REQUIREMENT COST ALLOCATION Other Revenues $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Late Charges $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Connect / Re-Connect Fees $1,447,561 $0 $238,435 $0 $0 $0 $0 $813,584 $0 $353,479 $42,064 Misc Revenue $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Joint Use Pole Attachment Income $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Misc Revenue (Other)$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Transfer Credits $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Hydro Adjuster $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Dividends from Affiliates, Interest $7,000,000 $1,120,000 $5,880,000 $0 $0 $0 $0 $0 $0 $0 $0 Interdepartmental Sales $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Income (Loss) from Equity Investments $699,559 $0 $699,559 $0 $0 $0 $0 $0 $0 $0 $0 Open $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Other Revenues $274,394 $0 $274,394 $0 $0 $0 $0 $0 $0 $0 $0 Investment Income $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Misc Income (RA Sales & Surplus Sales)$37,045,073 $0 $37,045,073 $0 $0 $0 $0 $0 $0 $0 $0 Public Benefits Revenue $4,517,748 $0 $4,517,748 $0 $0 $0 $0 $0 $0 $0 $0 Total Other Revenues $50,984,335 $1,120,000 $48,655,209 $0 $0 $0 $0 $813,584 $0 $353,479 $42,064 REVENUE REQUIREMENT for COST ALLOCATION $164,587,138 $12,059,111 $85,775,612 $0 $0 $0 $0 $48,672,424 $0 $16,489,682 $1,590,310 Schedule 3.3 Page 5 of 5 February 2024 Prepared By EES Consulting, Inc. City of Palo Alto - 100% Demand Allocation Date 2025 Total Expenses Operation & Maintenance Expense Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Power Purchases Western Power Purchases $7,903,405 $1,221,404 $514,251 $2,899,059 $3,251,553 $17,138 Contra Surplus Energy -$13,328,841 -$2,131,707 -$852,949 -$4,730,438 -$5,583,570 -$30,177 NCPA Pooling $10,148,225 $1,623,025 $649,412 $3,601,629 $4,251,182 $22,976 NCPA Facilities $2,542,371 $406,606 $162,693 $902,294 $1,065,022 $5,756 Local Capacity Purchase $7,486,559 $945,117 $529,355 $3,214,232 $2,785,379 $12,476 Load Advance $0 $0 $0 $0 $0 $0 Renewable Energy $37,130,836 $5,898,903 $2,383,976 $13,265,097 $15,499,495 $83,364 Carbon Neutral Purchases (REC)$9,741 $1,558 $623 $3,457 $4,081 $22 Market Power Purchases $8,892,531 $1,422,200 $569,057 $3,155,981 $3,725,161 $20,133 PA Green Comm Purch $0 $0 $0 $0 $0 $0 TANC & Calveras O&M $6,816,709 $1,074,134 $439,424 $2,454,783 $2,833,221 $15,148 CVP O&M $7,000,000 $1,081,791 $455,469 $2,567,680 $2,879,881 $15,179 EMA Purchases $0 $0 $0 $0 $0 $0 Energy Risk Mgmt $0 $0 $0 $0 $0 $0 Budget True-up $0 $0 $0 $0 $0 $0 Resource Management Admin $3,337,316 $533,743 $213,564 $1,184,421 $1,398,031 $7,556 Transmission/Ancillary Services Purchases Transmission Purchases $28,377,775 $4,538,512 $1,815,971 $10,071,340 $11,887,704 $64,248 Other Surplus Energy $13,328,841 $2,131,707 $852,949 $4,730,438 $5,583,570 $30,177 Low Carbon Fuel G&A $0 $0 $0 $0 $0 $0 Carbon Allowance Revenues -$4,111,816 -$657,611 -$263,126 -$1,459,293 -$1,722,476 -$9,309 open $0 $0 $0 $0 $0 $0 Allocated G&A $0 $0 $0 $0 $0 $0 Renewable Energy Salaries & General $0 $0 $0 $0 $0 $0 Total Purchased Power $115,533,652 $18,089,382 $7,470,671 $41,860,681 $47,858,233 $254,685 Total Production $115,533,652 $18,089,382 $7,470,671 $41,860,681 $47,858,233 $254,685 REVENUE REQUIREMENT COST ALLOCATION BY CUSTOMER Schedule 3.4 Schedule 3.4 Page 1 of 5 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto - 100% Demand Allocation Date 2025 Total Expenses Operation & Maintenance Expense Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights REVENUE REQUIREMENT COST ALLOCATION BY CUSTOMER Schedule 3.4 Distribution Op. Supervision & Engineering $11,890,278 $1,883,208 $754,097 $5,213,269 $3,151,370 $888,335 Load Dispatching $0 $0 $0 $0 $0 $0 Line and Station Expenses $0 $0 $0 $0 $0 $0 Overhead Lines $0 $0 $0 $0 $0 $0 Underground Lines $0 $0 $0 $0 $0 $0 Street Lighting & Signal System $0 $0 $0 $0 $0 $0 Meters $7,396 $3,442 $525 $2,981 $448 $0 Customer Installations $1,153,617 $536,899 $81,846 $464,880 $69,951 $41 Misc. Distribution $1,889,789 $333,523 $124,004 $908,672 $518,476 $5,115 Rents $6,733,141 $1,188,310 $441,813 $3,237,512 $1,847,281 $18,225 Maint. Supervision & Engineering $4,769,435 $841,742 $312,959 $2,293,299 $1,308,526 $12,910 Maint. of Structures $0 $0 $0 $0 $0 $0 Maint. of Station Equipment $0 $0 $0 $0 $0 $0 Maint. of Structures and Equipment $0 $0 $0 $0 $0 $0 Maint. of Overhead Lines $4,538,857 $667,042 $360,611 $1,989,683 $1,504,397 $17,125 Maint. Of Underground Lines $80,123 $11,775 $6,366 $35,123 $26,557 $302 Maint. of Lines $0 $0 $0 $0 $0 $0 Maint. of Line Transformers $0 $0 $0 $0 $0 $0 Maint. of Line Transformers - Underground $0 $0 $0 $0 $0 $0 Maint. of Street Lighting & Signal System $603,558 $0 $0 $0 $0 $603,558 Maint. of Meters $0 $0 $0 $0 $0 $0 Maint. of Misc. Distribution Plant -$3,882,192 -$614,870 -$246,214 -$1,702,139 -$1,028,927 -$290,043 Communications $221,461 $39,085 $14,532 $106,486 $60,759 $599 Total Distribution $28,005,465 $4,890,155 $1,850,538 $12,549,763 $7,458,839 $1,256,169 Total Operation & Maintenance $143,539,117 $22,979,538 $9,321,209 $54,410,444 $55,317,072 $1,510,854 Schedule 3.4 Page 2 of 5 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto - 100% Demand Allocation Date 2025 Total Expenses Operation & Maintenance Expense Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights REVENUE REQUIREMENT COST ALLOCATION BY CUSTOMER Schedule 3.4 Customer Service, Accounts, & Sales Supervision $2,584,782 $1,202,969 $183,384 $1,041,606 $156,731 $93 Meter Reading $694,215 $323,102 $49,255 $279,762 $42,096 $0 Customer Records Collection $968,331 $157,109 $67,796 $389,510 $341,120 $12,795 Uncollectable Accounts $1,727,779 $280,328 $120,967 $694,997 $608,656 $22,831 Misc. Customer Accounts (Customer Deposits)$0 $0 $0 $0 $0 $0 Customer Service & Information -$744,743 -$643,788 -$78,513 -$20,646 -$1,747 -$50 Customer Communication & Education $122,716 $106,081 $12,937 $3,402 $288 $8 Customer Assistance $0 $0 $0 $0 $0 $0 Misc. Customer Service & Information $270,056 $233,448 $28,470 $7,486 $634 $18 Demonstrating & Selling $0 $0 $0 $0 $0 $0 Advertising $0 $0 $0 $0 $0 $0 Misc. Sales Expenses $295,823 $137,677 $20,988 $119,210 $17,938 $11 Sales Expenses $0 $0 $0 $0 $0 $0 Key Accounts $0 $0 $0 $0 $0 $0 Energy Efficiency, DSM& Low Income Program $6,689,764 $1,028,709 $530,112 $2,215,660 $2,915,283 $0 Low Income Residential Energy Assistance Program $0 $0 $0 $0 $0 $0 Total Customer Service, Accounts & Sales $12,608,722 $2,825,637 $935,395 $4,730,987 $4,080,998 $35,706 Total O&M w/o Purchased Power Supply & A&G $40,614,187 $7,715,792 $2,785,933 $17,280,750 $11,539,837 $1,291,875 Administrative & General Administrative & General Salaries $2,840,007 $539,538 $194,811 $1,208,382 $806,940 $90,336 Office Supplies $110,579 $21,008 $7,585 $47,050 $31,419 $3,517 Administrative Transfer - Credit $0 $0 $0 $0 $0 $0 Outside Services & Pension Credit $637,787 $121,165 $43,749 $271,369 $181,216 $20,287 Property Insurance $230,547 $37,107 $15,640 $103,920 $65,340 $8,540 Injuries and Damages $179,837 $34,165 $12,336 $76,518 $51,098 $5,720 Employee Pension & Benefits $2,346,975 $445,873 $160,991 $998,604 $666,853 $74,654 Franchise Requirements $23,187 $4,405 $1,591 $9,866 $6,588 $738 Regulatory Expense $0 $0 $0 $0 $0 $0 Duplicate Charge - Credit $0 $0 $0 $0 $0 $0 General Advertising $0 $0 $0 $0 $0 $0 Misc. General Expense $0 $0 $0 $0 $0 $0 General Advertising $0 $0 $0 $0 $0 $0 Misc. General Expense $111,099 $21,106 $7,621 $47,271 $31,567 $3,534 Environmental $2,034 $386 $140 $865 $578 $65 COVID Expenses $0 $0 $0 $0 $0 $0 Maint. of General Plant & Communication Equipment $7,022 $1,334 $482 $2,988 $1,995 $223 Transportation $0 $0 $0 $0 $0 $0 Cost Plan Charges $1,209,398 $229,759 $82,959 $514,581 $343,630 $38,469 Total Administrative & General $7,698,473 $1,455,847 $527,903 $3,281,415 $2,187,225 $246,083 Total O&M plus A&G $163,846,313 $27,261,021 $10,784,507 $62,422,846 $61,585,295 $1,792,643 Schedule 3.4 Page 3 of 5 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto - 100% Demand Allocation Date 2025 Total Expenses Operation & Maintenance Expense Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights REVENUE REQUIREMENT COST ALLOCATION BY CUSTOMER Schedule 3.4 Depreciation Generation Plant $0 $0 $0 $0 $0 $0 Transmission Plant $0 $0 $0 $0 $0 $0 Distribution Plant $0 $0 $0 $0 $0 $0 General Plant $0 $0 $0 $0 $0 $0 Amortization of Plant $0 $0 $0 $0 $0 $0 Amortization of Loss on Refunding $0 $0 $0 $0 $0 $0 Miscellaneous Intangible Plant $0 $0 $0 $0 $0 $0 Total Depreciation $0 $0 $0 $0 $0 $0 Interest and Debt Service Expense Interest and Debt Service Electric $4,770,582 $767,840 $323,639 $2,150,357 $1,352,040 $176,706 Amortization of Debt Discount $0 $0 $0 $0 $0 $0 Other Interest Expense $0 $0 $0 $0 $0 $0 Annual LT Debt Service $0 $0 $0 $0 $0 $0 Annual ST Debt Service (AMI)$0 $0 $0 $0 $0 $0 Accelerated Debt Reduction - LT Debt $0 $0 $0 $0 $0 $0 Ind A Interest Expense $0 $0 $0 $0 $0 $0 Total Interest / Debt Service Expense $4,770,582 $767,840 $323,639 $2,150,357 $1,352,040 $176,706 Capital Projects Funded From Rates Production $0 $0 $0 $0 $0 $0 Transmission $0 $0 $0 $0 $0 $0 Distribution $6,500,000 $1,056,184 $519,787 $2,792,253 $2,107,800 $23,976 General $0 $0 $0 $0 $0 $0 Retirements $0 $0 $0 $0 $0 $0 Open $0 $0 $0 $0 $0 $0 Total Capital Projects Funded From Rates $6,500,000 $1,056,184 $519,787 $2,792,253 $2,107,800 $23,976 Other Contributions General Fund Transfer to/(from)$15,121,000 $2,420,039 $971,840 $5,421,506 $6,260,895 $46,720 Reserves $23,800,000 $4,260,379 $1,640,551 $9,988,374 $7,843,259 $67,436 Debt Service Coverage Requirement $0 $0 $0 $0 $0 $0 Other transfers out $1,533,578 $246,834 $104,039 $691,266 $434,634 $56,805 Transfers In $0 $0 $0 $0 $0 $0 Reserve Alloc Reapp $0 $0 $0 $0 $0 $0 Margin Requirement $0 $0 $0 $0 $0 $0 Total Other Contributions $40,454,578 $6,927,252 $2,716,430 $16,101,145 $14,538,789 $170,961 Revenue Requirement Before Other Revenues $215,571,473 $36,012,298 $14,344,364 $83,466,601 $79,583,924 $2,164,286 Revenue Req. Before Taxes and Other Revenues $215,571,473 $36,012,298 $14,344,364 $83,466,601 $79,583,924 $2,164,286 Schedule 3.4 Page 4 of 5 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto - 100% Demand Allocation Date 2025 Total Expenses Operation & Maintenance Expense Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights REVENUE REQUIREMENT COST ALLOCATION BY CUSTOMER Schedule 3.4 Other Revenues Late Charges $0 $0 $0 $0 $0 $0 Connect / Re-Connect Fees $1,447,561 $275,004 $99,296 $615,916 $411,300 $46,045 Misc Revenue $0 $0 $0 $0 $0 $0 Joint Use Pole Attachment Income $0 $0 $0 $0 $0 $0 Misc Revenue (Other)$0 $0 $0 $0 $0 $0 Transfer Credits $0 $0 $0 $0 $0 $0 Hydro Adjuster $0 $0 $0 $0 $0 $0 Dividends from Affiliates, Interest $7,000,000 $1,081,791 $455,469 $2,567,680 $2,879,881 $15,179 Interdepartmental Sales $0 $0 $0 $0 $0 $0 Income (Loss) from Equity Investments $699,559 $111,882 $44,767 $248,275 $293,052 $1,584 Open $0 $0 $0 $0 $0 $0 Other Revenues $274,394 $43,884 $17,559 $97,383 $114,946 $621 Investment Income $0 $0 $0 $0 $0 $0 Misc Income (RA Sales & Surplus Sales)$37,045,073 $5,924,690 $2,370,615 $13,147,385 $15,518,512 $83,871 Public Benefits Revenue $4,517,748 $722,532 $289,103 $1,603,360 $1,892,525 $10,228 Total Other Revenues $50,984,335 $8,159,783 $3,276,809 $18,279,999 $21,110,216 $157,528 REVENUE REQUIREMENT for COST ALLOCATION $164,587,138 $27,852,514 $11,067,556 $65,186,601 $58,473,708 $2,006,759 Schedule 3.4 Page 5 of 5 February 2024 Prepared By EES Consulting, Inc. City of Palo Alto - 100% Demand Allocation Date 2024 Total Expenses Operation & Maintenance Expense Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Power Purchases Western Power Purchases $0 $0 $0 $0 $0 $0 Contra Surplus Energy $0 $0 $0 $0 $0 $0 NCPA Pooling $0 $0 $0 $0 $0 $0 NCPA Facilities $0 $0 $0 $0 $0 $0 Local Capacity Purchase $0 $0 $0 $0 $0 $0 Load Advance $0 $0 $0 $0 $0 $0 Renewable Energy $0 $0 $0 $0 $0 $0 Carbon Neutral Purchases (REC)$0 $0 $0 $0 $0 $0 Market Power Purchases $0 $0 $0 $0 $0 $0 PA Green Comm Purch $0 $0 $0 $0 $0 $0 TANC & Calveras O&M $0 $0 $0 $0 $0 $0 CVP O&M $0 $0 $0 $0 $0 $0 EMA Purchases $0 $0 $0 $0 $0 $0 Energy Risk Mgmt $0 $0 $0 $0 $0 $0 Budget True-up $0 $0 $0 $0 $0 $0 Resource Management Admin $0 $0 $0 $0 $0 $0 Transmission/Ancillary Services Purchases Transmission Purchases $0 $0 $0 $0 $0 $0 Other Surplus Energy $0 $0 $0 $0 $0 $0 Low Carbon Fuel G&A $0 $0 $0 $0 $0 $0 Carbon Allowance Revenues $0 $0 $0 $0 $0 $0 open $0 $0 $0 $0 $0 $0 Allocated G&A $0 $0 $0 $0 $0 $0 Renewable Energy Salaries & General $0 $0 $0 $0 $0 $0 Total Purchased Power $0 $0 $0 $0 $0 $0 Total Production $0 $0 $0 $0 $0 $0 REVENUE REQUIREMENT COST ALLOCATION DIRECT ASSIGNMENT BY CUSTOMER Schedule 3.5 Schedule 3.5 Page 1 of 5 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto - 100% Demand Allocation Date 2024 Total Expenses Operation & Maintenance Expense Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights REVENUE REQUIREMENT COST ALLOCATION DIRECT ASSIGNMENT BY CUSTOMER Schedule 3.5 Distribution Op. Supervision & Engineering $856,151 $0 $0 $0 $0 $856,151 Load Dispatching $0 $0 $0 $0 $0 $0 Line and Station Expenses $0 $0 $0 $0 $0 $0 Overhead Lines $0 $0 $0 $0 $0 $0 Underground Lines $0 $0 $0 $0 $0 $0 Street Lighting & Signal System $0 $0 $0 $0 $0 $0 Meters $0 $0 $0 $0 $0 $0 Customer Installations $0 $0 $0 $0 $0 $0 Misc. Distribution $0 $0 $0 $0 $0 $0 Rents $0 $0 $0 $0 $0 $0 Maint. Supervision & Engineering $0 $0 $0 $0 $0 $0 Maint. of Structures $0 $0 $0 $0 $0 $0 Maint. of Station Equipment $0 $0 $0 $0 $0 $0 Maint. of Structures and Equipment $0 $0 $0 $0 $0 $0 Maint. of Overhead Lines $0 $0 $0 $0 $0 $0 Maint. Of Underground Lines $0 $0 $0 $0 $0 $0 Maint. of Lines $0 $0 $0 $0 $0 $0 Maint. of Line Transformers $0 $0 $0 $0 $0 $0 Maint. of Line Transformers - Underground $0 $0 $0 $0 $0 $0 Maint. of Street Lighting & Signal System $603,558 $0 $0 $0 $0 $603,558 Maint. of Meters $0 $0 $0 $0 $0 $0 Maint. of Misc. Distribution Plant -$279,534 $0 $0 $0 $0 -$279,534 Communications $0 $0 $0 $0 $0 $0 Total Distribution $1,180,175 $0 $0 $0 $0 $1,180,175 Total Operation & Maintenance $1,180,175 $0 $0 $0 $0 $1,180,175 Schedule 3.5 Page 2 of 5 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto - 100% Demand Allocation Date 2024 Total Expenses Operation & Maintenance Expense Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights REVENUE REQUIREMENT COST ALLOCATION DIRECT ASSIGNMENT BY CUSTOMER Schedule 3.5 Customer Service, Accounts, & Sales Supervision $0 $0 $0 $0 $0 $0 Meter Reading $0 $0 $0 $0 $0 $0 Customer Records Collection $0 $0 $0 $0 $0 $0 Uncollectable Accounts $0 $0 $0 $0 $0 $0 Misc. Customer Accounts (Customer Deposits)$0 $0 $0 $0 $0 $0 Customer Service & Information $0 $0 $0 $0 $0 $0 Customer Communication & Education $0 $0 $0 $0 $0 $0 Customer Assistance $0 $0 $0 $0 $0 $0 Misc. Customer Service & Information $0 $0 $0 $0 $0 $0 Demonstrating & Selling $0 $0 $0 $0 $0 $0 Advertising $0 $0 $0 $0 $0 $0 Misc. Sales Expenses $0 $0 $0 $0 $0 $0 Sales Expenses $0 $0 $0 $0 $0 $0 Key Accounts $0 $0 $0 $0 $0 $0 Energy Efficiency, DSM& Low Income Program $0 $0 $0 $0 $0 $0 Low Income Residential Energy Assistance Program $0 $0 $0 $0 $0 $0 Total Customer Service, Accounts & Sales $0 $0 $0 $0 $0 $0 Total O&M w/o Purchased Power Supply & A&G $1,180,175 $0 $0 $0 $0 $1,180,175 Administrative & General Administrative & General Salaries $82,525 $0 $0 $0 $0 $82,525 Office Supplies $3,213 $0 $0 $0 $0 $3,213 Administrative Transfer - Credit $0 $0 $0 $0 $0 $0 Outside Services & Pension Credit $18,533 $0 $0 $0 $0 $18,533 Property Insurance $7,858 $0 $0 $0 $0 $7,858 Injuries and Damages $5,226 $0 $0 $0 $0 $5,226 Employee Pension & Benefits $68,199 $0 $0 $0 $0 $68,199 Franchise Requirements $674 $0 $0 $0 $0 $674 Regulatory Expense $0 $0 $0 $0 $0 $0 Duplicate Charge - Credit $0 $0 $0 $0 $0 $0 General Advertising $0 $0 $0 $0 $0 $0 Misc. General Expense $0 $0 $0 $0 $0 $0 General Advertising $0 $0 $0 $0 $0 $0 Misc. General Expense $3,228 $0 $0 $0 $0 $3,228 Environmental $59 $0 $0 $0 $0 $59 COVID Expenses $0 $0 $0 $0 $0 $0 Maint. of General Plant & Communication Equipment $204 $0 $0 $0 $0 $204 Transportation $0 $0 $0 $0 $0 $0 Cost Plan Charges $35,143 $0 $0 $0 $0 $35,143 Total Administrative & General $224,862 $0 $0 $0 $0 $224,862 Total O&M plus A&G $1,405,037 $0 $0 $0 $0 $1,405,037 Schedule 3.5 Page 3 of 5 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto - 100% Demand Allocation Date 2024 Total Expenses Operation & Maintenance Expense Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights REVENUE REQUIREMENT COST ALLOCATION DIRECT ASSIGNMENT BY CUSTOMER Schedule 3.5 Depreciation Generation Plant $0 $0 $0 $0 $0 $0 Transmission Plant $0 $0 $0 $0 $0 $0 Distribution Plant $0 $0 $0 $0 $0 $0 General Plant $0 $0 $0 $0 $0 $0 Amortization of Plant $0 $0 $0 $0 $0 $0 Amortization of Loss on Refunding $0 $0 $0 $0 $0 $0 Miscellaneous Intangible Plant $0 $0 $0 $0 $0 $0 Total Depreciation $0 $0 $0 $0 $0 $0 Interest and Debt Service Expense Interest and Debt Service Electric $162,593 $0 $0 $0 $0 $162,593 Amortization of Debt Discount $0 $0 $0 $0 $0 $0 Other Interest Expense $0 $0 $0 $0 $0 $0 Annual LT Debt Service $0 $0 $0 $0 $0 $0 Annual ST Debt Service (AMI)$0 $0 $0 $0 $0 $0 Accelerated Debt Reduction - LT Debt $0 $0 $0 $0 $0 $0 Ind A Interest Expense $0 $0 $0 $0 $0 $0 Total Interest / Debt Service Expense $162,593 $0 $0 $0 $0 $162,593 Capital Projects Funded From Rates Production $0 $0 $0 $0 $0 $0 Transmission $0 $0 $0 $0 $0 $0 Distribution $0 $0 $0 $0 $0 $0 General $0 $0 $0 $0 $0 $0 Retirements $0 $0 $0 $0 $0 $0 Open $0 $0 $0 $0 $0 $0 Total Capital Projects Funded From Rates $0 $0 $0 $0 $0 $0 Other Contributions General Fund Transfer to/(from)$12,475 $0 $0 $0 $0 $12,475 Reserves $0 $0 $0 $0 $0 $0 Debt Service Coverage Requirement $0 $0 $0 $0 $0 $0 Other transfers out $52,268 $0 $0 $0 $0 $52,268 Transfers In $0 $0 $0 $0 $0 $0 Reserve Alloc Reapp $0 $0 $0 $0 $0 $0 Margin Requirement $0 $0 $0 $0 $0 $0 Total Other Contributions $64,743 $0 $0 $0 $0 $64,743 Revenue Requirement Before Other Revenues $1,632,374 $0 $0 $0 $0 $1,632,374 Revenue Req. Before Taxes and Other Revenues $1,632,374 $0 $0 $0 $0 $1,632,374 Schedule 3.5 Page 4 of 5 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto - 100% Demand Allocation Date 2024 Total Expenses Operation & Maintenance Expense Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights REVENUE REQUIREMENT COST ALLOCATION DIRECT ASSIGNMENT BY CUSTOMER Schedule 3.5 Other Revenues Late Charges $0 $0 $0 $0 $0 $0 Connect / Re-Connect Fees $42,064 $0 $0 $0 $0 $42,064 Misc Revenue $0 $0 $0 $0 $0 $0 Joint Use Pole Attachment Income $0 $0 $0 $0 $0 $0 Misc Revenue (Other)$0 $0 $0 $0 $0 $0 Transfer Credits $0 $0 $0 $0 $0 $0 Hydro Adjuster $0 $0 $0 $0 $0 $0 Dividends from Affiliates, Interest $0 $0 $0 $0 $0 $0 Interdepartmental Sales $0 $0 $0 $0 $0 $0 Income (Loss) from Equity Investments $0 $0 $0 $0 $0 $0 Open $0 $0 $0 $0 $0 $0 Other Revenues $0 $0 $0 $0 $0 $0 Investment Income $0 $0 $0 $0 $0 $0 Misc Income (RA Sales & Surplus Sales)$0 $0 $0 $0 $0 $0 Public Benefits Revenue $0 $0 $0 $0 $0 $0 Total Other Revenues $42,064 $0 $0 $0 $0 $42,064 REVENUE REQUIREMENT for COST ALLOCATION $1,590,310 $0 $0 $0 $0 $1,590,310 Schedule 3.5 Page 5 of 5 February 2024 Prepared By EES Consulting, Inc. City of Palo Alto INPUT RATE BASE INPUT RATE BASE Schedule 4.1 Schedule 4.1 Year Classification 2021 & Allocation Cost, $Function Factor Classification & Allocation Method FERC Account Distribution Plant 360.00 Land & Rights D NCPP Non-Coincident Peak - Primary 361.00 Structures & Improvements $7,154,333 D NCPP Non-Coincident Peak - Primary 362.00 Station Equipment - Distribution $59,404,780 D NCPP Non-Coincident Peak - Primary 363.00 Storage & Battery Equipment $2,659,291 D NCPP Non-Coincident Peak - Primary 364.00 Poles, Towers, & Fixtures $44,602,342 D 100%DP Demand Only - Poles, Towers & Fixtures (100% Demand) 365.00 Overhead Conductors & Devices $18,501,977 D 100%DC Demand Only - Overhead and Underground Conduit (100% Demand) 366.00 Underground Conduit $1,763,879 D 100%DC Demand Only - Overhead and Underground Conduit (100% Demand) 367.00 Underground Conductors & Devices $85,733,395 D 100%DC Demand Only - Overhead and Underground Conduit (100% Demand) 368.00 Line Transformers $31,475,442 D 100%DT Demand Only- Transformers (100% Demand) 369.00 Services $68,019,093 D SERV Services 370.00 Meters $4,490,213 D CUSTM Customers Weighted for Meters and Services 371.00 Installation on Customer Premises $1,258,542 D CUSTM Customers Weighted for Meters and Services 372.00 Leased Property on Cust. Premises D CUSTM Customers Weighted for Meters and Services 373.00 Street Lights and Signal Systems $25,222,037 D DA1 Direct Assignment for Streetlights Total Distribution Plant $350,285,324 Total Transmission & Distribution $350,285,324 General Plant 389.00 Land & Land Rights SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 390.00 Structures & Improvements $1,897,484 SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 391.00 Office Furniture & Equipment $8,874,818 SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 392.00 Transportation Equipment $415,330 SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 393.00 Stores Equipment SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 394.00 Tools, Shop, & Garage Equipment $2,685,629 SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 395.00 Laboratory Equipment SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 396.00 Power Operated Equipment SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 397.00 Communication Equipment $22,487,683 SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 398.00 Misc. Equipment $10,832,848 SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) 399.00 Other Tangible Property - EV Charging $29,836 SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) Total General Plant $47,223,629 Total Plant Before General Plant & Intangible $350,285,324 Total Gross Plant in Service $397,508,952 Schedule 4.1 Page 1 of 2 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto INPUT RATE BASE INPUT RATE BASE Schedule 4.1 Schedule 4.1 Year Classification 2021 & Allocation Cost, $Function Factor Classification & Allocation Method FERC Account Less: Accumulated Depreciation Intangible Plant P RBIG On the Basis of Intangible Plant Rate Base Transmission Plant T RBT On the Basis of Transmission Rate Base Distribution Plant $139,992,346 D RBD-NoDA As Distribution Ratebase without DA Street Lighting General Plant $29,441,360 SS RBGP On the Basis of General Plant Rate Base Street Lighting $19,389,916 D DA1 Direct Assignment for Streetlights Misc. Plant SS RBGP On the Basis of General Plant Rate Base Total Accumulated Depreciation $188,823,622 Total Net Plant $208,685,330 Working Capital 90 Days of Non Power Supply O&M $10,832,188 SS OMWOP On the Basis of O&M (w/o Purch. Power Supply) 90 Days of Power Supply Cost $28,459,651 P OMP On the Basis of Purchased Power O&M Total Working Capital $39,291,839 Less: Net Customer Contributions Production Plant $0 P RBG On the Basis of Generation Rate Base Transmission Plant $0 T RBT On the Basis of Transmission Rate Base Distribution Plant $0 D RBD On the Basis of Distribution Rate Base Street Lights $0 D CUSTM Customers Weighted for Meters and Services General Plant $0 SS RBGP On the Basis of General Plant Rate Base Total Contributions $0 TOTAL RATE BASE $247,977,170 CWIP 107.00 Production Plant $0 P RBG On the Basis of Generation Rate Base 107.00 Transmission Plant $0 T RBT On the Basis of Transmission Rate Base 107.00 Distribution Plant $0 D RBD On the Basis of Distribution Rate Base Services $0 D RBD On the Basis of Distribution Rate Base 107.00 General Plant $0 SS RBGP On the Basis of General Plant Rate Base Other $0 SS GPLT On the Basis of Gross Plant (w/o General Plant & Intangible) Total CWIP $0 TOTAL RATE BASE plus CWIP $247,977,170 Schedule 4.1 Page 2 of 2 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto - 100% Demand Direct Direct Direct Total Demand Energy Assignment Demand Energy Assignment Demand Energy Customer Assignment Account Description Rate Base PD PE PDA TD TE TDA DD DE DC DDA Distribution Plant Land & Rights $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Structures & Improvements $7,154,333 $0 $0 $0 $0 $0 $0 $7,154,333 $0 $0 $0 Station Equipment - Distribution $59,404,780 $0 $0 $0 $0 $0 $0 $59,404,780 $0 $0 $0 Storage & Battery Equipment $2,659,291 $0 $0 $0 $0 $0 $0 $2,659,291 $0 $0 $0 Poles, Towers, & Fixtures $44,602,342 $0 $0 $0 $0 $0 $0 $44,602,342 $0 $0 $0 Overhead Conductors & Devices $18,501,977 $0 $0 $0 $0 $0 $0 $18,501,977 $0 $0 $0 Underground Conduit $1,763,879 $0 $0 $0 $0 $0 $0 $1,763,879 $0 $0 $0 Underground Conductors & Devices $85,733,395 $0 $0 $0 $0 $0 $0 $85,733,395 $0 $0 $0 Line Transformers $31,475,442 $0 $0 $0 $0 $0 $0 $31,475,442 $0 $0 $0 Services $68,019,093 $0 $0 $0 $0 $0 $0 $0 $0 $68,019,093 $0 Meters $4,490,213 $0 $0 $0 $0 $0 $0 $0 $0 $4,490,213 $0 Installation on Customer Premises $1,258,542 $0 $0 $0 $0 $0 $0 $0 $0 $1,258,542 $0 Leased Property on Cust. Premises $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Street Lights and Signal Systems $25,222,037 $0 $0 $0 $0 $0 $0 $0 $0 $0 $25,222,037 Total Distribution Plant $350,285,324 $0 $0 $0 $0 $0 $0 $251,295,438 $0 $73,767,848 $25,222,037 Total Transmission & Distribution $350,285,324 $0 $0 $0 $0 $0 $0 $251,295,438 $0 $73,767,848 $25,222,037 General Plant Land & Land Rights $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Structures & Improvements $1,897,484 $0 $0 $0 $0 $0 $0 $1,361,259 $0 $399,598 $136,627 Office Furniture & Equipment $8,874,818 $0 $0 $0 $0 $0 $0 $6,366,814 $0 $1,868,980 $639,025 Transportation Equipment $415,330 $0 $0 $0 $0 $0 $0 $297,958 $0 $87,466 $29,905 Stores Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Tools, Shop, & Garage Equipment $2,685,629 $0 $0 $0 $0 $0 $0 $1,926,676 $0 $565,576 $193,377 Laboratory Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Power Operated Equipment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Communication Equipment $22,487,683 $0 $0 $0 $0 $0 $0 $16,132,712 $0 $4,735,762 $1,619,209 Misc. Equipment $10,832,848 $0 $0 $0 $0 $0 $0 $7,771,508 $0 $2,281,328 $780,011 Other Tangible Property - EV Charging $29,836 $0 $0 $0 $0 $0 $0 $21,404 $0 $6,283 $2,148 Total General Plant $47,223,629 $0 $0 $0 $0 $0 $0 $33,878,332 $0 $9,944,994 $3,400,303 Total Plant Before General Plant & Intangible $350,285,324 $0 $0 $0 $0 $0 $0 $251,295,438 $0 $73,767,848 $25,222,037 Total Gross Plant in Service $397,508,952 $0 $0 $0 $0 $0 $0 $285,173,770 $0 $83,712,843 $28,622,340 RATE BASE FOR COST ALLOCATION DistributionPower Supply Transmission FUNCTIONALIZATION AND CLASSIFICATION Schedule 4.2 Schedule 4.2 Page 1 of 2 February 2024 Prepared By EES Consulting, Inc. Direct Direct Direct Total Demand Energy Assignment Demand Energy Assignment Demand Energy Customer Assignment Account Description Rate Base PD PE PDA TD TE TDA DD DE DC DDA RATE BASE FOR COST ALLOCATION DistributionPower Supply Transmission FUNCTIONALIZATION AND CLASSIFICATION Schedule 4.2 Less: Accumulated Depreciation Intangible Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Transmission Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Distribution Plant $139,992,346 $0 $0 $0 $0 $0 $0 $100,430,808 $0 $39,561,538 $0 General Plant $29,441,360 $0 $0 $0 $0 $0 $0 $21,121,294 $0 $6,200,162 $2,119,903 Street Lighting $19,389,916 $0 $0 $0 $0 $0 $0 $0 $0 $0 $19,389,916 Misc. Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Total Accumulated Depreciation $188,823,622 $0 $0 $0 $0 $0 $0 $121,552,102 $0 $45,761,701 $21,509,819 Total Net Plant $208,685,330 $0 $0 $0 $0 $0 $0 $163,621,668 $0 $37,951,142 $7,112,520 Working Capital 90 Days of Non Power Supply O&M $10,832,188 $0 $1,775,709 $0 $0 $0 $0 $6,099,572 $0 $2,641,883 $315,023 90 Days of Power Supply Cost $28,459,651 $2,837,950 $25,621,702 $0 $0 $0 $0 $0 $0 $0 $0 Total Working Capital $39,291,839 $2,837,950 $27,397,411 $0 $0 $0 $0 $6,099,572 $0 $2,641,883 $315,023 Less: Net Customer Contributions Production Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Transmission Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Distribution Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Street Lights $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 General Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Total Contributions $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 TOTAL RATE BASE $247,977,170 $2,837,950 $27,397,411 $0 $0 $0 $0 $169,721,240 $0 $40,593,025 $7,427,544 CWIP Production Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Transmission Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Distribution Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Services $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 General Plant $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Other $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Total CWIP $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 TOTAL RATE BASE plus CWIP $247,977,170 $2,837,950 $27,397,411 $0 $0 $0 $0 $169,721,240 $0 $40,593,025 $7,427,544 Schedule 4.2 Page 2 of 2 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto - 100% Demand Account Description Total Rate Base Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Distribution Plant Land & Rights $0 $0 $0 $0 $0 $0 Structures & Improvements $7,154,333 $1,051,419 $568,409 $3,136,220 $2,371,292 $26,993 Station Equipment - Distribution $59,404,780 $8,730,274 $4,719,690 $26,041,063 $19,689,619 $224,134 Storage & Battery Equipment $2,659,291 $390,816 $211,280 $1,165,744 $881,418 $10,033 Poles, Towers, & Fixtures $44,602,342 $6,554,871 $3,543,641 $19,552,171 $14,783,375 $168,284 Overhead Conductors & Devices $18,501,977 $2,719,096 $1,469,976 $8,110,646 $6,132,450 $69,808 Underground Conduit $1,763,879 $259,224 $140,140 $773,225 $584,635 $6,655 Underground Conductors & Devices $85,733,395 $12,599,593 $6,811,490 $37,582,645 $28,416,196 $323,471 Line Transformers $31,475,442 $4,625,709 $2,500,713 $13,797,778 $10,432,485 $118,757 Services $68,019,093 $13,711,891 $1,660,424 $43,161,532 $9,485,246 $0 Meters $4,490,213 $3,777,333 $460,661 $203,761 $48,459 $0 Installation on Customer Premises $1,258,542 $1,058,732 $129,117 $57,111 $13,582 $0 Leased Property on Cust. Premises $0 $0 $0 $0 $0 $0 Street Lights and Signal Systems $25,222,037 $0 $0 $0 $0 $25,222,037 Total Distribution Plant $350,285,324 $55,478,957 $22,215,541 $153,581,897 $92,838,756 $26,170,173 Total Transmission & Distribution $350,285,324 $55,478,957 $22,215,541 $153,581,897 $92,838,756 $26,170,173 General Plant Land & Land Rights $0 $0 $0 $0 $0 $0 Structures & Improvements $1,897,484 $300,528 $120,341 $831,948 $502,905 $141,763 Office Furniture & Equipment $8,874,818 $1,405,613 $562,852 $3,891,146 $2,352,160 $663,047 Transportation Equipment $415,330 $65,781 $26,341 $182,100 $110,078 $31,030 Stores Equipment $0 $0 $0 $0 $0 $0 Tools, Shop, & Garage Equipment $2,685,629 $425,356 $170,326 $1,177,509 $711,793 $200,646 Laboratory Equipment $0 $0 $0 $0 $0 $0 Power Operated Equipment $0 $0 $0 $0 $0 $0 Communication Equipment $22,487,683 $3,561,649 $1,426,197 $9,859,680 $5,960,080 $1,680,078 Misc. Equipment $10,832,848 $1,715,730 $687,033 $4,749,640 $2,871,111 $809,333 Other Tangible Property - EV Charging $29,836 $4,725 $1,892 $13,082 $7,908 $2,229 Total General Plant $47,223,629 $7,479,382 $2,994,983 $20,705,105 $12,516,034 $3,528,125 Total Plant Before General Plant & Intangible $350,285,324 $55,478,957 $22,215,541 $153,581,897 $92,838,756 $26,170,173 Total Gross Plant in Service $397,508,952 $62,958,339 $25,210,523 $174,287,002 $105,354,790 $29,698,298 RATE BASE COST ALLOCATION CLASSIFICATION BY CUSTOMER Schedule 4.3 Schedule 4.3 Page 1 of 2 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto - 100% Demand Account Description Total Rate Base Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights RATE BASE COST ALLOCATION CLASSIFICATION BY CUSTOMER Schedule 4.3 Less: Accumulated Depreciation Intangible Plant $0 $0 $0 $0 $0 $0 Transmission Plant $0 $0 $0 $0 $0 $0 Distribution Plant $139,992,346 $24,706,790 $9,185,973 $67,312,840 $38,407,819 $378,925 General Plant $29,441,360 $4,662,987 $1,867,208 $12,908,505 $7,803,065 $2,199,594 Street Lighting $19,389,916 $0 $0 $0 $0 $19,389,916 Misc. Plant $0 $0 $0 $0 $0 $0 Total Accumulated Depreciation $188,823,622 $29,369,777 $11,053,181 $80,221,345 $46,210,884 $21,968,435 Total Net Plant $208,685,330 $33,588,562 $14,157,342 $94,065,657 $59,143,905 $7,729,863 Working Capital $0 $0 $0 $0 $0 90 Days of Non Power Supply O&M $10,832,188 $2,056,374 $742,996 $4,610,246 $3,077,746 $344,826 90 Days of Power Supply Cost $28,459,651 $4,455,996 $1,840,266 $10,311,631 $11,789,021 $62,737 Total Working Capital $39,291,839 $6,512,371 $2,583,262 $14,921,877 $14,866,767 $407,563 Less: Net Customer Contributions $0 $0 $0 $0 $0 Production Plant $0 $0 $0 $0 $0 $0 Transmission Plant $0 $0 $0 $0 $0 $0 Distribution Plant $0 $0 $0 $0 $0 $0 Street Lights $0 $0 $0 $0 $0 $0 General Plant $0 $0 $0 $0 $0 $0 Total Contributions $0 $0 $0 $0 $0 $0 TOTAL RATE BASE $247,977,170 $40,100,933 $16,740,604 $108,987,533 $74,010,673 $8,137,426 CWIP $0 $0 $0 $0 $0 Production Plant $0 $0 $0 $0 $0 $0 Transmission Plant $0 $0 $0 $0 $0 $0 Distribution Plant $0 $0 $0 $0 $0 $0 Services $0 $0 $0 $0 $0 $0 General Plant $0 $0 $0 $0 $0 $0 Other $0 $0 $0 $0 $0 $0 Total CWIP $0 $0 $0 $0 $0 $0 TOTAL RATE BASE plus CWIP $247,977,170 $40,100,933 $16,740,604 $108,987,533 $74,010,673 $8,137,426 Schedule 4.3 Page 2 of 2 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto - 100% Demand Account Description Total Rate Base Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E- 7 Street/Traffic Lights Distribution Plant Land & Rights $0 $0 $0 $0 $0 $0 Structures & Improvements $0 $0 $0 $0 $0 $0 Station Equipment - Distribution $0 $0 $0 $0 $0 $0 Storage & Battery Equipment $0 $0 $0 $0 $0 $0 Poles, Towers, & Fixtures $0 $0 $0 $0 $0 $0 Overhead Conductors & Devices $0 $0 $0 $0 $0 $0 Underground Conduit $0 $0 $0 $0 $0 $0 Underground Conductors & Devices $0 $0 $0 $0 $0 $0 Line Transformers $0 $0 $0 $0 $0 $0 Services $0 $0 $0 $0 $0 $0 Meters $0 $0 $0 $0 $0 $0 Installation on Customer Premises $0 $0 $0 $0 $0 $0 Leased Property on Cust. Premises $0 $0 $0 $0 $0 $0 Street Lights and Signal Systems $25,222,037 $0 $0 $0 $0 $25,222,037 Total Distribution Plant $25,222,037 $0 $0 $0 $0 $25,222,037 Total Transmission & Distribution $25,222,037 $0 $0 $0 $0 $25,222,037 General Plant Land & Land Rights $0 $0 $0 $0 $0 $0 Structures & Improvements $136,627 $0 $0 $0 $0 $136,627 Office Furniture & Equipment $639,025 $0 $0 $0 $0 $639,025 Transportation Equipment $29,905 $0 $0 $0 $0 $29,905 Stores Equipment $0 $0 $0 $0 $0 $0 Tools, Shop, & Garage Equipment $193,377 $0 $0 $0 $0 $193,377 Laboratory Equipment $0 $0 $0 $0 $0 $0 Power Operated Equipment $0 $0 $0 $0 $0 $0 Communication Equipment $1,619,209 $0 $0 $0 $0 $1,619,209 Misc. Equipment $780,011 $0 $0 $0 $0 $780,011 Other Tangible Property - EV Charging $2,148 $0 $0 $0 $0 $2,148 Total General Plant $3,400,303 $0 $0 $0 $0 $3,400,303 Total Plant Before General Plant & Intangible $25,222,037 $0 $0 $0 $0 $25,222,037 Total Gross Plant in Service $28,622,340 $0 $0 $0 $0 $28,622,340 RATE BASE COST ALLOCATION DIRECT ASSIGNMENT BY CUSTOMER Schedule 4.4 Schedule 4.4 Page 1 of 2 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto - 100% Demand Account Description Total Rate Base Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E- 7 Street/Traffic Lights RATE BASE COST ALLOCATION DIRECT ASSIGNMENT BY CUSTOMER Schedule 4.4 Less: Accumulated Depreciation Intangible Plant $0 $0 $0 $0 $0 $0 Transmission Plant $0 $0 $0 $0 $0 $0 Distribution Plant $0 $0 $0 $0 $0 $0 General Plant $2,119,903 $0 $0 $0 $0 $2,119,903 Street Lighting $19,389,916 $0 $0 $0 $0 $19,389,916 Misc. Plant $0 $0 $0 $0 $0 $0 Total Accumulated Depreciation $21,509,819 $0 $0 $0 $0 $21,509,819 Total Net Plant $7,112,520 $0 $0 $0 $0 $7,112,520 Working Capital $0 $0 $0 $0 $0 $0 90 Days of Non Power Supply O&M $315,023 $0 $0 $0 $0 $315,023 90 Days of Power Supply Cost Total Working Capital $315,023 $0 $0 $0 $0 $315,023 Less: Net Customer Contributions $0 Production Plant $0 $0 $0 $0 $0 $0 Transmission Plant $0 $0 $0 $0 $0 $0 Distribution Plant $0 $0 $0 $0 $0 $0 Street Lights $0 $0 $0 $0 $0 $0 General Plant $0 $0 $0 $0 $0 $0 Total Contributions $0 $0 $0 $0 $0 $0 TOTAL RATE BASE $7,427,544 $0 $0 $0 $0 $7,427,544 CWIP $0 $0 $0 $0 $0 $0 Production Plant $0 $0 $0 $0 $0 $0 Transmission Plant $0 $0 $0 $0 $0 $0 Distribution Plant $0 $0 $0 $0 $0 $0 Services $0 $0 $0 $0 $0 $0 General Plant $0 $0 $0 $0 $0 $0 Other $0 $0 $0 $0 $0 $0 Total CWIP $0 $0 $0 $0 $0 $0 TOTAL RATE BASE plus CWIP $7,427,544 $0 $0 $0 $0 $7,427,544 Schedule 4.4 Page 2 of 2 February 2024 Prepared By EES Consulting, Inc. City of Palo Alto Classification Factors Total % Allocated Demand Energy Direct Assignment Demand Energy Direct Assignment Demand Energy Customer Direct Assignment PD PE PDA TD TE TDA DD DE DC DDA CP1 100.00%100.00%100.00%100.0% CP2 100.00%100.00%100.00%100.0% CPS 100.00%100.00%100.00%100.0% CP12 100.00%100.00%100.00%100.0% LF 37.45%62.55%100.0% TCP1 100.00%100.0% TCP2 100.00%100.0% TCPS 100.00%100.0% TCP12 100.00%100.0% TAE 100.00%100.0% CPG 100.00%100.00%100.00%100.0% CPT 100.00%100.00%100.00%100.0% AE 100.00%100.00%100.00%100.0% NCP 100.00%100.00%100.00%100.0% NCPP 100.00%100.00%100.00%100.0% NCPS 100.00%100.00%100.00%100.0% kWh 100.00%100.00%100.00%100.0% kWhP 100.00%100.00%100.00%100.0% kWhO 100.00%100.00%100.00%100.0% kWhPJAN 100.00%100.00%100.00%100.0% kWhPFEB 100.00%100.00%100.00%100.0% kWhPMAR 100.00%100.00%100.00%100.0% kWhPAPR 100.00%100.00%100.00%100.0% kWhPMAY 100.00%100.00%100.00%100.0% kWhPJUN 100.00%100.00%100.00%100.0% kWhPJUL 100.00%100.00%100.00%100.0% kWhPAUG 100.00%100.00%100.00%100.0% kWhPSEP 100.00%100.00%100.00%100.0% kWhPOCT 100.00%100.00%100.00%100.0% kWhPNOV 100.00%100.00%100.00%100.0% kWhPDEC 100.00%100.00%100.00%100.0% kWhOJAN 100.00%100.00%100.00%100.0% kWhOFEB 100.00%100.00%100.00%100.0% kWhOMAR 100.00%100.00%100.00%100.0% kWhOAPR 100.00%100.00%100.00%100.0% kWhOMAY 100.00%100.00%100.00%100.0% Production Transmission Distribution CLASSIFICATION and ALLOCATION BY FUNCTION Schedule 6.1 Schedule 6.1 Page 1 of 5 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Classification Factors Total % Allocated Demand Energy Direct Assignment Demand Energy Direct Assignment Demand Energy Customer Direct Assignment PD PE PDA TD TE TDA DD DE DC DDA Production Transmission Distribution CLASSIFICATION and ALLOCATION BY FUNCTION Schedule 6.1 kWhOJUN 100.00%100.00%100.00%100.0% kWhOJUL 100.00%100.00%100.00%100.0% kWhOAUG 100.00%100.00%100.00%100.0% kWhOSEP 100.00%100.00%100.00%100.0% kWhOOCT 100.00%100.00%100.00%100.0% kWhONOV 100.00%100.00%100.00%100.0% kWhODEC 100.00%100.00%100.00%100.0% CUST 100.00%100.0% CUSTW 100.00%100.0% CUSTM 100.00%100.0% CUSTMR 100.00%100.0% MINSYSP 60.00%40.00%100.0% MINSYSC 60.00%40.00%100.0% MINSYST 50.00%50.00%100.0% 100%DP 100.00%0.00%100.0% 100%DC 100.00%0.00%100.0% 100%DT 100.00%0.00%100.0% DA1 100.000%100.0% DA2 100.000%100.0% DA3 100.000%0.000%0.000%100.0% DA4 100.000%0.000%0.000%100.0% DA5 100.000%0.000%0.000%100.0% DA6 100.000%0.000%100.0% DA7 100.000%0.000%100.0% DA8 100.000%0.000%100.0% DA9 0.000%100.000%0.000%0.000%0.000%0.000%0.000%0.000%100.0% DA10 8.026%72.463%0.000%0.000%0.000%0.000%14.024%0.000%4.664%0.822%100.0% REV 0.00%0.00%0.00%0.00%0.00%0.00%100.00%0.00%100.0% REV-P 0.00%0.00%0.00%0.00%0.00%0.00%100.00%0.00%0.00%0.00%100.0% REV-T 0.00%0.00%0.00%0.00%0.00%0.00%100.00%0.00%0.00%0.00%100.0% REV-D 0.00%0.00%0.00%0.00%0.00%0.00%100.00%0.00%0.00%0.00%100.0% OTHER 0.00%0.00%0.00%0.00%0.00%0.00%100.00%0.00%0.00%100.0% RB 1.14%11.05%0.00%0.00%0.00%0.00%68.44%0.00%16.37%3.00%100.0% RB-P 1.14%11.05%0.00%0.00%0.00%0.00%68.44%0.00%16.37%3.00%100.0% RB-T 1.14%11.05%0.00%0.00%0.00%0.00%68.44%0.00%16.37%3.00%100.0% RB-D 1.14%11.05%0.00%0.00%0.00%0.00%68.44%0.00%16.37%3.00%100.0% RBG 0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.0% RBIG 0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.0% Schedule 6.1 Page 2 of 5 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Classification Factors Total % Allocated Demand Energy Direct Assignment Demand Energy Direct Assignment Demand Energy Customer Direct Assignment PD PE PDA TD TE TDA DD DE DC DDA Production Transmission Distribution CLASSIFICATION and ALLOCATION BY FUNCTION Schedule 6.1 RBIG-P 0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.0% RBIG-T 0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.0% RBIG-D 0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.0% RBSG 0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.0% RBHG 0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.0% RBGG 0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.0% RBT 0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.0% RBD 0.00%0.00%0.00%0.00%0.00%0.00%71.74%0.00%21.06%7.20%100.0% RBGP 0.00%0.00%0.00%0.00%0.00%0.00%71.74%0.00%21.06%7.20%100.0% RBGP-P 0.00%0.00%0.00%0.00%0.00%0.00%71.74%0.00%21.06%7.20%100.0% RBGP-T 0.00%0.00%0.00%0.00%0.00%0.00%71.74%0.00%21.06%7.20%100.0% RBGP-D 0.00%0.00%0.00%0.00%0.00%0.00%71.74%0.00%21.06%7.20%100.0% RBSE 0.00%0.00%0.00%0.00%0.00%0.00%100.00%0.00%0.00%0.00%100.0% RBOH 0.00%0.00%0.00%0.00%0.00%0.00%100.00%0.00%0.00%0.00%100.0% RBUG 0.00%0.00%0.00%0.00%0.00%0.00%100.00%0.00%0.00%0.00%100.0% RBTR 0.00%0.00%0.00%0.00%0.00%0.00%100.00%0.00%0.00%0.00%100.0% OM 8.03%72.46%0.00%0.00%0.00%0.00%14.02%0.00%4.66%0.82%100.0% OM-P 8.03%72.46%0.00%0.00%0.00%0.00%14.02%0.00%4.66%0.82%100.0% OM-T 8.03%72.46%0.00%0.00%0.00%0.00%14.02%0.00%4.66%0.82%100.0% OM-D 8.03%72.46%0.00%0.00%0.00%0.00%14.02%0.00%4.66%0.82%100.0% OMAG 0.00%16.47%0.00%0.00%0.00%0.00%56.20%0.00%24.42%2.91%100.0% OMAG-P 0.00%16.47%0.00%0.00%0.00%0.00%56.20%0.00%24.42%2.91%100.0% OMAG-T 0.00%16.47%0.00%0.00%0.00%0.00%56.20%0.00%24.42%2.91%100.0% OMAG-D 0.00%16.47%0.00%0.00%0.00%0.00%56.20%0.00%24.42%2.91%100.0% OMG 9.97%90.03%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%100.0% OMT 0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.0% OMD 0.00%0.00%0.00%0.00%0.00%0.00%71.88%0.00%23.90%4.21%100.0% OMDLUGT 0.00%0.00%0.00%0.00%0.00%0.00%71.88%0.00%23.90%4.21%100.0% OMDS&E 0.00%0.00%0.00%0.00%0.00%0.00%72.09%0.00%25.06%2.86%100.0% MARKET 100.00%100.0% GPLT 0.00%0.00%0.00%0.00%0.00%0.00%71.74%0.00%21.06%7.20%100.0% GPLT-P 0.00%0.00%0.00%0.00%0.00%0.00%71.74%0.00%21.06%7.20%100.0% GPLT-T 0.00%0.00%0.00%0.00%0.00%0.00%71.74%0.00%21.06%7.20%100.0% GPLT-D 0.00%0.00%0.00%0.00%0.00%0.00%71.74%0.00%21.06%7.20%100.0% GRSPLT 0.00%0.00%0.00%0.00%0.00%0.00%71.74%0.00%21.06%7.20%100.0% GRSPLT-P 0.00%0.00%0.00%0.00%0.00%0.00%71.74%0.00%21.06%7.20%100.0% GRSPLT-T 0.00%0.00%0.00%0.00%0.00%0.00%71.74%0.00%21.06%7.20%100.0% Schedule 6.1 Page 3 of 5 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Classification Factors Total % Allocated Demand Energy Direct Assignment Demand Energy Direct Assignment Demand Energy Customer Direct Assignment PD PE PDA TD TE TDA DD DE DC DDA Production Transmission Distribution CLASSIFICATION and ALLOCATION BY FUNCTION Schedule 6.1 GRSPLT-D 0.00%0.00%0.00%0.00%0.00%0.00%71.74%0.00%21.06%7.20%100.0% NETPLT 0.00%0.00%0.00%0.00%0.00%0.00%78.41%0.00%18.19%3.41%100.0% NETPLT-P 0.00%0.00%0.00%0.00%0.00%0.00%78.41%0.00%18.19%3.41%100.0% NETPLT-T 0.00%0.00%0.00%0.00%0.00%0.00%78.41%0.00%18.19%3.41%100.0% NETPLT-D 0.00%0.00%0.00%0.00%0.00%0.00%78.41%0.00%18.19%3.41%100.0% TOTCST 6.11%62.36%0.00%0.00%0.00%0.00%22.96%0.00%7.81%0.76%100.0% TOTCST-P 6.11%62.36%0.00%0.00%0.00%0.00%22.96%0.00%7.81%0.76%100.0% TOTCST-T 6.11%62.36%0.00%0.00%0.00%0.00%22.96%0.00%7.81%0.76%100.0% TOTCST-D 6.11%62.36%0.00%0.00%0.00%0.00%22.96%0.00%7.81%0.76%100.0% OMP 9.97%90.03%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%100.0% OMWOP 0.00%16.39%0.00%0.00%0.00%0.00%56.31%0.00%24.39%2.91%100.0% OMWOP-P 0.00%16.39%0.00%0.00%0.00%0.00%56.31%0.00%24.39%2.91%100.0% OMWOP-T 0.00%16.39%0.00%0.00%0.00%0.00%56.31%0.00%24.39%2.91%100.0% OMWOP-D 0.00%16.39%0.00%0.00%0.00%0.00%56.31%0.00%24.39%2.91%100.0% PROD 9.97%90.03%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%100.0% OMPT 0.00%100.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%0.00%100.0% NCPplcc 100.00%100.0% NCPPplcc 100.00%100.0% NCPSplcc 100.00%100.0% WEST 16.000%84.000%100.0% REN 3.158%96.842%100.0% CALA 7.000%93.000%100.0% CREDIT 100.000%100.0% CUST SERV 100.000%100.0% SERV 100.000%100.0% RR 6.114%62.360%0.000%0.000%0.000%0.000%22.956%0.000%7.813%0.757%100.0% RR-P 0.0% RR-T 0.0% RR-D 0.0% RBD-ST 61.755%24.326%13.919%100.0% RBD-NoDA 71.740%28.260%100.0% DSRE 100.000%100.0% DSMEE 100.000%100.0% GF 2.197%95.432%0.000%0.000%0.000%0.000%1.596%0.000%0.693%0.083%100.0% Schedule 6.1 Page 4 of 5 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Classification Factors Total % Allocated Demand Energy Direct Assignment Demand Energy Direct Assignment Demand Energy Customer Direct Assignment PD PE PDA TD TE TDA DD DE DC DDA Production Transmission Distribution CLASSIFICATION and ALLOCATION BY FUNCTION Schedule 6.1 GF-P 0.0% GF-T 0.0% GF-D 0.0% RSR 0.0% RBD-NoDA Services 0.000%0.000%0.000%0.000%0.000%0.000%97.764%0.000%2.236%0.000%100.0% Rcontr 5.572%33.899%0.000%0.000%0.000%0.000%45.137%0.000%15.393%0.000%100.0% Rcontr-P 0.0% Rcontr-D 0.0% Rcontr-T 0.0% Schedule 6.1 Page 1 of 1 February 2024 Prepared By EES Consulting, Inc. City of Palo Alto Test Year: 2025 Classification Factors Total Allocated Residential E-1 Small Commercial E-2 Medium Commercial E- 4 Large Commercial E- 7 Street/Traffic Lights CP1 0% CP2 0% CPS 0% CP12 0% LF 100%15.993%6.399%35.490%41.891%0.226% TCP1 0% TCP2 0% TCPS 0% TCP12 0% TAE 0% CPG 0% CPT 0% AE 0% NCP 0% NCPP 0% NCPS 0% kWh 100%15.993%6.399%35.490%41.891%0.226% kWhP 100%15.982%6.400%35.506%41.887%0.226% kWhO 100%16.010%6.399%35.468%41.897%0.226% kWhPJAN 100%14.410%6.917%36.363%42.085%0.225% kWhPFEB 100%14.545%6.663%37.241%41.340%0.211% kWhPMAR 100%12.525%6.257%37.045%43.965%0.207% kWhPAPR 100%14.629%6.632%37.416%41.083%0.240% kWhPMAY 100%15.374%6.104%35.671%42.626%0.225% kWhPJUN 100%16.525%6.785%36.380%40.069%0.240% kWhPJUL 100%20.858%6.237%30.909%41.781%0.215% kWhPAUG 100%18.454%6.359%35.102%39.861%0.225% kWhPSEP 100%19.895%6.565%33.558%39.740%0.242% kWhPOCT 100%15.624%5.946%34.732%43.460%0.238% kWhPNOV 100%14.925%6.224%36.034%42.584%0.234% kWhPDEC 100%14.497%6.127%35.423%43.731%0.222% kWhOJAN 100%14.410%6.917%36.363%42.085%0.225% kWhOFEB 100%14.545%6.663%37.241%41.340%0.211% CLASSIFICATION AND ALLOCATION BY CUSTOMER - ENERGY Schedule 6.2 Schedule 6.2 (Energy) Page 1 of 5 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2025 Classification Factors Total Allocated Residential E-1 Small Commercial E-2 Medium Commercial E- 4 Large Commercial E- 7 Street/Traffic Lights CLASSIFICATION AND ALLOCATION BY CUSTOMER - ENERGY Schedule 6.2 kWhOMAR 100%12.525%6.257%37.045%43.965%0.207% kWhOAPR 100%14.629%6.632%37.416%41.083%0.240% kWhOMAY 100%15.374%6.104%35.671%42.626%0.225% kWhOJUN 100%16.525%6.785%36.380%40.069%0.240% kWhOJUL 100%20.858%6.237%30.909%41.781%0.215% kWhOAUG 100%18.454%6.359%35.102%39.861%0.225% kWhOSEP 100%19.895%6.565%33.558%39.740%0.242% kWhOOCT 100%15.624%5.946%34.732%43.460%0.238% kWhONOV 100%14.925%6.224%36.034%42.584%0.234% kWhODEC 100%14.497%6.127%35.423%43.731%0.222% CUST 0% CUSTW 0% CUSTM 0% CUSTMR 0% MINSYSP 0% MINSYSC 0% MINSYST 0% 100%DP 0% 100%DC 0% 100%DT 0% DA1 0%0.000%0.000%0.000%0.000%0.000% DA2 0%0.000%0.000%0.000%0.000%0.000% DA3 100%0.000%0.000%0.000%0.000%0.000% DA4 100%0.000%0.000%0.000%0.000%0.000% DA5 100%0.000%0.000%0.000%0.000%0.000% DA6 0%0.000%0.000%0.000%0.000%0.000% DA7 100%15.993%6.399%35.490%41.891%0.226% DA8 100%15.993%6.399%35.490%41.891%0.226% DA9 0%0.000%0.000%0.000%0.000%0.000% DA10 100%100.000%0.000%0.000%0.000%0.000% REV 100%16.225%7.001%40.225%35.228%1.321% REV-P 100%16.225%7.001%40.225%35.228%1.321% REV-T 100%16.225%7.001%40.225%35.228%1.321% REV-D 100%16.225%7.001%40.225%35.228%1.321% OTHER 0% RB 100%15.953%6.498%35.337%42.000%0.212% RB-P 100%15.953%6.498%35.337%42.000%0.212% Schedule 6.2 (Energy) Page 2 of 5 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2025 Classification Factors Total Allocated Residential E-1 Small Commercial E-2 Medium Commercial E- 4 Large Commercial E- 7 Street/Traffic Lights CLASSIFICATION AND ALLOCATION BY CUSTOMER - ENERGY Schedule 6.2 RB-T 0%0.000%0.000%0.000%0.000%0.000% RB-D 0%0.000%0.000%0.000%0.000%0.000% RBG 0%0.000%0.000%0.000%0.000%0.000% RBIG 0%0.000%0.000%0.000%0.000%0.000% RBIG-P 0%0.000%0.000%0.000%0.000%0.000% RBIG-T 0%0.000%0.000%0.000%0.000%0.000% RBIG-D 0%0.000%0.000%0.000%0.000%0.000% RBSG 0%0.000%0.000%0.000%0.000%0.000% RBHG 0%0.000%0.000%0.000%0.000%0.000% RBGG 0%0.000%0.000%0.000%0.000%0.000% RBT 0%0.000%0.000%0.000%0.000%0.000% RBD 0%0.000%0.000%0.000%0.000%0.000% RBGP 0%0.000%0.000%0.000%0.000%0.000% RBGP-P 0%0.000%0.000%0.000%0.000%0.000% RBGP-T 0%0.000%0.000%0.000%0.000%0.000% RBGP-D 0%0.000%0.000%0.000%0.000%0.000% RBSE 0%0.000%0.000%0.000%0.000%0.000% RBOH 0%0.000%0.000%0.000%0.000%0.000% RBUG 0%0.000%0.000%0.000%0.000%0.000% RBTR 0%0.000%0.000%0.000%0.000%0.000% OM 100%15.993%6.399%35.490%41.891%0.226% OM-P 100%15.993%6.399%35.490%41.891%0.226% OM-T 0%0.000%0.000%0.000%0.000%0.000% OM-D 0%0.000%0.000%0.000%0.000%0.000% OMAG 100%15.377%7.924%33.120%43.578%0.000% OMAG-P 100%15.377%7.924%33.120%43.578%0.000% OMAG-T 0%0.000%0.000%0.000%0.000%0.000% OMAG-D 0%0.000%0.000%0.000%0.000%0.000% OMG 100%15.993%6.399%35.490%41.891%0.226% OMT 0%0.000%0.000%0.000%0.000%0.000% OMD 0%0.000%0.000%0.000%0.000%0.000% OMDLUGT 0% OMDS&E 0%0.000%0.000%0.000%0.000%0.000% MARKET 0% GPLT 0%0.000%0.000%0.000%0.000%0.000% GPLT-P 0%0.000%0.000%0.000%0.000%0.000% Schedule 6.2 (Energy) Page 3 of 5 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2025 Classification Factors Total Allocated Residential E-1 Small Commercial E-2 Medium Commercial E- 4 Large Commercial E- 7 Street/Traffic Lights CLASSIFICATION AND ALLOCATION BY CUSTOMER - ENERGY Schedule 6.2 GPLT-T 0%0.000%0.000%0.000%0.000%0.000% GPLT-D 0%0.000%0.000%0.000%0.000%0.000% GRSPLT 0% GRSPLT-P 0% GRSPLT-T 0% GRSPLT-D 0% NETPLT 0%0.000%0.000%0.000%0.000%0.000% NETPLT-P 0%0.000%0.000%0.000%0.000%0.000% NETPLT-T 0%0.000%0.000%0.000%0.000%0.000% NETPLT-D 0%0.000%0.000%0.000%0.000%0.000% TOTCST 0% TOTCST-P 0% TOTCST-T 0% TOTCST-D 0% OMP 100%15.993%6.399%35.490%41.891%0.226% OMWOP 100%15.377%7.924%33.120%43.578%0.000% OMWOP-P 100%15.377%7.924%33.120%43.578%0.000% OMWOP-T 0%0.000%0.000%0.000%0.000%0.000% OMWOP-D 0%0.000%0.000%0.000%0.000%0.000% UNP 0% LABORRB 0% LABORRR 0% TRANSP 0% ST 0% DC 0% PI 0% PROD 0% OMPT 100%15.99%6.40%35.49%41.89%0.23% NCPplcc 0% NCPPplcc 0% NCPSplcc 0% WEST 100%15.993%6.399%35.490%41.891%0.226% REN 100%15.993%6.399%35.490%41.891%0.226% CALA 100%15.993%6.399%35.490%41.891%0.226% CREDIT 0% CUST SERV 0% SERV 0% RR 0% RR-P 0% RR-T 0% RR-D 0% RBD-ST 0% Schedule 6.2 (Energy) Page 4 of 5 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2025 Classification Factors Total Allocated Residential E-1 Small Commercial E-2 Medium Commercial E- 4 Large Commercial E- 7 Street/Traffic Lights CLASSIFICATION AND ALLOCATION BY CUSTOMER - ENERGY Schedule 6.2 RBD-NoDA 0% DSRE 100%20.855%8.271%33.548%37.325% DSMEE 100%15.377%7.924%33.120%43.578% GF 100%15.990%6.407%35.479%41.899%0.225% GF-P 100%15.990%6.407%35.479%41.899%0.225% GF-T 100%15.990%6.407%35.479%41.899%0.225% GF-D 100%15.990%6.407%35.479%41.899%0.225% RSR 0% RBD-NoDA Services 0% Rcontr 100%15.918%6.584%35.203%42.096%0.199% Rcontr-P 100%15.918%6.584%35.203%42.096%0.199% Rcontr-D 0% Rcontr-T 100%15.918%6.584%35.203%42.096%0.199% Schedule 6.2 (Energy) Page 5 of 5 February 2024 Prepared By EES Consulting, Inc. City of Palo Alto Test Year: 2025 Classification Factors Total Allocated Residential E-1 Small Commercial E-2 Medium Commercial E- 4 Large Commercial E- 7 Street/Traffic Lights CP1 100%12.009%6.793%44.857%36.073%0.268% CP2 100%12.171%6.872%44.850%35.967%0.140% CPS 100%12.171%6.872%44.850%35.967%0.140% CP12 100%12.624%7.071%42.933%37.205%0.167% LF 100%15.695%7.635%41.687%34.599%0.384% TCP1 100%12.009%6.793%44.857%36.073%0.268% TCP2 100%12.171%6.872%44.850%35.967%0.140% TCPS 100%12.171%6.872%44.850%35.967%0.140% TCP12 100%12.624%7.071%42.933%37.205%0.167% TAE 100%15.695%7.635%41.687%34.599%0.384% CPG 100%12.624%7.071%42.933%37.205%0.167% CPT 100%12.624%7.071%42.933%37.205%0.167% AE 100%15.695%7.635%41.687%34.599%0.384% NCP 100%14.696%7.945%43.837%33.145%0.377% NCPP 100%14.696%7.945%43.837%33.145%0.377% NCPS 100%14.696%7.945%43.837%33.145%0.377% kWh 0%0.000%0.000%0.000%0.000%0.000% kWhP 0%0.000%0.000%0.000%0.000%0.000% kWhO 0%0.000%0.000%0.000%0.000%0.000% kWhPJAN 0%0.000%0.000%0.000%0.000%0.000% kWhPFEB 0%0.000%0.000%0.000%0.000%0.000% kWhPMAR 0%0.000%0.000%0.000%0.000%0.000% kWhPAPR 0%0.000%0.000%0.000%0.000%0.000% kWhPMAY 0%0.000%0.000%0.000%0.000%0.000% kWhPJUN 0%0.000%0.000%0.000%0.000%0.000% kWhPJUL 0%0.000%0.000%0.000%0.000%0.000% kWhPAUG 0%0.000%0.000%0.000%0.000%0.000% kWhPSEP 0%0.000%0.000%0.000%0.000%0.000% kWhPOCT 0%0.000%0.000%0.000%0.000%0.000% kWhPNOV 0%0.000%0.000%0.000%0.000%0.000% kWhPDEC 0%0.000%0.000%0.000%0.000%0.000% kWhOJAN 0%0.000%0.000%0.000%0.000%0.000% kWhOFEB 0%0.000%0.000%0.000%0.000%0.000% kWhOMAR 0%0.000%0.000%0.000%0.000%0.000% kWhOAPR 0%0.000%0.000%0.000%0.000%0.000% kWhOMAY 0%0.000%0.000%0.000%0.000%0.000% kWhOJUN 0%0.000%0.000%0.000%0.000%0.000% kWhOJUL 0%0.000%0.000%0.000%0.000%0.000% kWhOAUG 0%0.000%0.000%0.000%0.000%0.000% kWhOSEP 0%0.000%0.000%0.000%0.000%0.000% CLASSIFICATION AND ALLOCATION BY CUSTOMER - DEMAND Schedule 6.2 Schedule 6.2 (Demand) Page 1 of 10 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2025 Classification Factors Total Allocated Residential E-1 Small Commercial E-2 Medium Commercial E- 4 Large Commercial E- 7 Street/Traffic Lights CLASSIFICATION AND ALLOCATION BY CUSTOMER - DEMAND Schedule 6.2 kWhOOCT 0%0.000%0.000%0.000%0.000%0.000% kWhONOV 0%0.000%0.000%0.000%0.000%0.000% kWhODEC 0%0.000%0.000%0.000%0.000%0.000% CUST 0% CUSTW 0% CUSTM 0% CUSTMR 0% MINSYSP 100%6.134%7.635%48.737%37.072%0.422% MINSYSC 100%6.134%7.635%48.737%37.072%0.422% MINSYST 100%5.910%7.627%48.866%37.175%0.423% 100%DP 100%14.696%7.945%43.837%33.145%0.377% 100%DC 100%14.696%7.945%43.837%33.145%0.377% 100%DT 100%14.696%7.945%43.837%33.145%0.377% DA1 0%0.000%0.000%0.000%0.000%0.000% DA2 100%0.000%40.000%60.000%0.000%0.000% DA3 100%0.000%0.000%0.000%0.000%0.000% DA4 100%0.000%0.000%0.000%0.000%0.000% DA5 100%0.000%0.000%0.000%0.000%0.000% DA6 0%0.000%0.000%0.000%0.000%0.000% DA7 0%0.000%0.000%0.000%0.000%0.000% DA8 0%0.000%0.000%0.000%0.000%0.000% DA9 0%0.000%0.000%0.000%0.000%0.000% DA10 100%100.000%0.000%0.000%0.000%0.000% REV 100%16.225%7.001%40.225%35.228%1.321% REV-P 100%16.225%7.001%40.225%35.228%1.321% REV-T 100%16.225%7.001%40.225%35.228%1.321% REV-D 100%16.225%7.001%40.225%35.228%1.321% OTHER 0% RB 100%14.669%7.927%43.807%33.220%0.378% RB-P 100%12.624%7.071%42.933%37.205%0.167% RB-T 0%0.000%0.000%0.000%0.000%0.000% RB-D 100%14.703%7.941%43.821%33.154%0.381% RBG 0%0.000%0.000%0.000%0.000%0.000% RBIG 0%0.000%0.000%0.000%0.000%0.000% RBIG-P 0%0.000%0.000%0.000%0.000%0.000% RBIG-T 0%0.000%0.000%0.000%0.000%0.000% RBIG-D 0%0.000%0.000%0.000%0.000%0.000% RBSG 0%0.000%0.000%0.000%0.000%0.000% RBHG 0%0.000%0.000%0.000%0.000%0.000% RBGG 0%0.000%0.000%0.000%0.000%0.000% RBT 0%0.000%0.000%0.000%0.000%0.000% RBD 100%14.696%7.945%43.837%33.145%0.377% Schedule 6.2 (Demand) Page 2 of 10 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2025 Classification Factors Total Allocated Residential E-1 Small Commercial E-2 Medium Commercial E- 4 Large Commercial E- 7 Street/Traffic Lights CLASSIFICATION AND ALLOCATION BY CUSTOMER - DEMAND Schedule 6.2 RBGP 100%14.696%7.945%43.837%33.145%0.377% RBGP-P 0%0.000%0.000%0.000%0.000%0.000% RBGP-T 0%0.000%0.000%0.000%0.000%0.000% RBGP-D 100%14.696%7.945%43.837%33.145%0.377% RBSE 100%14.696%7.945%43.837%33.145%0.377% RBOH 100%14.696%7.945%43.837%33.145%0.377% RBUG 100%14.696%7.945%43.837%33.145%0.377% RBTR 100%14.696%7.945%43.837%33.145%0.377% OM 100%13.942%7.627%43.508%34.623%0.301% OM-P 100%12.624%7.071%42.933%37.205%0.167% OM-T 0%0.000%0.000%0.000%0.000%0.000% OM-D 100%14.696%7.945%43.837%33.145%0.377% OMAG 100%14.877%7.834%43.410%33.391%0.489% OMAG-P 0%0.000%0.000%0.000%0.000%0.000% OMAG-T 0%0.000%0.000%0.000%0.000%0.000% OMAG-D 100%14.877%7.834%43.410%33.391%0.489% OMG 100%12.624%7.071%42.933%37.205%0.167% OMT 0%0.000%0.000%0.000%0.000%0.000% OMD 100%14.696%7.945%43.837%33.145%0.377% OMDLUGT 0% OMDS&E 100%14.696%7.945%43.837%33.145%0.377% MARKET 0% GPLT 100%14.696%7.945%43.837%33.145%0.377% GPLT-P 0%0.000%0.000%0.000%0.000%0.000% GPLT-T 0%0.000%0.000%0.000%0.000%0.000% GPLT-D 100%14.696%7.945%43.837%33.145%0.377% GRSPLT 0% GRSPLT-P 0% GRSPLT-T 0% GRSPLT-D 0% NETPLT 100.0000%14.696%7.945%43.837%33.145%0.377% NETPLT-P 0%0.000%0.000%0.000%0.000%0.000% NETPLT-T 0%0.000%0.000%0.000%0.000%0.000% NETPLT-D 100%14.696%7.945%43.837%33.145%0.377% TOTCST 0% TOTCST-P 0% TOTCST-T 0% TOTCST-D 0% OMP 100%12.624%7.071%42.933%37.205%0.167% Schedule 6.2 (Demand) Page 3 of 10 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2025 Classification Factors Total Allocated Residential E-1 Small Commercial E-2 Medium Commercial E- 4 Large Commercial E- 7 Street/Traffic Lights CLASSIFICATION AND ALLOCATION BY CUSTOMER - DEMAND Schedule 6.2 OMWOP 100%14.876%7.834%43.413%33.389%0.488% OMWOP-P 0%0.000%0.000%0.000%0.000%0.000% OMWOP-T 0%0.000%0.000%0.000%0.000%0.000% OMWOP-D 100%14.876%7.834%43.413%33.389%0.488% UNP 0% LABORRB 0% LABORRR 0% TRANSP 0% ST 0% DC 0% PI 0% PROD 0% OMPT 0%0.00%0.00%0.00%0.000%0.00% NCPplcc 100%6.285%7.640%48.651%37.003%0.421% NCPPplcc 100%6.190%7.637%48.705%37.047%0.421% NCPSplcc 100%5.910%7.627%48.866%37.175%0.423% WEST 100%12.624%7.071%42.933%37.205%0.167% REN 100%12.624%7.071%42.933%37.205%0.167% CALA 100%12.624%7.071%42.933%37.205%0.167% CREDIT 0% CUST SERV 0% SERV 0% RR 0% RR-P 0% RR-T 0% RR-D 0% RBD-ST 100%14.696%7.945%43.837%33.145%0.377% RBD-NoDA 100.0000000%14.696%7.945%43.837%33.145%0.377% DSRE 0% DSMEE 0% GF 100%13.572%7.392%43.134%35.600%0.302% GF-P 100%13.572%7.392%43.134%35.600%0.302% GF-T 100%13.572%7.392%43.134%35.600%0.302% GF-D 100%13.572%7.392%43.134%35.600%0.302% RSR 0% RBD-NoDA Services 100%14.696%7.945%43.837%33.145%0.377% Rcontr 0% Rcontr-P 100%12.624%7.071%42.933%37.205%0.167% Rcontr-D 100%14.826%7.865%43.530%33.322%0.457% Rcontr-T 0% Schedule 6.2 (Demand) Page 4 of 10 February 2024 Prepared By EES Consulting, Inc. City of Palo Alto Test Year: 2025 Classification Factors Total Allocated Residential E-1 Commercial E-2 Commercial E- Commercial E- Lights CP1 0%0.000%0.000%0.000% CP2 0%0.000%0.000%0.000% CPS 0%0.000%0.000%0.000% CP12 0%0.000%0.000%0.000% LF 0% TCP1 0% TCP2 0% TCPS 0% TCP12 0% TAE 0% CPG 0% CPT 0% AE 0% NCP 0% NCPP 0% NCPS 0% kWh 0% kWhP 0% kWhO 0% kWhPJAN 0% kWhPFEB 0% kWhPMAR 0% kWhPAPR 0% kWhPMAY 0% kWhPJUN 0% kWhPJUL 0% kWhPAUG 0% kWhPSEP 0% kWhPOCT 0% kWhPNOV 0% kWhPDEC 0% kWhOJAN 0% kWhOFEB 0% kWhOMAR 0% kWhOAPR 0% CLASSIFICATION AND ALLOCATION BY CUSTOMER - CUSTOMER Schedule 6.2 Schedule 6.2 (Customer) Page 1 of 5 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2025 Classification Factors Total Allocated Residential E-1 Commercial E-2 Commercial E- Commercial E- Lights CLASSIFICATION AND ALLOCATION BY CUSTOMER - CUSTOMER Schedule 6.2 kWhOMAY 0% kWhOJUN 0% kWhOJUL 0% kWhOAUG 0% kWhOSEP 0% kWhOOCT 0% kWhONOV 0% kWhODEC 0% CUST 100%86.444%10.542%2.772%0.235%0.007% CUSTW 100%46.540%7.095%40.298%6.064%0.004% CUSTM 100%84.124%10.259%4.538%1.079%0.000% CUSTMR 100%46.542%7.095%40.299%6.064%0.000% MINSYSP 100%86.444%10.542%2.772%0.235%0.007% MINSYSC 100%86.444%10.542%2.772%0.235%0.007% MINSYST 100%86.444%10.542%2.772%0.235%0.007% 100%DP 0% 100%DC 0% 100%DT 0% DA1 0%0.000%0.000%0.000%0.000%0.000% DA2 0%0.000%0.000%0.000%0.000%0.000% DA3 0%0.000%0.000%0.000%0.000%0.000% DA4 0%0.000%0.000%0.000%0.000%0.000% DA5 0%0.000%0.000%0.000%0.000%0.000% DA6 0%0.000%0.000%0.000%0.000%0.000% DA7 100%15.993%6.399%35.490%41.891%0.226% DA8 100%15.993%6.399%35.490%41.891%0.226% DA9 0%0.000%0.000%0.000%0.000%0.000% DA10 100%100.000%0.000%0.000%0.000%0.000% REV 100%16.225%7.001%40.225%35.228%1.321% REV-P 100%16.225%7.001%40.225%35.228%1.321% REV-T 100%16.225%7.001%40.225%35.228%1.321% REV-D 100%16.225%7.001%40.225%35.228%1.321% OTHER 0% Schedule 6.2 (Customer) Page 2 of 5 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2025 Classification Factors Total Allocated Residential E-1 Commercial E-2 Commercial E- Commercial E- Lights CLASSIFICATION AND ALLOCATION BY CUSTOMER - CUSTOMER Schedule 6.2 RB 100%25.665%3.158%58.418%12.759%0.000% RB-P 0% RB-T 0% RB-D 0% RBG 0%0.000%0.000%0.000%0.000%0.000% RBIG 0%0.000%0.000%0.000%0.000%0.000% RBIG-P 0% RBIG-T 0% RBIG-D 0% RBSG 0%0.000%0.000%0.000%0.000%0.000% RBHG 0%0.000%0.000%0.000%0.000%0.000% RBGG 0%0.000%0.000%0.000%0.000%0.000% RBT 0%0.000%0.000%0.000%0.000%0.000% RBD 100%25.144%3.050%58.864%12.942%0.000% RBGP 100%25.144%3.050%58.864%12.942%0.000% RBGP-P 0% RBGP-T 0% RBGP-D 0% RBSE 0%0.000%0.000%0.000%0.000%0.000% RBOH 0%0.000%0.000%0.000%0.000%0.000% RBUG 0%0.000%0.000%0.000%0.000%0.000% RBTR 0%0.000%0.000%0.000%0.000%0.000% OM 100%28.854%3.752%55.644%11.749%0.001% OM-P 0% OM-T 0% OM-D 0% OMAG 100%33.186%4.716%51.989%10.109%0.001% OMAG-P 0% OMAG-T 0% OMAG-D 0% OMG 0% OMT 0% OMD 100%28.854%3.752%55.644%11.749%0.001% OMDLUGT 0% OMDS&E 100%33.882%4.702%51.281%10.133%0.001% Schedule 6.2 (Customer) Page 3 of 5 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2025 Classification Factors Total Allocated Residential E-1 Commercial E-2 Commercial E- Commercial E- Lights CLASSIFICATION AND ALLOCATION BY CUSTOMER - CUSTOMER Schedule 6.2 MARKET 0% GPLT 100%25.144%3.050%58.864%12.942%0.000% GPLT-P 0% GPLT-T 0% GPLT-D 0% GRSPLT 0% GRSPLT-P 0% GRSPLT-T 0% GRSPLT-D 0% NETPLT 100%25.144%3.050%58.864%12.942%0.000% NETPLT-P 0% NETPLT-T 0% NETPLT-D 0% TOTCST 0% TOTCST-P 0% TOTCST-T 0% TOTCST-D 0% OMP 0% OMWOP 100%33.157%4.710%52.013%10.119%0.001% OMWOP-P 0% OMWOP-T 0% OMWOP-D 0% UNP 0% LABORRB 0% LABORRR 0% TRANSP 0% ST 0% DC 0% PI 0% PROD 0% OMPT 0% NCPplcc 0% NCPPplcc 0% NCPSplcc 0% WEST 0% Schedule 6.2 (Customer) Page 4 of 5 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2025 Classification Factors Total Allocated Residential E-1 Commercial E-2 Commercial E- Commercial E- Lights CLASSIFICATION AND ALLOCATION BY CUSTOMER - CUSTOMER Schedule 6.2 REN 0% CALA 0% CREDIT 100.000000%35.000%50.000%14.000%1.000% CUST SERV 100.000000%16.188%7.502%36.806%39.149%0.355% SERV 100.000000%20.159%2.441%63.455%13.945% RR 100%29.131%9.306%51.253%10.308% RR-P 0% RR-T 0% RR-D 100%29.131%9.306%51.253%10.308% RBD-ST 100%25.144%3.050%58.864%12.942% RBD-NoDA 100.000000%25.144%3.050%58.864%12.942%0.000% DSRE 0% DSMEE 0% GF 100%33.186%4.716%51.989%10.109%0.001% GF-P 100%33.186%4.716%51.989%10.109%0.001% GF-T 100%33.186%4.716%51.989%10.109%0.001% GF-D 100%33.186%4.716%51.989%10.109%0.001% RSR 0% RBD-NoDA Services 100%84.124%10.259%4.538%1.079%0.000% Rcontr 100%33.193%4.659%51.937%10.210%0.001% Rcontr-P 0% Rcontr-D 0% Rcontr-T 0% Schedule 6.2 (Customer) Page 5 of 5 February 2024 Prepared By EES Consulting, Inc. City of Palo Alto Test Year: 2025 Classification Factors Total Allocated Residential E-1 Small Commercial E-2 Medium Commercial E- 4 Large Commercial E- 7 Street/Traffic Lights CP1 0%0.000%0.000%0.000%0.000%0.000% CP2 0%0.000%0.000%0.000%0.000%0.000% CPS 0%0.000%0.000%0.000%0.000%0.000% CP12 0%0.000%0.000%0.000%0.000%0.000% LF 0% TCP1 0% TCP2 0% TCPS 0% TCP12 0% TAE 0% CPG 0% CPT 0% AE 0% NCP 0% NCPP 0% NCPS 0% kWh 0% kWhP 0% kWhO 0% kWhPJAN 0% kWhPFEB 0% kWhPMAR 0% kWhPAPR 0% kWhPMAY 0% kWhPJUN 0% kWhPJUL 0% kWhPAUG 0% kWhPSEP 0% kWhPOCT 0% kWhPNOV 0% kWhPDEC 0% kWhOJAN 0% kWhOFEB 0% kWhOMAR 0% kWhOAPR 0% kWhOMAY 0% kWhOJUN 0% kWhOJUL 0% kWhOAUG 0% kWhOSEP 0% CLASSIFICATION AND ALLOCATION BY CUSTOMER - DIRECT ASSIGNMENT Schedule 6.2 Schedule 6.2 (DA) Page 1 of 4 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2025 Classification Factors Total Allocated Residential E-1 Small Commercial E-2 Medium Commercial E- 4 Large Commercial E- 7 Street/Traffic Lights CLASSIFICATION AND ALLOCATION BY CUSTOMER - DIRECT ASSIGNMENT Schedule 6.2 kWhOOCT 0% kWhONOV 0% kWhODEC 0% CUST 0% CUSTW 0% CUSTM 0% CUSTMR 0% MINSYSP 0% MINSYSC 0% MINSYST 0% 100%DP 0% 100%DC 0% 100%DT 0% DA1 100%0.000%0.000%0.000%0.000%100.000% DA2 100%0.000%0.000%40.000%60.000%0.000% DA3 0%0.000%0.000%0.000%0.000%0.000% DA4 0%0.000%0.000%0.000%0.000%0.000% DA5 0%0.000%0.000%0.000%0.000%0.000% DA6 0%0.000%0.000%0.000%0.000%0.000% DA7 100%15.993%6.399%35.490%41.891%0.226% DA8 100%15.993%6.399%35.490%41.891%0.226% DA9 0%0.000%0.000%0.000%0.000%0.000% DA10 100%100.000%0.000%0.000%0.000%0.000% REV 100%16.225%7.001%40.225%35.228%1.321% REV-P 100%16.225%7.001%40.225%35.228%1.321% REV-T 100%16.225%7.001%40.225%35.228%1.321% REV-D 100%16.225%7.001%40.225%35.228%1.321% OTHER 0% RB 100%0%0%0%0%100% RB-P 0%0%0%0%0%0% RB-T 0%0%0%0%0%0% RB-D 100%0%0%0%0%100% RBG 0%0%0%0%0%0% RBIG 0%0%0%0%0%0% RBIG-P 0%0%0%0%0%0% RBIG-T 0%0%0%0%0%0% RBIG-D 0%0%0%0%0%0% RBSG 0%0%0%0%0%0% RBHG 0%0%0%0%0%0% RBGG 0%0%0%0%0%0% RBT 0%0%0%0%0%0% RBD 100%0%0%0%0%100% Schedule 6.2 (DA) Page 2 of 4 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2025 Classification Factors Total Allocated Residential E-1 Small Commercial E-2 Medium Commercial E- 4 Large Commercial E- 7 Street/Traffic Lights CLASSIFICATION AND ALLOCATION BY CUSTOMER - DIRECT ASSIGNMENT Schedule 6.2 RBGP 100%0%0%0%0%100% RBGP-P 0%0%0%0%0%0% RBGP-T 0%0%0%0%0%0% RBGP-D 100%0%0%0%0%100% RBSE 0%0%0%0%0%0% RBOH 0%0%0%0%0%0% RBUG 0%0%0%0%0%0% RBTR 0%0%0%0%0%0% OM 100%0%0%0%0%100% OM-P 0%0%0%0%0%0% OM-T 0%0%0%0%0%0% OM-D 100%0%0%0%0%100% OMAG 100%0%0%0%0%100% OMAG-P 0%0%0%0%0%0% OMAG-T 0%0%0%0%0%0% OMAG-D 100%0%0%0%0%100% OMG 0%0%0%0%0%0% OMT 0%0%0%0%0%0% OMD 100%0%0%0%0%100% OMDLUGT 0% OMDS&E 100%0%0%0%0%100% MARKET 0% GPLT 100%0%0%0%0%100% GPLT-P 0%0%0%0%0%0% GPLT-T 0%0%0%0%0%0% GPLT-D 100%0%0%0%0%100% GRSPLT 0% GRSPLT-P 0% GRSPLT-T 0% GRSPLT-D 0% NETPLT 100%0%0%0%0%100% NETPLT-P 0%0%0%0%0%0% NETPLT-T 0%0%0%0%0%0% NETPLT-D 100%0%0%0%0%100% TOTCST 0% TOTCST-P 0% TOTCST-T 0% TOTCST-D 0% OMP 0%0%0%0%0%0% OMWOP 100%0%0%0%0%100% OMWOP-P 0%0%0%0%0%0% OMWOP-T 0%0%0%0%0%0% Schedule 6.2 (DA) Page 3 of 4 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Test Year: 2025 Classification Factors Total Allocated Residential E-1 Small Commercial E-2 Medium Commercial E- 4 Large Commercial E- 7 Street/Traffic Lights CLASSIFICATION AND ALLOCATION BY CUSTOMER - DIRECT ASSIGNMENT Schedule 6.2 OMWOP-D 100%0%0%0%0%100% UNP 0% LABORRB 0% LABORRR 0% TRANSP 0% ST 0% DC 0% PI 0% PROD 0% OMPT 0%0%0%0%0%0% NCPplcc 0% NCPPplcc 0% NCPSplcc 0% WEST 0% REN 0% CALA 0% CREDIT 0% CUST SERV 0% SERV 0% RR 0% RR-P 0% RR-T 0% RR-D 0% RBD-ST 100%100.000% RBD-NoDA 0% DSRE 0% DSMEE 0% GF 100%0.000%0.000%0.000%0.000%100.000% GF-P 100%0.000%0.000%0.000%0.000%100.000% GF-T 100%0.000%0.000%0.000%0.000%100.000% GF-D 100%0.000%0.000%0.000%0.000%100.000% RSR 0% RBD-NoDA Services 0% Rcontr 100%100.000% Rcontr-P 100%100.000% Rcontr-D 100%100.000% Rcontr-T 100%100.000% Schedule 6.2 (DA) Page 4 of 4 February 2024 Prepared By EES Consulting, Inc. City of Palo Alto Total Residential E-1 Small Commercial E- 2 Medium Commercial E-4 Large Commercial E- 7 Street/Traffic Lights Number of Customers Jul-24 30,193 26,100 3,183 837 71 2 Aug-24 30,193 26,100 3,183 837 71 2 Sep-24 30,193 26,100 3,183 837 71 2 Oct-24 30,193 26,100 3,183 837 71 2 Nov-24 30,193 26,100 3,183 837 71 2 Dec-24 30,193 26,100 3,183 837 71 2 Jan-25 30,193 26,100 3,183 837 71 2 Feb-25 30,193 26,100 3,183 837 71 2 Mar-25 30,193 26,100 3,183 837 71 2 Apr-25 30,193 26,100 3,183 837 71 2 May-25 30,193 26,100 3,183 837 71 2 Jun-25 30,193 26,100 3,183 837 71 2 Total / Average 30,193 26,100 3,183 837 71 2 Forecast kWh Jul-24 69,728,396 10,047,691 4,823,364 25,354,847 29,344,725 157,769 Aug-24 74,503,529 10,836,529 4,964,387 27,745,735 30,799,109 157,769 Sep-24 75,658,405 9,476,043 4,734,220 28,027,226 33,263,147 157,769 Oct-24 65,340,638 9,558,379 4,333,383 24,447,795 26,843,312 157,769 Nov-24 69,856,019 10,739,687 4,263,783 24,918,097 29,776,683 157,769 Dec-24 65,331,624 10,795,783 4,432,799 23,767,626 26,177,647 157,769 Jan-25 73,125,979 15,252,399 4,560,746 22,602,289 30,552,776 157,769 Feb-25 69,834,775 12,886,886 4,440,722 24,513,210 27,836,188 157,769 Mar-25 64,774,498 12,886,886 4,252,277 21,736,433 25,741,133 157,769 Apr-25 65,881,345 10,293,013 3,917,332 22,881,308 28,631,923 157,769 May-25 67,111,575 10,016,184 4,176,855 24,182,374 28,578,394 157,769 Jun-25 70,797,053 10,263,351 4,337,854 25,078,476 30,959,603 157,769 Total / Average 831,943,836 133,052,833 53,237,722 295,255,415 348,504,639 1,893,227 FORECAST OF REVENUES FROM CURRENT RATES Schedule 7.1 Schedule 7.1 Page 1 of 4 February 2024 Prepared By EES Consulting, Inc. Total Residential E-1 Small Commercial E- 2 Medium Commercial E-4 Large Commercial E- 7 Street/Traffic Lights FORECAST OF REVENUES FROM CURRENT RATES Schedule 7.1 Energy Rates $0.1806 $0.1210 Flat Rate:Flat Rate $/kWh Seasonal Rate:J-24 $0.25991 $0.15795 $0.13992 A-24 $0.25991 $0.15795 $0.13992 S-24 $0.25991 $0.15795 $0.13992 O-24 $0.25991 $0.15795 $0.13992 N-24 $0.18057 $0.13667 $0.09287 D-24 $0.18057 $0.13667 $0.09287 J-25 $0.18057 $0.13667 $0.09287 F-25 $0.18057 $0.13667 $0.09287 M-25 $0.18057 $0.13667 $0.09287 A-25 $0.18057 $0.13667 $0.09287 M-25 $0.25991 $0.15795 $0.13992 J-25 $0.25991 $0.15795 $0.13992 Distribution Charge for $/kWh: Block Rate:1st Block kWh $0.1695 2nd Block kWh $0.24098 % in first block 1st Block $/kWh 50%100%100%100% 2nd Block $/kWh 50% Energy Revenues Jul-24 $11,426,691 $2,062,339 $1,253,640 $4,004,798 $4,105,914 $0 Aug-24 $12,206,396 $2,224,252 $1,290,294 $4,382,439 $4,309,411 $0 Sep-24 $12,256,556 $1,945,005 $1,230,471 $4,426,900 $4,654,179 $0 Oct-24 $10,705,640 $1,961,905 $1,126,290 $3,861,529 $3,755,916 $0 Nov-24 $9,145,203 $2,204,374 $769,911 $3,405,556 $2,765,361 $0 Dec-24 $8,695,758 $2,215,889 $800,431 $3,248,321 $2,431,118 $0 Jan-25 $9,880,656 $3,130,631 $823,534 $3,089,055 $2,837,436 $0 Feb-25 $9,382,326 $2,645,098 $801,861 $3,350,220 $2,585,147 $0 Mar-25 $8,774,229 $2,645,098 $767,834 $2,970,718 $2,390,579 $0 Apr-25 $8,606,280 $2,112,692 $707,353 $3,127,188 $2,659,047 $0 May-25 $10,959,773 $2,055,872 $1,085,606 $3,819,606 $3,998,689 $0 Jun-25 $11,527,069 $2,106,604 $1,127,452 $3,961,145 $4,331,868 $0 Subtotal $123,566,578 $27,309,759 $11,784,676 $43,647,477 $40,824,665 $0 Surcharge/Discounts $0 Total $123,566,578 $27,309,759 $11,784,676 $43,647,477 $40,824,665 $0 Schedule 7.1 Page 2 of 4 February 2024 Prepared By EES Consulting, Inc. Total Residential E-1 Small Commercial E- 2 Medium Commercial E-4 Large Commercial E- 7 Street/Traffic Lights FORECAST OF REVENUES FROM CURRENT RATES Schedule 7.1 Demand kW Jul-24 148,032 20,223 11,639 65,431 50,134 606 Aug-24 151,008 21,377 13,191 65,627 50,284 530 Sep-24 151,269 19,118 12,406 67,977 51,280 487 Oct-24 148,549 18,106 13,961 65,108 50,950 424 Nov-24 157,405 20,712 14,292 70,111 51,892 398 Dec-24 163,545 20,262 11,056 75,010 56,863 353 Jan-25 150,616 28,211 9,431 63,847 48,801 326 Feb-25 146,886 26,483 12,015 58,871 49,127 391 Mar-25 137,130 24,101 11,059 56,143 45,442 386 Apr-25 143,248 22,692 11,104 57,987 51,028 438 May-25 140,778 20,712 11,228 58,321 50,046 471 Jun-25 146,854 22,626 12,552 59,586 51,543 548 Total / Average Total 1,785,322 264,621 143,933 764,019 607,389 5,359 Demand Revenues Rate: $/kVa $0.00 Demand Revenues Rate: $/kW Jul-24 $38.82 $39.08 Aug-24 $38.82 $39.08 Sep-24 $38.82 $39.08 Oct-24 $38.82 $39.08 Nov-24 $24.16 $21.71 Dec-24 $24.16 $21.71 Jan-25 $24.16 $21.71 Feb-25 $24.16 $21.71 Mar-25 $24.16 $21.71 Apr-25 $24.16 $21.71 May-25 $38.82 $39.08 Jun-25 $38.82 $39.08 Schedule 7.1 Page 3 of 4 February 2024 Prepared By EES Consulting, Inc. Total Residential E-1 Small Commercial E- 2 Medium Commercial E-4 Large Commercial E- 7 Street/Traffic Lights FORECAST OF REVENUES FROM CURRENT RATES Schedule 7.1 Jul-24 $4,499,246 $0 $0 $2,540,016 $1,959,231 $0 Aug-24 $4,512,744 $0 $0 $2,547,636 $1,965,108 $0 Sep-24 $4,642,921 $0 $0 $2,638,881 $2,004,041 $0 Oct-24 $4,518,626 $0 $0 $2,527,495 $1,991,130 $0 Nov-24 $2,820,451 $0 $0 $1,693,875 $1,126,576 $0 Dec-24 $3,046,746 $0 $0 $1,812,254 $1,234,492 $0 Jan-25 $2,602,019 $0 $0 $1,542,549 $1,059,470 $0 Feb-25 $2,488,859 $0 $0 $1,422,322 $1,066,538 $0 Mar-25 $2,342,942 $0 $0 $1,356,404 $986,539 $0 Apr-25 $2,508,780 $0 $0 $1,400,962 $1,107,818 $0 May-25 $4,219,820 $0 $0 $2,264,028 $1,955,793 $0 Jun-25 $4,327,409 $0 $0 $2,313,126 $2,014,283 $0 Total $42,530,564 $0 $0 $24,059,546 $18,471,018 $0 $31.49 $30.41 Total Revenues Residential E-1 Small Commercial E- 2 Medium Commercial E-4 Large Commercial E- 7 Street/Traffic Lights Jul-24 $15,925,938 $2,062,339 $1,253,640 $6,544,814 $6,065,144 $0 Aug-24 $16,719,140 $2,224,252 $1,290,294 $6,930,075 $6,274,520 $0 Sep-24 $16,899,478 $1,945,005 $1,230,471 $7,065,781 $6,658,220 $0 Oct-24 $15,224,266 $1,961,905 $1,126,290 $6,389,025 $5,747,047 $0 Nov-24 $11,965,654 $2,204,374 $769,911 $5,099,431 $3,891,937 $0 Dec-24 $11,742,504 $2,215,889 $800,431 $5,060,575 $3,665,610 $0 Jan-25 $12,482,675 $3,130,631 $823,534 $4,631,604 $3,896,907 $0 Feb-25 $11,871,186 $2,645,098 $801,861 $4,772,542 $3,651,684 $0 Mar-25 $11,117,171 $2,645,098 $767,834 $4,327,122 $3,377,118 $0 Apr-25 $11,115,060 $2,112,692 $707,353 $4,528,150 $3,766,865 $0 May-25 $15,179,593 $2,055,872 $1,085,606 $6,083,634 $5,954,481 $0 Jun-25 $15,854,477 $2,106,604 $1,127,452 $6,274,271 $6,346,150 $0 Subtotal $166,097,142 $27,309,759 $11,784,676 $67,707,023 $59,295,683 $0 Surcharge/Discounts $2,224,184 $2,224,184 Total $168,321,326 $27,309,759 $11,784,676 $67,707,023 $59,295,683 $2,224,184 Actual Revenue 2020 $121,767,882 $25,990,767 $0 $78,969,022 $16,808,093 Schedule 7.1 Page 4 of 4 February 2024 Prepared By EES Consulting, Inc. City of Palo Alto Number of Customers / Services Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-20 29,646 25,600 3,146 828 70 2 Aug-20 29,646 25,600 3,146 828 70 2 Sep-20 29,646 25,600 3,146 828 70 2 Oct-20 29,646 25,600 3,146 828 70 2 Nov-20 29,646 25,600 3,146 828 70 2 Dec-20 29,646 25,600 3,146 828 70 2 Jan-21 29,646 25,600 3,146 828 70 2 Feb-21 29,646 25,600 3,146 828 70 2 Mar-21 29,646 25,600 3,146 828 70 2 Apr-21 29,646 25,600 3,146 828 70 2 May-21 29,646 25,600 3,146 828 70 2 Jun-21 29,657 25,600 3,155 830 70 2 Total Average 29,647 25,600 3,147 828 70 2 Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Input Recorded Data Energy Sales (kWh)815,778,523 161,545,337 45,675,813 242,402,726 364,257,301 1,897,346 Total Billing Capacity (kW)1,297,123 0 0 669,694 627,429 0 Avg. Monthly Billing Capacity (kW)108,094 0 0 55,808 52,286 0 Number of Customers 29,647 25,600 3,147 828 70 2 Ratio of NCP to Avg. Billing Capacity 0 0 0 1 1 0 Rate Classes NCP Demand at Meter 143,946 26,353 9,983 56,601 50,402 607 Estimated Based on Recorded Data Annual NCP Load Factor 65%70%52%49%82%36% Rate Classes CP Demand at Input Voltage 129,587 21,580 6,696 48,905 52,406 0 Annual CP Load Factor 72%85%78%57%79%0% Average On-Peak kWh as a % of Total kWh 0 59%59%59%59%59% Average Off-Peak kWh as a % of Total kWh 0 41%41%41%41%41% kWh Sales at the Meter Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-20 73,231,986 14,023,120 3,706,590 20,012,168 35,331,996 158,112 Aug-20 73,849,149 12,251,918 3,952,369 23,388,764 34,097,986 158,112 Sep-20 68,373,227 14,404,467 4,238,732 21,872,119 27,699,797 158,112 Oct-20 70,549,047 11,747,936 3,748,368 20,983,888 33,910,743 158,112 Nov-20 70,794,348 12,875,793 3,843,162 22,652,340 31,264,941 158,112 Dec-20 65,980,397 14,943,618 3,802,946 18,419,856 28,655,865 158,112 Jan-21 73,133,571 17,810,143 4,189,079 19,934,934 31,041,303 158,112 Feb-21 61,492,368 13,177,401 3,776,468 18,167,050 26,213,337 158,112 Mar-21 66,127,244 15,568,887 3,644,218 18,844,923 27,911,104 158,112 Apr-21 64,491,682 12,519,998 3,635,974 18,951,818 29,225,780 158,112 May-21 60,888,633 11,166,525 3,553,485 19,181,670 26,828,841 158,112 Jun-21 66,866,869 11,055,531 3,584,422 19,993,196 32,075,608 158,112 Total Sales 815,778,523 161,545,337 45,675,813 242,402,726 364,257,301 1,897,346 Load Data And Customer Sales -- Recorded Year -- Historic Energy, Demand And Customer Count RECORDED CUSTOMERS AND ENERGY SALES Schedule 8.4 Historic Year By Rate Class Schedule 8.1 Page 1 of 16 February 2024 Prepared By EES Consulting, Inc. City of Palo Alto Metered Demand - kVA Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-20 115,509 0 0 56,986 58,523 0 Aug-20 116,971 0 0 59,892 57,079 0 Sep-20 112,729 0 0 64,300 48,429 0 Oct-20 120,509 0 0 63,081 57,428 0 Nov-20 118,056 0 0 64,070 53,986 0 Dec-20 101,695 0 0 51,203 50,492 0 Jan-21 96,729 0 0 48,603 48,126 0 Feb-21 95,270 0 0 48,287 46,983 0 Mar-21 102,713 0 0 51,730 50,983 0 Apr-21 106,043 0 0 51,216 54,827 0 May-21 95,855 0 0 52,131 43,725 0 Jun-21 115,044 0 0 58,194 56,850 0 Total 1,297,123 0 0 669,694 627,429 0 Individual Load Factor Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-20 66.78%55.70%47.20%81.15%35.00% Aug-20 68.14%50.59%52.49%80.29%40.00% Sep-20 68.84%53.00%45.72%76.88%45.00% Oct-20 70.96%41.72%44.71%79.37%50.00% Nov-20 72.02%41.43%47.52%77.84%55.00% Dec-20 71.61%53.89%48.35%76.28%60.00% Jan-21 72.67%65.00%55.13%86.69%65.00% Feb-21 72.41%55.00%50.57%74.99%60.00% Mar-21 71.87%51.68%48.96%73.58%55.00% Apr-21 63.00%49.00%49.74%71.65%50.00% May-21 65.00%50.00%49.46%82.47%45.00% Jun-21 63.00%48.00%46.18%75.84%40.00% Individual NCP (kW) Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Power Factor:100%100%100%100%100% Jul-20 153,284 28,224 8,944 56,986 58,523 607 Aug-20 155,944 26,758 11,627 59,892 57,079 588 Sep-20 152,074 28,124 10,749 64,300 48,429 472 Oct-20 156,422 22,995 12,479 63,081 57,428 439 Nov-20 154,939 24,030 12,467 64,070 53,986 386 Dec-20 140,844 28,982 9,801 51,203 50,492 366 Jan-21 138,660 32,941 8,662 48,603 48,126 327 Feb-21 129,312 24,459 9,229 48,287 46,983 354 Mar-21 142,993 30,087 9,793 51,730 50,983 399 Apr-21 143,152 26,711 9,974 51,216 54,827 425 May-21 130,074 23,860 9,871 52,131 43,725 488 Jun-21 149,199 23,587 10,037 58,194 56,850 531 Maximum 156,422 32,941 12,479 64,300 58,523 607 RECORDED CUSTOMER DEMAND Schedule 8.5 Schedule 8.1 Page 2 of 16 February 2024 Prepared By EES Consulting, Inc. Group Coincidence Factor Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-20 80.00%80.00%86.88%86.12%100.00% Aug-20 80.00%80.00%86.88%86.12%100.00% Sep-20 80.00%80.00%86.88%86.12%100.00% Oct-20 70.00%80.00%86.88%86.12%100.00% Nov-20 80.00%80.00%88.34%85.06%100.00% Dec-20 90.00%90.00%82.99%83.64%100.00% Jan-21 80.00%80.00%82.50%85.08%100.00% Feb-21 80.00%80.00%82.50%85.08%100.00% Mar-21 80.00%80.00%86.91%80.23%100.00% Apr-21 80.00%80.00%85.76%82.17%100.00% May-21 85.00%85.00%84.76%83.77%100.00% Jun-21 80.00%80.00%86.04%83.68%100.00% Rate Class NCP @ Meter (kW)Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-20 130,254 22,579 7,155 49,510 50,402 607 Aug-20 132,490 21,406 9,301 52,035 49,159 588 Sep-20 129,144 22,499 8,600 55,864 41,709 472 Oct-20 130,784 16,097 9,983 54,805 49,459 439 Nov-20 132,104 19,224 9,974 56,601 45,919 386 Dec-20 119,994 26,084 8,821 42,494 42,230 366 Jan-21 114,650 26,353 6,930 40,096 40,944 327 Feb-21 107,111 19,567 7,383 39,835 39,971 354 Mar-21 118,165 24,070 7,835 44,959 40,903 399 Apr-21 118,745 21,369 7,979 43,922 45,050 425 May-21 109,973 20,281 8,390 44,183 36,630 488 Jun-21 125,071 18,869 8,030 50,071 47,570 531 Maximum 132,490 26,353 9,983 56,601 50,402 607 Rate Class NCP @ Primary Voltage (kW)Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Line Losses:2.85%2.85%2.85%2.85%2.85% Jul-20 134,079 23,242 7,365 50,964 51,882 625 Aug-20 136,380 22,035 9,575 53,563 50,602 605 Sep-20 132,936 23,159 8,852 57,505 42,934 486 Oct-20 134,624 16,570 10,276 56,415 50,912 452 Nov-20 135,984 19,789 10,266 58,263 47,268 398 Dec-20 123,518 26,850 9,080 43,742 43,470 377 Jan-21 118,016 27,127 7,133 41,273 42,146 337 Feb-21 110,256 20,142 7,600 41,005 41,145 365 Mar-21 121,635 24,777 8,065 46,279 42,104 411 Apr-21 122,232 21,996 8,213 45,212 46,373 438 May-21 113,202 20,877 8,637 45,481 37,705 502 Jun-21 128,744 19,423 8,265 51,541 48,967 547 Maximum 136,380 27,127 10,276 58,263 51,882 625 Schedule 8.1 Page 3 of 16 February 2024 Prepared By EES Consulting, Inc. Rate Class NCP @ Input Voltage (kW)Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Line Losses:1.00%1.00%1.00%1.00%1.00% Jul-20 135,433 23,477 7,440 51,478 52,406 631 Aug-20 137,758 22,258 9,671 54,104 51,114 612 Sep-20 134,279 23,393 8,942 58,086 43,368 491 Oct-20 135,984 16,737 10,380 56,985 51,426 457 Nov-20 137,357 19,989 10,370 58,852 47,745 402 Dec-20 124,766 27,121 9,172 44,183 43,909 381 Jan-21 119,208 27,401 7,205 41,690 42,572 340 Feb-21 111,370 20,345 7,677 41,419 41,561 368 Mar-21 122,864 25,027 8,146 46,746 42,529 415 Apr-21 123,466 22,219 8,296 45,668 46,842 442 May-21 114,345 21,088 8,724 45,940 38,086 507 Jun-21 130,044 19,620 8,349 52,062 49,462 552 Maximum 137,758 27,401 10,380 58,852 52,406 631 System Coincidence Factor Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-20 91.92%90.00%95.00%100.00%0.00% Aug-20 66.42%90.00%95.00%100.00%0.00% Sep-20 76.11%85.00%90.00%100.00%0.00% Oct-20 60.19%85.00%90.00%100.00%100.00% Nov-20 81.25%60.00%82.00%100.00%100.00% Dec-20 86.82%90.00%95.00%100.00%100.00% Jan-21 93.28%60.00%72.00%90.00%100.00% Feb-21 88.98%90.00%95.00%100.00%100.00% Mar-21 90.27%80.00%88.00%100.00%100.00% Apr-21 67.71%70.00%80.00%100.00%0.00% May-21 70.75%95.00%95.00%100.00%0.00% Jun-21 87.30%95.00%100.00%100.00%0.00% Coincident Peak (CP) @ Input (kW) Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-20 129,587 21,580 6,696 48,905 52,406 0 Aug-20 126,000 14,784 8,704 51,398 51,114 0 Sep-20 121,049 17,804 7,600 52,277 43,368 0 Oct-20 122,065 10,073 8,823 51,286 51,426 457 Nov-20 118,868 16,241 6,222 48,258 47,745 402 Dec-20 118,065 23,547 8,255 41,974 43,909 381 Jan-21 98,555 25,561 4,323 30,017 38,315 340 Feb-21 106,290 18,104 6,909 39,348 41,561 368 Mar-21 113,189 22,591 6,517 41,137 42,529 415 Apr-21 104,227 15,044 5,807 36,535 46,842 0 May-21 104,938 14,920 8,288 43,643 38,086 0 Jun-21 126,583 17,128 7,931 52,062 49,462 0 Total 1,389,416 217,376 86,075 536,840 546,762 2,362 Peak Month 129,587 21,580 6,696 48,905 52,406 0 Schedule 8.1 Page 4 of 16 February 2024 Prepared By EES Consulting, Inc. City of Palo Alto kWh @ Input Voltage Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-20 76,166,455 14,585,038 3,855,116 20,814,073 36,747,779 164,448 Aug-20 76,808,348 12,742,863 4,110,744 24,325,972 35,464,322 164,448 Sep-20 71,113,001 14,981,666 4,408,582 22,748,554 28,809,752 164,448 Oct-20 73,376,008 12,218,686 3,898,568 21,824,730 35,269,576 164,448 Nov-20 73,631,139 13,391,737 3,997,161 23,560,039 32,517,754 164,448 Dec-20 68,624,288 15,542,422 3,955,333 19,157,955 29,804,130 164,448 Jan-21 76,064,096 18,523,811 4,356,939 20,733,744 32,285,155 164,448 Feb-21 63,956,420 13,705,431 3,927,794 18,895,019 27,263,728 164,448 Mar-21 68,777,020 16,192,746 3,790,245 19,600,055 29,029,526 164,448 Apr-21 67,075,919 13,021,685 3,781,671 19,711,234 30,396,882 164,448 May-21 63,328,493 11,613,977 3,695,876 19,950,296 27,903,896 164,448 Jun-21 69,546,282 11,498,536 3,728,053 20,794,341 33,360,905 164,448 Total Purchases - Bottom Up 848,467,469 168,018,597 47,506,082 252,116,011 378,853,404 1,973,374 Historic Load Reconciliation Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Secondary Line Losses 2.85%2.85%2.85%2.85%2.85% Primary Line Losses 1.00%1.00%1.00%1.00%1.00% Total Jul-20 Aug-20 Sep-20 Oct-20 Dec-20 Recorded Energy Purchases kWh 825,333,010 70,830,000 75,565,000 71,045,000 70,942,000 70,740,000 Bottom-Up Energy Purchases kWh 848,467,469 76,166,455 76,808,348 71,113,001 73,376,008 68,624,288 % Difference -2.73%-7%-2%0%-3%3% Measured System Demand kW 1,498,919 130,922 145,019 140,484 127,402 120,490 CP @ Input Demand kW 1,389,416 129,587 126,000 121,049 122,065 118,065 % Difference 7.9%1.0%15.1%16.1%4.4%2.1% On-Peak Energy Use by Percentage Average Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-20 57%57%57%57%57%57% Aug-20 60%60%60%60%60%60% Sep-20 61%61%61%61%61%61% Oct-20 61%61%61%61%61%61% Nov-20 57%57%57%57%57%57% Dec-20 62%62%62%62%62%62% Jan-21 57%57%57%57%57%57% Feb-21 60%60%60%60%60%60% Mar-21 61%61%61%61%61%61% Apr-21 61%61%61%61%61%61% May-21 57%57%57%57%57%57% Jun-21 62%62%62%62%62%62% Total (Derived)59%59%59%59%59%59% RECORDED kWh AT INPUT Schedule 8.6 Schedule 8.1 Page 5 of 16 February 2024 Prepared By EES Consulting, Inc. On-Peak kWh @ Input Voltage Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-20 43,523,334 8,334,240 2,202,906 11,893,659 20,998,560 93,969 Aug-20 45,943,446 7,622,232 2,458,870 14,550,749 21,213,230 98,366 Sep-20 43,054,796 9,070,530 2,669,140 13,772,929 17,442,633 99,564 Oct-20 44,473,644 7,405,820 2,362,946 13,228,102 21,377,104 99,673 Nov-20 42,019,648 7,642,366 2,281,090 13,445,188 18,557,157 93,847 Dec-20 42,373,311 9,596,950 2,442,292 11,829,427 18,403,100 101,541 Jan-21 43,464,843 10,584,948 2,489,659 11,847,757 18,448,509 93,969 Feb-21 38,255,976 8,197,998 2,349,437 11,302,187 16,307,988 98,366 Mar-21 41,640,495 9,803,768 2,294,773 11,866,696 17,575,694 99,564 Apr-21 40,655,122 7,892,522 2,292,094 11,947,098 18,423,735 99,673 May-21 36,140,158 6,627,838 2,109,154 11,385,189 15,924,131 93,847 Jun-21 42,942,613 7,099,979 2,301,954 12,839,843 20,599,296 101,541 Total On-Peak Energy - Bottom-Up 504,487,387 99,879,191 28,254,316 149,908,824 225,271,136 1,173,919 Off-Peak Energy Use by Percentage Average Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-20 43%43%43%43%43%43% Aug-20 40%40%40%40%40%40% Sep-20 39%39%39%39%39%39% Oct-20 39%39%39%39%39%39% Nov-20 43%43%43%43%43%43% Dec-20 38%38%38%38%38%38% Jan-21 43%43%43%43%43%43% Feb-21 40%40%40%40%40%40% Mar-21 39%39%39%39%39%39% Apr-21 39%39%39%39%39%39% May-21 43%43%43%43%43%43% Jun-21 38%38%38%38%38%38% Total (Derived)41%41%41%41%41%41% Off-Peak kWh @ Input Voltage Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-20 32,643,121 6,250,799 1,652,211 8,920,414 15,749,220 70,478 Aug-20 30,864,902 5,120,631 1,651,874 9,775,223 14,251,092 66,082 Sep-20 28,058,205 5,911,137 1,739,441 8,975,624 11,367,119 64,884 Oct-20 28,902,364 4,812,866 1,535,622 8,596,629 13,892,472 64,775 Nov-20 31,611,490 5,749,372 1,716,070 10,114,850 13,960,597 70,601 Dec-20 26,250,977 5,945,472 1,513,041 7,328,529 11,401,030 62,907 Jan-21 32,599,253 7,938,862 1,867,280 8,885,987 13,836,645 70,478 Feb-21 25,700,444 5,507,432 1,578,357 7,592,832 10,955,740 66,082 Mar-21 27,136,525 6,388,978 1,495,472 7,733,359 11,453,832 64,884 Apr-21 26,420,797 5,129,163 1,489,577 7,764,135 11,973,147 64,775 May-21 27,188,335 4,986,140 1,586,722 8,565,107 11,979,765 70,601 Jun-21 26,603,669 4,398,556 1,426,099 7,954,498 12,761,609 62,907 Total Off-Peak Energy - Bottom-Up 343,980,083 68,139,407 19,251,766 102,207,187 153,582,267 799,455 Schedule 8.1 Page 6 of 16 February 2024 Prepared By EES Consulting, Inc. Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights 0 831,943,836 133,052,833 53,237,722 295,255,415 348,504,639 1,893,227 1,371,408 0 0 764,019 607,389 0 114,284 0 0 63,668 50,616 0 30,193 26,100 3,183 837 71 2 2 0%0%98%94%0% 144,419 22,568 11,434 62,252 47,558 606 3 67%53%54%84%36% 137,082 16,462 9,311 61,491 49,449 367 4 92%65%55%80%59% 3 59%59%59%59%59% 2 41%41%41%41%41% City of Palo Alto Energy Sales (kWh) Total Billing Capacity (kVa) Avg. Monthly Billing Capacity (kVa) Number of Customers Ratio of NCP to Avg. Billing Rate Classes NCP Demand at Meter Annual NCP Load Factor Rate Classes CP Demand at Input Voltage Annual CP Load Factor On-Peak kWh as a % of Total kWh Off-Peak kWh as a % of Total kWh Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Current kWh Forecast: 2022 815,778,523 161,545,337 45,675,813 242,402,726 364,257,301 1,897,346 Forecast Year: 2022 814,734,383 150,839,180 46,559,059 258,128,836 357,314,081 1,893,227 Forecast Year: 2023 810,356,252 158,172,937 52,965,635 261,629,660 335,694,792 1,893,227 Forecast Year: 2024 831,943,836 133,052,833 53,237,722 295,255,415 348,504,639 1,893,227 Forecast Year: 2025 831,943,836 133,052,833 53,237,722 295,255,415 348,504,639 1,893,227 Forecast Year: 2026 836,224,351 133,738,977 53,512,265 296,778,028 350,301,854 1,893,227 Current Customer Forecast: 2022 29,647 25,600 3,147 828 70 2 Forecast Year: 2022 29,683 25,626 3,155 830 70 2 Forecast Year: 2023 30,012 25,944 3,164 832 70 2 Forecast Year: 2024 30,102 26,022 3,173 834 71 2 Forecast Year: 2025 30,193 26,100 3,183 837 71 2 Forecast Year: 2026 30,284 26,178 3,193 840 71 2 Forecast Rate Class Customer Count Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 30,193 26,100 3,183 837 71 2 Aug-24 30,193 26,100 3,183 837 71 2 Sep-24 30,193 26,100 3,183 837 71 2 Oct-24 30,193 26,100 3,183 837 71 2 Nov-24 30,193 26,100 3,183 837 71 2 Dec-24 30,193 26,100 3,183 837 71 2 Jan-25 30,193 26,100 3,183 837 71 2 Feb-25 30,193 26,100 3,183 837 71 2 Mar-25 30,193 26,100 3,183 837 71 2 Apr-25 30,193 26,100 3,183 837 71 2 May-25 30,193 26,100 3,183 837 71 2 Jun-25 30,193 26,100 3,183 837 71 2 Total Average Forecast Customers 30,193 26,100 3,183 837 71 2 Schedule 8.1 FORECAST ENERGY, DEMAND AND CUSTOMER COUNT FORECAST CUSTOMERS AND ENERGY SALES SUMMARY OF Schedule 8.1 Page 7 of 16 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Schedule 8.1 FORECAST CUSTOMERS AND ENERGY SALES Customer Information Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Weighting Factors for: Customers Meters & Services 994.00$ 994.00$ 1,672.00$ 4,698.00$ -$ Customer Billing and Collection 1.00 1.25 27.00 48.00 1.00 Customer Meter Reading 1.00 1.25 27.00 48.00 0.00 Weighted Number of Customers Customers Meters & Services 30,839,588 25,943,400 3,163,902 1,399,464 332,822 - Customer Billing and Collection 56,080 26,100 3,979 22,599 3,400 2 Customer Meter Reading 56,078 26,100 3,979 22,599 3,400 - Provided Services Power Purchased from Utility*1 1 1 1 1 Reg & Shaping from Utility*1 1 1 1 1 Uses Utility Transmission*1 1 1 1 1 Uses Primary Distribution*1 1 1 1 1 Uses Secondary Distribution*1 1 1 1 1 Test Date Forecast Rate Class Sales kWh Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-22 67,689,876 11,430,517 3,842,021 23,573,069 28,686,500 157,769 Aug-22 68,217,175 11,336,143 3,739,407 23,520,212 29,463,644 157,769 Sep-22 73,543,374 12,597,531 4,233,790 26,249,560 30,304,724 157,769 Oct-22 70,184,004 11,053,402 3,972,027 25,015,742 29,985,064 157,769 Nov-22 65,022,004 12,135,523 3,302,030 22,290,316 27,136,366 157,769 Dec-22 69,444,669 15,288,678 3,622,175 21,912,700 28,463,347 157,769 Jan-23 71,077,996 16,288,179 3,826,925 22,656,899 28,148,224 157,769 Feb-23 66,135,441 15,360,803 3,506,239 20,702,276 26,408,354 157,769 Mar-23 80,239,962 15,486,385 4,660,352 20,960,972 38,974,484 157,769 Apr-23 70,916,234 13,739,325 3,847,262 22,331,572 30,840,306 157,769 May-23 62,208,176 11,021,806 3,385,099 21,388,033 26,255,469 157,769 Jun-23 45,677,342 12,434,645 11,028,308 11,028,309 11,028,310 157,769 Total Sales 810,356,252 158,172,937 52,965,635 261,629,660 335,694,792 1,893,227 Forecast Rate Class Sales kWh Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 69,728,396 10,047,691 4,823,364 25,354,847 29,344,725 157,769 Aug-24 74,503,529 10,836,529 4,964,387 27,745,735 30,799,109 157,769 Sep-24 75,658,405 9,476,043 4,734,220 28,027,226 33,263,147 157,769 Oct-24 65,340,638 9,558,379 4,333,383 24,447,795 26,843,312 157,769 Nov-24 69,856,019 10,739,687 4,263,783 24,918,097 29,776,683 157,769 Dec-24 65,331,624 10,795,783 4,432,799 23,767,626 26,177,647 157,769 Jan-25 73,125,979 15,252,399 4,560,746 22,602,289 30,552,776 157,769 Feb-25 69,834,775 12,886,886 4,440,722 24,513,210 27,836,188 157,769 Mar-25 64,774,498 12,886,886 4,252,277 21,736,433 25,741,133 157,769 Apr-25 65,881,345 10,293,013 3,917,332 22,881,308 28,631,923 157,769 May-25 67,111,575 10,016,184 4,176,855 24,182,374 28,578,394 157,769 Jun-25 70,797,053 10,263,351 4,337,854 25,078,476 30,959,603 157,769 Total Sales 831,943,836 133,052,833 53,237,722 295,255,415 348,504,639 1,893,227 Schedule 8.1 Page 8 of 16 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Schedule 8.1 FORECAST CUSTOMERS AND ENERGY SALES City of Palo Alto Billing Demand - kW Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 115,564 0 0 65,431 50,134 0 Aug-24 115,911 0 0 65,627 50,284 0 Sep-24 119,258 0 0 67,977 51,280 0 Oct-24 116,058 0 0 65,108 50,950 0 Nov-24 122,003 0 0 70,111 51,892 0 Dec-24 131,873 0 0 75,010 56,863 0 Jan-25 112,648 0 0 63,847 48,801 0 Feb-25 107,997 0 0 58,871 49,127 0 Mar-25 101,584 0 0 56,143 45,442 0 Apr-25 109,015 0 0 57,987 51,028 0 May-25 108,367 0 0 58,321 50,046 0 Jun-25 111,128 0 0 59,586 51,543 0 Total 1,371,408 0 0 764,019 607,389 0 Individual Load Factor Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 67%56%47%81%35% Aug-24 68%51%52%80%40% Sep-24 69%53%46%77%45% Oct-24 71%42%45%79%50% Nov-24 72%41%48%78%55% Dec-24 72%54%48%76%60% Jan-25 73%65%55%87%65% Feb-25 72%55%51%75%60% Mar-25 72%52%49%74%55% Apr-25 63%49%50%72%50% May-25 65%50%49%82%45% Jun-25 63%48%46%76%40% Individual NCP (kW) Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 148,032 20,223 11,639 65,431 50,134 606 Aug-24 151,008 21,377 13,191 65,627 50,284 530 Sep-24 151,269 19,118 12,406 67,977 51,280 487 Oct-24 148,549 18,106 13,961 65,108 50,950 424 Nov-24 157,405 20,712 14,292 70,111 51,892 398 Dec-24 163,545 20,262 11,056 75,010 56,863 353 Jan-25 150,616 28,211 9,431 63,847 48,801 326 Feb-25 146,886 26,483 12,015 58,871 49,127 391 Mar-25 137,130 24,101 11,059 56,143 45,442 386 Apr-25 143,248 22,692 11,104 57,987 51,028 438 May-25 140,778 20,712 11,228 58,321 50,046 471 Jun-25 146,854 22,626 12,552 59,586 51,543 548 Maximum 163,545 28,211 14,292 75,010 56,863 606 FORECAST CUSTOMER DEMAND Schedule 8.2 Schedule 8.1 Page 9 of 16 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Schedule 8.1 FORECAST CUSTOMERS AND ENERGY SALES Group Coincidence Factor Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 80%80%87%86%100% Aug-24 80%80%87%86%100% Sep-24 80%80%87%86%100% Oct-24 70%80%87%86%100% Nov-24 80%80%88%85%100% Dec-24 90%90%83%84%100% Jan-25 80%80%82%85%100% Feb-25 80%80%82%85%100% Mar-25 80%80%87%80%100% Apr-25 80%80%86%82%100% May-25 85%85%85%84%100% Jun-25 80%80%86%84%100% Rate Class NCP @ Meter (kW) Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 126,119 16,178 9,311 56,846 43,178 606 Aug-24 128,508 17,101 10,553 57,017 43,307 530 Sep-24 128,930 15,294 9,925 59,059 44,165 487 Oct-24 124,714 12,674 11,169 56,566 43,881 424 Nov-24 134,478 16,569 11,434 61,937 44,139 398 Dec-24 138,350 18,236 9,950 62,252 47,558 353 Jan-25 124,629 22,568 7,545 52,672 41,518 326 Feb-25 121,551 21,186 9,612 48,566 41,795 391 Mar-25 113,764 19,281 8,847 48,793 36,457 386 Apr-25 119,132 18,153 8,883 49,729 41,929 438 May-25 118,976 17,605 9,544 49,430 41,925 471 Jun-25 123,088 18,101 10,041 51,268 43,129 548 Maximum 138,350 22,568 11,434 62,252 47,558 606 Rate Class NCP @ Meter (kW) - Winter Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 0 0 0 0 0 0 Aug-24 0 0 0 0 0 0 Sep-24 0 0 0 0 0 0 Oct-24 124,714 12,674 11,169 56,566 43,881 424 Nov-24 134,478 16,569 11,434 61,937 44,139 398 Dec-24 138,350 18,236 9,950 62,252 47,558 353 Jan-25 124,629 22,568 7,545 52,672 41,518 326 Feb-25 121,551 21,186 9,612 48,566 41,795 391 Mar-25 113,764 19,281 8,847 48,793 36,457 386 Apr-25 119,132 18,153 8,883 49,729 41,929 438 May-25 0 0 0 0 0 0 Jun-25 0 0 0 0 0 0 Maximum 138,350 22,568 11,434 62,252 47,558 438 Schedule 8.1 Page 10 of 16 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Schedule 8.1 FORECAST CUSTOMERS AND ENERGY SALES Rate Class NCP @ Meter (kW) - Summer Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 126,119 16,178 9,311 56,846 43,178 606 Aug-24 128,508 17,101 10,553 57,017 43,307 530 Sep-24 128,930 15,294 9,925 59,059 44,165 487 Oct-24 0 0 0 0 0 0 Nov-24 0 0 0 0 0 0 Dec-24 0 0 0 0 0 0 Jan-25 0 0 0 0 0 0 Feb-25 0 0 0 0 0 0 Mar-25 0 0 0 0 0 0 Apr-25 0 0 0 0 0 0 May-25 118,976 17,605 9,544 49,430 41,925 471 Jun-25 123,088 18,101 10,041 51,268 43,129 548 Maximum 128,930 18,101 10,553 59,059 44,165 606 Rate Class NCP @ Primary Voltage (kW) Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Line Losses:2.85%2.85%2.85%2.85%2.85% Jul-24 129,823 16,653 9,585 58,516 44,445 624 Aug-24 132,281 17,603 10,862 58,691 44,579 546 Sep-24 132,716 15,743 10,216 60,793 45,462 501 Oct-24 128,376 13,046 11,497 58,227 45,169 437 Nov-24 138,426 17,056 11,770 63,756 45,435 410 Dec-24 142,413 18,771 10,243 64,080 48,955 364 Jan-25 128,289 23,231 7,766 54,218 42,737 336 Feb-25 125,120 21,808 9,894 49,993 43,022 403 Mar-25 117,104 19,847 9,107 50,226 37,527 397 Apr-25 122,630 18,687 9,144 51,189 43,160 451 May-25 122,469 18,122 9,824 50,882 43,157 485 Jun-25 126,702 18,633 10,336 52,774 44,396 564 Maximum 142,413 23,231 11,770 64,080 48,955 624 NCP @ Primary Voltage (kW) - Winter Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 0 0 0 0 0 0 Aug-24 0 0 0 0 0 0 Sep-24 0 0 0 0 0 0 Oct-24 128,376 13,046 11,497 58,227 45,169 437 Nov-24 138,426 17,056 11,770 63,756 45,435 410 Dec-24 142,413 18,771 10,243 64,080 48,955 364 Jan-25 128,289 23,231 7,766 54,218 42,737 336 Feb-25 125,120 21,808 9,894 49,993 43,022 403 Mar-25 117,104 19,847 9,107 50,226 37,527 397 Apr-25 122,630 18,687 9,144 51,189 43,160 451 May-25 0 0 0 0 0 0 Jun-25 0 0 0 0 0 0 Maximum 142,413 23,231 11,770 64,080 48,955 451 Schedule 8.1 Page 11 of 16 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Schedule 8.1 FORECAST CUSTOMERS AND ENERGY SALES NCP @ Primary Voltage (kW) - Summer Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 129,823 16,653 9,585 58,516 44,445 624 Aug-24 132,281 17,603 10,862 58,691 44,579 546 Sep-24 132,716 15,743 10,216 60,793 45,462 501 Oct-24 0 0 0 0 0 0 Nov-24 0 0 0 0 0 0 Dec-24 0 0 0 0 0 0 Jan-25 0 0 0 0 0 0 Feb-25 0 0 0 0 0 0 Mar-25 0 0 0 0 0 0 Apr-25 0 0 0 0 0 0 May-25 122,469 18,122 9,824 50,882 43,157 485 Jun-25 126,702 18,633 10,336 52,774 44,396 564 Maximum 132,716 18,633 10,862 60,793 45,462 624 Rate Class NCP @ Input Voltage (kW) Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Line Losses:1.00%1.00%1.00%1.00%1.00% Jul-24 131,134 16,822 9,681 59,107 44,894 630 Aug-24 133,618 17,781 10,972 59,284 45,029 551 Sep-24 134,057 15,902 10,320 61,407 45,921 506 Oct-24 129,673 13,178 11,613 58,815 45,625 441 Nov-24 139,825 17,228 11,889 64,400 45,894 414 Dec-24 143,851 18,961 10,346 64,728 49,449 367 Jan-25 129,585 23,466 7,845 54,766 43,169 339 Feb-25 126,384 22,029 9,994 50,498 43,457 407 Mar-25 118,287 20,047 9,199 50,734 37,906 401 Apr-25 123,869 18,875 9,236 51,706 43,596 456 May-25 123,706 18,305 9,923 51,396 43,592 490 Jun-25 127,982 18,821 10,441 53,307 44,844 570 Maximum 143,851 23,466 11,889 64,728 49,449 630 NCP @ Input Voltage (kW) - Winter Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 0 0 0 0 0 0 Aug-24 0 0 0 0 0 0 Sep-24 0 0 0 0 0 0 Oct-24 129,673 13,178 11,613 58,815 45,625 441 Nov-24 139,825 17,228 11,889 64,400 45,894 414 Dec-24 143,851 18,961 10,346 64,728 49,449 367 Jan-25 129,585 23,466 7,845 54,766 43,169 339 Feb-25 126,384 22,029 9,994 50,498 43,457 407 Mar-25 118,287 20,047 9,199 50,734 37,906 401 Apr-25 123,869 18,875 9,236 51,706 43,596 456 May-25 0 0 0 0 0 0 Jun-25 0 0 0 0 0 0 Maximum 143,851 23,466 11,889 64,728 49,449 456 Schedule 8.1 Page 12 of 16 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Schedule 8.1 FORECAST CUSTOMERS AND ENERGY SALES NCP @ Input Voltage (kW) - Summer Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 131,134 16,822 9,681 59,107 44,894 630 Aug-24 133,618 17,781 10,972 59,284 45,029 551 Sep-24 134,057 15,902 10,320 61,407 45,921 506 Oct-24 0 0 0 0 0 0 Nov-24 0 0 0 0 0 0 Dec-24 0 0 0 0 0 0 Jan-25 0 0 0 0 0 0 Feb-25 0 0 0 0 0 0 Mar-25 0 0 0 0 0 0 Apr-25 0 0 0 0 0 0 May-25 123,706 18,305 9,923 51,396 43,592 490 Jun-25 127,982 18,821 10,441 53,307 44,844 570 Maximum 134,057 18,821 10,972 61,407 45,921 630 System Coincidence Factor Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 92%90%95%100%0% Aug-24 66%90%95%100%0% Sep-24 76%85%90%100%0% Oct-24 60%85%90%100%100% Nov-24 81%60%82%100%100% Dec-24 87%90%95%100%100% Jan-25 93%60%72%90%100% Feb-25 89%90%95%100%100% Mar-25 90%80%88%100%100% Apr-25 68%70%80%100%0% May-25 71%95%95%100%0% Jun-25 87%95%100%100%0% Coincident Peak (CP) @ Input (kW) Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 125,221 15,462 8,713 56,151 44,894 0 Aug-24 123,035 11,811 9,875 56,320 45,029 0 Sep-24 122,062 12,103 8,772 55,267 45,921 0 Oct-24 116,802 7,931 9,871 52,934 45,625 441 Nov-24 120,247 13,998 7,133 52,808 45,894 414 Dec-24 137,082 16,462 9,311 61,491 49,449 367 Jan-25 105,219 21,890 4,707 39,432 38,852 339 Feb-25 120,433 19,602 8,995 47,973 43,457 407 Mar-25 108,408 18,096 7,359 44,646 37,906 401 Apr-25 104,206 12,780 6,465 41,365 43,596 0 May-25 114,797 12,952 9,427 48,826 43,592 0 Jun-25 124,500 16,431 9,919 53,307 44,844 0 Total CP Demand - Bottom Up 1,422,013 179,517 100,547 610,518 529,061 2,370 Peak Month 137,082 16,462 9,311 61,491 49,449 367 Schedule 8.1 Page 13 of 16 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Schedule 8.1 FORECAST CUSTOMERS AND ENERGY SALES City of Palo Alto kWh @ Input Voltage Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 72,895,620 10,504,203 5,042,511 26,506,830 30,677,986 164,091 Aug-24 77,887,708 11,328,881 5,189,941 29,006,347 32,198,449 164,091 Sep-24 79,095,056 9,906,582 4,949,317 29,300,627 34,774,439 164,091 Oct-24 68,308,507 9,992,659 4,530,268 25,558,567 28,062,923 164,091 Nov-24 73,029,041 11,227,639 4,457,506 26,050,236 31,129,570 164,091 Dec-24 68,299,083 11,286,284 4,634,201 24,847,494 27,367,013 164,091 Jan-25 76,447,570 15,945,383 4,767,961 23,629,212 31,940,925 164,091 Feb-25 73,006,833 13,472,395 4,642,484 25,626,954 29,100,910 164,091 Mar-25 67,716,644 13,472,395 4,445,476 22,724,016 26,910,666 164,091 Apr-25 68,873,780 10,760,670 4,095,314 23,920,907 29,932,798 164,091 May-25 70,159,906 10,471,264 4,366,628 25,281,086 29,876,837 164,091 Jun-25 74,012,830 10,729,661 4,534,942 26,217,902 32,366,235 164,091 Total Purchases - bottom up 869,732,579 139,098,013 55,656,547 308,670,178 364,338,751 1,969,090 growth in Purchases against Recorded (bottom-up)-17%17%22%-4%0% On-Peak Energy Use by Percentage Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 57%57%57%57%57%57% Aug-24 60%60%60%60%60%60% Sep-24 61%61%61%61%61%61% Oct-24 61%61%61%61%61%61% Nov-24 57%57%57%57%57%57% Dec-24 62%62%62%62%62%62% Jan-25 57%57%57%57%57%57% Feb-25 60%60%60%60%60%60% Mar-25 61%61%61%61%61%61% Apr-25 61%61%61%61%61%61% May-25 57%57%57%57%57%57% Jun-25 62%62%62%62%62%62% Total 59%59%59%59%59%59% On-Peak kWh @ Input Voltage Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 41,654,301 6,002,353 2,881,411 15,146,637 17,530,135 93,765 Aug-24 46,589,073 6,776,449 3,104,399 17,350,347 19,259,726 98,152 Sep-24 47,887,467 5,997,861 2,996,524 17,739,830 21,053,905 99,347 Oct-24 41,402,201 6,056,611 2,745,823 15,491,202 17,009,108 99,456 Nov-24 41,676,045 6,407,363 2,543,799 14,866,289 17,764,951 93,643 Dec-24 42,172,507 6,968,920 2,861,471 15,342,536 16,898,258 101,321 Jan-25 43,683,970 9,111,573 2,724,527 13,502,297 18,251,808 93,765 Feb-25 43,669,543 8,058,606 2,776,934 15,328,940 17,406,911 98,152 Mar-25 40,998,499 8,156,753 2,691,478 13,758,073 16,292,847 99,347 Apr-25 41,744,817 6,522,107 2,482,195 14,498,607 18,142,451 99,456 May-25 40,038,693 5,975,717 2,491,937 14,427,352 17,050,044 93,643 Jun-25 45,700,564 6,625,224 2,800,182 16,188,719 19,985,119 101,321 Total 517,217,679 82,659,536 33,100,680 183,640,829 216,645,263 1,171,371 FORECAST kWh AT INPUT Schedule 8.3 Schedule 8.1 Page 14 of 16 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Schedule 8.1 FORECAST CUSTOMERS AND ENERGY SALES Off-Peak Energy Use by Percentage Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 43%43%43%43%43%43% Aug-24 40%40%40%40%40%40% Sep-24 39%39%39%39%39%39% Oct-24 39%39%39%39%39%39% Nov-24 43%43%43%43%43%43% Dec-24 38%38%38%38%38%38% Jan-25 43%43%43%43%43%43% Feb-25 40%40%40%40%40%40% Mar-25 39%39%39%39%39%39% Apr-25 39%39%39%39%39%39% May-25 43%43%43%43%43%43% Jun-25 38%38%38%38%38%38% Total 41%41%41%41%41%41% Off-Peak kWh @ Input Voltage Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 31,241,320 4,501,850 2,161,099 11,360,194 13,147,851 70,325 Aug-24 31,298,635 4,552,432 2,085,542 11,655,999 12,938,724 65,939 Sep-24 31,207,589 3,908,721 1,952,793 11,560,798 13,720,534 64,743 Oct-24 26,906,306 3,936,048 1,784,445 10,067,364 11,053,815 64,634 Nov-24 31,352,997 4,820,276 1,913,707 11,183,948 13,364,619 70,448 Dec-24 26,126,576 4,317,363 1,772,729 9,504,959 10,468,755 62,770 Jan-25 32,763,601 6,833,810 2,043,434 10,126,915 13,689,116 70,325 Feb-25 29,337,289 5,413,788 1,865,550 10,298,014 11,693,999 65,939 Mar-25 26,718,145 5,315,641 1,753,998 8,965,943 10,617,819 64,743 Apr-25 27,128,964 4,238,562 1,613,119 9,422,300 11,790,347 64,634 May-25 30,121,213 4,495,547 1,874,691 10,853,734 12,826,793 70,448 Jun-25 28,312,267 4,104,437 1,734,760 10,029,183 12,381,116 62,770 Total Off-Peak Energy 352,514,901 56,438,477 22,555,867 125,029,350 147,693,488 797,720 Summary of Future Test Period Seasonal Load Data Power Supply - System kWh @ Input Voltage- Winter Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 0 0 0 0 0 0 Aug-24 0 0 0 0 0 0 Sep-24 0 0 0 0 0 0 Oct-24 68,308,507 9,992,659 4,530,268 25,558,567 28,062,923 164,091 Nov-24 73,029,041 11,227,639 4,457,506 26,050,236 31,129,570 164,091 Dec-24 68,299,083 11,286,284 4,634,201 24,847,494 27,367,013 164,091 Jan-25 76,447,570 15,945,383 4,767,961 23,629,212 31,940,925 164,091 Feb-25 73,006,833 13,472,395 4,642,484 25,626,954 29,100,910 164,091 Mar-25 67,716,644 13,472,395 4,445,476 22,724,016 26,910,666 164,091 Apr-25 68,873,780 10,760,670 4,095,314 23,920,907 29,932,798 164,091 May-25 0 0 0 0 0 0 Jun-25 0 0 0 0 0 0 Total Winter 495,681,459 86,157,423 31,573,209 172,357,386 204,444,804 1,148,636 Schedule 8.1 Page 15 of 16 February 2024 Prepared By EES Consulting, Inc.City of Palo Alto Schedule 8.1 FORECAST CUSTOMERS AND ENERGY SALES -System kWh @ Input Voltage- Summer Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 72,895,620 10,504,203 5,042,511 26,506,830 30,677,986 164,091 Aug-24 77,887,708 11,328,881 5,189,941 29,006,347 32,198,449 164,091 Sep-24 79,095,056 9,906,582 4,949,317 29,300,627 34,774,439 164,091 Oct-24 0 0 0 0 0 0 Nov-24 0 0 0 0 0 0 Dec-24 0 0 0 0 0 0 Jan-25 0 0 0 0 0 0 Feb-25 0 0 0 0 0 0 Mar-25 0 0 0 0 0 0 Apr-25 0 0 0 0 0 0 May-25 70,159,906 10,471,264 4,366,628 25,281,086 29,876,837 164,091 Jun-25 74,012,830 10,729,661 4,534,942 26,217,902 32,366,235 164,091 Total Summer 374,051,121 52,940,590 24,083,338 136,312,792 159,893,946 820,454 0 0 0 0 0 CP @ Input Voltage- Winter Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 0 0 0 0 0 0 Aug-24 0 0 0 0 0 0 Sep-24 0 0 0 0 0 0 Oct-24 116,802 7,931 9,871 52,934 45,625 441 Nov-24 120,247 13,998 7,133 52,808 45,894 414 Dec-24 137,082 16,462 9,311 61,491 49,449 367 Jan-25 105,219 21,890 4,707 39,432 38,852 339 Feb-25 120,433 19,602 8,995 47,973 43,457 407 Mar-25 108,408 18,096 7,359 44,646 37,906 401 Apr-25 104,206 12,780 6,465 41,365 43,596 0 May-25 0 0 0 0 0 0 Jun-25 0 0 0 0 0 0 Total Winter 812,397 110,759 53,841 340,648 304,779 2,370 CP @ Input Voltage- Summer Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/Traffic Lights Jul-24 125,221 15,462 8,713 56,151 44,894 0 Aug-24 123,035 11,811 9,875 56,320 45,029 0 Sep-24 122,062 12,103 8,772 55,267 45,921 0 Oct-24 0 0 0 0 0 0 Nov-24 0 0 0 0 0 0 Dec-24 0 0 0 0 0 0 Jan-25 0 0 0 0 0 0 Feb-25 0 0 0 0 0 0 Mar-25 0 0 0 0 0 0 Apr-25 0 0 0 0 0 0 May-25 114,797 12,952 9,427 48,826 43,592 0 Jun-25 124,500 16,431 9,919 53,307 44,844 0 Total Summer 609,616 68,758 46,706 269,870 224,281 0 Schedule 8.1 Page 16 of 16 February 2024 Electric Cost of Service and Rate Study DRAFT 8 City of Palo Alto Add Date PREPARED BY EES CONSULTING February 8, 2024 16701 NE 80th Street  Suite 102  Redmond, WA 98052  425-889-2700  Fax 866-611-3791  www.eesconsulting.com Georgia  Texas  Alabama  New Hampshire  Wisconsin  Florida  Maine  Washington  California Amber Gschwend, Managing Director amber.gschwend@gdsassociates.com February 8, 2024 Mr. Micah Babbitt City of Palo Alto 250 Hamilton Avenue Palo Alto, CA 94301 SUBJECT: Electric Cost of Service and Rate Study – DRAFT 8 Dear Mr. Babbitt: Please find attached the draft report for the Electric Cost of Service and Rate Study performed for the City of Palo Alto (City). We appreciate all of the help you and your staff have provided in conjunction with this study. Please feel free to contact me directly with any questions or comments. Very truly yours, Amber Gschwend Managing Director, EES Consulting CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING, A GDS ASSOCIATES COMPANY ● P a g e | i Contents 1 EXECUTIVE SUMMARY...................................................................................................1 1.1 Revenue Requirement........................................................................................................................................1 1.1.1 Rate Classes...................................................................................................................................2 1.2 Cost of Service Analysis......................................................................................................................................2 1.3 Current Rate Design Overview........................................................................................................................4 1.3.1 Rate Design – Distribution...........................................................................................................5 1.3.2 Rate Design – Commodity............................................................................................................6 1.3.3 Customer Charge and Minimum Bill Recommendation...........................................................6 1.4 Recommendation.................................................................................................................................................6 2 OVERVIEW OF RATE SETTING PRINCIPLES..................................................................9 2.1 Overview and Organization of Report..........................................................................................................9 2.2 Overview of Revenue requirement..............................................................................................................10 2.3 Cost of Service Overview.................................................................................................................................10 2.4 Rate Design Analysis.........................................................................................................................................10 3 DEVELOPMENT OF THE REVENUE REQUIREMENTS.................................................12 3.1 Overview of the City’s Revenue Requirement Methodology............................................................12 3.2 Power Supply Costs (Commodity)...............................................................................................................12 3.3 Other Operations and Maintenance Costs...............................................................................................13 3.4 General Fund Transfer......................................................................................................................................13 3.5 Rate-Funded Capital Improvement Program (CIP)...............................................................................13 3.6 Transfer from Reserves....................................................................................................................................13 3.7 Miscellaneous Revenues..................................................................................................................................14 3.8 Summary of Revenue Requirement............................................................................................................14 3.9 Recommendation...............................................................................................................................................14 4 COST OF SERVICE ANALYSIS.......................................................................................15 4.1 Rate Classes..........................................................................................................................................................15 4.2 COSA General Principles.................................................................................................................................15 4.3 Functionalization of Costs..............................................................................................................................16 4.4 Classification and Allocation of Costs........................................................................................................17 4.5 Cost of Service Results.....................................................................................................................................26 CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING, A GDS ASSOCIATES COMPANY ● P a g e | ii 5 RATE DESIGN................................................................................................................29 5.1 Customer Charge and Minimum Bill..........................................................................................................30 5.2 Residential E-1.....................................................................................................................................................30 5.2.1 E-1 Bill Impacts...........................................................................................................................31 5.2.2 Bill Comparison with PG&E.......................................................................................................34 5.2.3 Rate Impacts for Low-Income E-1 (RAP)..................................................................................34 5.3 Small Commercial E-2......................................................................................................................................37 5.4 Medium Commercial E-4................................................................................................................................38 5.5 E-4 TOU..................................................................................................................................................................39 5.6 Large Commercial E-7......................................................................................................................................41 5.6.1 E-7 TOU........................................................................................................................................42 5.7 Public Benefits Charge.....................................................................................................................................44 5.8 Street Lighting and Traffic Signals...............................................................................................................44 6 TECHNICAL APPENDIX................................................................................................45 CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 1 1 Executive Summary The City of Palo Alto (City) retained EES Consulting (EES), a GDS Associates Company, to perform an electric cost of service analysis (COSA) and rate study as part of its ongoing efforts to maintain fiscally prudent and fair, cost-based rates for its electric customers. The purpose of this report is to discuss the data inputs, assumptions and results that were part of developing the rate study. A comprehensive rate study generally consists of three separate, yet interrelated analyses. These three analyses are the revenue requirement, the COSA, and the rate design. 1.1 REVENUE REQUIREMENT A revenue requirement analysis compares the overall revenues of the utility to its expenses and helps determine whether an overall adjustment to rate levels is required. For this analysis, a “cash basis” method was used for determining the City’s revenue requirement. Recorded annual operating expenses for Fiscal Year (FY) 2021-22 as well as the FY 2022-23, FY 2023-24, and FY 2024-25 approved and budget forecasts provided by the City were used to determine the revenue requirement. The study relies on the proposed FY2024-25 budget for the revenue requirement study. If the City’s rates currently in effect remain unchanged, FY 2024-25 revenues from all sources would equal $219.3 million, while budgeted expenses and reserve contributions are $215.5 million.1 The revenue adjustment necessary to avoid surplus funds is a 2.2% decrease. Table 1.1 summarizes the FY 2024-25 revenue requirement. TABLE 1.1: SUMMARY OF THE REVENUE REQUIREMENT – FY2024-25 Power Supply (Commodity)$115,533,652 Distribution $28,005,465 Customer Accounts and Services $12,608,722 Administration and General $7,698,473 Capital Projects Funded from Rates $6,500,000 Debt Service $4,770,582 General Fund Transfer $15,121,000 Reserve Contribution $25,333,578 Total Expenses $215,571,473 Other Revenues $50,984,335 Total Revenue Required from Rates (Revenue Requirement)$164,587,138 Revenue Based on Rates Currently in Effect $168,321,326 Additional Rate Revenue Needed (Surplus)($3,734,187) Net Required Rate Revenue Increase (Decrease)(2.2%) 1 Expenses exclude capital expenses reimbursed by connection fees or other direct reimbursement agreements. CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 2 1.1.1 Rate Classes Part of the revenue requirement analysis includes an analysis of revenue from current retail rates ($168.3 million in Table 1.1). These revenues are calculated for each rate class to later determine if each class is collecting its assigned revenue goal (determined by the COSA). The following rate classes are modeled in the Revenue Requirement Study and COSA: E-1 Residential: All residential customers, excluding master-metered multifamily customers. E-2 Small Commercial: Electric service for small commercial customers and master-metered multifamily customers. Any customer with energy usage over 8,000 kWh per month for three consecutive months would be moved to E-4 (see below), while any E-4 customer with energy usage below 6,000 kWh per month for 12 consecutive months would be switched to E-2. When analyzing customer load data this study used the rate schedule designation for each customer in the utility billing system to determine whether the customer currently fell into the E-2 or E-4 class. E-4 Medium Commercial: Demand metered electric service for commercial customers with a maximum demand below 1,000 kilowatts per month and usage over 8,000 kWh per month. E-7 Large Commercial: Demand metered electric service for commercial customers with a maximum demand of at least 1,000 kilowatts per month per site, and who have sustained this demand level for at least 3 consecutive months during previous 12-month period. Street and Traffic Lights: This class applies to all street and highway lighting installations that the City of Palo Alto Utilities Department elects to operate and maintain, generally lights owned by the City, the County, or another government entity and located on public streets. For purposes of the analysis in this study, customers are assigned to a customer class without regard to whether they participate in Palo Alto Green, Net Energy Metering, Time of Use Metering or Low Income programs. Master-metered multi-family customers are treated as commercial customers rather than residential customers. 1.2 COST OF SERVICE ANALYSIS A COSA is concerned with the equitable allocation of the revenue requirement to the various customer classes of service. The revenue requirement shown in Table 1-1 for the City was functionalized, classified and allocated. Specifically: •Functionalization is the attribution of each cost line-item to Power Supply (Commodity) (purchase or production of electric energy), Transmission (transmitting electric energy via power lines rated CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 3 for 115 kiloVolts (kV) and above),2 Distribution (moving electric energy from supply or transmission infrastructure to end users via power lines rated for less than 115 kV), and Customer (primarily costs associated with metering and billing). The City does not own any power lines that would be categorized as Transmission, so there were no costs allocated to this function. •Classification is the determination of whether the costs associated with a functionalized line item are most appropriately allocated based on energy use (kWh), demand (kW-- the maximum usage of energy over a specified period of time), or customer (simply having a service account). •Allocation is the process of using the classification for each functionalized line item to assign costs to each customer class. For example, a cost item classified as “energy use” might be allocated based on an annual kWh allocator. This means that the line-item cost is directly correlated to the quantity of energy used by each customer class annually. Another example of an energy-based allocator for energy classified costs would be kWh used in the month of January. This process is described in more detail in the section titled “Cost of Service Analysis.” Table 1-2 shows the results of the COSA. It shows the revenues that would be realized in FY 2024-25 without any rate changes (i.e. keeping the rates currently in effect), the share of the FY 2024-25 revenue requirement that should be allocated to each rate class as determined by the COSA, and the surplus/(deficiency) in revenue if current rates are left unchanged. Without a rate change, FY 2024-25 revenues will be slightly more than allocated FY 2024-25 costs for some classes of service. The variance between revenues and costs is greater for some classes than others. The last column of Table 1-2 shows the increase or decrease in revenue required for each rate class. The results of the COSA are summarized in Table 1.2 and the COSA methodology is described in more detail below in the “Cost of Service Analysis” section of this report. TABLE 1.2: SUMMARY OF COST OF SERVICE ANALYSIS FOR FY 2024-25 TEST YEARS Projected Revenues under Current Rates Net Revenue Requirement Projected Surplus/ (Deficiency) in Revenue Based on Current Rates Revenue Increase/ (Decrease) Needed3 Residential E-1 $27,309,759 $27,852,514 -$542,755 2.0% Small Commercial E-2 $11,784,676 $11,067,556 $717,121 -6.1% Medium Commercial E-4 $67,707,023 $65,186,601 $2,520,422 -3.7% Large Commercial E-7 $59,295,683 $58,473,708 $821,975 -1.4% Street and Traffic Lighting $2,224,184 $2,006,759 $217,425 -9.8% TOTAL $168,321,326 $164,587,138 $3,734,187 -2.2% 2 Note that the Transmission function is for costs associated with moving electric energy over CPAU-owned transmission lines. Payments for transmission service on lines owned by other utilities are included in the Power Supply (Commodity) function. 3 Projected FY 2024-25 revenue surplus/(deficiency) divided by projected FY 2024-25 revenue based on rates currently in effect. CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 4 The projected cost of service allocation has changed across rate classes since the study completed in 2016. The primary drivers for the changes include the following: 1. Updated electric usage information (more detail provided in Section 4.4 Cost of Service Results). 2. Increase in Residential usage results in more costs assigned to residential class. a. Decreased Commercial usage, yielding Residential contributing a greater percentage of total energy usage. b. Increased residential usage as a class is due to higher average electric usage. Average residential usage increased from 457 kWh/mo in 2019 to 526 kWh/mo in FY2020-2021. The increased average use may be from multiple factors including increased adoption of electric vehicles and air conditioning, electrification, or the work from home trend beginning at the start of the 2020 pandemic. 3. The current E-1 (residential) rate structure includes a two-tier energy rate. Tier 1 energy rates apply to kWh usage up to 330 kWh per month. Tier 2 energy rates apply to usage above 330 kWh per month. COSA. The ratio of the Tier 2 rate to the Tier 1 rate has declined over time due to changes in the utility’s costs, but this means that the increase in Tier 2 usage relative to Tier 1 usage has not resulted in as significant an increase in residential rate revenue in recent years than would otherwise be expected. This results in an even greater increase needed for the residential class than would be required just based on the average residential usage increase alone. 4. Streetlights have lower expenses due to newer LED bulbs requiring less in operations and maintenance costs. 1.3 EXISTING RATES OVERVIEW The rates for residential and commercial customers are designed to take into account differences in energy costs for various generating resources as well as the impacts seasonal changes in energy use and peak demand have on the utility’s distribution capacity needs. The E-1 (Residential) rate is an inclining 2-tier metered rate. Electric use below a certain threshold is charged at one rate per kWh and each kWh used in excess of that threshold is charged at a higher rate. The rates at each tier are comprised of a Commodity rate (which captures Power Supply charges and purchased transmission service) and a Distribution rate. In addition, E-1 customers pay a separate “public benefits charge” on a per kWh basis for all energy consumed, regardless of tier. The E-2 (Small Commercial) is a seasonal metered rate. For purposes of this rate, the year is divided into two seasons, each of which has a different rate per kWh used. The summer season (period) is defined as May 1 through October 31. The winter period is November 1 through April 30. The higher rate that is applicable during the summer reflects the higher cost of energy during summer months, and the cost of the extra infrastructure needed to meet the City’s seasonal non-residential peak, which occurs in the summer (unlike the residential class, which peaks in the winter). Due to the diversity of usage characteristics within the E-2 customer class, the seasonal structure better captures these seasonal distribution cost variations than a tiered rate structure would. The rates for each season are comprised of a “commodity” rate and a “distribution” rate. Additionally, E-2 customers pay the “public benefits charge” at the same rate as is charged to E-1 customers. The E-4 (Medium Commercial) and E-7 (Large Commercial) rates are seasonal metered rates, but for each season there is both an Energy Charge (measuring consumption in kWh) and a Demand Charge (measuring, in kW, the peak energy delivered in the highest 15-minute period of the day). Because the infrastructure costs of meeting the peak demand are collected through the Demand Charge, the rate CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 5 variations between seasons only reflect seasonal variation in the utility’s costs. The Energy Charge and the Demand Charge for each season are each comprised of a “commodity” rate and a “distribution” rate. Additionally, E-4 and E-7 customers pay the “public benefits charge” at the same rate as is charged to other customers TOU rates are made available to E-4 and E-7 customers; these rates reflect both seasonal and hourly demand and energy cost of service. TOU rates are applied to electricity usage and demand as measured during 3 periods: peak, mid-peak, and off peak. TOU rates differ between seasons as well. Customers on the regular E-4 or E-7 rate schedules may opt to be billed according to the TOU rate schedule if desired. TOU rates are meant to reflect the hourly and seasonally varying costs of providing electric service and need to be adjusted as those costs change over time. 1.4 RATE DESIGN 1.4.1 Distribution Rates The allocation of distribution costs is based on an analysis of the average and excess monthly energy and capacity costs associated with that rate class: the ‘Average and Excess’ method. The Average and Excess method compares the average capacity and energy used against the maximum capacity and energy used over the season (the “excess”). This captures the level of system capacity required to serve the customer during peak times as opposed to average times. As mentioned, the distribution rate design for E-1 consists of a 2-tier rate. The Tier 1 distribution rate recovers the cost of providing distribution capacity to each customer. The Tier 1 rate includes costs associated with the capacity requirements during the lower usage months: May through October. This level of capacity is used year-round. The additional costs associated with the distribution capacity needed to serve higher winter demands is collected through the Tier 2 distribution rate. For E-2 costs associated with demand-related system costs (such as transformers or lines) were separated into seasons using the average and excess demand information from the COSA. The methodology assigns costs associated with average demand to both seasons, while costs related to the distribution capacity required to serve peak demands is allocated to the summer season.4 For the E-4 and E-7 rates the demand-related system costs are recovered through demand charges. The recommended rate design for each rate class includes a monthly customer charge. This customer charge is based on a portion of the utility’s fixed costs for metering and billing. The customer charge ensures that even for customers who consume zero or negative energy, the customer charge would recover the meter reading and billing costs. 4 Summer is May 1-October 31. Commercial customers have higher usage during summer whereas residential customers have higher usage during winter. CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 6 1.4.2 Commodity Rates The City purchases wholesale electricity from a variety of resources including, for example, hydropower, wind resources, or market transactions. Each resource provides benefit to the utility and its ratepayers in the form of energy, capacity, or renewable attributes. All California utilities are required to meet capacity requirements (known as resource adequacy) determined by the CPUC (California Public Utility Commission) and the CEC (California Energy Commission). These requirements ensure that the grid, as a whole, can meet electric demands across various electric usage scenarios. The City’s capacity costs are directly impacted by how and when electric customers consume electricity. Lastly, the City does not own its own transmission lines to transfer energy from the generators it contracts with to the City’s distribution system and therefore purchases transmission services from others. The commodity rates reflect the cost of providing energy, capacity, renewable energy, and purchased transmission service to end-use customers. In the case of E-1, the lower Tier 1 commodity rate recovers costs associated with lower cost energy resources. The higher Tier 2 commodity rate recovers higher cost resources. The current rate design for non-residential classes remains largely the same in the proposals. Commodity rates for rate classes E-2 (Small Commercial), E-4 (Medium Commercial), and E-7 (Large Commercial), are determined such that the costs for each generating resource are assigned to the season in which the costs are incurred. Demand rates are calculated by allocating average capacity costs to both summer and winter rates. Because summer peaks drive capacity costs for the utility, the costs of meeting capacity requirements are allocated to the summer (peak demand) season. 1.5 RECOMMENDATION Based on the projected revenue requirement and COSA analysis, the following observations can be made for the City: The City needs a small rate decrease to match FY 2024-25 revenue and expenses. Revenues for each rate class should be aligned with the costs allocated to that rate class. Rate design recommendations include: o Adjust the E-1 Tier 1 quantity of kWh for increased average usage within this class, as discussed in Section 5.1. o Implement a monthly customer charge for all classes to recover billing and metering costs. o Adjust TOU periods for optional TOU rates to better align with marginal energy and system peak demand costs. o Consider additional rate assistance for low-income households as E-1 rates transition to flat rate design and a minimum bill is implemented. Low-income program funds are collected through the Public Benefits Charge paid by all customers. CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 7 TABLE 1.3: RECOMMENDED RATES Commodity Distribution PBC Total Residential (E-1) Tier 1 (up to 461 kWh), $/kWh $0.10270 $0.08518 $0.00549 $0.19337 Tier 2 (> 461 kWh), $/kWh $0.13311 $0.08272 $0.00549 $0.22132 Customer Charge, $/month $4.64 Small Commercial (E-2) Summer, $/kWh $0.14926 $0.09735 $0.00549 $0.25210 Winter, $/kWh $0.09242 $0.06623 $0.00549 $0.16414 Customer Charge, $/month $5.60 Medium Commercial (E-4) Summer, $/kWh $0.12318 $0.02520 $0.00549 $0.15387 Winter, $/kWh $0.07949 $0.02520 $0.00549 $0.11018 Summer, $/kW-month $10.98 $34.31 $45.29 Winter, $/kW-month $2.57 $21.16 $23.73 Customer Charge, $/month $113.73 Medium Commercial (E-4 TOU) Summer Peak (4-9 pm)$0.17038 $0.02538 $0.00549 $0.20125 Summer Mid Peak (2-4 pm and 9- 11 pm)$0.14041 $0.02538 $0.00549 $0.17128 Summer Off Peak (all other hours)$0.10556 $0.02538 $0.00549 $0.13643 Winter Peak (4-9 pm)$0.11976 $0.02500 $0.00549 $0.15025 Winter Mid Peak (9 am -2 pm)$0.09452 $0.02500 $0.00549 $0.12501 Winter Off Peak (all other hours)$0.06525 $0.02500 $0.00549 $0.09574 Summer Peak Period Demand, $/kW-month $9.72 $17.18 $26.90 Summer Max Demand, $/kW- month $1.29 $17.18 $18.47 Winter Peak Period Demand, $/kW- month $1.30 $10.73 $12.03 Winter Max Demand, $/kW-month $1.30 $10.73 $12.03 Customer Charge, $/month $113.73 Large Commercial (E-7) Summer, $/kWh $0.12659 $0.00362 $0.00549 $0.13570 Winter, $/kWh $0.07894 $0.00354 $0.00549 $0.08797 Summer, $/kW-month $11.95 $28.41 $40.36 Winter, $/kW-month $2.79 $25.00 $27.79 Customer Charge, $/month $520.80 CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 8 Commodity Distribution PBC Total Large Commercial (E-7 TOU) Customer Charge, $/month $520.80 Summer Peak (4-9 pm)$0.18019 $0.00362 $0.00549 $0.18930 Summer Mid Peak (2-4 pm and 9- 11 pm) $0.14850 $0.00362 $0.00549 $0.15761 Summer Off Peak (all other hours)$0.11164 $0.00362 $0.00549 $0.12075 Winter Peak (4-9 pm)$0.12104 $0.00354 $0.00549 $0.13007 Winter Mid Peak (9 am -2 pm)$0.09552 $0.00354 $0.00549 $0.10455 Winter Off Peak (all other hours)$0.06594 $0.00354 $0.00549 $0.07497 Summer Peak Period Demand, $/kW-month $11.28 $14.71 $25.99 Summer Max Demand, $/kW- month $1.45 $14.71 $16.16 Winter Peak Period Demand, $/kW- month $1.45 $12.99 $14.44 Winter Max Demand, $/kW-month $1.45 $12.99 $14.44 CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 9 2 Overview of Rate Setting Principles EES Consulting (EES), a GDS Associates Company, was retained by the City of Palo Alto (City) to perform a comprehensive electric cost of service and rate study. Performing an electric rate study is necessary to assure that City rates are structured to be fair, equitable and based on the cost of providing service to all City customers. Further, on September 1, 2021, the City’s Utilities Advisory Commission approved an Electric Rate Policy5 which includes 5 guidelines for electric cost of service and rate-making: 1. Rates must be based on the cost of providing service. 2. The effect of any recommended rate design changes on low-income customers should be considered, to the extent permissible within a cost-based rate structure. 3. Rates should not create unnecessary barriers to building and vehicle electrification, including public EV charging, while remaining cost-based. 4. Rates should not create unnecessary barriers to on-site generation and storage while simultaneously avoiding subsidies between customer classes. 5. The COSA and rate design should support a transition to more time variant rates (such as TOU, seasonal, etc.) as advanced metering infrastructure (AMI) is deployed. This Study was prepared while considering the above guidelines. In conducting a cost of service and rate study, three inter-related analyses are performed: 1.Revenue Requirement Analysis: This analysis examines the various sources and uses of funds for the utility and determines the overall revenue required to operate the utility. 2.Cost of Service Analysis (COSA): The COSA is used to determine the fair and equitable allocation of the total revenue requirement to the various customer classes of service (e.g. residential, small non- residential, medium non-residential, etc.). This analysis provides a determination of the level of revenue responsibility of each class of service and the adjustments from current revenues required to meet the cost of service. 3.Rate Design Analysis: The third analysis involves evaluating the rate design options available and designing rate schedules that can be applied to each rate class to equitably collect revenues that match the cost to serve each customer in that class. 2.1 OVERVIEW AND ORGANIZATION OF REPORT This report is divided into sections that follow these three analyses. This first section is a generic discussion of the theory and financial principles behind setting rates. This is followed by a section discussing the development of the revenue requirement analysis for the City. The next section discusses the COSA. Finally, rate design options are presented in the fourth and final section. A technical appendix is attached 5 https://www.cityofpaloalto.org/files/assets/public/agendas-minutes-reports/agendas-minutes/utilities-advisory- commission/archived-agenda-and-minutes/agendas-and-minutes-2021/09-01-2021-special/id-13426-item-3.pdf CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 10 at the end of this report that provides details of the various analyses. The schedules contained in the technical appendix are referenced throughout the report. The purpose of this section of the report is to provide a brief overview of the fundamentals of cost identification and allocation for purposes of developing electric rates. From this base-level of knowledge, more insight and understanding can be obtained from the following sections of the report that discuss the specifics of the Revenue Requirement, Cost of Service, and Rate Design analyses mentioned above. 2.2 OVERVIEW OF REVENUE REQUIREMENT The revenue requirement is the amount of revenue required to be collected from retail rates in order for the utility to cover costs. The revenue requirement includes all electric department expenses (operating and non-operating) less non-rate revenue such as interest income or other unrelated credits. For this study, a cash basis was used to determine the City’s electric utility revenue requirement. The cash basis methodology aligns with the City’s electric utility budgeting process. Revenue projections and expenses for fiscal year 2024-25 are the basis for the revenue requirement study. 2.3 COST OF SERVICE OVERVIEW After the total revenue requirement has been determined, the requirement is allocated across the various classes6 of service based on a cost-based methodology that reflects cost causation between customer characteristics and the Commodity (also known as Power Supply) costs (purchase or generation of the electric commodity and purchased transmission service) and Distribution (delivery of electric service across City-owned distribution line). A COSA begins by assigning each cost in a utility’s revenue requirement into major categories such as Commodity, Transmission, Distribution and Customer. This is called “functionalization.” Next, the functionalized costs are classified to specific categories, such as demand-related, energy-related, costs based on the portion of the utility’s rate base (its distribution assets and general plant assets) serving each customer type, services provided to customers (purchase and delivery/distribution of power), customer-related or a direct assignment of costs to one or more class. This classification is the basis for developing the COSA unit costs (average cost-based rates in terms of $/kWh, $/kW, or $/customer). Allocation factors are factors that add to 100% across all service classes. An example of an allocation factor is the share of the total number of customers or the share of retail sales. These factors are used to spread costs to each class of service. Once the revenue requirement has been allocated to each class of service a determination of the necessary revenue goal for each class can be made. 2.4 RATE DESIGN ANALYSIS The final step in the rate study process is to design rates for each class of service. Rates can be structured in many ways, but ultimately, they should reflect the types of costs that the utility incurs to serve the 6 The relevant classes of service for the City of Palo Alto include E-1, E-2, E-4, E-7, and lighting and streetlights. Classes of service can mean rate classes or just customer type such as residential, small general service, industrial etc. In this study, all residential customers are included in E-1, all small general service are in E-2, and E-4 and E-7 include both non-TOU and TOU customers within each respective class. CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 11 customer (e.g. demand-, energy- and customer-related costs), and should collect the required level of revenues to safely and reliably operate the utility. The Power Supply (Commodity) rate design options can provide accurate, cost-based prices for the cost of power supply. Specifically, electric utility rate design should reflect the power supply cost structure and how each class of service is responsible for its fair share of each power supply cost component. Given appropriate prices, consumers can then make informed decisions regarding their electricity use. The distribution portion of retail rates should be developed such that each ratepayer is responsible for their fair share of the electric distribution service provided. Distribution rates can be bundled with Power Supply (Commodity) rates or unbundled and shown separately as the City has continued to do. Depending on the unique nature of each utility, class of service, or utility goals distribution rate design can vary. While the COSA provides average distribution costs for each class, the rates that are implemented may be designed a number of ways. Regardless of rate design choice, retail rates should follow best practices7 for rate design which include: •Promote efficient use of energy and competing products and services •Simplicity, easy to understand, publicly acceptable, and feasible to implement •Recovers the revenue requirement •Provides stability and minimizes adverse impacts on customers •Fairly apportions cost of service among different consumers Rate design recommendations are presented in Section 5. 7 Summarized from Bonbright’s Eight Criteria of Sound Rate Structure. CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 12 3 Development of the Revenue Requirements This section of the report presents the development of the electric revenue requirement for the City. Simply stated, a revenue requirement analysis compares the overall revenues of the utility to its expenses and determines the overall adjustment to rate levels that is required. 3.1 OVERVIEW OF THE CITY’S REVENUE REQUIREMENT METHODOLOGY The City utilizes the “cash basis” approach for determining its revenue requirement. In summary, the components of its revenue requirement include the elements shown in Table 3-1. TABLE 3-1: ELEMENTS OF A CASH BASIS REVENUE REQUIREMENT + Operation and Maintenance Expenses (O&M) Power Supply Expense Distribution Expense Customer Accounting Expenses Administrative and General Expense + Capital Improvements funded from Rates + Debt Service (Interest and Principal) + General Fund Transfer =Total Revenue Requirement - Transfers from Reserves - Miscellaneous Revenue Sources = Net Revenues Required from Rates From this basic analytical framework, the next step in determining the revenue requirement is to select a time period over which to project revenue and expenses. In the case of the City, a fiscal year test period was utilized (July through June) rather than a calendar year test period. The recommended rate changes are for July 1, 2024; therefore, the 2024-25 fiscal year (July 2024 through June 2025), was chosen as the test period for the COSA. The next step in the analysis was to translate the City budgeted costs into the system used by the Federal Electric Regulatory Commission (FERC), the FERC System of Accounts. A summary of the FY 2024-25 revenue requirement (using the FERC System of Accounts) is provided in Schedule 1.4, and the details are shown in Schedule 3.1. 3.2 POWER SUPPLY COSTS (COMMODITY) As with most electric utilities, the major expense associated with operating the utility is power supply. Approximately $115.5 million, or 54 percent of the FY 2024-25 total revenue requirement of the utility, is power supply costs, as shown in Schedule 3.1. Power supply costs include costs from renewable and non- renewable resources, including Western Area Power Administration (WAPA), Northern California Power Agency (NCPA) resources and power purchase agreements. In addition, power supply costs include California Independent System Operator (CAISO) transmission and ancillary charges. The City’s proposed FY 2024-25 Operating Budget was used for power supply expenses. CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 14 first debt issuance associated with that project. See the FY 2024-25 Electric Utility Financial Plan for more detail. 3.7 MISCELLANEOUS REVENUES The City receives additional operating and non-operating revenues and contributions, which are distinct from ratepayer revenues. These come in the form of carbon allowance revenues, interest revenues, miscellaneous service revenues, rents and other revenue. Service revenues received from connections and other fees offset the costs of those services. Interest revenues represent interest on the utility’s reserves. Miscellaneous service revenues also include minor revenue sources like pole attachment fees for other utilities such as telecommunications, transfers from other City-owned utilities for shared services, and charges for damaged utility property. Other revenues include wholesale sales of surplus energy. For FY 2024-25 the projection for such revenues and contributions is $51.0 million, as shown in Schedules 1.4 and 3.1. 3.8 SUMMARY OF REVENUE REQUIREMENT Once all of the components of the cash basis revenue requirement have been determined, the parts can be summed to equal the total revenue requirement. The City’s revenue requirement for the FY 2024-25 test period is summarized in Table 3-2. More detail on the individual components of the revenue requirement can be found in Schedules 1.4 and 3.1. TABLE 3-2: SUMMARY OF THE REVENUE REQUIREMENT – FY: 2024 -25 Purchased Power $115,533,652 Distribution $28,005,465 Customer Accounts and Services $12,608,722 Administration and General $7,698,473 Capital Projects Funded from Rates $6,500,000 Debt Service $4,770,582 General Fund Transfer $15,121,000 Reserve Contribution $25,333,578 Total Expenses $215,571,473 Other Revenues $50,984,335 Total Revenue Required from Rates (Revenue Requirement)$164,587,138 Revenue Based on Rates Currently in Effect $168,321,326 Additional Rate Revenue Needed (Surplus)($3,734,187) Net Required Rate Revenue Increase (Decrease)(2.2%) 3.9 RECOMMENDATION The City’s revenues are slightly more than its cost obligations in FY 2024-25 using current rates; therefore, a rate reduction is recommended. It is important to note that the City’s revenue-to-cost balance needs to be continually monitored. The City regularly reviews revenue requirements to update retail rates and ensure financial objectives are met. CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 15 4 Cost of Service Analysis The objective of the cost of service analysis (COSA) is to allocate the costs in the revenue requirement to each customer class of service to determine the cost to serve those customers. An essential principle of cost allocation is the concept of cost-causation. Cost-causation evaluates which customer or group of customers causes the utility to incur a cost by linking system facility investments and the operating costs to serve certain facilities to the way customers use those facilities and services. This section of the report will discuss the general approach used to apportion the City’s costs, and will provide a summary of the results. 4.1 CUSTOMER CLASSES A primary input into the COSA is the classes of service. Classes can be modeled by each rate schedule; however, rate schedules for similar customers may also be combined in the COSA. Combining rate schedules recognizes that those groups of customers have similar usage characteristics. For example, E-4 Medium Commercial and TOU-E-4 Medium Commercial customers are likely to have similar load characteristics. The following rate classes are modeled in the COSA: E-1 Residential: All residential customers, excluding from master-metered multifamily customers.. E-2 Small Commercial: Electric service for small commercial customers and master-metered multifamily customers. Any customer with energy usage over 8,000 kWh per month for three consecutive months would be moved to E-4 (see below), while any E-4 customer with energy usage below 6,000 kWh per month for 12 consecutive months would be switched to E-2. When analyzing customer load data this study used the rate schedule designation for each customer in the utility billing system to determine whether the customer currently fell into the E-2 or E-4 class. E-4 Medium Commercial: Demand metered electric service for commercial customers with a maximum demand below 1,000 kilowatts per month and usage over 8,000 kWh per month. E-7 Large Commercial: Demand metered electric service for commercial customers with a maximum demand of at least 1,000 kilowatts per month per site, and who have sustained this demand level for at least 3 consecutive months during previous 12-month period. Street and Traffic Lights: This class applies to all street and highway lighting installations that the City of Palo Alto Utilities Department elects to operate and maintain, generally lights owned by the City, the County, or another government entity and located on public streets. For purposes of the analysis in this study, customers are assigned to a customer class without regard to whether they participate in Palo Alto Green, Net Energy Metering, Time of Use Metering or Low Income programs. Master-metered multi-family customers are treated as commercial customers rather than residential customers. CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 16 4.2 COSA GENERAL PRINCIPLES A COSA study allocates the costs of providing utility service to the various customer classes served by the utility based upon the cost-causal relationship associated with specific expense items. This approach is taken to develop a fair and equitable designation of costs to each class of service. Because the majority of costs are not incurred by any one type of customer, the COSA allocates joint and common costs among the various classes using factors appropriate to each type of expense. The COSA is the second step in a traditional three-step process for developing electric service rates, after development of the revenue requirement but before designing rates. This COSA is performed using the embedded cost methodology. Embedded costs reflect the actual costs incurred by the utility and closely track the expenses kept in its accounting records. There are three basic steps to follow in developing a COSA: Functionalization Classification Allocation Functionalization separates costs into major categories that reflect the different services provided to customers. The functional categories for the City are Power Supply (Commodity) and Distribution. Shared service costs (generally overhead) that will be allocated across both functional categories are also identified in this phase. Classification determines the portion of each cost that is related to identified “classifiers” (cost-causal factors). Table 4-3 shows the classifiers used in this analysis. Generally, costs are classified as one or more of: demand-related (related to the class of service’s peak energy usage over a given period), energy- related (related to the total energy used by the class of service over a given period), and customer-related (costs incurred as a result of receiving service, regardless of the energy use or peak demand), though there are some other classifiers. Power Supply (Commodity) costs are related to generating and supplying power to customers on the system and are often demand- or energy-related. The distribution system is designed to extend service to all customers attached to the system and to meet the peak demand requirement of each customer, meaning that costs are often demand-related. Some operational costs, such as billing, are generally customer-related. Costs can also be classified based on system revenues or directly assigned to a customer or group of customers if appropriate (for example, for street lighting customers). Allocation of costs to specific classes of service happens after those costs have been classified. Allocation factors are chosen to allocate the costs assigned to each classification, and the share of costs allocated to each class of service are based on the class’s contribution to the specific allocation factor selected. For example, certain Power Supply (Commodity) costs might be classified as partially demand-related and partially energy-related. The demand-related Power Supply (Commodity) costs would be allocated to the classes of service using each class’s contribution to the annual system peak demand (the highest demand for the system as a whole at any time during the year), while the energy-related costs would be allocated to classes based on their annual energy usage. In this example, the allocation factors are 1) each class of service’s contribution to the annual system peak demand and 2) the annual energy usage of each class of service. An analysis of customer requirements, and usage characteristics is completed to develop allocation factors reflecting each of the classifiers employed within the COSA. CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 17 4.3 FUNCTIONALIZATION OF COSTS As discussed above, the first step in the COSA process following finalization of the revenue requirement is to functionalize the revenue requirement. Certain types of costs in the revenue requirement (primarily O&M costs associated with various types of capital assets) are allocated based on the use of the underlying capital assets by customer class. To determine this, the underlying capital assets of the utility (the “rate base”) are functionalized into cost categories and allocated to customer classes. The functionalization, classification, and allocation of the rate base will be used as a basis for functionalization, classification, and allocation of certain types of operating expenses in the revenue requirement, such as maintenance of the capital assets included in the rate base. In the City’s case, the rate base and revenue requirement are functionalized into Power Supply (Commodity), Distribution, and Shared Services functional categories. Schedule 3.1 shows the functional category for each cost in the revenue requirement, while Schedule 3.3 shows the results of the functionalization and classification of each cost. Schedules 4.1 and 4.2 show the same information for the rate base. The functional categories are described in more detail below: Power Supply (Commodity). The Power Supply functional category includes all power-related services that are obtained by the utility through generation and direct purchase. The City purchases power from a variety of renewable and hydroelectric generating sources, as well as purchasing power in the energy markets. The transmission services that the City must acquire to deliver the purchased power supply to the service area are included in purchased power costs. Distribution. Distribution services include all services required to move the electricity from the point of interconnection between the transmission system and the distribution system to the end user of the power. These include substations, primary and secondary poles and conductors, line transformers, services and meters as well as customer costs and any direct assignment items. Shared Services. Shared services include assets used across multiple functions or costs that apply across multiple functions, such as facilities used for general management of the operation or insurance or benefits costs. Assets and costs in the shared services category are not shown in the attached schedules as a separate functional category. Instead, they are allocated across the Power Supply (Commodity) and Distribution functions as overhead. 4.4 CLASSIFICATION AND ALLOCATION OF COSTS The next step in performing a COSA is to classify and allocate the functionalized expenses. The classifications and allocations are directly related to specific consumption behavior or system configuration measurements such as coincident peak (CP) or non-coincident peak (NCP)9 demand, energy 9 Coincident peak represents the customer class’s contribution to the system peak demand (i.e. its demand coincident with, or at the time of, the system peak), while non-coincident peak represents the customer class’s peak CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 18 consumption, or number of customers. Each cost in the revenue requirement will be classified into one or more categories and will then be allocated to customer classes of service based on a specific allocator. For example, 7% of the costs associated with the Calaveras hydroelectric generating resource were classified into the demand classification and 93% were classified into the energy classification, with the demand classifier allocated to classes of service based on each class’s CP demand, and the energy portion of the cost allocated based on each class’s annual energy consumption. The classification and allocation factors used for each component of the rate base and revenue requirement are shown in Tables 4-1 and4-2 and are discussed in more detail below. Descriptions of each factor are included in Table 4-3. The following are the specific classifiers used in the City’s COSA within the Power Supply and Distribution functions. As noted earlier, the Shared Services function is spread across the Power Supply and Distribution functions as overhead, so it does not have its own classifiers: Power Supply (Commodity) Function Within this study, Power Supply (Commodity) function costs are classified to demand and energy based on discussion with the City staff related to cost causation. The specific classifiers used for the Power Supply (Commodity) function include: Energy. Energy-related costs are those that vary with the total amount of electricity consumed by a customer. Electricity usage measured in kWh is used in this portion of the analysis. Energy costs are the costs of consumption over a specified period of time, such as a month or year. Demand. Demand-related costs are those that vary with the maximum demand or the maximum rates of energy supplied to classes of service. Customer and system demands for this analysis were measured in kW. Demand costs are generally related to the size (capacity) of facilities needed to meet a customer’s maximum demand at any point in time. Resource capacity costs are functionalized as demand. When referring to customer peak electricity use or requirements, the term demand is used. When referring to resource attributes, the term capacity is used. In order to classify Power Supply (Commodity) costs, each resource or type of cost was evaluated based on how the City is charged and whether the resource provides energy or capacity10 to the City. Power purchase agreements for the output from the Western Area Power Administration (WAPA) and Calaveras hydroelectric generating resources and all renewable resources provide differing amounts of energy and capacity, and so were classified according to the relative market value of the energy and capacity provided by each resource. An analysis of the amount of capacity and energy provided demand regardless of when it occurs. A customer class’s demand at the time of the system peak demand may be lower than its peak demand, which may occur at some other time of the year. 10 When referring to a generating resource, “capacity” refers to its potential generating capacity regardless of whether it is actually generating energy. Capacity must be held to meet customer peak demand, regardless of whether it is used to generate energy at all times of the year. Capacity costs are usually assigned to the demand classifier. CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 19 by each resources was done, and the market value of each of those was calculated based on historical energy and capacity prices. The market value is used rather than actual operating expenses since the resources generate revenues that offset their operating expenses, and the actual cost to Palo Alto depends on the market value for energy, and capacity less the individual resource cost. The ratio of energy to capacity value was used to classify the cost of the resource and assign resource costs to energy or demand. Costs associated with services provided to the City by Northern California Power Agency (NCPA) (such as scheduling generating resources and interacting with the California Independent System Operator (CAISO) on the City’s behalf) are classified as energy costs because these services are necessitated by City’s energy purchases. Purchases of energy from marketers11 are classified as energy-related costs, while purchases of capacity are classified as demand-related costs.12 CAISO transmission costs are classified as energy-related costs, as this is the way those costs are allocated to distribution utilities by the CAISO, and the CAISO transmission costs therefore vary with the total City system energy. Distribution Function Distribution services include all services required to get energy supply from the point of interconnection between the transmission system and the utility’s service area to the end user of the power. Most distribution costs are split between demand and customer components. The demand component is the cost of facilities like distribution substations, lines, or line transformers built to serve a particular peak demand. The customer component is the cost of facilities that varies with the number of customers, such as meters. The following are the specific classifiers used for the City’s distribution function: Demand. Demand-related costs are those that vary with the maximum demand or the maximum rates of energy supplied to classes of service. Customer and system demands for this analysis are measured in kW. Demand costs are generally related to the size of facilities needed to meet a customer’s maximum demand at any point in time. Customer. Customer-related costs are those that vary with the number of customers. Customer costs may be weighted to account for differences in the cost of providing services to those customers. For example, the service drop and metering associated with serving a large commercial customer is more costly and requires substantially more work and material than the service and meter for a small residential customer. Direct Assignment. Some costs are directly assigned to specific classes of service. Costs associated with providing account representatives to large customers are allocated directly to those classes of service. Direct maintenance costs associated with streetlights and traffic signals are directly 11 City purchases energy and capacity from various marketers and other agencies (BP Energy Company, Cargill Power Markets, Exelon Generation Co., Iberdrola Renewables, Nextera Energy Marketing, Pacificorp, Powerex, Shell Energy North America, and Turlock Irrigation District) through its Electric Master Agreements. 12 Energy purchases require that energy is delivered to the system during some specified period of time, while capacity purchases enable the City to count generating capacity from a specific generating unit owned by another agency or marketer toward the generating capacity requirements imposed on it by the CAISO. CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 20 allocated to the streetlight / traffic signal class. Schedules 3.5 and 4.4 provide the background information for all directly assigned costs associated with the revenue requirement and rate base. The methodology for functionalization, classification, and allocation of the City’s rate base is summarized in Table 4-1 and in Technical Appendix Schedule 4.1. The results of the process for the rate base can be found in Schedule 4.2. The same information for the revenue requirement can be found in Table 7, Schedule 3.1, and Schedule 3.3. More detail on the classification and allocation factor codes used in the classification and allocation process can be found in Table 8. Schedule 6.1 shows how each code is used to separate costs into functions (power supply and distribution) and classifications (demand, energy, customer, and direct assignment). Schedule 6.2 shows the way each code then allocates the costs within each classification across classes of service. TABLE 4-1: RATE BASE FUNCTIONALIZATION, CLASSIFICATION AND ALLOCATION FERC Account Asset Description Functionalization Category Classification and Allocation Factor Code13 Distribution Plant 361.0 Structures and Improvements Distribution NCPP 362.0 Station Equipment – Distribution Distribution NCPP 363.0 Storage & Battery Equipment Distribution NCPP 364.0 Poles, Towers & Fixtures Distribution 100% DP 365.0 Overhead Conductor & Devices Distribution 100% DC 366.0 Underground Conduit Distribution 100% DC 367.0 Underground Conductors Distribution 100% DC 368.0 Line Transformers Distribution 100% DT 369.0 Services Distribution SERV 370.0 Meters Distribution CUSTM 371.0 Installations on Customer Premises Distribution CUSTM 373.0 Street Lighting Systems Distribution DA1 General Plant 390.0 Structures & Improvements Shared Services GPLT 391.0 Office Furniture & Equipment Shared Services GPLT 392.0 Transportation Equipment Shared Services GPLT 394.0 Tools, Shop & Garage Equipment Shared Services GPLT 397.0 Communication Equipment Shared Services GPLT 398.0 Miscellaneous Equipment Shared Services GPLT 399.0 Other Tangible Property – EV Charging Shared Services GPLT Accumulated Depreciation Distribution Plant Distribution RBD-NoDA General Plant Shared Services RBGP Street Lighting Distribution DA1 13 See Table 4.3 for more detail and fully spelled-out acronyms CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 21 FERC Account Asset Description Functionalization Category Classification and Allocation Factor Code13 Working Capital 90 Days Distribution O&M Shared Services OMWOP 90 Days of Commodity Cost Power Supply OMP 1/12 Purchased Transmission Charges Power Supply OMPT Construction Work in Progress Construction Work in Progress Distribution RBD CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 22 TABLE 4-2: REVENUE REQUIREMENT FUNCTIONALIZATION, CLASSIFICATION AND ALLOCATION FERC Account Plant Description Functionalization Category Classification and Allocation Factor Code14 Power Purchases 555.70 Western Power Purchases Power Supply WEST 555.71 Contra Surplus Energy Power Supply kWh 555.72 NCPA Pooling Power Supply kWh 555.73 NCPA Facilities Power Supply kWh 555.74 Local Capacity Purchase Power Supply CP12 555.76 Renewable Energy Power Supply REN 555.77 Carbon Neutral Purchases (RECs)Power Supply kWh 555.78 Market Power Purchases Power Supply kWh 555.80 TANC & Calveras O&M Power Supply CALA 555.90 CVP O&M Power Supply WEST 555.15 Resource Management Admin Power Supply kWh Other 555.10 Surplus Energy Power Supply kWh 555.30 Carbon Allowance Revenues Power Supply kWh Distribution 580.0 Operations Supervision and Engineering Distribution RBD 586.0 Meters Distribution CUSTW 587.0 Customer Installations Distribution CUSTW 588.0 Miscellaneous Distribution Distribution RBD-NoDA 589.0 Rents Distribution RBD-NoDA 590.0 Maintenance Supervision and Engineering Distribution RBD-NoDA 593.0 Maintenance of Overhead Lines Distribution RBOH 594.0 Maintenance Of Underground Lines Distribution RBUG 596.0 Street Lighting & Signal Systems Distribution DA1 598.0 Maintenance of Misc. Distribution Plant Distribution RBD 598.1 Communication O&M Distribution RBD-NoDA Customer Service, Accounts & Sales 901.0 Supervision Distribution CUSTW 902.0 Meter Reading Expenses Distribution CUSTMR 903.0 Cust. Records Collection Expense Distribution REV 904.0 Uncollectable Accounts Distribution REV 906.0 Customer Service & Information Distribution CUST 907.0 Customer Communication & Education Distribution CUST 910.0 Misc. Customer Service & Information Distribution CUST 916.0 Misc. Sales Expense Distribution CUST 906.1 Key Accounts Distribution OM 906.2 Energy Efficiency & Demand-Side Management (DSM) Distribution DSMEE 14 See Table 4.3 for more detail. CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 23 FERC Account Plant Description Functionalization Category Classification and Allocation Factor Code14 906.3 Low Income Residential Energy Assistance Program Distribution DSMEE Administrative and General (A&G) Expenses 920.0 Salaries Shared Services OMAG 921.0 Office Supplies and Expense Shared Services OMAG 923.0 Outside Services Shared Services OMAG 924.0 Property Insurance Shared Services NETPLT 925.0 Injuries and Damages Shared Services OMAG 926.0 Employee Pension and Benefits Shared Services OMAG 927.0 Franchise Requirements Shared Services OMAG 930.2 Miscellaneous General Expense Shared Services OMAG 930.3 Environmental Fees Shared Services OMAG 932.0 Maintenance of General Plant & Communication Equipment Shared Services OMAG 935.0 Cost Plan Charges Shared Services OMAG Interest and Debt Service Expense 427.0 Interest and Debt Service Electric Shared Services NETPLT Capital Projects From Rates Distribution Distribution RBD-NoDA Services Other Contributions General Fund Transfer Shared Services GF Other Transfers In/Out Shared Services NETPLT Reserve Contribution Shared Services RContr Misc. & Other Revenues and Income 451.0 Connect / Re-Connect Fees Shared Services OMAG 419/424 Dividends from Affiliates, Interest Power Supply WEST 415/416 Income from Equity Investments Shared Services OM 421.0 Misc. Income (RA Sales & Surplus Sales)Power Supply kWh 421.1 Public Benefits Revenue Power Supply kWh CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 24 TABLE 4-3: CLASSIFICATION AND ALLOCATION FACTORS Factor Code Factor Name Classification Allocation Basis Rate Base Classification and Allocation Factors NCPP Non-coincident Peak - Primary 100% Demand The total peak kW demand, regardless of when it occurs. 100% DP 100% Demand (Poles, Towers, Fixtures) 100% Demand The total peak kW demand, regardless of when it occurs. 100% DC 100% Demand (Overhead and Underground Conduit) 100% Demand The total peak kW demand, regardless of when it occurs. 100% DT 100% Demand (Transformers) 100% Demand The total peak kW demand, regardless of when it occurs. SERV Services15 100% Customer # customers weighted for the cost of installing and replacing services CUSTM Customers weighted for accounting / metering 100% Customer # customers weighted for cost of installing, maintaining and reading meters, billing, and account management DA1 Street Light Rate Base Assignment 100% Direct Assignment Street lighting assets allocated directly to street light customer class of service GPLT Gross Plant 71.7% Demand, 21.1% Customer 7.2% Direct Assignment Allocated on the Basis of Gross Plant (w/o General Plant & Intangible) RBD-ST Rate Base: Distribution Adjusted for Street Light Direct Assignments 61.8% Demand, 24.3% Customer 13.9% Direct Assignment Classified and allocated to classes of service based on the value of all operational and shared services assets assigned to each class of service. Used for accumulated depreciation RBD-NoDA As Distribution Ratebase without DA Street Lighting 71.7% Demand, 28.3% Customer Allocated as Distribution Rate Base without DA Street Lighting RBD-NoDA Services As Distribution Ratebase without DA Street Lighting or Services 97.8 Demand, 2.2% Customer As Distribution Rate Base without DA Street Lighting or Services RBGP Rate Base - General Plant 71.7% Demand, 21.1% Customer, 7.20% Direct Assignment On the Basis of General Plant Rate Base RContr 50.7% Demand, 33.9% Energy 15.4% Customer Based on Commodity and Distribution Split 15 This is a technical term referring to the connection from the line transformer to the customer’s electrical panel. CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 25 Factor Code Factor Name Classification Allocation Basis OMWOP O&M without Power Supply 51.6% Demand, 17.7% Energy, 27.7% Customer 3.0% Direct Assignment Allocated based on O&M without Power Supply costs OMP O&M: Purchase Power 9.3% Demand, 90.7% Energy Allocated based on Purchased Power costs OMPT O&M: Purchased Transmission 100% Energy Allocated based on Purchased Transmission costs RBD Rate Base: Distribution 71.7% Demand, 21.1% Customer 7.2% Direct Assignment Classified and allocated to classes of service based on the net book value of all shared services assets and other capital assets assigned to each class of service. Revenue Requirement Classification and Allocation Factors WEST Western Base Resource allocation 16% Demand, 84% Energy Western Base Resource costs. Classified according to the relative market value of the capacity and energy provided by the resource, and allocated to classes of service based on each class’s energy consumption and coincident peak demand. kWh Energy consumption (kWh) 100% Energy Energy consumption of each class of service in kWh CP12 12-month Coincident Peak 100% Demand Customer class of service’s contribution to the utility’s annual system peak demand CALA Calaveras Hydroelectric Resource allocation 7% Demand, 93% Energy Calaveras hydroelectric resource costs. Classified according to the relative market value of the capacity and energy provided by the resource, and allocated to classes of service based on each class’s energy consumption and coincident peak demand. REN Renewable Power Purchase Agreements 3% Demand, 97% Energy Renewable Power Purchase Agreement costs. Classified according to the relative market value of the capacity and energy provided by the resource, and allocated to classes of service based on each class’s energy consumption and coincident peak demand. RBD Distribution Rate Base 71.7% Demand, 21.1% Customer, 7.2% Direct Assignment On the Basis of Distribution Rate Base RBD-NoDA Distribution Rate Base Excluding Street Lighting and Traffic Signals 71.7% Demand, 28.3% Customer Used for allocation of most distribution system infrastructure O&M costs other than street light/traffic signal maintenance. Classified and allocated to classes of service based on the net book value of all shared services assets and other capital assets assigned to each class of service, excluding street lighting and traffic signals. CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 26 Factor Code Factor Name Classification Allocation Basis RBD-NoDA Services As Distribution Rate Base without DA Street Lighting or Services 97.8 Demand, 2.2% Customer As Distribution Rate Base without Direct Assignment to Street Lighting and excluding Services (FERC 369) DA1 Street Light and Traffic Signal Direct Assignment 100% Direct Assignment Costs associated with operating and maintaining streetlight and traffic signal assets GF General Fund Allocator 4% Demand 95% Energy 1% Customer Allocator for General fund Contributions based on Surplus Sales RContr Reserves Contribution 50.7% Demand, 33.9% Energy 15.4% Customer Based on Commodity and Distribution split RBOH Rate Base (Overhead Lines) 100% Demand Used for allocation of maintenance costs for overhead lines. Classified and allocated to classes of service based on the net book value of overhead lines assigned to each class of service. RBUG Rate Base (Underground Lines) 100% Demand On the Basis of all Underground Rate Base REV Retail Revenues 100% Demand Share of retail rate revenue CUSTW Customers weighted for accounting / metering 100% Customer # customers weighted for cost of installing, maintaining and reading meters, billing, and account management CUSTMR Customers weighted for meter reading 100% Customer # customers weighted for cost of reading meters CREDIT Credit and Collections 100% Customer # customers weighted for credit and collections costs CUST SERV Customer Service 100% Customer # customers weighted for customer service costs CUST Actual Customers 100% Customer Actual (unweighted) customer count OMAG O&M omitting A&G and Power Supply Shared Services On the basis of all other O&M costs allocated to each class of service excluding A&G and Power Supply. Allocated to Power supply Function (12.6% Energy) and Distribution Function (48.7% Demand, 31.5% Customer, 7.2% Direct Assignment) OM All O&M Shared Services Allocated on the basis of all other O&M costs in the revenue requirement. Allocated to Power Supply Function (4.9% Demand, 12.6% Energy) and Distribution Function (48.7% Demand, 31.5% Customer, 7.2% Direct Assignment) DSRE Demand-Side Renewable Energy Allocator Power Supply Allocated based on PV Partners solar rebate budget allocation CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 27 Factor Code Factor Name Classification Allocation Basis DSMEE DSM / EE Allocator Power Supply Based on historical residential / non- residential program expenditures. Residential direct assignment, non- residential based on annual kWh. No allocation to Street/Traffic Lights NETPLT Net Plant 78.4% Demand, 18.2% Customer, 3.4% Direct Assignment Allocated on the basis of the net book value of all capital assets (initial cost less accumulated depreciation) assigned to each class of service. 4.5 COST OF SERVICE RESULTS Given the key assumptions listed above, the COSA was completed. Schedules 3.4 and 4.3 in the appendix show the functionalized and classified rate base and revenue requirement allocated to each class of service. These schedules are calculated by multiplying the applicable classification and allocation factors to each cost in the revenue requirement or rate base. Given the above assumptions regarding the COSA, the various costs were classified and allocated to the customer classes of service. Table 4-4 provides the COSA results. Summary data and additional detail is presented in Schedules 1.1 and 1.2. TABLE 4-4: SUMMARY OF COST OF SERVICE ANALYSIS FOR FY 2024-25 TEST YEAR Projected Revenues under Current Rates Net Revenue Requirement Projected Surplus/ (Deficiency) in Revenue Based on Current Rates Revenue Increase/ (Decrease) Needed16 Residential E-1 $27,309,759 $27,852,514 -$542,755 2.0% Small Commercial E-2 $11,784,676 $11,067,556 $717,121 -6.1% Medium Commercial E-4 $67,707,023 $65,186,601 $2,520,422 -3.7% Large Commercial E-7 $59,295,683 $58,473,708 $821,975 -1.4% Residential E-1 $2,224,184 $2,006,759 $217,425 -9.8% TOTAL $168,321,326 $164,587,138 $3,734,187 -2.2% The results show that with present rates, the City would collect surplus revenues in FY 2024-25. As discussed previously in the report, the amount of additional revenue required varies by class of service. While customers on Rate Schedule E-7 are paying close to cost of service already, the E-1 rate class will need a rate increase. The varying cost requirements are a result of changes in customer usage 16 Projected FY 2024-25 revenue surplus/(deficiency) divided by projected FY 2024-25 revenue based on rates currently in effect. CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 28 characteristics since the last COSA and rate redesign. These changing consumption patterns affect use of the system and the way costs are allocated among customers. As described throughout this section, costs are allocated to customers based on their consumption patterns, particularly energy consumption and peak demand. As customer consumption patterns change, some of the utility’s costs change as well, but others are fixed over the short term. For example, some charges to the utility, like market energy purchases, are directly related to energy consumption. These costs decrease as customer energy consumption decreases, usually in real-time. If a customer class uses less energy, fewer of these costs will be allocated to them and their revenue requirement will decrease. Other costs only change slowly over time, such as the amount of distribution capacity the utility builds and maintains. These costs are largely fixed and change over the long term with changes in peak demand or energy use. The majority of the City of Palo Alto’s costs change slowly over the long term. Rates for each customer class are set based on the energy and peak demand patterns over the study period. If energy use and peak demand decrease or increase after the rate study is completed, costs that change only over the long term might not change. When a subsequent COSA is performed, different revenue adjustments may need to be made for each customer class. The impacts to each class required as a result of the analysis done in the COSA are described below: Energy consumption and demand has increased for the E-1 (Residential)17 class of service. The share of costs allocated to this customer class increased as a result. Revenues need to increase more than average for this class of service. Small Commercial (E-2) needs a larger rate decrease due to an updated assessment of the cost allocation factors for customer service costs for this customer class. The Medium Commercial (E-4) annual load factor has remained consistent with the previous COSA; however, energy usage and demand usage has decreased. This results in less cost allocation to E-4. Large Commercial (E-7) load factors18 have increased. The share of costs allocated to this class decreased as a result. The streetlight and traffic signal class reflects lower maintenance costs and capital expenditures allocated to lighting. The table below compares usage data from this study (FY 2023-24) with the previous COSA (FY 2016-17). Note that E-18 (City Accounts) were combined with commercial classes in the last COSA (FY 2016-17). Rather than developing separate E-18 rates, the City included City Accounts in the appropriate commercial classes based on individual customer demand size as described in the retail rate schedules. Retail sales data and number of customers was provided by the City. Billed demand19 for applicable classes was also provided by the City. Not all classes have meters that measure demand, therefore, for classes without 17 While this class of service is named “Residential Electric Service,” it does not include 100% of residential use. Some master-metered multi-family residential buildings take service under other rate schedules. 18 See previous footnote. 19 Billed demand refers to the maximum measured kW in any given month. Billed demand is based on a customer’s maximum demand regardless of the time of the utility system peak (non-coincident demand at the meter). CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 29 billed demand, demands are calculated using load factor data calculated from an appropriate City feeder (i.e. a feeder20 that is mostly serving residential customers is used to calculate monthly load factors). TABLE 4-5: COMPARISON OF LOAD CHARACTERISTICS Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 City Accounts E-18 Street & Traffic Lights Total Retail Sales, MWh FY2016-17 153,030 70,451 320,995 394,322 29,231 1,897 969,926 Forecast FY2024-25 133,053 53,238 295,255 348,505 0 1,893 831,944 Peak Demand (12NCP, kW )[1] FY2016-17 304,102 190,983 773,606 747,738 76,890 5,371 2,098,690 Forecast FY2024-25 264,621 143,933 764,019 607,389 0 5,359 1,785,322 Load Factor[2] Average Monthly FY2016-17 69%51%54%74%53%50% Forecast FY2024-25 69%51%49%78%NA 50% Customers FY2016-17 25,341 3,073 736 66 123 1 29,339 Forecast FY2024-25 26,100 3,183 837 71 0 2 30,193 When examining the results, it is important to note that the inter-class cost allocation is based on usage data estimates and usage pattern assumptions. Since these can vary from year to year, the results of applying this COSA may deviate from these allocations over time. To avoid these deviations, the COSA model can be updated when necessitated by significant changes to customer consumption patterns or the City’s costs. This study utilizes the FY 2020-21 and FY2021-22 historic years and the City’s forecasted load growth to estimate FY2024-25 loads. The historic data includes usage patterns that have continued since the pandemic. This data best reflects the near-term usage characteristics. It is recommended to revisit the load characteristics in future COSA studies. 20A feeder is the part of the distribution system which connects the power supply to the area where power is to be distributed (and eventually to individual customers). CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 30 5 Rate Design The final step in the rate study process is to design rates for each class of service. It is important to note that the results of the revenue requirement and COSA study are dependent on forecasted usage data estimates and usage pattern assumptions. Actual electricity usage patterns may differ from forecast. For this study, rates are developed based on the forecasted usage and observed historical usage patterns for each rate class. As part of the electric cost of service study, a rate design analysis is prepared to update the City’s current and recommended rate schedules. The City’s existing rate model and methodologies are largely preserved for each rate classes. In some cases, rate components for existing schedules have recommended updates. This section of the report summarizes the rate design analysis for FY 2024-25 electric rates. Table 5-1 summarizes the recommended rate adjustments by class. These rate adjustments are taken directly from the COSA results. TABLE 5-1: RATE ADJUSTMENT RECOMENDATION OVERVIEW Total Residential E-1 Small Commercial E-2 Medium Commercial E-4 Large Commercial E-7 Street/ Traffic Lights Current Rate Revenue $168,321,326 $27,309,759 $11,784,676 $67,707,023 $59,295,683 $2,224,184 Rate Revenue Goal $164,583,349 $27,852,514 $11,067,651 $65,184,561 $58,471,865 $2,006,759 Rate Adjustment -2.2%2.0%-6.1%-3.7%-1.4%-9.8% Table 5-2 summarizes the current rate design for each rate schedule and recommended rate design updates. TABLE 5-2: RATE DESIGN RECOMMENDATION OVERVIEW Rate Schedule Current Rate Design Recommended Rate Design Residential E-1 Energy Only Tiered Rate with 2 Inclining Blocks •Add Customer Charge •Increase Tier 1 kWh to average summer usage Small Commercial E-2 Seasonal Rates energy charge only •Update Seasonal Costs •Add Customer Charge Medium Commercial E-4 Seasonal with Energy and Demand Charges •Update Seasonal Costs •Add Customer Charge •Adjust kW billing methodology Medium Commercial E-4- TOU 6-period TOU Energy and Demand Rates •Update TOU Periods •Commodity Rate Based on updated Marginal Cost •Add Customer Charge Large Commercial E-7 Seasonal with Energy and Demand Charge •Update Seasonal Costs •Add Customer Charge Large Commercial E-7-TOU 6-period TOU with Energy and Demand Charge •Update TOU Periods •Commodity Rate Based on updated Marginal Cost •Add Customer Charge •Adjust kW billing methodology CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 31 5.1 CUSTOMER CHARGE AND MINIMUM BILL Table 5-2 recommends adding monthly customer charges to each rate schedule.21 The recommended customer charges recover the cost of metering and billing in each class. Customer charge bill impacts to low-income customers are addressed in section 5.2 below. 5.2 RESIDENTIAL E-1 The current rate design is based on a 2-tier inclining block rate as described in Table 5-3. The costs allocated to Tier 1 include the cost of maintaining and replacing the distribution capacity used year-round, while the costs allocated to Tier 2 represent the cost of maintaining and replacing the distribution capacity used only in the winter, which is when residential consumption peaks. Local capacity costs (resource adequacy) are allocated to Tier 2 as well. The current break point between Tier 1 and Tier 2 is 330 kWh per month. An analysis of residential consumption for CY 2020 shows the average summer residential consumption is 461 kWh per month. This is most representative of the current annual year-round usage. Therefore, the recommended rate design change is to increase the Tier 2 threshold to 461 kWh per month. TABLE 5-3: RESIDENTIAL E-1 TIERED ENERGY RATE DESIGN Current Rates Recommended Rate Design Tier 1 kWh 330 461 Tier 2 kWh Above 330 Above 461 It is recommended that the City implement a monthly customer charge.21 This customer charge recovers customer-specific costs such as billing and meter reading. Additionally, a customer charge is a way to improve cost of service recovery within each class; low users pay their share of costs. Low-income programs would continue to be available to mitigate rate impacts to vulnerable customers. Table 5-4 shows the recommended rates preserving the tiered rate structure. TABLE 5-4: RECOMMENDED E-1 RATES Commodity Distribution PBC Total Current Rates Tier 1 (up to 330 kWh), $/kWh $0.09999 $0.06954 $0.00568 $0.17521 Tier 2 (> 330 kWh), $/kWh $0.13873 $0.10225 $0.00568 $0.24666 Recommended Rate Tier 1 (up to 461 kWh), $/kWh $0.10270 $0.08518 $0.00549 $0.19337 21 A monthly customer charge can be referred to as a facilities charge, fixed charge, basic charge, fixed delivery charge or other nomenclature. This study refers to the customer charge as fixed or facilities charge. All of these are essentially the same type of rate meant to recover a portion of fixed costs incurred just to serve a customer. CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 32 Commodity Distribution PBC Total Tier 2 (> 461 kWh), $/kWh $0.13311 $0.08272 $0.00549 $0.22133 Customer Charge, $/month $4.64 COSA Rate Adjustment 2.0% The above rates are based on the cost of service for each rate component. Table 5-5 summarizes the components for the recommended rate design. TABLE 5-5: COST BASIS FOR RECOMMENDED RATES Rate Component Cost-Basis Reasoning Commodity Tier 1 Average Energy Costs Full cost recovery of energy-related power supply purchases Commodity Tier 2 Average Energy Costs plus Local Capacity Costs Higher-users contribute more to demand costs than customers in lower tiers. Customers in higher tiers use more energy in summer months which directly impact the utility’s capacity costs Distribution Tier 1 All Customer-Related Distribution Costs less Customer Charge Revenue plus Average demand-related distribution costs Average demand-related costs are recovered even at lower usage levels. Distribution Tier 2 Average and Excess Demand-Related Costs Average demand-related costs plus Excess demand-related costs collected for usage over the Tier 1 kWh. Excess demand is related to higher usage levels. Customer Charge Recovers Fixed Customer Metering and Billing Costs All customers should pay for their fixed costs independent of usage. 5.2.1 E-1 Bill Impacts The figures below show impacts of the recommended rates. As expected, the customers in the lowest usage tier (<200 kWh/month) experience the greatest impact. Note that the bill impacts are calculated in reference to the current rate level and rate structure. The average customer using less than 200 kWh/month would experience a 68% bill increase. CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 33 FIGURE 5-1: BILL IMPACTS 66% 18% 8% -1%-5%-8% -20% -10% 0% 10% 20% 30% 40% 50% 60% 70% <200 9,311 200-330 5,337 330-500 5,935 500-1,000 8,402 1,000-1,500 1,996 >1,500 951 Ra t e I m p a c t o v e r C u r r e n t R a t e s kWh/Month # Service Accounts CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 34 While the monthly bills increase by a large percentage for the 200 kWh/month and less group, the actual dollar increase is smaller, averaging less than $3.40/month (Figure 5-4). FIGURE 5-2: BILL IMPACTS, $/MONTH $3.39 $6.46 $4.97 -$1.82 -$13.19 -$35.52-$40.00 -$35.00 -$30.00 -$25.00 -$20.00 -$15.00 -$10.00 -$5.00 $0.00 $5.00 $10.00 <200 9,311 200-330 5,337 330-500 5,935 500-1,000 8,402 1,000-1,500 1,996 >1,500 951 Av e r a g e M o n t h l y B i l l I m p a c t o v e r Cu r r e n t R a t e s , $ kWh/month # Service Accounts CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 35 5.2.2 Bill Comparison with PG&E Figure 5-3 compares the current and recommended E-1 rates to PG&E current rates for a range of consumption levels: low, average, and high use. Regardless of usage, PG&E current rates are approximately twice the recommended rate level for Palo Alto E-1 rates. FIGURE 5-3: E-1 BILL COMPARISON: PALO ALTO AND PG&E, AVERAGE BILL Note that the PG&E baseline allowance for Tier 1 is 198 and 228 kWh/mo (winter and summer respectively). PG&E current rates are 36 cents/kWh and 45 cents/kWh Tier 1 and Tier 2 respectively. 5.2.3 Rate Impacts for Low-Income E-1 (RAP) One particular concern related to rate design change is the impact on low-income customers. This section presents bill impacts to customers currently participating in the City’s Rate Assistance Program (RAP). The RAP program provides bill discounts of 25% to qualifying customers. Discounts are paid from the Public Benefits Charge (PBC) fund.22 All customers pay into the PBC fund through the PBC charge, which is implemented via a variable rate (applied to kWh consumption). As a group, participating RAP customers use less energy than non-RAP customers on average. Most RAP customers, (495 out of 817 or 61%), use 330 kWh or less per month and 78% use less than 461 kWh per month on average. As such, the inclusion of a minimum bill or monthly customer charge will disproportionately affect RAP customers. The charts below compare RAP bill impacts for current and recommended rates. Because these customers receive rate assistance, the bill impact (%) and the dollar per month impact are lower compared to the E-1 class as a whole (see previous figures). 22 California Code, Public Utilities Code - PUC § 385 $35.04 $43.31 $71.68$94.82 $97.99 $195.49$223.08 $213.08 $427.89 $0 $50 $100 $150 $200 $250 $300 $350 $400 $450 Current Rates Recommended Rate PG&E 200 kWh/Month 480 kWh/Month 1,000 kWh/Month $/M o n t h CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 36 FIGURE 5-4 RAP CUSTOMER BILL IMPACTS 43% 21% 16% 7% -1% -5%-10% 0% 10% 20% 30% 40% 50% <200 368 200-330 153 330-500 127 500-1,000 128 1,000-1,500 14 >1,500 6 Ra t e I m p a c t o v e r C u r r e n t R a t e s kWh/Month # Service Accounts CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 37 FIGURE 5-5 RAP CUSTOMER BILL IMPACTS, $/MONTH $3.25 $7.13 $8.49 $6.77 -$1.93 -$18.00-$20.00 -$15.00 -$10.00 -$5.00 $0.00 $5.00 $10.00 <200 368 200-330 153 330-500 127 500-1,000 128 1,000-1,500 14 >1,500 6 Av e r a g e M o n t h l y B i l l I m p a c t o v e r Cu r r e n t R a t e s , $ kWh/month # Service Accounts CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 38 The table below shows the average monthly bill increase and rate assistance needed to eliminate adverse bill impacts from the recommended rates. Also shown are the smallest estimated bill impacts (minimum, or “Min”) and highest estimated bill impacts (maximum, or “Max”). For example, if the recommended tiered energy rate is implemented, it is estimated that the average monthly bill for a RAP customer is $5.19 higher compared with current rate levels and rate design. The customer with the largest bill decrease will see an average of $32.75 less on their monthly bills while the customer with the largest bill increase will see an increase of $11.68/month on average. If all RAP bill increases are mitigated with additional assistance, the City can expect to increase RAP funding by $51,000 per year. This rate assistance would both support the 2% rate level increase and the rate design change. The City would fund this incremental increase to program spending with the PBC fund if necessary. TABLE 5-6: LOW INCOME MONTHLY BILL IMPACT AND RATE ASSISTANCE NEED ESTIMATES Impacts Recommended Tiered Energy Rate Average Bill Impact: $5.19 Min: -$32.75 Max: $11.68 Rate Assist. Need: $51,000/yr 5.3 SMALL COMMERCIAL E-2 The current E-2 rate is a seasonal rate with energy charges only. The seasonal Commodity component of the rate is based on actual seasonal Commodity costs. Distribution demand costs are split into summer and winter based on the average and excess method where summer receives a higher allocation consistent with higher summer peak demands. Distribution customer costs are shared equally across seasons. Table 5-7 shows the current and recommended rates. TABLE 5-7: CURRENT AND RECOMMENDED E-2 RATES Commodity Distribution PBC Total Current Rates Summer, $/kWh $0.14216 $0.11775 $0.00568 $0.26559 Winter, $/kWh $0.10196 $0.07861 $0.00568 $0.18625 Recommended Rates Summer, $/kWh $0.14926 $0.09735 $0.00549 $0.25211 Winter, $/kWh $0.09242 $0.06623 $0.00549 $0.16415 Customer Charge, $/month $5.60 COSA Rate Adjustment -6.1% Just as in the E-1 rate design, the recommended customer charge recovers customer billing and meter reading costs. Figures 5-6 and 5-7 illustrate the monthly bill impact from a percent change perspective as well as dollar amount. While the lowest usage groups experience high bill impacts from a % change perspective, the dollar amount is less than $2 per month on average. CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 39 FIGURE 5-6: E-2 BILL IMPACTS FIGURE 5-7: E-2 BILL IMPACTS, $/MONTH 5.4 MEDIUM COMMERCIAL E-4 The E-4 rate schedule, as shown in Table 5-8, is seasonal with a demand component. As mentioned previously, there is also an optional TOU option for E-4. The default E-4 rate separates Commodity costs into summer and winter seasons based on actual seasonal costs. Local capacity costs (resource adequacy) are allocated to summer rates only. Other demand-related Commodity costs are allocated to both summer and winter based on kW. Distribution customer costs are the same across seasons. Billing and metering costs are collected through the customer charge. Distribution demand costs are allocated to each season based on average and excess where summer receives a larger allocation. 378% 48% -4%-6%-7%-7%-50% 0% 50% 100% 150% 200% 250% 300% 350% 400% <0 17 0-500 1,687 500-1,000 545 1,000-2,000 510 2,000-3,000 255 >3,000 382 Ra t e I m p a c t o v e r C u r r e n t R a t e s kWh/Month Number of Service Accounts $0.92 $1.58 -$6.90 -$17.78 -$35.10 -$83.51-$90.00 -$80.00 -$70.00 -$60.00 -$50.00 -$40.00 -$30.00 -$20.00 -$10.00 $0.00 $10.00 <0 17 0-500 1,687 500-1,000 545 1,000-2,000 510 2,000-3,000 255 >3,000 382 Av e r a g e M o n t h l y B i l l I m p a c t o v e r Cu r r e n t R a t e s , $ kWh/Month Number of Service Accounts CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 40 TABLE 5-8: CURRENT AND RECOMMENDED E-4 RATES Commodity Distribution PBC Total Current Rates Summer, $/kWh $0.13157 $0.02638 $0.00568 $0.16363 Winter, $/kWh $0.09461 $0.02638 $0.00568 $0.12667 Summer, $/kW-month $5.28 $31.54 $36.82 Winter, $/kWh-month $3.29 $20.87 $24.16 Recommended Rates Summer, $/kWh $0.12318 $0.02520 $0.00549 $0.15387 Winter, $/kWh $0.07949 $0.02520 $0.00549 $0.11018 Summer, $/kW-month $10.98 $34.31 $45.29 Winter, $/kW-month $2.57 $21.16 $23.73 Customer Charge, $/month $113.73 COSA Rate Adjustment -1.9% Summer demand rates are increased significantly due to local capacity costs equaling a larger share of total power-related demand costs. 5.5 E-4 TOU As solar has penetrated the market, daytime prices have become the lowest priced time to purchase energy. Table 5-9 compares the current and recommended TOU periods. The peak period is both the maximum priced energy period (for purchases of wholesale energy), and the City’s system peak has occurred within this period in each month over the previous 3 years. Capacity requirements are set based on system peaks during this time period. The mid peak period represents mid-afternoon and or late evening periods when energy costs are lower. Off peak periods represent all other hours and the lowest energy prices. All weekends and federal holidays are considered off peak. TABLE 5-9: PRESENT AND RECOMMENDED TOU PERIODS Current TOU Periods Recommended TOU Periods Summer Winter Summer Winter Energy & Demand Energy Peak 12 – 6 PM M-F 8 AM- 9 PM M-F Peak 4-9 PM M-F 4-9 PM M-F Mid Peak 8 AM-12 PM, 6 PM- 9 PM M-F None Mid Peak 2-4 PM & 9-11 PM, M-F 9 AM-2 PM M-F Off Peak 9 PM- 8 AM M-F All Day Sat & Sun All Other Hours Off Peak All Other Hours All Other Hours Demand Peak 4-9 PM M-F 4-9 PM M-F Max Peak All Hours All Hours To illustrate why it is recommended to shift TOU periods, Table 5-10 compares the marginal cost of energy for the current and recommended TOU periods. These values are calculated by averaging hourly market prices over each period. These costs represent the value of energy if the City were to sell or purchase CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 41 wholesale energy within these time periods. The recommended TOU periods maintain the current seasons where Summer is May 1- October 31. Table 5-10 shows that the current TOU periods do not have a pricing differential in winter months. Also, under the current structure, summer mid peak is the most expensive period. TABLE 5-10: CURRENT AND RECOMMENDED TOU MARGINAL COSTS Marginal Cost, $/MWh Current TOU Periods Summer Peak (noon -6 pm M-F)$57.61 Summer Mid Peak (8 am - noon & 6 pm - 9 pm M-F $73.81 Summer Off Peak (9pm - 8 am M-F, all day Sat & Sun)$62.24 Winter Peak (8 am - 9 pm M-F)$48.00 Winter Off Peak (all other times)$48.00 Recommended TOU Periods Summer Peak (4-9 pm)$81.29 Summer Mid Peak (2-4 pm and 9 am - 11 pm)$66.99 Summer Off Peak (all other hours)$50.36 Winter Peak (4-9 pm)$63.51 Winter Mid Peak (9 am -2 pm)$50.13 Winter Off Peak (all other hours)$34.60 The recommended TOU rates adjust both the TOU periods and the demand billing methodology as shown in Table 5-11 below. The marginal costs from Table 5-10 (recommended TOU periods) are used to determine the commodity rate for each period. The current method applies demand charges for each TOU period. This design choice will incentivize customers to reduce demand during both peak and mid peak periods. However, demand rates contain largely fixed costs. The recommended rate provides a simplification where customers are still able to reduce costs by shifting usage away from peak periods, and the City will collect a larger share of its fixed distribution costs with a non-TOU demand charge. Said another way, the peak demand charge recovers the associated commodity costs plus a share of distribution costs attributed to maximum demand in summer months. The non-TOU demand charge collects distribution demand costs for average demand consumption. CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 42 TABLE 5-11: CURRENT AND RECOMMENDED E-4 TOU RATES Commodity Distribution PBC Total Current Rates Summer Peak (noon -6 pm M-F)$0.12020 $0.02636 $0.00568 $0.15224 Summer Mid Peak (8 am - noon & 6 pm - 9 pm M-F)$0.15204 $0.02636 $0.00568 $0.18408 Summer Off Peak (9pm - 8 am M-F, all day Sat & Sun)$0.09229 $0.02636 $0.00568 $0.12433 Winter Peak (8 am - 9 pm M-F)$0.14744 $0.02636 $0.00568 $0.17948 Winter Off Peak (all other times)$0.12619 $0.02636 $0.00568 $0.15823 Summer Peak Period Demand, $/kW-month $3.22 $10.85 $14.07 Summer Mid Peak Period Demand, $/kW-month $1.11 $10.85 $11.96 Summer Off Peak Demand, $/kW-month $1.11 $10.85 $11.96 Winter Peak Period Demand, $/kW-month $1.83 $11.63 $13.46 Winter Off-Peak Demand, $/kW-month $1.83 $11.63 $13.46 Recommended Rates Customer Charge, $/month $113.73 Summer Peak (4-9 pm)$0.17038 $0.02538 $0.00549 $0.20125 Summer Mid Peak (2-4 pm and 9-11 pm)$0.14041 $0.02538 $0.00549 $0.17128 Summer Off Peak (all other hours)$0.10556 $0.02538 $0.00549 $0.13643 Winter Peak (4-9 pm)$0.11976 $0.02500 $0.00549 $0.15025 Winter Mid Peak (9 am -2 pm)$0.09452 $0.02500 $0.00549 $0.12501 Winter Off Peak (all other hours)$0.06525 $0.02500 $0.00549 $0.09574 Summer Peak Period Demand, $/kW-month $9.72 $17.18 $26.90 Summer Max Demand, $/kW-month $1.29 $17.18 $18.47 Winter Peak Period Demand, $/kW-month $1.30 $10.73 $12.03 Winter Max Demand, $/kW-month $1.30 $10.73 $12.03 Since the majority of commodity-related demand costs are from local resource adequacy purchases (capacity), the commodity portion is low in winter months and off-peak summer periods. High summer peak period demand charges reflect the marginal costs for demand requirements during the most expensive periods. The local RA cost is based on the City’s system peak demand, which occurs during the 4 pm to 9 pm peak period in the summer. The TOU rate designs allocate costs seasonally using the same methodology as the underlying non-TOU rate designs, but they also take into account hourly variations in energy prices. Most generating capacity costs are allocated to the summer peak periods, since the City’s system peak demand occurs during that time. Most of the City’s resource adequacy (generating capacity) costs result from requirements imposed by the CAISO based on the City’s annual system peak demand. Resource Adequacy costs are allocated to the peak periods based on the impact peak demand has on those costs. 5.6 LARGE COMMERCIAL E-7 The E-7 rate schedule is seasonal with a demand component. The E-7 rate separates Commodity costs into summer and winter seasons based on actual seasonal costs. Local RA (capacity costs) are allocated to summer rates only. Other power-demand costs are allocated to both summer and winter based on kW. CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 43 Billing and metering costs are recovered through the recommended customer charge. Other Distribution customer costs are the same across seasons. Distribution demand costs are allocated to each season based on average and excess where summer receives a larger allocation consistent with higher summer usage which drives distribution system costs. Note that distribution demand costs are spread more evenly across seasons due to flatter seasonal load profiles for E-7 customers. TABLE 5-12: CURRENT AND RECOMMENDED E-7 RATES Commodity Distribution PBC Total Current Rates Summer, $/kWh $0.13917 $0.00075 $0.00568 $0.14560 Winter, $/kWh $0.09212 $0.00075 $0.00568 $0.09855 Summer, $/kW-month $6.03 $33.05 $39.08 Winter, $/kWh-month $3.46 $18.25 $21.71 Recommended Rates Summer, $/kWh $0.12659 $0.00362 $0.00549 $0.13570 Winter, $/kWh $0.07894 $0.00354 $0.00549 $0.08797 Summer, $/kW-month $11.95 $28.41 $40.36 Winter, $/kW-month $2.79 $25.00 $27.79 Customer Charge, $/month $520.80 COSA Rate Adjustment -1.4% 5.6.1 E-7 TOU The recommended TOU rates adjust both the TOU periods and the demand billing methodology in the same manner as the recommended E-4 TOU rate. CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 44 TABLE 5-13: CURRENT AND RECOMMENDED E-7 TOU RATES Commodity Distribution PBC Total Current Rates Summer Peak (noon -6 pm M-F)$0.14457 $0.00075 $0.00568 $0.15100 Summer Mid Peak (8 am - noon & 6 pm - 9 pm M-F)$0.18205 $0.00075 $0.00568 $0.18848 Summer Off Peak (9pm - 8 am M-F, all day Sat & Sun)$0.11171 $0.00075 $0.00568 $0.11814 Winter Peak (8 am - 9 pm M-F)$0.09697 $0.00075 $0.00568 $0.10340 Winter Off Peak (all other times)$0.08323 $0.00075 $0.00568 $0.08966 Summer Peak Period Demand, $/kW-month $3.86 $11.08 $14.94 Summer Mid-Peak Period Demand, $/kW-month $1.13 $11.08 $12.21 Summer Off-Peak Demand, $/kW-month $1.13 $11.08 $12.21 Winter Peak Period Demand, $/kW-month $1.78 $9.22 $11.00 Winter Off-Peak Demand, $/kW-month $1.78 $9.22 $11.00 Recommended Rates Customer Charge, $/month $520.80 Summer Peak (4-9 pm)$0.18019 $0.00362 $0.00549 $0.18930 Summer Mid Peak (2-4 pm and 9-11 pm)$0.14850 $0.00362 $0.00549 $0.15761 Summer Off Peak (all other hours)$0.11164 $0.00362 $0.00549 $0.12075 Winter Peak (4-9 pm)$0.12104 $0.00354 $0.00549 $0.13007 Winter Mid Peak (9 am -2 pm)$0.09552 $0.00354 $0.00549 $0.10455 Winter Off Peak (all other hours)$0.06594 $0.00354 $0.00549 $0.07497 Summer Peak Period Demand, $/kW-month $11.28 $14.71 $25.99 Summer Max Demand, $/kW-month $1.45 $14.71 $16.16 Winter Peak Period Demand, $/kW-month $1.45 $12.99 $14.44 Winter Max Demand, $/kW-month $1.45 $12.99 $14.44 The ratio of distribution demand costs collected through the Peak Period Demand charge to those collected through the Max Demand charge is determined based on load profile data. The Max Demand charge collects costs that were allocated based on the non-coincident peak (NCP) of the customer class. Just over half (52%) of all costs allocated under the recommended rate design are based on customer maximum peak (NCP). Therefore, 52% of demand-related distribution costs are collected through the Max Demand charge. The remaining 48% are collected through the Peak Demand charge. For summer demand charges these calculations coincidentally resulted in an identical distribution demand charge for both the Peak and Max Demand charge.. Table 5-14 illustrates the demand billing determinants assuming the entire E-7 class is on the TOU schedule. TABLE 5-14: TOU E-7 BILLED DEMAND ASSUMPTIONS Share of Total Billed Demand Estimated Class Billing Determinant, kW Summer Winter Summer Winter Peak Demand 48.2%48.0%283,362 280,165 Max Peak Demand (NCP)51.8%52.0%304,237 303,152 CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 45 5.7 PUBLIC BENEFITS CHARGE Public Utilities Code Section 385 requires all POUs to have a public benefits charge built into their rates. The rate must recover revenue equal to a set percentage of all other sales revenue based on a formula in that law. Most California POUs have interpreted this formula to require collection of an additional 2.85% of sales revenue for this purpose, as has the City. The revenue collected must be spent on a specified set of energy efficiency and other demand-side measures, including: 1) demand side-management services to promote efficiency and conservation, 2) new investment in renewable energy and technologies, 3) research and development programs for the public interest, and 4) services and discounts for low income electricity customers. The public benefits charge is collected as a flat charge assessed on every kWh that results in the revenue level described above. The FY 2024-25 Public Benefits Charge is calculated at $0.00568/kWh. 5.8 STREET LIGHTING AND TRAFFIC SIGNALS The City’s electric utility also provides lighting and traffic signal maintenance services, which are captured in the E-14 Street Lights schedule. These services are primarily provided to the City itself, but also to a few other governmental agencies. Table 5-17 shows the updated lighting rates based on current rates adjusted by the 9.8% rate reduction. Maintenance Class A indicates that the City provides electricity and switching service only. Maintenance Class C indicates that the City supplies electricity, switching, and maintains the lighting system including lamps and glassware. TABLE 5-17: SCHEDULE E-14 RECOMMENDED RATES Maintenance Class Lamp Rating Current Rate $/mo. Recommended Rate $/mo. A HPS 100W $6.21 $5.60 A HPS 200W $11.46 $10.34 A HPS 250W $14.08 $12.70 A HPS 310W $17.42 $15.72 A HPS 400W $22.43 $20.24 C Mercury-Vapor 400W $35.83 $32.33 C HPS 70W $32.97 $29.75 C HPS 100W $34.55 $31.17 C HPS 150W $37.17 $33.54 C HPS 250W $42.42 $38.27 C LED 70W-EQ $29.48 $26.60 C LED 100W-EQ $30.68 $27.68 C LED 150W-EQ $31.77 $28.66 C LED 250W-EQ $34.78 $31.38 CITY OF PALO ALTO Electric Cost of Service and Rate Study – Draft Report prepared by EES CONSULTING 46 6 Technical Appendix 3 6 6 3 FY 2025 ELECTRIC UTILITY FINANCIAL PLAN FY 2025 TO FY 2029 2 | P a g e FY 2025 ELECTRIC UTILITY FINANCIAL PLAN FY 2025 TO FY 2029 TABLE OF CONTENTS Section 1: Definitions and Abbreviations.................................................................................4 Section 2: Executive Summary and Recommendations............................................................5 Section 2A: Overview of Financial Position..................................................................................5 Section 2B: Summary of Proposed Actions................................................................................10 Section 3: Detail of FY 2023 Rate and Reserves Proposals......................................................11 Section 3A: Rate Design.............................................................................................................11 Section 3B: Current and Proposed Rates...................................................................................11 Section 3C: Bill Impact of Proposed Rate Changes....................................................................14 Section 3D: Proposed Reserve Transfers ...................................................................................15 Section 4: Utility Overview....................................................................................................17 Section 4A: Electric Utility History.............................................................................................17 Section 4B: Customer Base........................................................................................................20 Section 4C: Distribution System.................................................................................................20 Section 4D: Cost Structure and Revenue Sources......................................................................21 Section 4E: Reserves Structure..................................................................................................22 Section 4F: Competitiveness......................................................................................................23 Section 5: Utility Financial Projections...................................................................................24 Section 5A: Load Forecast .........................................................................................................24 Section 5B: FY 2018 to FY 2022 Cost and Revenue Trends........................................................26 Section 5C: FY 2022 Results.......................................................................................................28 Section 5D: FY 2023 Projections................................................................................................28 Section 5E: FY 2024 – FY 2028 Projections................................................................................29 Section 5F: Risk Assessment and Reserves Adequacy................................................................31 3 | P a g e Section 5G: Long-Term Outlook.................................................................................................36 Section 5H: Alternative Rate Projections...................................................................................38 Section 6: Details and Assumptions.......................................................................................38 Section 6A: Electricity Purchases...............................................................................................38 Section 6B: Operations..............................................................................................................40 Section 6C: Capital Improvement Program (CIP).......................................................................41 Section 6D: Debt Service............................................................................................................42 Section 6E: Equity Transfer........................................................................................................44 Section 6F: Wholesale Revenues and Other Revenues..............................................................44 Section 6G: Sales Revenues.......................................................................................................44 Section 7: Communications Plan............................................................................................46 Appendices............................................................................................................................47 Appendix A: Electric Utility Financial Forecast Detail................................................................48 Appendix B: Electric Utility Reserves Management Practices ...................................................52 Appendix C: Description of Electric utility Operational Activities..............................................58 Appendix D: Samples of Recent Electric Utility Outreach Communications..............................59 4 | P a g e SECTION 1: DEFINITIONS AND ABBREVIATIONS CAISO California Independent System Operator CARB California Air Resources Board CIP Capital Improvement Program CPAU City of Palo Alto Utilities Department CPUC California Public Utilities Commission CVP Central Valley Project GWh a gigawatt-hour, equal to 1,000 MWh or 1,000,000 kWh. Commonly used for discussing total monthly or annual electric load for the entire city, or the monthly or annual output of an electric generator. kWh a kilowatt-hour, the standard unit of measurement for electricity sales to customers. kW a kilowatt, a unit of measurement used in reference a customer’s peak demand (the highest 15 minute average consumption level in a month), which is used for billing large and mid-size commercial customers. kV a kilovolt, one thousand volts, a unit of measurement of the voltage at which a section of the distribution system operates. The transmission system operates at 115-500 kV, and this is lowered to 60 kV in the sub-transmission section of the Electric Utility’s distribution section, then 12 kV or 4 kV in the rest of the distribution system, and finally 120, 240, or 480 volts at the electric outlet. MWh a megawatt-hour, equal to 1,000 kWh. Commonly used for measuring wholesale electricity purchases. MW a megawatt, equal to 1,000 kW. Commonly used when discussing maximum electricity demand for all customers in aggregate. PG&E Pacific Gas and Electric REC Renewable Energy Certificate RPS Renewable Portfolio Standard Sub-transmission System: The section of the Electric Utility’s distribution system that operates at 60 kV and which interfaces with PG&E’s transmission system. Transmission System: Sections of the electric grid that operate at high voltages, generally 115 kV or more. The voltage at the intersection of the Electric Utility’s distribution system and PG&E’s transmission system is 115 kV. The Electric Utility does not own or operate any transmission lines. UCC Utility Control Center SCADA Supervisory Control and Data Acquisition system, the system of sensors, communications, and monitoring stations that enables system operators to monitor and operate the system remotely. WAPA, or Western: Western Area Power Administration, the agency that markets power from CVP hydroelectric generators and other hydropower owned by the Bureau of Reclamation. 5 | P a g e SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS This document presents a Financial Plan for the City of Palo Alto (City) Electric Utility for the next five-year forecast, FY 2025 - 2029. This Financial Plan describes how revenues will cover the costs of operating the utility safely over that time while adequately investing for the future. It also addresses the financial risks facing the utility over the short term and long term and includes measures to mitigate and manage those risks. SECTION 2A: OVERVIEW OF FINANCIAL POSITION From July 2019 through April 2022 the City did not increase rates, to mitigate the economic impact of the COVID-19 pandemic on residents and businesses. In that time supply and distribution expenses increased $50 million (30%). The expense increases combined with pandemic-related electricity sales revenue declines created a $43 million shortfall in FY 2022. Some of this was related to the impacts of extreme drought and rising electricity market prices, and in response, the City activated the hydroelectric rate adjuster (E-HRA) in April 2022. In 2023 the City began increasing base rates to begin recovering costs, starting with a 5% rate increase on July 1, 2022. The intent was to use loans from the Electric Special Projects Reserve and what Operations Reserves remained to phase in rate increases gradually. But in late 2022 electricity market prices increased at unprecedented levels, leading to the need to increase the hydroelectric rate adjuster on January 1, 2023 to match the cost of replacing hydroelectric power with market power. On July 1, 2023 the City removed the hydroelectric rate adjuster while increasing its base electric rate 21%, the net result of which was a 5% rate decrease. This was possible due to heavy rains in the winter of 2022 / 2023 and the receipt of a judgment in a lawsuit related to the City’s contract with the Western Area Power Administration for hydroelectric power from the Federal Central Valley Project. These two factors, combined with decreases in energy prices from the extreme winter 2022 / 2023 levels, enabled the City to replenish its reserves and stabilize rates at a level that fully recovers costs. This forecast assumes long-term power prices continue to remain elevated over FY 2022 and earlier levels based on forward market price curve projections from independent commodity brokers. To reduce hydroelectric-related volatility in the future, staff is now making its rate projections assuming that long-term “normal” production from the City’s hydroelectric resources is about 80% of historical average levels. In contrast to last year’s projection, this year’s forecast includes significant one-time electric supply net revenues in FY 2024 and FY 2025 due to two factors. First, the utility had higher than average surplus electric energy sales due to the high hydroelectric generation associated with the heavy rains for winter 2022 / 2023 (for FY 2024). Second, the utility had significant revenue due to sales of surplus resource adequacy (generating capacity) under favorable market conditions that are not expected to continue long term. These one-time revenues are allowing the City to add to its hydroelectric stabilization reserve, which can be used to minimize the rate impacts of the additional costs associated with future dry years where hydroelectric generation is low. 6 | P a g e There are also significant one-time costs in this forecast that were not in last year’s forecast. They include large one-time costs associated capital investment, including a major Hanover Substation upgrade and grid modernization. There is also a timing issue associated with the first budget for grid modernization. This project was budgeted in FY 2024, but the debt issuance is not expected to take place until FY 2025, so this $25 million project is impacting reserves. This will require a one-year $20 million additional loan from the Electric Special Projects Reserve in FY 2024 rather than the $10 million repayment of a previous loan that was planned. This Financial Plan includes repayment of the total $30 million in outstanding Electric Special Projects Reserve loans in FY 2025. Over the forecast period other costs are increasing as well. Cost increases include: •Increases in transmission costs •Increases in capital investment to replace aging infrastructure and modernize the electric grid •Increased operations costs •Debt service costs for grid modernization improvements and investments in fiber infrastructure to support AMI. Because of these long-term cost increases rates are projected to increase the median residential bill 8% in FY 2025 and 5% per year for FY 2026 through FY 2029. For July 1, 2024 (FY 2025) staff has worked with a consultant to complete a cost of service analysis (COSA) that showed the need for rate decreases for non-residential customers ranging from 1% to 6% due to shifts in consumption patterns related to the COVID-19 pandemic. As a result, net sales revenue for FY 2025 is expected to remain about the same as in FY 2024. Because the regional economy is still recovering from that pandemic, leading to uncertainties in future consumption patterns, staff intends to continue to update the cost of service model in future years as the recovery proceeds. It is possible that a lower than average increase will be needed for residential customers in future years as the recovery continues and a higher one for non-residential customers. There are some significant uncertainties in this forecast. Load is assumed to stay fairly flat in this forecast, with long-term declines in electric load offset by some load growth due to electrification and potential new data centers. If load growth exceeds expectations it could improve this forecast and reduce the size of future rate increases. On the other hand, if costs for electrification-related grid modernization and electrification programs exceed forecasts, which is quite possible given the high uncertainties involved in current cost projections, it could offset the benefits of increased load. Due to the cash flow issue related to the budgeting of the first grid modernization project (in FY 2024) and the timing of the first debt issuance (in FY 2025), the Electric Utility’s costs are high in FY 2024 and low in FY 2025. On average, though, the utility’s costs for these two years is lower than FY 2023 levels. Expenses are expected to rise in FY 2026 through FY 2029, in part due to increasing power supply purchase costs, and in part due to grid modernization expenses. The 7 | P a g e average increase in utility costs from FY 2025 to 2029 is 3% annually1 as shown in Table 1. Electric supply purchases continue to increase mainly due to rising transmission costs over the span of the financial plan and tightening requirements for resource adequacy.2 Overall supply costs are projected to increase at 3% per year on average from FY 2025 to FY 2029. Operations and maintenance costs are projected to increase by about 2% per year on average due to both inflation as well as salary and benefits increases. Capital improvement costs, including debt service for grid modernization, are projected to increase 3.6% per year from FY 2025 through FY 2029. Table 1: Electric Utility Expenses for FY 2023 to FY 2029 Expenses ($000)FY 2023 (act) FY 2024 (est)FY 2025 FY 2026 FY 2027 FY 2028 FY 2029 Power Supply Purchases 128,512 114,427 121,079 127,167 128,726 131,243 132,597 Operations 62,472 63,971 65,897 67,180 68,041 70,407 73,666 Capital - Rate Funded 21,656 66,884 0 15,143 14,671 12,688 13,089 Capital Debt Service 21 0 0 4,030 9,300 14,880 14,880 TOTAL 212,661 245,282 186,975 213,521 220,738 229,218 234,233 Table 2 below shows the proposed rates for FY 2025 and projections for FY 2026 through FY 2029. As noted above staff has completed a COSA and is proposing different rate changes for different customer classes in FY 2025 to align with the COSA results. Rates for non-residential customers will slightly decrease while rates for residential customers will increase. This is due to changes in consumption patterns related to the pandemic. Staff intends to continue to update the COSA model as the pandemic recovery continues which may result in additional rate adjustments by customer class in future years if consumption returns to historical patterns. Table 2: Projected Electric Rates, FY 2025 to FY 2029 Projection FY 2025 FY 2026 FY 2027 FY 2028 FY 2029 Current -6% to +8%3 5%5%5%5% Last Year 5%5%5%5%N/A Staff is proposing several significant transfers in FY 2024 due to some very significant one-time revenues and expenses that have affected reserves. One-time revenues include a $24 million refund from the successful litigation against the Bureau of Reclamation for overcharges related 1 Using the average of FY 2024 and FY 2025 for capital expenses. 2 Resource adequacy represents the cost of maintaining generating capacity to fulfill the California Independent System Operator’s capacity requirements assigned to the City. 3 Rates for individual customers may vary significantly from this projection based on their consumption patterns. 8 | P a g e to power purchases from the Central Valley Project as well as large one-time revenues related to resource adequacy sales, and large capital expenses related to grid modernization. As noted above, the capital expenses related to grid modernization are affecting the reserves in FY 2024, but this represents a temporary cash flow issue until the debt issuance to cover those expenses in FY 2025, at which time the reserves will be restored. However, as noted above, an internal loan from the Electric Special Projects Reserve will be required along with some inter-fund transfers. This will be added to the following $10 million in outstanding loans from prior years: •In FY 2018 Council approved (Staff Report 81864), a $10 million transfer from the Electric Special Projects (ESP) Reserve to the Operations Reserve to mitigate higher supply costs due to the drought, the costs of new renewable energy projects coming online and increasing transmission charges. $5 million was repaid in FY 2020 •In FY 2022 Council approved (Staff Report 13361, June 13, 2022), a $5 million transfer from the ESP Reserve to the Operations Reserve to avoid rate increases exceeding 5%. This Financial Plan includes the repayment of all $30 million in loans in FY 2025. In addition to the above transfers staff proposes to transfer $17 million to the Hydroelectric Stabilization Reserve in FY 2024 rather than $8.4 million (as was anticipated in the FY 2024 Electric Utility Financial Plan), bringing the balance to its target level and eliminating the chance that the hydroelectric rate adjuster will be activated if the winter of 2023/2024 ends up being dry. Rainfall patterns in California usually involve occasional above average hydroelectric years followed by multiple below-average years, so it is important to use the one-time revenues from wet years like the winter of 2022/2023 to replenish reserves and bring them above the target level. Lastly, this plan includes a $5 million transfer in FY 2025 from the Distribution Operations Reserve to the CIP Reserve to bring it above its minimum level. Table 4 shows the projected reserve transfers over the forecast period. 4 https://www.cityofpaloalto.org/files/assets/public/agendas-minutes-reports/reports/city- manager-reports-cmrs/year-archive/2017/8186.pdf 9 | P a g e Table 3: Reserves Starting and Ending Balances, Revenues, Expenses, Transfers To/(From) Reserves, Operations and Capital (CIP) Reserve Guideline Levels for FY 2023 to FY 2028 ($000) FY 2024 FY 2025 FY 2026 FY 2027 FY 2028 FY 2029 Starting Reserve Balances 1 Supply Operations 44,463 15,601 27,652 26,757 26,337 25,855 2 Distribution Operation (5,581)6,921 12,020 14,317 14,429 15,362 3 CIP Reserve 880 880 5,880 5,880 5,880 5,880 4 Electric Special Projects 20,149 149 30,149 32,149 34,149 36,149 5 Hydro Stabilization 400 17,400 17,400 17,400 17,400 17,400 6 Cap and Trade Program 2,231 3,231 4,941 6,151 7,231 8,141 7 Public Benefits 5,673 7,431 9,033 10,569 12,032 13,422 8 Low Carbon Fuel Standard (LCFS)6,713 4,053 1,486 --- 9 Electrific ation Reserve 4,500 4,500 4,500 4,500 4,500 4,500 Revenues 10 Supply 145,323 142,902 133,822 133,976 136,567 139,122 11 Distribution 71,803 69,511 75,545 82,068 88,469 92,046 12 Cap and Trade Revenues 3,016 2,992 2,999 3,024 3,013 3,039 13 Public Benefits Revenues 4,780 4,690 4,584 4,551 4,520 4,488 14 LCFS Revenues 1,100 1,120 1,232 1,355 1,400 1,400 15 Electrific ation Reserve Repayments ------ Transfers from Supply Operations Res erve to Other Res erves or to Distribution Fund 16 From/(To)Distribution Operation (58,000)26,000 -2,000 2,000 2,000 17 From/(To)Electric Special Projects 20,000 (30,000)(2,000)(2,000)(2,000)(2,000) 18 From/(To)Hydro Stabilization (17,000)----- 19 From/(To)Cap and Trade ------ 20: =16+17+18+19 Supply Operations Total (55,000)(4,000)(2,000)--- Transfers from Distribution Operations Res erve to Other Res erves or to Supply Fund 21 From/(To)Supply Operations 58,000 (26,000)-(2,000)(2,000)(2,000) 22 From/(To)CIP Reserve -(5,000)---- 23 From/(To)LCFS ------ 24: =21+22+23 Distribution Operations Total 58,000 (31,000)-(2,000)(2,000)(2,000) Expenses 25 Supply Funded Expenses (119,185)(126,851)(132,717)(134,396)(137,049)(139,289) 26 Distribution Non-CIP Expenses (50,482)(52,153)(58,105)(65,285)(72,848)(74,969) 27 Distribution Planned CIP Ex pense (66,884)18,655 (15,143)(14,671)(12,688)(13,089) 28 Cap and Trade Expenses (2,016)(1,282)(1,789)(1,944)(2,103)(2,309) 29 Public Benefits Expenses (2,956)(3,003)(3,049)(3,088)(3,130)(3,177) 30 LCFS Expenses (3,759)(3,687)(2,718)(1,355)(1,400)(1,400) 31 Electrific ation Reserve Expenditures ------ Ending Reserve Balance 32: =1+10+20+25 Supply Operations 15,601 27,652 26,757 26,337 25,855 25,687 33: =2+11+24+26+27 Distribution Operation 6,856 11,934 14,317 14,429 15,362 17,350 34: =3+22 CIP Reserve 880 5,880 5,880 5,880 5,880 5,880 35: =4+17 Electric Special Projects 149 30,149 32,149 34,149 36,149 38,149 36: =5+18 Hydro Stabilization 17,400 17,400 17,400 17,400 17,400 17,400 37: =6+12+19+28 Cap and Trade Program 3,231 4,941 6,151 7,231 8,141 8,871 38: =7+13+29 Public Benefits 7,497 9,119 10,569 12,032 13,422 14,733 39: =8+14+23+30 Low Carbon Fuel Standard 4,053 1,486 ---- 40: =9+15+31 Electrific ation Reserve 4,500 4,500 4,500 4,500 4,500 4,500 Operations Reserve Guidelines (Supply) Minimum 21,063 22,111 22,412 22,874 23,149 23,601 Max imum 42,126 44,221 44,824 45,749 46,297 47,202 Operations Reserve Guidelines (Dis tribution) Minimum 10,800 11,701 12,742 14,084 14,526 14,763 Max imum 17,736 19,382 21,303 23,821 24,530 24,824 CIP Reserve Guidelines Minimum 1,192 2,489 2,412 2,086 2,152 2,223 Max imum 5,962 13,898 13,494 13,494 13,494 13,494 10 | P a g e SECTION 2B: SUMMARY OF PROPOSED ACTIONS Staff recommends the City Council adopt a Resolution: 1. Approving the Fiscal Year (FY) 2025 Electric Financial Plan, which includes the following actions; a. Amending the Electric Utility Reserves Management Practices, to direct staff to transfer to the CIP reserve, at the end of each fiscal year, any budgeted capital investment that remains unspent, uncommitted, and which is not proposed for reappropriation to the following fiscal year and to clarify how the Cap and Trade Program Reserve is adjusted each year. b. Approving the following transfers at the end of FY 2024: i. Up to $20 million from the Electric Special Projects Reserve to the Supply Operations Reserve ii. Up to $17 million from the Supply Operations Reserve to the Hydroelectric Stabilization Reserve iii. Up to $58 million from the Supply Operations Reserve to the Distribution Operations Reserve; and c. Approving the following transfers in FY 2025: i. Up to $26 million from the Distribution Operations Reserve to the Supply Operations Reserve; and ii. Up to $30 million from the Supply Operations Reserve to the Electric Special Projects Reserve iii. Up to $5 million from the Distribution Operations Reserve to the CIP Reserve 2. Approving the following rate actions for FY 2025: a. Changing retail electric rates E-1 (Residential Electric Service), E-2 (Small Non- Residential Electric Service), E-4 (Medium Non-Residential Electric Service), E-4 TOU (Medium Non-Residential Time of Use Electric Service), E-7 (Large Non- Residential Electric Service), and E-7 TOU (Large Non-Residential Time of Use Electric Service) by varying percentages depending on rate schedule and consumption with an overall revenue increase of 0.5% effective July 1, 2024; b. Decreasing the Net Surplus Electricity Compensation (E-NSE-1) rate to reflect 2023 avoided cost, effective July 1, 2024; c. Decreasing the Export Electricity Compensation (E-EEC-1) rate to reflect current projections of FY 2025 avoided cost, effective July 1, 2024; and d. Updating the Residential Master-Metered and Small Non-Residential Green Power Electric Service (E-2-G), the Medium Non-Residential Green Power Electric Service (E-4-G), and the Large Non-Residential Green Power Electric Service (E-7-G) rate schedules to reflect modified distribution and commodity components, effective July 1, 2024. 11 | P a g e SECTION 3: DETAIL OF FY 2024 RATE AND RESERVES PROPOSALS SECTION 3A: RATE DESIGN The Electric Utility’s rates are evaluated and implemented in compliance with cost of service requirements set forth in the California Constitution and applicable statutory law. This Financial Plan is based on staff’s assessment of the financial position of the Electric Utility and updated using the methodology from the “City of Palo Alto Electric Cost of Service and Rate Study”5 drafted by EES Consulting, Inc. in 2023/2024. The COSA is also based on design guidelines adopted by Council on November 11, 2021 (Staff Report 13546). SECTION 3B: CURRENT AND PROPOSED RATES The City adopted the current rates effective July 1, 2023, when the City increased the electric base rates by 21% while simultaneously removing the hydroelectric rate adjuster for a net decrease of 5% in the overall rate. This large rate change was needed because the City did not increase rates during the COVID-19 pandemic and instead drew down reserves. While using reserves mitigated larger increases during the pandemic, costs continued to rise and higher rates were needed to recover costs. The City’s consultant has completed a review and revision of the Electric Utility’s Cost of Service study and rates. This study determined the rate changes needed for the residential and commercial classes to align them with the customer class cost of service identified in the study.. To ensure the median residential customer experiences no more than an 8% rate increase staff is recommending no revenue change for the electric utility this year, as discussed above. The current rates and proposed FY 2025 rates are reflected in Table 4 below: 5 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274 12 | P a g e Table 4: Current and Proposed Electric Rates Net Energy Metering Compensation Rates The City operates two Net Energy Metering (NEM) programs. Solar customers served by the City of Palo Alto's (CPAU) original NEM program, also called NEM 1, are compensated at retail rates for electricity they export to the grid, and solar customers served by the NEM successor program, or NEM 2 (effective after the City reached its NEM 1 cap at the end of 2017), are compensated at the Export Electricity Compensation (EEC-1) rate for exported electricity. Customers on the NEM 1 program who have chosen to have the value of any annual net generation they produced over the past 12 months credited back to their account do so under the Net Metering Net Surplus Electricity Compensation (E-NSE) rate. The Net Surplus Electricity Compensation rate represents the value of the City’s avoided cost or value of customer- generated electricity in Palo Alto, including compensation for the energy, avoided capacity charges, avoided transmission and ancillary service charges, avoided transmission and Propo sed Rates (7/1/2024)$% E-1 (Res idential ) Tier 1 Energ y ($/kWh)0.17522 0.19337 0.01815 10% Tier 2 Energ y ($/kWh)0.24666 0.20335 -0.04331 -18% Cus tomer Charg e ($/day)0.15250 0.15250 Summer Energ y ($/kWh)0.26560 0.25211 -0.01349 -5% Winter Energy ($/kWh)0.18626 0.16415 -0.02211 -12% Cus tomer Charg e ($/day)0.18410 0.18410 Summer Energ y ($/kWh)0.16363 0.15387 -0.00976 -6% Winter Energy ($/kWh)0.12667 0.11018 -0.01649 -13% Summer Demand ($/kW)36.82668 45.29000 8.46332 23% Winter Demand ($/kW)24.16296 23.73000 -0.43296 -2% Cus tomer Charg e ($/day)3.73900 3.73900 Summer Energ y ($/kWh)0.14561 0.13570 -0.00991 -7% Winter Energy ($/kWh)0.09856 0.08797 -0.01059 -11% Summer Demand ($/kW)39.08286 40.36000 1.27714 3% Winter Demand ($/kW)21.71270 27.79000 6.07730 28% Cus tomer Charg e ($/day)17.12210 17.12210 Cu rrent Rates Change E-2 & E-2-G (Smal l Non-Res idential) E-4 & E-4-G (Medium Non-Res idential) E-7 & E-7-G (Large Non-Res idential) 13 | P a g e distribution (T&D) losses, and renewable energy credits (RECs), or environmental attributes. Staff proposes decreasing the E-NSE-1 rate to $0.1427/kWh based on updated avoided cost calculations reflecting declines in long-term electricity market prices expected to continue into the future. Under the City’s NEM successor program, participating solar customers in Palo Alto are billed at the current retail rate for electricity drawn from the grid, and receive a credit for electricity they export to the grid at the Export Electricity Compensation (EEC-1) rate. This compensation rate also reflects the avoided cost or value of customer-generated electricity in Palo Alto, calculated on a forward-looking basis for the upcoming fiscal year. As shown in the table below, the current avoided cost for solar generation in Palo Alto is $0.1535/kWh, which is higher than the City’s projected avoided cost, which requires the proposed NEM compensation rate (E-EEC) to decrease to $0.1420/kWh. This decrease in the overall avoided cost is driven by changes in electricity market prices. Table 5: NEM Buyback Rates – Current vs. Proposed Rate Current $/kWh Proposed $/kWh Net Surplus Electricity (E-NSE)$0.1535 $0.1427 Export Electricity (E-EEC)$0.1685 $0.1420 Palo Alto Green (PAG) Program The Palo Alto Green (PAG) program provides CPAU’s commercial customers an opportunity to voluntarily pay a premium to receive renewable electricity credits to match their energy usage. Under this program, CPAU staff purchase and retire Green-e certified renewable energy certificates (RECs) in the wholesale market on behalf of PAG customers. This enables participating commercial customers to claim credit for the REC purchases in order to satisfy their corporate sustainability goals and meet federal “green certification” requirements. The PAG charge is a pass-through charge; the revenue collected through the PAG rate premium is intended to fully recover the costs of administering the program. The PAG program has very low overhead costs (e.g., the cost of hiring an auditor to carry out an annual Green-e verification process for the program), so most of the program cost is the purchase cost of the RECs. In the past year the wholesale cost of Green-e certified RECs in the Western US market has remained relatively flat at around $7.00/REC. As such, the PAG rate premium should remain at $7.5 per 1,000 kWh block (.75 cents/kWh), enough to cover the cost of the RECs and overhead. The PAG rate premium is reflected on the Residential Master-Metered and Small Non-Residential Green Power Electric Service (E-2-G), the Medium Non-Residential Green Power Electric Service (E-4- G), and the Large Non-Residential Green Power Electric Service (E-7-G) rate schedules. 14 | P a g e SECTION 3C: BILL IMPACT OF PROPOSED RATE CHANGES Table 6 shows the impact of the proposed July 1, 2024 rate changes on the residential and non- residential bills for various consumption levels. The rate changes vary by customer class due to the completion of a cost of service analysis as noted in Section 3B: Current and Proposed Rates. Because of the addition of a customer charge and the changes in the design of the tiers for the E-1 customer class usage in this class varies widely depending on consumption, generally increasing for customers who use less electricity and decreasing for those who use more. The increase for the median residential customer is about 8%. This trend is expected to continue when the utility moves to time of use rates, which provides prices that vary by time of day rather than by how much electricity a customer uses in a month. It is worth noting, however, that increases among low users, while large in percentage terms, are small in absolute dollar terms (no more than $10.63 per month, and most low users will see less of an increase than that). For residents in need, staff is investigating whether it is possible to adjust the rate assistance program to offset these increases. For more on comparisons of rates with surrounding agencies, see Section 4F: Competitiveness below. Table 6: Impact of Proposed Electric Rate Changes on Customer Bills Bill under Change Rate Schedule Usage (kWh/mo) Peak Demand (kW-mo) Current Rates ($/mo) Bill Under Rates Proposed 7/1/24 ($/mo)$/mo % 300 N/A $52.57 $62.65 $10.08 19% (Summer Median) 365 N/A $66.46 $75.22 $8.76 13% (Winter Median) 453 N/A $88.16 $92.24 $4.07 5% 650 N/A $136.75 $135.61 ($1.14)-1% E-1 (Residential) 1200 N/A $272.42 $257.34 ($15.07)-6% E-2 (Small Non- Residential) 1,000 N/A $225.93 $213.73 ($12.20)-5% 160,000 274 $31,580 $30,693 ($887)-3%E-4 (Medium Non- Residential) 500,000 856 $98,680 $95,667 ($3,014)-3% E-7 (Large Non- Residential 2,000,000 3,424 $348,247 $340,864 ($7,383)-2% 15 | P a g e SECTION 3D: PROPOSED RESERVE TRANSFERS Staff is proposing various reserve transfers to manage a one-year cash flow issue related to the grid modernization project. The first $25 million phase of the project was budgeted in the FY 2024 fiscal year, while the first debt issuance associated with the project is expected in FY 2025. This will have a negative impact on the distribution operation reserve in FY 2024. Without transfers from other reserves the distribution operations reserve would be significantly negative by the end of FY 2024. Fortunately, one-time revenues associated with a $24 million judgment from successful litigation against the Bureau of Reclamation (recognized in FY 2023 in the Supply Operations Reserve, leaving it close to the maximum reserve guideline) will help manage this cash flow issue, along with a one-year internal loan from the Electric Special Projects reserve. In the FY 2024 Electric Utility Financial Plan staff had intended to repay an earlier $10 million in internal loans from the Electric Special Projects Reserve in FY 2024. Instead, staff recommends postponing that loan repayment until FY 2025 and taking an additional $20 million in internal loans from the reserve for one year. The following transfers are proposed: •In FY 2024, to keep the distribution operations reserve from going negative: o A transfer of $20 million from the Electric Special Projects Reserve to the Supply Operations Reserve o A transfer of $58 million from the Supply Operations Reserve to the Distribution Operations Reserve •In FY 2025, to repay the internal loans from the Electric Special Projects Reserve and replenish the Supply Operations Reserve: o A transfer of $20 million from the Distribution Operations Reserve to the Supply Operations Reserve o A transfer of $30 million from the Supply Operations Reserve to the Electric Special Projects Reserve The FY 2025 transfers are tentative and may need to be adjusted in the FY 2026 Financial Plan based on the results for the FY 2024 and FY 2025 fiscal years. The electric utility is also experiencing one-time sales revenues and supply cost savings in FY 2024 related to high hydroelectric generation resulting from the rainy winter of 2022/2023. In addition, current market conditions are enabling the utility to realize higher than usual sales revenue related to surplus resource adequacy and REC sales in FY 2024, FY 2025, and FY 2026. Staff is recommending using these one-time revenues to replenish the hydroelectric stabilization reserve, bringing it to $17.4 million, a level which will allow the City to avoid having to activate the hydroelectric rate adjuster if upcoming winters are drier than average. There are repayments of $2 million per year from FY 2026 through FY 2030 to the ESP Reserve for loans to the electric, gas, and fiber utilities for AMI investments. The City maintains a Cap and Trade Program Reserve within the Electric fund to hold any 16 | P a g e revenues from the sale of carbon allowances freely allocated by the California Air Resources Board to the City’s electric utility that are not spent within the fiscal year. Cap and Trade Program revenues are provided to the electric utility to support a wide variety of carbon reducing activities. Until the establishment of the REC Exchange program, adopted by Council in August 2020 (Staff Report #11556),6 all of this Cap and Trade Program revenue was spent on purchasing renewable energy and none was held in reserve. In accordance with Council’s August 2020 direction, the City has begun selling City-owned renewable energy (Category 1 RECs, which mostly represent in-state renewable energy) and replacing them with purchased Category 3 RECs, which represent mostly out of state electricity. This exchange takes advantage of market conditions to reduce supply costs, fund electric utility programs and capital investment, and raise funds for local emissions reduction. On December 12, 20227 Council approved continuation of the program with 100% of revenue going to local emissions reduction. In accordance with Council policy, staff will fund the Cap and Trade Program Reserve with unspent revenues from the sale of carbon allowances freely allocated to the electric utility in an amount equal to 100% of each FY’s Renewable Energy Credit (REC) Exchange program revenues, currently estimated to be between $0.7 million and $1.7 million going forward, for future local decarbonization projects. Figure 8 (for Supply Fund Reserves) and Figure 9 (for Distribution Fund Reserves) in Section 5E: FY 2025 – FY 2029 Projections show the impact of these transfers on reserves levels. Table 7 shows the projected balance of each of the Electric Utility reserves for the period covered by this Financial Plan. See also: Appendix A: Electric Utility Financial Forecast Detail 6Staff Report 11556 https://www.cityofpaloalto.org/civicax/filebank/documents/78046 7https://cityofpaloalto.primegov.com/Public/CompiledDocument?meetingTemplateId=8715&c ompileOutputType=1 Staff Report 14735 Item 3, Agenda Item 3, Utilities Advisory Commission Recommend the City Council Affirm the Continuation of the REC Exchange Program, Staff Report #14375 17 | P a g e Table 7: End of Fiscal Year Electric Utility Reserve Balances for FY 2023 to FY 2029 SECTION 4: UTILITY OVERVIEW This section provides an overview of the utility and its operations. It is intended as general background information to help readers better understand the forecasts in Section 5: Utility Financial Projections and Section 6: Details and Assumptions. SECTION 4A: ELECTRIC UTILITY HISTORY On January 16, 1900, Palo Alto began operating its own electric system. One of the earliest sources of Palo Alto's electricity was a steam engine, which was later replaced by a diesel engine in 1914 due to rising fuel oil costs. As the population and the demand for electricity continued to grow, CPAU connected to PG&E’s system in the early 1920s. Power from PG&E proved more economical than the diesel engines, and by the late 1920s CPAU was using its own diesel engines only during peak demand periods. At that time CPAU owned 45 miles of distribution lines and the City used 9.7 GWh annually, less than 1% of today’s annual consumption. The diesel engines remained in operation until 1948, when they were retired. From 1950 to 1970 electric consumption in Palo Alto grew dramatically, just as it did throughout the rest of the country. In 1970 total annual sales were 602 GWh, twenty times the sales in 1950 (30 GWh). Some of that growth was related to a development boom in Palo Alto, which doubled the number of customers. Some was related to the proliferation of electric appliances, as evidenced by the fact that residential customers were using three times more electricity in 1970 than they had been in 1950. But the most notable factor was the growth of industry in Palo Alto Ending Rese rve Balance ($000)FY 2023 (Act)FY 2024 FY 2025 FY 2026 FY 2027 FY 2028 FY 2029 Re-a ppropri a ti ons 253 253 253 253 253 253 253 Commi tments 9,400 9,400 9,400 9,400 9,400 9,400 9,400 Low Ca rbon Fuel Sta nda rd (LCFS) 6,713 4,053 1,486 - - - - Ca p a nd Tra de 2,231 3,231 4,941 6,151 7,231 8,141 8,871 Under ground Loa n 727 727 727 727 727 727 727 Publ i c Benefi ts 5,673 7,431 9,033 10,569 12,032 13,422 14,733 Spec i a l Proj ec ts 20,149 149 30,149 32,149 34,149 36,149 38,149 Hydr o Sta bi l i za ti on 400 17,400 17,400 17,400 17,400 17,400 17,400 Ca pi ta l 880 880 5,880 5,880 5,880 5,880 5,880 Ra te Sta bi l i za ti on - - - - - - - Di s tr i buti on a nd Suppl y Oper a ti ons 38,882 22,522 39,672 41,074 40,766 41,216 43,037 Una s s i gned - - - - - - - TOTAL 85,306 66,046 118,941 123,602 127,837 132,588 138,449 18 | P a g e during that time. By 1970, commercial customers were using 20 times more electricity per customer than they had been in 1950. These decades also saw several other notable events, including: •1964: CPAU entered into a favorably priced 40-year contract with the Federal Bureau of Reclamation to purchase power from the Central Valley Project (CVP), a contract which later was managed by the Western Area Power Administration (WAPA) an office of the Department of Energy created in the 1970s to market power from various hydroelectric projects operated by the Federal Government, including the CVP. •1965: The City began a long-term program to underground its overhead utility lines (Ordinance 2231). •1968: Palo Alto joined several other small municipal utilities to form the Northern California Power Agency (NCPA), a joint action agency intended to make the group less vulnerable to actions by private utilities and to enable investment in energy supply projects. Palo Alto’s first new power plant investment in over 50 years came in the mid-80s. Palo Alto joined other NCPA members to invest in the construction and operation of the Calaveras Hydroelectric Project on the Stanislaus River in the Sierra-Nevada Mountains. The project commenced operation in 1990. The 1980s also saw an increased focus on infrastructure maintenance. In 1987 the Utilities Control Center was built to house the terminals for a new System Control and Data Acquisition system, which enabled utility staff to monitor the distribution system in real time, improving response time to outages. CPAU also commenced a preventative maintenance and planned replacement program for its underground system in the early 1990s. In the early 1990s the CPUC issued a ruling to deregulate the electric industry in California, and in 1996 the State legislature passed Assembly Bill 1890, which, among other things, created the California Independent System Operator (CAISO) to operate the transmission system and the Power Exchange to facilitate wholesale energy transactions. This restructuring was anticipated to bring lower costs to consumers, and while CPAU was not required to participate in the industry restructuring, in 1997 the Council approved a Direct Access Program for the Electric Utility8 that enabled CPAU to sell electricity outside its service territory and allowed customers within CPAU’s service territory to choose other providers. The utility unbundled its electric rates, creating separate supply and distribution components, which would enable customers to receive only distribution service while purchasing the electricity itself from another provider. The energy crisis in 2000 to 2001 led to the suspension of direct access by the CPUC in September 2001 as wholesale energy prices skyrocketed. The Electric Utility was less impacted than other utilities by the 2000 to 2001 energy crisis thanks to the Calaveras project and its contract with WAPA for CVP hydropower. 8 Implementation of Direct Access for Electric Utility Customers, CMR:460:97, December 1, 1997 19 | P a g e In 2001 CPAU began planning for the impacts associated with the new terms of its contract with WAPA, set to take effect in 2005. The previous contract had provided 90% of Palo Alto’s power supply at favorable rates, and PG&E, as a party to the contract, had provided supplemental power to balance the monthly and annual variability of CVP generation. The new contract would provide only a third of Palo Alto’s requirement, and the monthly and annual variability in CVP generation would be passed directly to Palo Alto. As a result, electric supply costs would increase and CPAU needed to manage its supply portfolio more actively. CPAU began purchasing power from marketers and investigated building a power plant in Palo Alto or partnering in the development of a gas-fired power plant elsewhere. Climate change was also becoming more of a concern to the community, and gradually CPAU shifted its focus to the procurement of renewable energy. In 2002 the Council adopted a goal of achieving 20% of its energy supply from renewables by 2015. Subsequently the City signed its first contract for renewable power, a contract for energy from a wind generator commencing deliveries in 2005. In 2011 the renewable energy goal was increased to at least 33% by 2015, and in 2013 the City adopted a plan to make its electric supply 100% carbon neutral, which it achieves through the combination of its carbon-free hydroelectric supplies, purchases of long-term renewable energy supplies, and short-term RECs to meet the balance of its needs. 20 | P a g e SECTION 4B: CUSTOMER BASE The City of Palo Alto’s Electric Utility provides electric service to the residents, businesses, and other electric customers in Palo Alto. There are about 29,700 customers connected to the electric system, 25,600 (86%) of which are residential and 4,100 (14%) of which are non-residential. Residential customers consumed 157 gigawatt-hours (GWh) in FY 2022, approximately 19% of the electricity sold, while non-residential customers consumed 81% or 669 GWh. Residential customers use electricity primarily for lighting, refrigeration, electronics, and air conditioning.9 Non-residential customers use most of their electricity for cooling, ventilation, lighting, office equipment (offices), cooking (restaurants), and refrigeration (grocery stores).10 As shown in Figure 1, large customer loads represent the biggest proportion of sales for the Electric Utility. The proportion of sales to large vs. small customers is greater than for the City’s other utilities. For example, the largest customers (the 70 customers on the E-7 rate schedule) account for about 42% of CPAU’s sales. The next largest customer group (the 890 non-residential customers on the E-4 rate schedule) represents another 33% of sales. In total, that means that about 3% of customers account for about three quarters of the electric load. SECTION 4C: DISTRIBUTION SYSTEM The Electric Utility receives electricity at a single connection point with PG&E’s transmission system. From there the electricity is delivered to customers through nearly 472 miles of distribution lines, of which 211 miles (45%) are overhead lines and 261 miles (55%) are underground. The Electric Utility also maintains nine substations, roughly 2,000 overhead line transformers, around 1,100 underground and substation transformers, and the associated electric services (which connect the distribution lines to the customers’ homes and businesses). These lines, substations, transformers, and services, along with their associated poles, meters, and other associated electric equipment, represent the vast majority of the infrastructure used to deliver electricity in Palo Alto. 9 Source: Residential Appliance Saturation Survey, California Energy Commission, 2010 10 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006. Figure 1: Customer Consumption By Class (FY 2023) 19% 6% 33% 42% Residential Small Comm. Med. Comm. Large Comm. 21 | P a g e SECTION 4D: COST STRUCTURE AND REVENUE SOURCES As shown in Figure 2, electric commodity purchases accounted for about 60% of the Electric Utility’s costs in FY 2022. Operational costs represented about 30%, and capital investment was responsible for the remaining 10%. CPAU’s non-hydro long-term commodity supply is heavily dependent on long-term contracts which have little variability in price. On average, costs for these long-term contracts are not predicted to increase as quickly as operations and CIP costs, and will steadily become a smaller proportion of the Electric Utility’s costs. Staff projects commodity supply costs to be approximately 55% of total costs in FY 2028. While average year purchase costs for the electric utility are predictable due to its long-term contracts, variability in hydroelectric generation can result in increased or decreased costs. This is by far the largest source of variability the utility faces. Figure 3 shows the difference in the annual load resource balance under high, projected, and low hydroelectric generation scenarios for FY 2022. Additional costs associated with a very low generation scenario can range from $8-20 million per year, depending on market prices. For the current hydroelectric risk assessment see Section 5F: Risk Assessment and Reserves Adequacy. As shown in Figure 4 the Electric Utility received about 72% of its revenue from sales of electricity and the remainder from connection fees, interest on reserves, cost recovery transfers from other funds for shared services provided by the electric utility, accounting entries that reflect things such as CPAU’s participation in a pre- Figure 2: Cost Structure (FY 2023) 61% 29% 10% Commodity Supply Operations Capital Figure 3: Hydroelectric Variability as a % of Load (FY 2023) 0% 50% 100% 150% 200% Low Hydro Average High Hydro Surplus Hydro (sales) Market Power/RECs Hydro Renewables Load Figure 4: Revenue Structure (FY 2023) 72% 28% Sales of Electric ity Other Revenue 22 | P a g e funding program associated with its contract with WAPA, revenues from sales of surplus hydroelectric energy during wet years, as well as LCFS and Cap and Trade revenues. Appendix A: Electric Utility Financial Forecast Detail shows more detail on the utility’s cost and revenue structures. As discussed in Section 4B: Customer Base, nearly three quarters of the utility’s electricity sales are to the 960 largest customers, which provide a similar share of the utility’s revenue stream. About 25% of the utility’s revenue comes from peak demand charges on large non-residential customers. Due to moderate weather and the prevalence of natural gas heating, however, loads (and therefore revenues) are very stable for this utility, without the large seasonal air conditioning or winter heating loads seen at some other utilities. SECTION 4E: RESERVES STRUCTURE CPAU maintains several reserves for its Electric Utility to manage various types of contingencies and for ease of reporting. It also maintains two funds, the Supply Fund and the Distribution Fund, to manage costs associated with electricity supply and electricity distribution, respectively. The City established this separation of supply and distribution costs as the City prepared to allow its customers a choice of electricity providers (referred to as “Direct Access”) in the late 1990s and early 2000s. Though the 2000/2001 energy crisis halted these plans, CPAU continues to maintain separate funds to facilitate separation of supply and distribution costs in the rates. This could be important if California ever decides to broadly reintroduce Direct Access, and is useful for rate design as the nature of utility service evolves in response to higher penetrations of distributed generation. Thus, individual reserves may reside within a particular fund (for instance, Electric Special Projects is under Electric Supply) or be included within both funds (there are both Supply and Distribution Reserves for Commitments). The summary below describes the various reserves, but see Appendix B: Electric Utility Reserves Management Practices for more detailed definitions and guidelines for reserve management: •Reserves for Commitments: Reserves equal to the utility’s outstanding contract liabilities for the current fiscal year. Most City funds, including the General Fund, have a Commitments Reserve. •Reserves for Reappropriations: Reserves for funds dedicated to projects re-appropriated by the City Council, nearly all of which are capital projects. Most City funds, including the General Fund, have a Re-appropriations Reserve. This is currently an important reserve for all utility funds, but changes in budgeting practices will change that in future years, as described in Section 3C (Reserves Management Practices). •Electric Special Projects (ESP) Reserve: This reserve was formerly called the Calaveras Reserve, which was accumulated during deregulation of California’s electric system to fund the stranded costs associated primarily with the Calaveras hydroelectric resource and the California-Oregon Transmission Project. When that reserve was no longer needed for that purpose, the reserve was renamed and the purpose was changed to fund projects with significant impact that provide demonstrable value to electric ratepayers. 23 | P a g e •Hydroelectric Stabilization Reserve: This contingency reserve is used for managing additional costs due to below average hydroelectric generation, or to hold surpluses resulting from above average hydroelectric generation. •Underground Loan Reserve: This reserve is an accounting tool used to offset receivables associated with loans made through the underground loan program. It is adjusted according to principal payments made on those loans. •Cap and Trade Program Reserve: This reserve tracks unspent or unallocated revenues from the sale of carbon allowances freely allocated by the California Air Resources Board to the electric utility, under the State’s Cap and Trade Program. Funds in this Reserve are managed in accordance with the City’s Policy on the Use of Freely Allocated Allowances under the State’s Cap and Trade Program. •Low Carbon Fuel Standard (LCFS) Reserve: This reserve tracks revenues earned via the sale of Low Carbon Fuel Credits allocated by the California Air Resources Board to the City, in accordance with California’s Low Carbon Fuel Standard program. •Public Benefits Reserve: CPAU’s electric rates include a separate charge called the “Public Benefits Charge” which generates revenue to be used for energy efficiency, demand-side renewable energy, research and development, and low-income energy efficiency services. Any funds not expended in the current year are added to the Public Benefits Reserve for use in future years. •Capital Improvement Program (CIP) Reserve: The CIP reserve can be used to accumulate funds for future expenditure on CIP projects, as well as to manage cash flow for ongoing capital projects. This reserve can also act as a contingency reserve for unforeseen capital expenses. This type of reserve is used in other utility funds (Water, Gas, and Wastewater Collection) as well. •Supply and Distribution Rate Stabilization Reserves: These reserves are intended to be empty unless one or more large rate increases are anticipated in the forecast period. In that case, funds can be accumulated to spread the impact of those future rate increases across multiple years. This type of reserve is used in other utility funds (Gas, Wastewater Collection, and Water) as well. •Supply and Distribution Operations Reserves: These are the primary contingency reserves for the Electric Utility and are used to manage yearly variances from budget for operational costs and electric supply costs (aside from variances related to hydroelectric generation). This type of reserve is used in other utility funds (Gas, Wastewater Collection, and Water) as well. •Unassigned Reserves (Supply/Distribution): As in the other utility funds, these reserves are for any financial resources not assigned to the other reserves and are normally empty. SECTION 4F: COMPETITIVENESS For the median consumption level, the annual CPAU residential electric bill for calendar year 2023 was $964, which was $667 (41%) lower than the annual bill for a PG&E customer with the same consumption ($1,632) and approximately $136 (34%) higher than the annual bill for a City of Santa Clara customer ($718). However, both PG&E and Santa Clara did large rate increases on January 1, 2024. As shown in Table 8, below, the Palo Alto winter and summer median residential 24 | P a g e bills are only 18% and 11% higher than Santa Clara, which is about the same as the historical difference between the two. The high difference for CY 2023 reflects the fact that the City acted earlier than Santa Clara in recognizing increasing long-term commodity costs. This was something the City had to do due to low reserves resulting in part from avoiding rate increases through the COVID-19 pandemic to help residents manage the pandemic’s economic impact. The PG&E bills based on the January 1, 2024 rates are 50% to 60% higher than Palo Alto, reflecting an increasing cost advantage for Palo Altans over utility customers in PG&E territory. The bill calculations for PG&E customers are based on PG&E Climate Zone X, which includes most surrounding comparison communities. Table 8 presents sample median residential bills for Palo Alto, PG&E, and the City of Santa Clara (Silicon Valley Power) for several usage levels. Rates used to calculate the monthly bills shown below were in effect as of January 1, 2024. Table 8: Residential Monthly Electric Bill Comparison (Effective 1/1/2024, $/mo.) Season Usage (kwh)Palo Alto PG&E Santa Clara 300 52.56 126.03 49.02 453 (Median)88.16 191.88 74.93 650 136.75 295.44 108.29Winter 1200 274.41 584.55 201.42 300 52.56 130.78 49.02 (Median) 365 66.45 153.33 60.03 650 136.75 314.76 108.29Summer 1200 282.18 603.87 161.54 SECTION 5: UTILITY FINANCIAL PROJECTIONS SECTION 5A: LOAD FORECAST Figure 5 shows a history of Palo Alto electricity consumption. Average electricity consumption grew from 1986 to 1998, then returned to 1986 levels by 2002. Since then, electricity consumption has declined slowly as a result of a continuing focus on energy efficiency, as well as the adoption of more stringent appliance efficiency standards and energy standards in building codes. Electrification will likely reverse some of this trend, although the pace of that impact is uncertain at this time. In recent years, some larger commercial customers have relocated operations or shifted to more light-commercial type usage. It is unknown how long this trend may continue, or what the longer-term impacts of COVID and work-from home policies might mean for commercial utilization in Palo Alto. 25 | P a g e Figure 5: Historical Electricity Consumption Figure 6 shows the forecast of electricity consumption through FY 2029. The solid black straight line is the long-term average trend of usage. The small-dash red line represents the projected retail sales used in the financial forecast. Sales, which are depressed due to the economic effects of the pandemic, are assumed to recover to a level slightly above the long-term trend line. These projections are uncertain and will be revised if continuing sales change. Potential factors that may offset declining sales include a potential data center project. Building and vehicle electrification at a business as usual level is included in this forecast but large increases in the rate of building and vehicle electrification could increase sales further as well. 26 | P a g e Figure 6: Forecasted Electricity Consumption SECTION 5B: FY 2019 TO FY 2023 COST AND REVENUE TRENDS As shown in Appendix A: Electric Utility Financial Forecast Detail, annual expenses for the Electric Utility increased significantly from FY 2019 to FY 2023. Electric supply costs increased as new renewable projects came online, and transmission costs rose and have continued to rise as improvements are made to the California grid. Capital investment and operational costs have increased due to construction inflation, increased investment in the electric system, and the cost of contract field crews to cover operational work due to challenges with vacancies. Section 6A: Electricity Purchases discusses the factors influencing electric supply expenses. During the drought in FY 2021 and FY 2022 costs increased due to a lack of hydroelectric generation. Better than average hydro conditions in FY 2019 led to lower than expected generation expenses as well as better than expected surplus energy revenues, but extreme drought followed. In FY 2023 the drought broke with record rainfall over the winter, but this was also accompanied by record high gas prices that drove electricity market prices high as well, offsetting the benefits of the rainfall. The commodity and distribution costs for FY 2025 in Figure 7 are unusual due to one-time commodity revenues and savings and due to the timing of various capital investments and related Projection 27 | P a g e debt issuances in FY 2024 and FY 2025. If using a more representative year (such as FY 2026), commodity costs can be seen to have increased 4% to 5% per year since FY 2020 and operational and capital investment costs can be seen to have increased 5% to 6% per year. The forecasted increases in distribution cost relate primarily to debt service for the grid modernization project as well as continuing construction inflation and other inflation. Combined, the utility’s costs 4% to 5% per year on average for the last few years (after adjusting for the unusually low FY 2025 expenses) Figure 7 shows the electric utility revenues, expenses, and proposed rate changes for the previous five years, the current year, and the projections for the next five years. The rate change percentages listed include the hydroelectric rate adjuster, which was activated in April 2022, increased in January 2023, and removed in July 2023. The removal of the hydroelectric rate adjuster was combined with a 21% base rate increase, leading to a 5% overall rate decrease. The cost bars in FY 2024 reflect a one-time timing issue with the startup of the grid modernization project. The first year of spending was budgeted in FY 2024, but the first debt issuance will not take place until FY 2025 (this was to allow time for the City to apply for a grant, which it did not receive). It also reflects a one-time transfer in FY 2024 related to new customer investments. Figure 7: Electric Utility Revenues, Expenses, and Rate Changes: Actual Costs through FY 2023 and Projections through FY 2029 28 | P a g e SECTION 5C: FY 2023 RESULTS FY 2023 revenues were $50 million higher than projections due to the activation of the hydroelectric rate adjuster ($26 million) and the receipt of the $24 million judgment related to a lawsuit against the Federal government related to the City’s contract with the Western Area Power Administration. This was partially offset by net supply purchase costs that came in $28 million higher than projected due to extraordinarily high electric market prices. Operational costs came in about $8.7 million lower than projected due to savings in administration and demand side management (DSM) costs. Capital projects costs were lower than projections by $7.5 million. Table 9 FY 2023, Actual Results vs. FY 2023 Financial Plan Forecast ($000) Net Cost/(Benefit)Type of change Higher revenues from Hydroelectric Rate Adjuster and judgment ($49,846)Revenue increase Higher electric supply costs $28,099 Cost increase Lower operational costs ($8,772)Cost decrease Lower than forecasted capital investment ($7,463)Cost decrease Net Cost / (Benefit) of Variances ($37,982) SECTION 5D: FY 2024 PROJECTIONS Net revenues are expected to be $6.3 million lower than projected, but this includes wholesale revenues that are $20 million higher than forecasted due to better hydroelectric conditions than were anticipated in the FY 2024 Financial Plan forecast and higher prices for resource adequacy and REC sales. This is offset by a $26.6 million decrease in other revenues because the judgment for the lawsuit mentioned above was received in FY 2023 rather than FY 2024 as anticipated. Purchase costs are currently projected to be $3.6 million lower due to market prices moderating and hydroelectric conditions improving. Operations costs are projected to be $5.4 million lower than forecasted, but due to grid modernization and a rebuild of the Hanover Substation capital investment costs are projected to be $41 million more than previously forecasted. The net effect of these forecasted changes is $38 million in net impact to reserves, which offsets the $38 million in net benefit to reserves from FY 2023 results compared to forecasts. Table 10 Change in Projected FY 2024 Results: FY 2025 Financial Plan Forecast vs. FY 2024 Financial Plan Forecast ($000) Net Cost/(Benefit)Type of change Higher wholesale revenues ($20,234)Revenue increase Other revenues lower than forecasted $26,605 Revenue decrease Lower than forecasted supply costs ($3,592)Cost decrease Lower than forecasted operational costs ($5,473)Cost decrease Additional capital investment costs $41,376 Cost increase Net Cost / (Benefit) of Variances to Ops Reserve $38,681 29 | P a g e SECTION 5E: FY 2025 – FY 2029 PROJECTIONS As shown in Figure 7 above, From FY 2025 through FY 2029 increasing power supply costs combined with rising capital investment and debt service costs due to the grid modernization project are projected to lead to 5% per year projected rate increases in FY 2026 through FY 2029. A one-time transfer in FY 2026 related to the electric utility’s share of the dark fiber system rebuild is also expected. With California reservoirs filled and prices declining, power supply costs are expected to be lower in FY 2024 than previously forecasted, but hydroelectric revenue continues to vary annually and will be negatively affected by climate change over time. To reduce hydroelectric-related volatility in the future, staff is now making its rate projections assuming that long-term “normal” production from the City’s hydroelectric resources is about 80% of historical average levels. Over the longer term, increasing transmission costs and tightening resource adequacy requirements are also expected to steadily increase electric supply costs. The projected rate increases of 5% per year for FY 2026 through FY 2029 are expected to keep revenues in line with expenses. Staff recommends against raising rates significantly in FY 2025 to allow for changes in rates among customer classes to align with the recently completed cost of service analysis. This will allow the City to limit the rate changes for any customer class to 8% or less in FY 2025. Reserves trends based on these revenue projections are shown in Figure 9 (for Supply Fund Reserves) and Figure 10 (for Distribution Fund Reserves), below. The Supply and Distribution Operations Reserves are projected to be slightly below the minimum level in FY 2024 but are expected to return to within guideline levels by the end of FY 2025. This Financial Plan includes the restoration of the hydroelectric stabilization reserve from nearly empty to $17.4 million by the end of FY 2025, close to the reserve maximum and enough to allow the utility to absorb the increased costs associated with lower hydroelectric generation across multiple dry years. It also includes repayment of all internal loans from the Electric Special Projects Reserve by the end of FY 2025. And lastly, it includes significant interfund transfers in FY 2024 and FY 2025 to manage the impact of the cash flow issue associated with the startup of the grid modernization project (see Section 3D: Proposed Reserve Transfers for more detail). The reserves charts below show significant increases in the Public Benefits and Cap and Trade reserves over the forecast period. This reflects that those funding sources are currently not fully utilized, but staff expects that to change as the City launches more electrification programs funded by those sources. 30 | P a g e Figure 9: Electric Utility Reserves (Supply Fund): Actual Reserve Levels through FY 2023 and Projections through FY 2029 Figure 10: Electric Utility Reserves (Distribution Fund): Actual Reserve Levels through FY 2023 and Projections through FY 2029 31 | P a g e SECTION 5F: RISK ASSESSMENT AND RESERVES ADEQUACY The Electric Utility currently has two primary contingency reserves, the Supply Operations Reserve and the Distribution Operations Reserve. In addition, the Electric Utility has a Hydro Stabilization Reserve, an ESP Reserve, and a Capital Reserve, which can be utilized with Council approval. There are a variety of risks associated with the Supply Fund related to resource generation variability, market price volatility, transmission cost increases, regulatory changes to market rules. Because of the high range of uncertainty in energy price predictions more than three years in the future, this risk assessment is only performed for the first two fiscal years of the forecast period. It is important to note that the likelihood of all these adverse scenarios occurring simultaneously and to the degree described in Table 12 is very low. 32 | P a g e Table 12: Electric Supply Fund Risk Assessment Categories of Electric Supply Cost Uncertainties Estimates of Adverse Outcomes (M$) Estimates of Adverse Outcomes (M$) FY 2025 FY 2026 1. Load Net Revenue 4.8 3.8 2. Hydro Production: Western & Calaveras 8.4 3.8 3. Renewable Production: Landfill, Wind, Solar, Geothermal 1.1 1.9 4. REC Purchases 0.5 0.5 5. REC Sales 3.8 2.8 6. Market Price 2.4 2.1 7. Resource Adequacy 3.2 1.1 8. Transmission/CAISO 4.8 5.0 9. Plant Outage 1.0 1.0 10. Western Cost 1.3 1.7 11. Legislative & Regulatory 0.0 0.0 12. Supplier Default+0.2 0.2 Electric Supply Fund Risks 31.6 23.9 Of the risks faced by the Electric Utility’s Supply Fund, the risk of a dry year with very low hydroelectric output is normally the largest, accounting for more than one-third ($8.4 million) of all the adverse cost uncertainty. Since the utility’s costs for its hydroelectric resources are almost entirely fixed, costs do not decline when the output of those resources are low, but the utility needs to buy power to replace the lost output. The converse happens when hydroelectric output is higher than average. Of the remaining risks for FY 2025, $4.8 million is related to potential transmission cost increases (above staff’s current forecast). $4.8 million is related to the potential that total load (and the associated retail sales revenue) may be lower than projected. Other risks related to production from the City’s renewable contracts and market prices for purchases and sales of energy and resource adequacy (Items 3, 4, 5, 6, and 7 above) total $11 million due to the unusually high market prices and surplus sales contract volumes in FY 2025. 33 | P a g e As shown in Figure 11, staff projects the Supply Operations Reserve to drop below the minimum guideline levels in FY 2024 but return to within guideline levels by the end of FY 2025. Note that the high reserve level in FY 2023 is related to the timing of a $24M judgment from a lawsuit related to the allocation of costs of the Central Valley Project. These funds are being redistributed to other purposes in FY 2024, with the transfers resulting in a reduction in the Supply Operations Reserve. Figure 12 shows that the combined Hydro Stabilization and Supply Operations Reserves are projected to be above the risk assessment level through the forecast period. Figure 11: Electric Supply Operations Reserve Adequacy 34 | P a g e Figure 12: Adequacy of Supply Operations and Hydro Stabilization Reserves, Combined Table 13 summarizes the risk assessment calculation for the Distribution Operations Reserve through FY 2029. As shown in Figure 13, the Distribution Operations Reserve is also projected to drop near to the minimum reserve guidelines in FY 2025, but is projected to recover to target levels over the course of the forecast period. The risk assessment includes the revenue shortfall that could accrue due to: 1. Lower than forecasted sales revenue; and 2. An increase of 10% of planned system improvement CIP expenditures for the budget year. Table 13: Electric Distribution Fund Risk Assessment ($000) FY 2025 FY 2026 FY 2027 FY 2028 FY 2029 Total non-commodity revenue $77,592 $82,369 $90,316 $98,135 $102,722 Max. revenue variance, previous ten years 8%8%8%8%8% Risk of revenue loss $6,124 $6,501 $7,128 $7,745 $8,107 CIP Budget $0 $15,143 $14,671 $12,688 $13,089 CIP Contingency @10%$0 $1,514 $1,467 $1,269 $1,309 Total Risk Assessment value $6,124 $8,015 $8,595 $9,014 $9,416 35 | P a g e Figure 13: Electric Distribution Operations Reserve Adequacy The Electric Utility also has a CIP Reserve that acts as a reserve for short term capital contingencies or as a place to set aside funds for large, one-time projects that the Utilities would otherwise need to debt-fund. Figure 14 below reflects the maximum and minimum CIP Reserve guideline levels, starting in FY 2023. Because of the fluctuating annual dollar amounts and timing of CIP projects budgeted to occur during the forecast period, as well as the potential for new ongoing projects to be included in the CIP plan in later years, four years of budgeted CIP are used to calculate the reserve maximum levels. The minimum CIP Reserve level is 20% of the maximum CIP Reserve guideline level. This Financial Plan plans to fund the CIP Reserve to its minimum level by the end of FY 2025 and includes additional contributions to the reserve in later years. In addition, staff recommends amending the reserve guidelines to direct staff to transfer any unspent CIP budget that is not reappropriated or encumbered at the end of each fiscal year to the CIP Reserve. These represent ratepayer funds already collected for the purpose of CIP investment, and retaining them in the CIP Reserve would allow the City to use them to fund future unanticipated CIP expenses (such as 36 | P a g e mid-year budget adjustments due to increased costs for specific projects) that were not included in a financial plan. Figure 14 shows the projected CIP Reserve balances and guideline levels for FY 2023 through FY 2029. The CIP reserve is projected to be above the minimum guideline by the end of FY 2025. Per the Reserves Management Practices (Appendix B), Section 10, any rate plan that does not return CIP reserves to minimum levels within one year requires Council approval. Council approved the FY 2024 Electric Utility Financial Plan, which included keeping the CIP Reserve below minimum until FY 2026. This plan achieves minimum CIP Reserve levels by the end of FY 2025. Figure 14: Electric CIP Reserve Adequacy SECTION 5G: LONG-TERM OUTLOOK This forecast covers the period from FY 2025 through FY 2029, but various long-term developments may create new costs for the utility over the next 10 to 35 years. While it is challenging to accurately forecast the impact these events will have on the utility’s costs, it is worth noting them as future milestones and keeping them in mind for long-term planning purposes. For the supply portfolio, the 2020s are seeing a number of notable events. The contract with the Western Area Power Administration (Western) for power from the Central Valley Project (CVP) is expiring in 2024, with an option in 2024 to reduce the City’s share. Determining the future 37 | P a g e relationship with Western after 2024 will be important in the years leading up to the contract expiration, especially because this resource represents nearly 40% of the electric portfolio and is the utility’s largest source of carbon-free electricity. Over the next decade six of the utility’s renewable contracts will begin expiring with the first contract expired in 2026 and the last in 2034. It is difficult to know whether renewable energy prices will be more or less favorable than the contract prices when those contracts expire. The costs of the Calaveras hydroelectric project is changing in the 2020s, with debt service costs dropping by half or approximately $4 million in 2025 as some of the debt is paid off, and all debt will be retired by the end of 2032. Some additional debt may be issued to fund the costs of relicensing the project, but this is not anticipated to be as high as the current debt service. The project will only be 40 years old at that time, and hydroelectric projects can last for 70-100 years before major rebuilding is needed. Calaveras debt service represents roughly 70% of the annual costs of that project (and nearly 7% of the utility’s total costs), so when the debt is retired, the project could be a low-cost asset for the utility, providing carbon-free energy equal to around 13% of the Electric Utility’s supply needs in an average year. Another factor that may affect the utility’s supply costs in the long run is carbon allowance revenue. Currently the Electric Utility receives $3 to $5 million per year in revenue from allocated carbon allowances under the State’s cap-and-trade program. It uses that revenue to pay for energy efficiency programs and to purchase renewable energy to support the utility’s Carbon Neutral Plan. Staff expects that revenue source to continue in some fashion through 2030, although the number of allowances allocated to Palo Alto have been reduced. Discussions at the state level are ongoing to determine any further restrictions CARB may wish to enact on both the number of future allowances received as well as usage of allocation sales revenues. If the Electric Utility no longer received these allowances or was limited in how it could spend revenues, it would have to fund these programs from sales revenues. Transmission costs are also continuing to rise. If the State continues to increase mandates or incentives for renewable energy development, integrating these new projects into the transmission grid will be an ever-increasing challenge, some costs of which will be borne by Palo Alto. The planned expansion of the CAISO to a larger regional grid control area may result in additional transmission costs that could further increase CPAU’s transmission costs. In addition to the costs of new transmission lines that will need to be built, flexible resources will be required to balance rapid changes in wind or solar output throughout the day. Palo Alto will likely bear some of the costs of these new lines and resources. CPAU is also currently investigating installing a second transmission interconnection for Palo Alto, which could be funded by the Electric Special Projects Reserve. Over the next several years the Electric Utility will continue to execute its usual monitoring, repair, and replacement routine for the distribution system, but is also beginning the rollout of various smart grid technologies and a major grid modernization effort that will result in rebuilding 38 | P a g e of the electric system and capacity increases. This rebuild will involve debt service that will be repaid over 30 years and will have an uncertain effect on electric system capital investment needs in the 2030s and beyond. The utility is actively promoting electric vehicle ownership and gas-to-electric fuel switching in Palo Alto. In the coming years these factors are expected to create notable increases in electric consumption and have a variety of impacts on the distribution system. Other technologies such as battery storage and rooftop solar installations are also becoming even more common. The utility has already started to take some of these factors into account in its long-term planning processes but will need to continue to incorporate them into its planning methodologies. Over the long term, electricity may replace natural gas and petroleum almost entirely as part of the City’s efforts to combat climate change. Many, if not most, vehicles would use electricity, though hydrogen is another potential fuel source under development and other technologies might be developed. Staff is undertaking initial analysis of these types of scenarios in the context of the Sustainability and Climate Action Plan (S/CAP) development process. Utility analyses in progress or completed that take into account potential load growth benefits and impacts include a grid modernization study, the Electric Integrated Resource Plan, and an upcoming S/CAP funding needs and sources study that may help assess the impact of these trends on rates. Staff will integrate results from these studies in Financial Plans as they become available. SECTION 5H: ALTERNATIVE RATE PROJECTIONS Staff is not presenting any alternative rate projections in this Financial Plan. SECTION 6: DETAILS AND ASSUMPTIONS SECTION 6A: ELECTRICITY PURCHASES As shown in Figure 16 the utility is projected to get roughly 45% of its energy from hydroelectric projects in a normal year, but is getting over 50% during FY 2024 and FY 2025 due to the favorable hydroelectric generation conditions resulting from the rains of the 2022/2023 winter. In the longer term contracts with renewable sources make up approximately 50% to 55% of the portfolio. If hydroelectric conditions end up being lower than forecasted (as they were in FY 2023) or if loads increase, some power may come from unspecified market sources. Under the City’s Carbon Neutral Plan, CPAU purchases RECs corresponding to the amount of market energy it purchases. 39 | P a g e Figure 16: Electricity Supply by Source Figure 16 shows the historical and projected costs for the electric supply portfolio,11 as well as average and actual hydroelectric generation.12 FY 2022 and FY 2023 had lower than average hydroelectric generation, while FY2024 and FY 2025 had higher than forecasted generation. Starting in FY 2023 (in the FY 2024 Electric Utility Financial Plan) staff lowered its projection of an average hydroelectric year to more closely align with the past 10 years of historical averages. But with the current favorable reservoir conditions staff is projecting hydroelectric generation to be better than average through FY 2026. Renewable energy costs have stayed relatively flat as one renewable energy contract ended while another renewable project came online to fulfill the City’s carbon neutral and RPS goals. The current market outlook is uncertain for newer renewables projects because of headwinds from supply chain issues and tailwinds from federal subsidies. Transmission charges are projected to increase as new transmission lines are built throughout California to accommodate new renewable projects. In total, net electric supply costs are projected to increase from about average of $83 million from FY 2022 through FY 2025 to about $106 million by FY 2029. 11 Costs are shown net of wholesale revenues and cannot be directly compared with the electric supply purchase figures shown in Appendix A: Electric Utility Financial Forecast Detail. 12 Average hydroelectric generation based on the current E-HRA rate schedule. 40 | P a g e Figure 17: Electric Supply Portfolio Costs, Historical and Projected SECTION 6B: OPERATIONS CPAU’s Electric Utility operations include the following activities: •Administration, including financial management of charges allocated to the Electric Utility for administrative services provided by the General Fund and for Utilities Department administration, as well as debt service and other transfers. Additional detail on Electric Utility debt service is provided in Section 6D (Debt Service) •Customer Service •Engineering work for maintenance activities (as opposed to capital activities) •Operations and Maintenance of the distribution system; and •Resource Management Appendix C: Description of Electric Utility Operational Activities includes detailed descriptions of the work associated with each of these activities. 41 | P a g e From FY 2019 to FY 2023, overall operations costs have risen annually by about 7% on average. This is primarily driven by increased operations and maintenance and administrative overhead allocations. Operations and maintenance costs are increasing primarily due to inflation driven by the tight labor market and the cost of using contract field crews to backfill for vacant positions. These costs may be reduced depending on how much work is needed and may be phased out as longer-term employees are gained. Figure 18: Historical and Projected Electric Utility Operational Costs SECTION 6C: CAPITAL IMPROVEMENT PROGRAM (CIP) Staff projects CIP spending for FY 2025 through FY 2029 to focus primarily on grid modernization. Other significant one-time projects include a rebuild of Hanover Substation (budgeted in FY 2024, mid-year), a major project at the Colorado Substation, undergrounding of power lines in the Foothills, and completion of the Smart Grid (Advanced Metering Infrastructure) project. Ongoing projects include replacement of deteriorated wood poles, substation physical security upgrades, and ongoing capital investment in smaller projects on the electric distribution system to maintain/improve reliability. Total spending over the forecast period, including the FY 2024 budget, is over $450 million, far higher than past CIP spending plans. Of this, about $330 million is planned to be financed through debt, as explained in Section 6D: Debt Service below. 42 | P a g e The remainder of the CIP plan for is primarily funded by utility rates, but other sources of funds include connection fees (for Customer Connections), phone and cable companies (primarily for undergrounding), and other funds (such as funds from the Electric Special Projects Reserve for smart grid). The details of the CIP budget will be available in the Proposed FY 2025 Utilities Capital Budget. Table 14 shows the FY 2025 projected budget and the five year CIP spending plan, although these figures are preliminary pending budget discussions starting in May. Table 14: Electric Utility CIP Spending ($000) SECTION 6D: DEBT SERVICE The Electric Utility made its last payment on the 2007 Electric Utility Clean Renewable Energy Tax Credit Bonds, Series A in FY 2021. This $1.5 million bond issuance was to fund a portion of the construction costs of solar demonstration projects at the Municipal Services Center, Baylands Interpretive Center, and Cubberley Community Center. It currently has no debt service expenses related to its own distribution system (though it does have debt service expenses related to the Calaveras Dam, a power supply expense). However, staff expects to issue substantial amounts of debt to fund up to $300 million in grid modernization expenses through FY 2030. A tentative projection of how much of the cost of that project will be debt funded vs. rate funded is shown in Figure 19 below. This plan is reflected in the financial projections in this Financial Plan. The timing and amount of the debt issuances will likely change as the grid modernization project progresses. Note that the debt issuance in FY 2025 will be used for FY 2024 expenses, resulting in the use of rate/reserve funding in FY 2024 and a refund to the reserves in FY 2025 as the bond proceeds are applied to those FY 2024 expenses. Project Category Current Budget * FY 2025 (New Budget, Excluding Reappropriations)FY 2026 FY 2027 FY 2028 FY 2029 One Time Projects 26,363,974 10,100,000 3,750,000 2,850,000 750,000 750,000 Reliability 4,516,765 765,000 798,300 900,000 529,000 544,870 Undergrounding 1,368 ----- 4/12 kV Conversion 2,487,541 ----- Underground Rebuild 1,112,000 ----- Ongoing 8,093,369 3,915,000 3,875,000 4,040,500 4,361,000 4,491,830 Cust omer Connections 5,865,828 2,700,000 2,700,000 2,700,000 2,700,000 2,781,000 Smart Grid 12,710,117 ----- Grid Modernization 25,000,000 25,000,000 50,000,000 50,000,000 50,000,000 50,000,000 Total 86,150,963 42,480,000 61,123,300 60,490,500 58,340,000 58,567,700 * Includes unspent funds from previous years carried forward or reappropriated to the current fiscal year 43 | P a g e Figure 19: Projected Funding Plan for Grid Modernization Project The Electric Utility pledges reserves and net revenue as security for the bond issuances listed in Table 15 even though the Electric Utility is not responsible for the debt service payments. The Electric Utility’s reserves or net revenues would only be called upon if the responsible utilities are unable to make their debt service payments. Staff does not currently foresee this occurring. Staff projects that the Electric Utility’s net revenues in each future year will exceed 125% of debt service (see Appendix B, line 70). Table 15: Other Issuances Secured by Electric Utility’s Revenues or Reserves Secured by Electric Utility’s:Bond Issuance Responsible Utilities Annual Debt Service ($000)Net Revenues Reserves 1999 Utility Revenue Bonds, Series A Storm Drain Wastewater Collection Wastewater Treatment $1,207 No Yes 2009 Water Revenue Bonds (Build America Bonds)Water $1,977*No Yes 2011 Utility Revenue Refunding Bonds, Series A Gas Water $1,457 No Yes *Net of Federal interest subsidy 44 | P a g e SECTION 6E: EQUITY TRANSFER The City calculates the equity transfer from its Electric Utility based on a methodology adopted by Council in 2009, which has remained unchanged since then.13 Each year it is calculated according to the 2009 Council-adopted methodology and does not require additional Council action. SECTION 6F: WHOLESALE REVENUES AND OTHER REVENUES The Electric Utility receives most of its revenues from sales of electricity, but about 20 to 25% comes from other sources. Of these other sources, about 50% to 75% represents wholesale revenues of surplus energy sales. These revenues may offset electric supply purchase costs, smooth rate increases, or fund reserves or other costs. Of the remaining revenues, the largest revenue sources are interest on reserves, connection fees for new or replacement electric services, and carbon allowance revenues associated with the State’s cap-and-trade program Revenues from connection fees have increased since FY 2009 but vary from year to year. Connection fee revenues are collected to offset costs incurred in setting up new connections and are pass-through in nature. Staff forecasts $1.4 million in FY 2025. Staff projects carbon allowance and interest income revenues to stay relatively stable through the forecast period. However, both of these revenue sources are subject to some uncertainty. This forecast assumes the program State’s cap-and-trade program will remain in place but with declining returns through 2030. It is possible this funding source may be removed entirely in the future, as the current CARB plan in the gas fund is for free allowances to stop entirely by 2030. The forecast for interest income assumes current interest rates continue and there are no major reserve reductions aside from what is anticipated in this Financial Plan. If interest rates rise, interest income could increase, and if reserves decrease (due to drought or a withdrawal from the ESP reserve for a major project), interest income would decrease. SECTION 6G: SALES REVENUES The load forecast in Section 5A: Load Forecast and the projected rate changes shown in Figure 7 provide the basis for sales revenue projections. As discussed in Section 5A, sales revenues for this utility have been decreasing due to load reduction but are helped by the mild climate in Palo Alto. Palo Alto is a built-out City, so the opportunities for increased load growth are limited to the existing footprint of commercial structures and incremental growth in population. As utilization of existing spaces changes, and energy efficiency measures continue, Palo Alto could see greater load loss. Increased loads from electric vehicles and the electrification of households may increase loads somewhat. 13 For more detail on the ordinance adopting the 2009 transfer methodology, see CMR 280:09, Budget Adoption Ordinance for Fiscal Years 2009 and 2010; and CMR 260:09, Finance Committee Report explaining proposed changes to equity transfer methodology. 45 | P a g e 46 | P a g e SECTION 7: COMMUNICATIONS PLAN The fiscal year (FY) 2025 electric utility communications strategy covers these primary areas: cost drivers, cost containment measures, efficiency services and utility bill savings, capital improvement projects for infrastructure safety and reliability, carbon neutral portfolio, and beneficial electrification. City of Palo Alto Utilities (CPAU) communication methods include utilities webpages, utility bill inserts, messaging on utility bills, email newsletters, print and digital ads, social media, and business and neighborhood customer presentations. In advance of the rate-setting process, staff working on rates and communications are focusing on informing customers of the need to recover funds to bring financial reserves above the minimum guideline following the 2020 through 2022 reserve drawdowns. It is also important to educate customers about the cost to buy and transport electricity to Palo Alto, as well as the cost to distribute it within Palo Alto, including maintaining and replacing infrastructure, customer service, billing, and administration. Long-term cost trends show supply and distribution costs increasing over time. CPAU implements cost containment as a priority and is improving efficiencies with metering and billing through Advanced Metering Infrastructure (AMI), and a new power Outage Management System (OMS) that automates customer notifications, allowing staff to devote time to restoring service. Despite raising rates, electric costs to customers still remain lower than the comparator regional investor-owned utility, PG&E. CPAU promotes energy efficiency programs to help customers keep utility bill costs low even as market prices increase or CPAU raises utility rates. Programs such as the Home Efficiency Genie and commercial energy efficiency audits help residents and businesses better understand energy usage, and activities they can implement to improve efficiency and keep utility costs low. The Home Efficiency Genie program now provides a home electrification readiness assessment so customers who want to switch out gas for electric appliances or install an electric vehicle (EV) charger can understand what may be necessary for electric panel upgrades. The City offers attractive financing and assistance with installation to eliminate barriers to adoption. The Business Energy Advisor (BEA) provides a “concierge” service for businesses to evaluate areas of their facility for efficiency improvements such as in the areas of building envelope, lighting, and heating. BEA acts as the flagship program for businesses to then learn about available rebates for appliance or facility upgrades and opportunities for building electrification. CPAU also offers programs to help non-residential facilities install EV charging infrastructure to assist employees and tenants with goals to switch from fossil fueled transportation to clean, electric driving. CPAU customers benefit from local control and policy setting, and community values-driven programs and services, including the decision to go carbon neutral in 2013. Palo Alto’s renewable energy purchase agreements contribute to our utility’s long-term energy security and commitment to sustainability. CPAU will highlight these environmental attributes and value in our communications. 47 | P a g e APPENDICES Appendix A: Electric Utility Financial Forecast Detail Appendix B: Electric Utility Reserves Management Practices Appendix C: Description of Electric utility Operational Activities Appendix D: Samples of Recent Electric Utility Outreach Communications 6056714 APPENDIX A: ELECTRIC UTILITY FINANCIAL FORECAST DETAIL 6056714 (page intentionally left blank) 6056714 1 FISCAL Y EAR FY 2019 F Y 2020 F Y 2021 F Y 2022 FY 2023 FY 2024 FY 2025 F Y 2026 F Y 2027 F Y 2028 FY 2029 2 3 STARTING RESERVES 4 Reappropriat ions (Non-CIP)---56,811 120,000 253,000 253,000 253,000 253,000 253,000 253,000 5 Commit ment s (Non-CIP)3,725,000 3,910,695 3,518,525 3,512,355 (2,321,000)9,400,307 9,400,307 9,400,307 9,400,307 9,400,307 9,400,307 6 Low Carbon F uel St andard (LCFS) Reserve --6,340,000 6,943,525 7,235,894 6,712,544 4,053,126 1,485,979 --- 7 Cap and T rade Program 1,189,000 1,189,000 2,230,759 3,230,759 4,940,759 6,150,759 7,230,759 8,140,759 8 Underground Loan Reserve 730,147 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659 9 Public Benefit s Reserves 681,330 809,700 1,904,547 3,027,599 3,890,872 5,672,542 7,431,387 9,033,068 10,568,541 12,031,587 13,421,659 10 Elec t ric Spec ial Projec t s Reserve 41,837,855 41,664,855 46,664,855 46,664,855 24,649,000 20,148,855 148,855 30,148,855 32,148,855 34,148,855 36,148,855 11 Hydro St abilizat ion Reserve 11,400,000 11,400,000 15,400,000 15,400,000 400,000 400,000 17,400,000 17,400,000 17,400,000 17,400,000 17,400,000 12 Capit al Reserves 879,964 879,964 5,879,964 879,964 879,964 879,964 879,964 5,879,964 5,879,964 5,879,964 5,879,964 13 Rat e St abilizat ion Reserves 9,010,840 ---------- 14 Elec t rific at ion Reserve 4,500,000 4,500,000 4,500,000 4,500,000 4,500,000 4,500,000 14 Operat ions Reserves (Supply & Dist )18,600,000 45,244,167 38,538,459 29,902,850 28,559,158 38,881,723 22,522,316 39,671,926 41,073,721 40,765,805 41,216,341 15 Unassigned 244,354 -0 (0)------- 16 T OT AL ST ART ING RESERVES 87,109,490 104,636,040 118,973,010 108,303,618 65,329,547 89,806,353 70,546,373 123,440,517 128,101,807 132,336,936 137,087,544 17 18 REVENUES 19 Net Sales 131,471,245 137,026,504 129,389,001 130,557,545 164,554,954 172,499,236 169,251,184 177,609,240 185,889,795 194,655,810 203,790,614 20 Wholesale Revenues 21,060,071 20,686,925 25,959,207 25,529,188 30,745,937 46,036,151 44,045,073 30,470,737 28,761,527 28,880,651 25,773,090 21 Ot her Revenues and T ransfers In 19,914,635 15,260,937 9,324,996 9,348,837 32,788,973 7,487,037 7,918,630 10,102,079 10,322,293 10,432,345 10,530,882 22 T OT AL REVENUES 172,445,951 172,974,366 164,673,204 165,435,570 228,089,864 226,022,424 221,214,887 218,182,056 224,973,615 233,968,806 240,094,586 23 24 EXPENSES 25 Elec t ric Supply Purc hases 97,989,910 97,716,399 106,202,833 120,493,205 128,512,096 114,427,008 121,078,734 127,167,371 128,726,357 131,243,066 132,597,189 26 Operat ing Expenses 27 Administ rat ion 28 Alloc at ed Charges 4,568,027 6,146,498 6,674,515 5,732,098 9,664,335 10,050,709 10,452,918 10,871,097 11,305,551 11,757,503 12,227,733 29 Rent 5,454,097 5,666,805 5,949,976 6,069,000 6,324,000 6,474,174 6,733,141 7,002,466 7,282,565 7,573,867 7,876,822 30 Equit y T r ansf er 12,973,000 13,134,000 13,638,000 14,138,000 14,534,000 14,905,000 15,121,000 15,550,000 15,989,000 16,421,000 16,892,000 31 T ransf ers and Ot her Adjust ment s 369,321 (3,000,057)(4,027,621)2,311,226 1,495,296 1,474,594 1,533,578 1,594,921 1,658,718 1,725,067 2,571,441 32 Subt ot al, Administ rat ion 23,364,445 21,947,247 22,234,870 28,250,324 32,017,631 32,904,477 33,840,636 35,018,484 36,235,834 37,477,437 39,567,996 33 Resourc e Management 2,082,405 2,870,524 2,781,010 2,824,303 3,086,893 3,199,728 3,337,316 3,474,146 3,592,267 3,726,330 3,872,887 34 Demand Side Management 3,655,547 2,733,047 3,819,646 4,086,083 3,477,495 6,715,260 6,689,764 5,766,493 4,442,832 4,530,005 4,577,027 35 Operat ions and Mt c 11,606,585 13,450,568 15,988,315 16,576,083 20,538,544 18,323,978 19,084,973 19,858,105 20,591,664 21,373,323 22,217,356 36 Engineering (Operat ing)1,838,799 2,051,303 2,408,524 1,806,550 2,022,434 2,102,495 2,187,351 2,275,108 2,364,474 2,457,918 2,555,940 37 Cust omer Servic e 2,180,400 2,228,469 2,320,338 2,974,968 1,328,808 1,378,296 1,436,736 1,495,354 1,547,991 1,604,957 1,667,871 38 Allowanc e for Unspent Budget -----(653,147)(680,138)(707,644)(734,072)(762,568)(792,845) 39 Subt ot al, Operat ing Expenses 44,728,180 45,281,157 49,552,702 56,518,311 62,471,805 63,971,087 65,896,638 67,180,047 68,040,990 70,407,403 73,666,233 40 Capit al Expenses 41 Capit al Program Cont ribut ion 10,770,456 15,539,840 21,487,061 34,524,744 21,656,368 66,884,310 -15,143,324 14,671,084 12,687,640 13,089,202 42 Capit al-Relat ed Debt Servic e 100,000 100,000 100,000 100,000 20,789 --4,030,024 9,300,055 14,880,088 14,880,088 43 Subt ot al, Capit al Expenses 10,870,456 15,639,840 21,587,061 34,624,744 21,677,157 66,884,310 -19,173,348 23,971,139 27,567,728 27,969,291 44 T OT AL EXPENSES 153,588,546 158,637,396 177,342,596 211,636,260 212,661,058 245,282,404 186,975,372 213,520,766 220,738,486 229,218,198 234,232,712 45 46 ENDING RESERVES 47 Reappropriat ions (Non-CIP)--56,811 120,000 253,000 253,000 253,000 253,000 253,000 253,000 253,000 48 Commit ment s (Non-CIP)3,910,695 3,518,525 3,512,355 (2,321,000)9,400,307 9,400,307 9,400,307 9,400,307 9,400,307 9,400,307 9,400,307 51 Low Carbon F uel St andard (LCFS) Reserve -6,340,000 6,943,525 7,235,894 6,712,544 4,053,126 1,485,979 ---- 52 Cap and T rade Program 1,189,000 1,189,000 2,230,759 3,230,759 4,940,759 6,150,759 7,230,759 8,140,759 8,870,759 53 Underground Loan Reserve 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659 726,659 54 Public Benefit s Reserves 809,700 1,904,547 3,027,599 3,890,872 5,672,542 7,431,387 9,033,068 10,568,541 12,031,587 13,421,659 14,733,094 55 Elec t ric Spec ial Projec t s Reserve 41,664,855 46,664,855 46,664,855 24,649,000 20,148,855 148,855 30,148,855 32,148,855 34,148,855 36,148,855 38,148,855 56 Hydro St abilizat ion Reserve 11,400,000 15,400,000 15,400,000 400,000 400,000 17,400,000 17,400,000 17,400,000 17,400,000 17,400,000 17,400,000 57 Capit al Reserve 879,964 5,879,964 879,964 879,964 879,964 879,964 5,879,964 5,879,964 5,879,964 5,879,964 5,879,964 58 Rat e St abilizat ion Reserve ----------- 59 Elec t rific at ion Reserve 4,500,000 4,500,000 4,500,000 4,500,000 4,500,000 4,500,000 4,500,000 60 Operat ions Reserve (Supply & Dist )45,244,167 38,538,459 29,902,850 28,559,158 38,881,723 22,522,316 39,671,926 41,073,721 40,765,805 41,216,341 43,036,780 61 Unassigned -0 (0)-------- 62 T OT AL ENDING RESERVES 104,636,040 118,973,010 108,303,618 65,329,547 89,806,353 70,546,373 123,440,517 128,101,807 132,336,936 137,087,544 142,949,418 6056714 1 F ISC AL YEAR FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 F Y 2027 F Y 2028 F Y 2029 2 3 ELEC TRIC LOAD 0 0 4 Purc hases (MWh)905,071 879,913 827,106 836,828 849,043 869,163 835,686 832,000 825,954 820,400 814,662 5 Sales (MWh)884,322 854,761 813,881 812,841 825,297 830,051 810,616 807,040 801,176 795,788 790,222 6 7 BILL AND RATE C HANGES 8 Syst em Average Rat e ($/kWh)0.1487$ 0.1603$ 0.1590$ 0.1606$ 0.1994$ 0.2078$ 0.2088$ 0.2201$ 0.2320$ 0.2446$ 0.2579$ 9 Change in Syst em Average Rat e 5%8%-1%1%24%4%0%5%5%5%5% 10 Change in Average Resident ial Bill 6%8%-1%-1%5%21%0%5%5%5%5% 11 12 REVENUES 13 Net Sales 76%79%79%78%61%76%77%81%83%83%85% 14 Ot her Revenues and T ransfers In 24%21%21%21%28%24%23%19%17%17%15% 15 T OT AL REVENUES 100%100%100%99%89%100%100%100%100%100%100% 16 17 EXPENSES 18 Commodit y Purc hases 53%53%53%55%58%39%55%51%51%50%50% 19 Operat ing Expenses 20 Administ rat ion 21 Alloc at ed Charges 3%4%4%3%5%4%6%5%5%5%5% 22 Rent 4%4%3%3%3%3%4%3%3%3%3% 23 Debt Ser vic e 6%5%4%4%4%4%3%4%6%9%8% 24 Equit y T ransf er 8%8%8%7%7%6%8%7%7%7%7% 25 T ransfer s and Ot her Adjust ment s 0%-2%-2%1%1%1%1%1%1%1%1% 26 Subt ot al, Administ rat ion 21%18%17%18%20%17%21%21%23%25%25% 27 Resourc e Management 1%2%2%1%2%1%2%2%2%2%2% 28 Operat ions and Mt c 8%8%9%8%10%7%10%9%9%9%9% 29 Engineering (Operat ing)1%1%1%1%1%1%1%1%1%1%1% 30 Cust omer Servic e 1%1%1%1%1%1%1%1%1%1%1% 31 Allowanc e f or Unspent Budget 0%0%0%0%0%0%0%0%0%0%0% 32 Subt ot al, Operat ing Expenses 32%31%31%30%33%27%34%33%35%37%38% 33 Capit al Program Cont ribut ion 7%10%11%11%7%27%0%7%7%6%6% 34 T OT AL EXPENSES 92%95%94%97%98%93%89%91%92%93%93% 35 36 SUPPLY OPERATIONS RESERVE 37 Min (60 days of non-c apit al expenses)16,831,022 16,957,154 18,345,636 20,817,535 22,301,354 19,923,460 21,062,871 22,110,623 22,412,033 22,874,360 23,148,588 38 T arget (90 days of non-c apit al expenses)25,246,533 25,435,732 27,518,453 31,226,303 33,452,031 29,885,189 31,594,307 33,165,935 33,618,049 34,311,540 34,722,882 39 Max (120 days of non-c apit al expenses)33,662,044 33,914,309 36,691,271 41,635,071 44,602,708 39,846,919 42,125,743 44,221,246 44,824,065 45,748,720 46,297,176 40 41 DISTRIBUTION OPERATIONS RESERVE 42 Min (60 days of non-c apit al expenses)7,869,900 8,621,917 8,051,581 7,811,860 10,035,492 10,426,314 10,800,438 11,701,048 12,741,650 14,084,430 14,525,802 43 T arget (90 days of non-c apit al expenses)10,096,233 11,071,856 10,898,913 10,608,212 13,266,354 13,781,173 14,267,972 15,541,561 17,022,183 18,952,824 19,527,952 44 Max (120 days of non-c apit al expenses)12,322,566 13,521,795 13,746,245 13,404,564 16,497,217 17,136,033 17,735,506 19,382,073 21,302,716 23,821,219 24,530,102 45 Risk Assessment Value 4,992,321 6,001,771 6,381,125 6,668,204 6,330,333 12,894,566 6,123,942 8,015,246 8,595,304 9,014,046 9,416,218 46 47 DEBT SERVICE C OVERAGE RATIO 48 Net Revenues (125% of Debt Servic e)451%518%214%-43%535%649%818%371%300%264%272% 49 Available Reserves (5x Debt Servic e)*11.9 16.1 13.4 8.4 9.4 7.0 23.9 13.5 8.7 6.5 6.8 50 *F or t he purposes of debt c ovenant s, t he unr est ric t ed reserves of ot her ut ilit ies may be c ount ed t owar d available r eserves for t his measure. A rat io below 5x means t hat t his ut ilit y is r elying on reserves of ot her ut ilit ies t o meet debt c ovenant s. ELECTRIC UTILITY FINANCIAL PLAN J u n e 2 0 1 8 52 | P a g e APPENDIX B: ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES The following reserves management practices are used when developing the Electric Utility Financial Plan: Section 1. Definitions a) “Financial Planning Period” – The Financial Planning Period is the range of future fiscal years covered by the Financial Plan. For example, if the Financial Plan delivered in conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019, FY 2015 to FY 2019 would be the Financial Planning Period. b) “Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers to the Utility’s Unrestricted Net Assets. c) “Net Assets” - The Government Accounting Standards Board defines a Utility’s Net Assets as the difference between its assets and liabilities. d) “Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital assets (net of related debt) or restricted for debt service or other restricted purposes. Section 2. Supply Fund Reserves The Electric Supply Fund Balance is reserved for the following purposes: a) For existing contracts, as described in Section 4 (Reserve for Commitments) b) For operating budgets reappropriated from previous years, as described in Section 5 (Reserve for Reappropriations) c) For special projects for the benefit of the Electric Utility ratepayers, as described in Section 6 (Electric Special Projects Reserve) d) For year to year balancing of costs associated with the Electric Utility’s hydroelectric resources, as described in Section 7 (Hydroelectric Stabilization Reserve) e) For rate stabilization, as described in Section 11 (Rate Stabilization Reserves) f) For operating contingencies, as described in Section 12 (Operations Reserves) g) For tracking unspent or unallocated revenues from the sale of carbon allowances freely allocated by the California Air Resources Board to the electric utility under the State’s Cap and Trade Program, as described in Section 16 (Cap and Trade Program Reserve) h) For tracking funding of City buildings, appliance and vehicle electrification projects and programs, as described in Section 17 (Electrification Reserve) i) Any funds not included in the other reserves will be considered Unassigned Reserves and shall be returned to ratepayers or assigned a specific purpose as described in Section 13 (Unassigned Reserves). Section 3. Distribution Fund Reserves The Electric Distribution Fund Balance is reserved for the following purposes: a) For existing contracts, as described in Section 4 (Reserves for Commitments) b) For operating and capital budgets reappropriated from previous years, as described in Section 5 (Reserves for Reappropriations) c) As an offset to underground loan receivables, as described in Section 8 (Underground Loan Reserve) ELECTRIC UTILITY FINANCIAL PLAN J u n e 2 0 1 8 53 | P a g e d) To hold Public Benefit Program funds collected but not yet spent, as described in Section 9 (Public Benefits Reserve) e) For cash flow management and contingencies related to the Electric Utility’s Capital Improvement Program (CIP), as described in Section 10 (CIP Reserve) f) For rate stabilization, as described in Section 11 (Rate Stabilization Reserves) g) For operating contingencies, as described in Section 12 (Operations Reserves) h) For tracking revenues earned via the sale of Low Carbon Fuel Credits allocated by the California Air Resources Board to the City, as well as expenses incurred, in accordance with California’s Low Caron Fuel Standard program, as described in Section 15 (Low Carbon Fuel Standard Reserve) i) Any funds not included in the other reserves will be considered Unassigned Reserves and shall be returned to ratepayers or assigned a specific purpose as described in Section 13 (Unassigned Reserves). Section 4. Reserves for Commitments At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund Reserves for Commitments will be set to an amount equal to the total remaining spending authority for all contracts in force for the Electric Supply Fund and Electric Distribution Fund, respectively, at that time. Section 5. Reserves for Reappropriations At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund Reserves for Reappropriations will be set to an amount equal to the amount of all remaining capital and non-capital budgets that will be reappropriated to the following fiscal year for each Fund in accordance with Palo Alto Municipal Code Section 2.28.090. Section 6. Electric Special Projects Reserve The Electric Special Projects Reserve (ESP Reserve) will be managed in accordance with the policies set forth in Resolution 9206 (Resolution of the Council of the City of Palo Alto Approving Renaming the Calaveras Reserve to the Electric Special Project Reserve and Adoption of Electric Special Project Reserve Guidelines). These policies are included from Resolution 9206 as amended to refer to the reserves structure set forth in these Reserves Management Practices: a) The purpose of the ESP Reserve is to fund projects that benefit electric ratepayers; b) The ESP Reserve funds must be used for projects of significant impact; c) Projects proposed for funding must demonstrate a need and value to electric ratepayers. The projects must have verifiable value and must not be speculative, or high-risk in nature; d) Projects proposed for funding must be substantial in size, requiring funding of at least $1 million; e) Set a goal to commit funds by the end of FY 2025; f) Any uncommitted funds remaining at the end of FY 2030 will be transferred to the Electric Supply Operations Reserve and the ESP Reserve will be closed; ELECTRIC UTILITY FINANCIAL PLAN J u n e 2 0 1 8 54 | P a g e Section 7. Hydroelectric Stabilization Reserve The Hydroelectric Stabilization Reserve is used to manage the supply cost impacts associated with variations in generation from hydroelectric resources. Staff will manage the Hydroelectric Stabilization Reserve as follows: a) Projected Hydro Output: Near the end of each fiscal year, staff will determine the actual and expected hydro output for that fiscal year, compare that to the long-term average annual output level (495,957 MWh as of March 2018), and multiply the difference by the average of the monthly round-the-clock forward market prices for each month of the current fiscal year. b) Changes in Reserves. Staff is authorized to transfer the amount described in Sec. 7(a) from the Operations Reserve to the Hydroelectric Stabilization Reserve for hydro output deviations above long-term average levels, or transfer this amount from the Hydroelectric Stabilization Reserve to the Operations Reserve for hydro output deviations below long-term average levels. c) Implementation of HRA. The level of the Hydroelectric Stabilization Reserve after the transfers described above shall be the basis for staff’s determination, with Council approval, of whether to implement the Hydro Rate Adjuster (Electric Rate E-HRA) for the following fiscal year. d) Reserve Guidelines. Staff will manage the Hydroelectric Stabilization Reserve according to the following guideline levels: Minimum Level $3 million Target Level $19 million Maximum Level $35 million Section 8. Underground Loan Reserve At the end of each fiscal year, the Underground Loan Reserve will be adjusted by the principal payments made against outstanding underground loans. Section 9. Public Benefits Reserve The Public Benefits Reserve will be increased by the amount of unspent Public Benefits Revenues remaining at the end of each fiscal year. Expenditure of these funds requires action by the City Council. Section 10. CIP Reserve The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for capital contingencies. Staff will manage the CIP Reserve according to the following practices: a) The following guideline levels are set forth for the CIP Reserve. These guideline levels are calculated for each fiscal year of the Financial Planning Period and approved by Council resolution. Minimum Level 20% of the maximum CIP Reserve guideline level ELECTRIC UTILITY FINANCIAL PLAN J u n e 2 0 1 8 55 | P a g e Maximum Level Average annual (12 month)14 CIP budget, for 48 months of budgeted CIP expenses15 b) Changes in Reserves: At the end of each fiscal year staff will transfer from the Distribution Operations Reserve to the CIP Reserve an amount equal to the amount of electric utility unspent CIP budget at the end of the fiscal year reduced by the amount of any contractual commitments and reappropriations. Any other additions to or withdrawals from the CIP reserve require Council action. c) Minimum Level: i) If, at the end of any fiscal year, the minimum guideline is not met, staff shall present a plan to the City Council to replenish the reserve. The plan shall be delivered by the end of the following fiscal year, and shall, at a minimum, result in the reserve reaching its minimum level by the end of the next fiscal year. For example, if the CIP Reserve is below its minimum level at the end of FY 2017, staff must present a plan by June 30, 2018 to return the reserve to its minimum level by June 30, 2019. In addition, staff may present, and the Council may adopt, an alternative plan that takes longer than one year to replenish the reserve, or that does so in a shorter period of time. d) Maximum Level: If there are funds in this reserve in excess of the maximum level staff must propose in the next Financial Plan to transfer these funds to another reserve or return them to ratepayers in the funds to ratepayers, or designate a specific use of funds for CIP investments that will be made by the end of the next Financial Planning period. Staff may also seek City Council to approve holding funds in this reserve in excess of the maximum level if they are held for a specific future purpose related to the CIP. Section 11. Rate Stabilization Reserves Funds may be added to the Electric Supply or Distribution Fund’s Rate Stabilization Reserves by action of the City Council and held to manage the trajectory of future year rate increases. Withdrawal of funds from either Rate Stabilization Reserve requires action by the City Council. If there are funds in either Rate Stabilization Reserve at the end of any fiscal year, any subsequent Electric Utility Financial Plan must result in the withdrawal of all funds from this Reserve by the end of the Financial Planning Period. The Council may approve exceptions to this requirement, when proposed by staff to provide greater rate stabilization to customers. Section 12. Operations Reserves The Electric Supply Fund and Electric Distribution Fund Operations Reserves are used to manage normal variations in the costs of providing electric service and as a reserve for contingencies. Any portion of the Electric Utility’s Fund Balance not included in the reserves described in Section 4 to 11 above will be included in the appropriate Operations Reserve unless the reserve has reached its maximum level as set forth in Section 12 (e) below. Staff will manage the Operations Reserves according to the following practices: ELECTRIC UTILITY FINANCIAL PLAN J u n e 2 0 1 8 56 | P a g e a) The following guideline levels are set forth for the Electric Supply Fund Operations Reserve. These guideline levels are calculated for each fiscal year of the Financial Planning Period based on the levels of Operations and Maintenance (O&M) and commodity expense forecasted for that year in the Financial Plan. Minimum Level 60 days of Supply Fund O&M and commodity expense Target Level 90 days of Supply Fund O&M and commodity expense Maximum Level 120 days of Supply Fund O&M and commodity expense b) The following guideline levels are set forth for the Electric Distribution Fund Operations Reserve. These guideline levels are calculated for each fiscal year of the Financial Planning Period based on the levels of O&M expense forecasted for that year in the Financial Plan. Minimum Level 60 days of Distribution Fund O&M expense Target Level 90 days of Distribution Fund O&M expense Maximum Level 120 days of Distribution Fund O&M expense c) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Supply Fund or Distribution Fund’s Operations Reserve are lower than the minimum level set forth above, staff shall present a plan to the City Council to replenish the reserve. The plan shall be delivered within six months of the end of the fiscal year, and shall, at a minimum, result in the reserve reaching its minimum level by the end of the following fiscal year. For example, if the Operations Reserve is below its minimum level at the end of FY 2014, staff must present a plan by December 31, 2014 to return the reserve to its minimum level by June 30, 2015. In addition, staff may present an alternative plan that takes longer than one year to replenish the reserve. d) Target Level: If, at the end of any fiscal year, either Operations Reserve is higher or lower than the target level, any Financial Plan created for the Electric Utility shall be designed to return both Operations Reserves to their target levels by the end of the forecast period. e) Maximum Level: If, at any time, either Operations Reserve reaches its maximum level, no funds may be added to this Reserve. Any further increase in that fund’s Fund Balance shall be automatically included in the Unassigned Reserve described in Section 13, below. Section 13. Unassigned Reserves If the Operations Reserve in either the Electric Supply Fund or the Electric Distribution Fund reaches its maximum level, any further additions to that fund’s Fund Balance will be held in the Unassigned Reserve. If there are any funds in either Unassigned Reserve at the end of any fiscal year, the next Financial Plan presented to the City Council must include a plan to assign them to a specific purpose or return them to the Electric Utility ratepayers by the end of the first fiscal year of the next Financial Planning Period. For example, if there were funds in the Unassigned Reserves at the end of FY 2016, and the next Financial Planning Period is FY 2017 through FY 2021, the Financial Plan shall include a plan to return or assign the funds in the Unassigned Reserve by the end of FY 2017. Staff may present an alternative plan that retains these funds or returns them over a longer period of time. Section 14. Intra-Utility Transfers between Supply and Distribution Funds ELECTRIC UTILITY FINANCIAL PLAN J u n e 2 0 1 8 57 | P a g e Transfers between Electric Distribution Fund Reserves and Electric Supply Fund Reserves are permitted if consistent with the purposes of the two reserves involved in the transfer. Such transfers require action by the City Council. Section 15. Low Carbon Fuel Standard (LCFS) Reserve This reserve tracks revenues earned via the sale of Low Carbon Fuel Credits allocated by the California Air Resources Board to the City, as well as expenses incurred, in accordance with California’s Low Caron Fuel Standard program. At the end of each fiscal year, the LCFS Reserve will be adjusted by the net of revenues and expenses associated with California’s LCFS program. Section 16. Cap and Trade Program Reserve This reserve tracks unspent or unallocated revenues from the sale of carbon allowances freely allocated by the California Air Resources Board to the electric utility, under the State’s Cap and Trade Program. Funds in this Reserve are managed in accordance with the City’s Policy on the Use of Freely Allocated Allowances under the State’s Cap and Trade Program (the Policy), adopted by Council Resolution 9487 in January 2015. At the end of each fiscal year, the Cap and Trade Program Reserve will be adjusted by the net of revenues and expenses associated with the Cap and Trade program. Section 17. Electrification Reserve This reserve is used to track funding of City buildings, appliance and vehicle electrification projects and programs, including development and implementation costs and associated financial incentives, loans and rebates for participating customers. The reserve may be funded by any lawful source of funds available for such programs, including new or ongoing utility revenues derived from customer participation. The reserve balance shall be annually adjusted based on the net of revenues and expenses associated with the City’s building appliance and vehicle electrification projects and programs using this reserve. ELECTRIC UTILITY FINANCIAL PLAN J u n e 2 0 1 8 58 | P a g e APPENDIX C: DESCRIPTION OF ELECTRIC UTILITY OPERATIONAL ACTIVITIES This appendix describes the activities associated with the various cost categories referred to in this Financial Plan. Customer Service: This category includes the Electric Utility’s share of the call center, meter reading, collections, and billing support functions. Billing support encompasses staff time associated with bill investigations and quality control on certain aspects of the billing process. It does not include maintenance of the billing system itself, which is included in Administration. This category also includes CPAU’s key account representatives, who work with large commercial customers who have more complex requirements for their electric services. Resource Management: This category includes supply portfolio management, energy procurement, rate setting, and tracking of legislation and regulation related to the electric industry. Operations and Maintenance: This category includes the costs of a variety of distribution system maintenance activities, including: •monitoring the substations and performing routine maintenance; •performing preventative maintenance on the system; •monitoring the system’s status from the UCC using SCADA; •maintaining the SCADA system; •investigating outages and other customer complaints and performing emergency repairs; •clearing vegetation near overhead power lines; and •testing and replacing meters to ensure accurate sales metering. Administration: Accounting, purchasing, legal, and other administrative functions provided by the City’s General Fund staff, as well as shared communications services, Utilities Department administrative overhead and billing system maintenance costs. Demand Side Management: Includes the cost of administering energy efficiency programs and the direct cost of rebates paid. Includes solar rebates. Engineering (Operating): The Electric Utility’s engineers focus primarily on the CIP, but a small portion of their time is spent assisting with distribution system maintenance. APPENDIX D: SAMPLES OF RECENT ELECTRIC UTILITY OUTREACH COMMUNICATIONS RESIDENTIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-1 CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-1-1 Supersedes Sheet No E-1-1 dated 7-1-20232 Effective 7-1-20243 A. APPLICABILITY: This Rate Schedule applies to separately metered single-family residential dwellings receiving Electric Service from the City of Palo Alto Utilities. B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total Tier 1 usage $ 0.1027009999 $ 0.085186954 $ 0.0054968 $ 0.193377521 Tier 2 usage Any usage over Tier 1 0.13311873 0.0827210225 0.0054968 0.221324666 Customer ChargeMinimum Bill ($/day) 0.15254181 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. The Customer Charge is based on the number of days in your particular billing cycle. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. 2. Calculation of Usage Tiers Tier 1 Electricity usage shall be calculated and billed based upon a level of 15.3711 kWh per day, prorated by Meter reading days of Service. As an example, for a 30-day bill, the Tier 1 level would be 461 330 kWh. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. RESIDENTIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-1 CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-1-2 Supersedes Sheet No E-1-2 dated 7-1-20232 Effective 7-1-20243 {End} RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-2 CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-2-1 Supersedes Sheet No E-2-1 dated 7-1-20223 Effective 7-1-20243 A. APPLICABILITY: This Rate Schedule applies to the following Customers receiving Electric Service from the City of Palo Alto Utilities: 1. Small nNon-residential Customers receiving Non-Demand Metered Electric Service; and 2. Customers with Accounts at Master-Metered multi-family facilities receiving Non- Demand Metered Electric Service. B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total Summer Period $ 0.14926216 $ 0.097350.117 75 $ 0.005490.00568 $ 0.252100.2 6559 Winter Period 0.092420.101 96 0.066230.078 61 0.005490.00568 0.164140.1 8625 Minimum BillCustomer Charge ($/day) 0.18411.06 46 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. 2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-2 CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-2-2 Supersedes Sheet No E-2-2 dated 7-1-20223 Effective 7-1-20243 from November 1 to April 30. When the billing period includes use in both the Summer and the Winter Periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive months, a maximum Demand Meter will be installed as promptly as is practicable and thereafter continued in service until the monthly use of energy has fallen below 6,000 kWh for twelve consecutive months, whereupon, at the option of the City, it may be removed. The maximum Demand in any month will be the maximum average power in kilowatts taken during any 15-minute interval in the month provided that if the Customer’s load is intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type Demand Meter which does not reset after a definite time interval may be used at the City's option. The billing Demand to be used in computing charges under this schedule will be the actual maximum Demand in kilowatts for the current month. An exception is that the billing Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual maximum Demand of such Customers between the hours of noon and 6 pm on weekdays. {End} RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-2-G CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-2-G-1 Supersedes Sheet No E-2-G-1 dated 7-1-20232 Effective 7-1-20243 A. APPLICABILITY: This Rate Schedule applies to the following Customers receiving Electric Service from the City of Palo Alto Utilities under the Palo Alto Green Program: 1. Small nNon-residential Customers receiving Non-Demand Metered Electric Service; and 2. Customers with Accounts at Master-Metered multi-family facilities receiving Non-Demand Metered Electric Service. B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: 1. 100% Renewable Option: Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Palo Alto Green Charge Total Summer Period $ 0.149260.14 216 $ 0.097350.11 775 $ 0.005490. 00568 $ 0.0075 $ 0.259600. 27309 Winter Period 0.092420.10 196 0.066230.07 861 0.005490. 00568 0.0075 $ 0.171640. 19375 Minimum BillCustomer Charge ($/day) 0.18411.0646 2. 1000 kWh Block Purchase Option: Per kilowatt-hour (kWh) Commodity Distribution Public Benefits Total Summer Period $ 0.149260.14 216 $ 0.097350.11 775 $ 0.005490. 00568 $ 0.252100. 26559 Winter Period 0.092420.10 0.066230.07 0.005490. 0.164140. RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-2-G CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-2-G-2 Supersedes Sheet No E-2-G-2 dated 7-1-20232 Effective 7-1-20243 196 861 00568 18625 Minimum BillCustomer Charge ($/day) 0.18411.0646 Palo Alto Green Charge (per 1000 kWh block) $7.50 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. 2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective from November 1 to April 30. When the billing period includes use in both the Summer and Winter Periods, usage will be prorated based upon the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Palo Alto Green Program Description and Participation Palo Alto Green provides for either the purchase of enough renewable energy credits (RECs) to either match 100% of the energy usage at the facility every month, or for the purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the production of renewable energy, increase the financial value of power from renewable sources, and create a transparent and sustainable market that encourages new development of wind and solar power. Customers choosing to participate shall fill out a Palo Alto Green Power Program application provided by the Customer Service Center. Customers may request at any time, RESIDENTIAL MASTER-METERED AND SMALL NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-2-G CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-2-G-3 Supersedes Sheet No E-2-G-3 dated 7-1-20232 Effective 7-1-20243 in writing, a change to the number of blocks they wish to purchase under the Palo Alto Green Program. 4. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive months, a maximum Demand Meter will be installed as promptly as is practicable and thereafter continued in service until the monthly use of energy has fallen below 6,000 kWh for twelve consecutive months, whereupon, at the option of the City, it may be removed. The maximum Demand in any month will be the maximum average power in kilowatts taken during any 15-minute interval in the month, provided that if the Customer-s load is intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type Demand Meter which does not reset after a definite time interval may be used at the City's option. The billing Demand to be used in computing charges under this schedule will be the actual maximum Demand in kilowatts for the current month. An exception is that the billing Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual maximum Demand of such Customers between the hours of noon and 6 pm on weekdays. {End} MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4 CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-4-1 Supersedes Sheet No E-4-1 dated 7-1-20232 Effective 7-1-20243 A. APPLICABILITY: This Rate Schedule applies to Demand metered Secondary Electric Service for Customers with a maximum Demand below 1,000 kilowatts. This Rate Schedule applies to three-phase Electric Service and may include Service to master-metered multi-family facilities or other facilities requiring Demand-metered Service, as determined by the City. B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh): Commodity Distribution Public Benefits Total Summer Period Demand Charge (per kW) $ 10.985.28 $ 34.3131.54 $ 45.2936.82 Energy Charge (per kWh) 0.123180.131 57 0.025200.026 38 0.005490.00 568 0.153870.1636 3 Winter Period Demand Charge (per kW) $ 2.573.29 $ 21.1620.87 $ 23.7324.16 Energy Charge (per kWh) 0.079490.094 61 0.025200.026 38 0.005490.00 568 0.110180.1266 7 Minimum BillCustomer Charge ($/day) 3.739022.0012 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4 CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-4-2 Supersedes Sheet No E-4-2 dated 7-1-20232 Effective 7-1-20243 2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective from November 1 to April 30. When the billing period includes use both in the Summer and the Winter Periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kWh for three consecutive months, a Maximum Demand Meter will be installed as promptly as is practicable and thereafter continued in Service until the monthly use of energy has fallen below 6,000 kWh for twelve consecutive months, whereupon, at the option of the City, it may be removed. The Maximum Demand in any month will be the maximum average power in kilowatts taken during any 15-minute interval in the month, provided that if the Customer’s load is intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type Demand Meter which does not reset after a definite time interval may be used at the City's option. The Billing Demand to be used in computing charges under this schedule will be the actual Maximum Demand in kilowatts for the current month. An exception is that the Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual Maximum Demand of such Customers between the hours of noon and 6 pm on weekdays. 4. Power Factor For new or existing Customers whose Demand is expected to exceed or has exceeded 300 kilowatts for three consecutive months, the City has the option of installing applicable Metering to calculate a Power Factor. The City may remove such Metering from the Service of a Customer whose Demand has been below 200 kilowatts for four consecutive months. When such metering is installed, the monthly Electric bill will include a “Power Factor Adjustment”, if applicable. The adjustment will be applied to a Customer’s bill prior to MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4 CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-4-3 Supersedes Sheet No E-4-3 dated 7-1-20232 Effective 7-1-20243 the computation of any primary voltage discount. The Power Factor Adjustment is applied by increasing the total energy and Demand charges for any month by 0.25 percent (0.25%) for each one percent (1%) that the monthly Power Factor of the Customer’s load was less than 95%. The monthly Power Factor is the average Power Factor based on the ratio of kilowatt hours to kilovolt-ampere hours consumed during the month. Where time-of-day Metering is installed, the monthly Power Factor shall be the Power Factor coincident with the Customer's Maximum Demand. 5. Changing Rate Schedules Customers may request a rate schedule change at any time to any City of Palo Alto full- service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile. 6. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be offered, but the City is not required to supply Service at a particular line voltage where it has, or will install, ample facilities for supplying at another voltage equally or better suited to the Customer's electrical requirements, as determined in the City’s sole discretion. The City retains the right to change its line voltage at any time after providing reasonable advance notice to any Customer receiving the discount in this section. The Customer then has the option to change his system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kilovolt-ampere size limitation. 7. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection D(7)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue meter and that occasionally require backup power from the City due to non-operation of the non-utility generation source. MEDIUM NON-RESIDENTIAL ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4 CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-4-4 Supersedes Sheet No E-4-4 dated 7-1-20232 Effective 7-1-20243 b. Standby Charges: Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $0.69 $15.23 $15.92 Winter Period $0.63 $9.04 $9.67 c. Meters. A separate Meter is required for each non-utility generation source. d. Calculation of Maximum Demand Credit. (1) In the event the Customer’s Maximum Demand (as defined in Section D.3) occurs when one or more of the non-utility generators on the Customer’s side of the City’s revenue meter are not operating, the Maximum Demand will be reduced by the sum of the Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero. (2) If the non-utility generation source does not operate for an entire billing cycle, the standby charge does not apply and the Customer shall not receive the Maximum Demand credit described in this Section. e. Exemptions. (1) The standby charge shall not apply to backup generators designed to operate only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases. (2) The standby charge shall not apply if the Customer meets the definition of an “Eligible Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4), as amended. (3) The applicability of these exemptions shall be determined at the discretion of the Utilities Director. {End} MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-4-G-1 Supersedes Sheet No E-4-G-1 dated 7-1-20232 Effective 7-1-20243 A. APPLICABILITY: This Rate Schedule applies to Demand metered Secondary Electric Service for Customers with a maximum Demand below 1,000 kilowatts (kW) who receive power under the Palo Alto Green Program. This Rate Schedule applies to three-phase Electric Service and may include Service to Master-metered multi-family facilities or other facilities requiring Demand metered Service, as determined by the City. B. TERRITORY: The rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: 1. 100% Renewable Option: Commodity Distribution Public Benefits Palo Alto Green Charge Total Summer Period Demand Charge (per kW) $ 10.985.28 $ 34.3131.54 $ 45.2936.8 2 Energy Charge (per kWh) 0.123180.13 157 0.025200.026 38 0.005490. 00568 0.0075 0.161370. 17113 Winter Period Demand Charge (per kW) $ 2.573.29 $ 21.1620.87 $ 23.7324.1 6 Energy Charge (per kWh) 0.079490.09 461 0.025200.026 38 0.005490. 00568 0.0075 0.117680. 13417 Minimum BillCustomer Charge ($/day) 3.739022.0012 MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-4-G-2 Supersedes Sheet No E-4-G-2 dated 7-1-20232 Effective 7-1-20243 2. 1000 kWh Block Purchase Option: Commodity Distribution Public Benefits Total Summer Period Demand Charge (per kW) $ 10.985.28 $ 34.3131.54 $ 45.2936.8 2 Energy Charge (per kWh) 0.123180.13 157 0.025200.02 638 0.005490. 00568 0.153870. 16363 Palo Alto Green Charge (per 1000 kWh block) $7.50 Winter Period Demand Charge (per kW) $ 2.573.29 $ 21.1620.87 $ 23.7324.1 6 Energy Charge (per kWh) 0.079490.09 461 0.025200.02 638 0.005490. 00568 0.110180. 12667 Palo Alto Green Charge (per 1000 kWh block) $7.50 Minimum BillCustomer Charge ($/day) 3.739022.0012 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges, and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. 2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective from November 1 to April 30. When the billing period includes use both in the Summer and the Winter Periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive months, a Maximum Demand Meter will be installed as promptly as is MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-4-G-3 Supersedes Sheet No E-4-G-3 dated 7-1-20232 Effective 7-1-20243 practicable and thereafter continued in Service until the monthly use of energy has dropped below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it may be removed. The Maximum Demand in any month will be the maximum average power in kilowatts taken during any 15-minute interval in the month, provided that if the Customer’s load is intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type Demand Meter, which does not reset after a definite time interval, may be used at the City's option. The Billing Demand to be used in computing charges under this schedule will be the actual Maximum Demand in kilowatts for the current month. An exception is that the Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual Maximum Demand of such Customers between the hours of noon and 6 PM on weekdays. 4. Power Factor For new or existing Customers whose Demand is expected to exceed or has exceeded 300 kilowatts for three consecutive months, the City has the option of installing applicable Metering to calculate a Power Factor. The City may remove such Metering from the Service of a Customer whose Demand has dropped below 200 kilowatts for four consecutive months. When such Metering is installed, the monthly Electric bill will include a “Power Factor Adjustment”, if applicable. The adjustment will be applied to a Customer’s bill prior to the computation of any primary voltage discount. The Power Factor Adjustment is applied by increasing the total energy and Demand charges for any month by 0.25 percent or (1/4) for each one percent (1%) that the monthly Power Factor of the Customer’s load was less than 95%. The monthly Power Factor is the average Power Factor based on the ratio of kilowatt-hours to kilovolt-ampere hours consumed during the month. Where time-of-day Metering is installed, the monthly Power Factor shall be the Power Factor coincident with the Customer's Maximum Demand. 5. Changing Rate Schedules Customers may request a rate schedule change at any time to any applicable full-service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile. MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-4-G-4 Supersedes Sheet No E-4-G-4 dated 7-1-20232 Effective 7-1-20243 6. Palo Alto Green Program Description and Participation Palo Alto Green provides for either the purchase of enough renewable energy credits (RECs) to either match 100% of the energy usage at the facility every month, or for the purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the production of renewable energy, increase the financial value of power from renewal sources, and creates a transparent and sustainable market that encourages new development of wind and solar. Customers choosing to participate shall fill out a Palo Alto Green Power Program application provided by the Customer Service Center. Customers may request at any time, in writing, a change to the number of blocks they wish to purchase under the Palo Alto Green Program. 7. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is supplied, a discount of 2.5 percent for available line voltages above 2 kilovolts will be offered, but the City is not required to supply Service at a particular line voltage where it has, or will install, ample facilities for supplying at another voltage equally or better suited to the Customer's electrical requirements, as determined in the City’s sole discretion. The City retains the right to change its line voltage at any time after providing reasonable advance notice to any Customer receiving the discount in this section. The Customer then has the option to change the system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kilovolt-ampere size limitation. 8. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue Meter and that occasionally require backup power from the City due to non-operation of the non-utility generation source. MEDIUM NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-4-G CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-4-G-5 Supersedes Sheet No E-4-G-5 dated 7-1-20232 Effective 7-1-20243 b. Standby Charges: Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $0.69 $15.23 $15.92 Winter Period $0.63 $9.04 $9.67 c. Meters: A separate Meter is required for each non-utility generation source. d. Calculation of Maximum Demand Credit: (1) In the event the Customer’s Maximum Demand (as defined in Section D.3) occurs when one or more of the non-utility generators on the Customer’s side of the City’s revenue Meter are not operating, the Maximum Demand will be reduced by the sum of the Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero. (2) If the non-utility generation source does not operate for an entire billing cycle, the standby charge does not apply and the Customer shall not receive the Maximum Demand credit described in this Section. e. Exemptions: (1) The standby charge shall not apply to backup generators designed to operate only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases. (2) The standby charge shall not apply if the Customer meets the definition of an “Eligible Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4), as amended. (3) The applicability of these exemptions shall be determined at the discretion of the Utilities Director. {End} MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-4 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-4-TOU-1 Supersedes Sheet No E-4-TOU-1 dated 7-1-20232 Effective 7-1-20243 A. APPLICABILITY: This voluntary Rate Schedule applies to Demand metered Secondary Electric Service for Customers with Demand between 500 and 1,000 kilowatts per month and who have sustained this level of usage for at least three consecutive months during the most recent 12 month period. This Rate Schedule applies to three-phase Electric Service and may include Service to Master- Metered multi-family facilities or other facilities requiring Demand-metered Service, as determined by the City. In addition, this Rate Schedule is applicable for Customers who did not pay power factor adjustments during the last 12 months. B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh): Commodity Distribution Public Benefits Total Summer Period Demand Charge (per kW) Peak $ 9.723.22 $ 17.1810.85 $ 26.9014.07 Mid-PeakMax Demand 1.291.11 17.1810.85 18.4711.96 Off-Peak 1.11 10.85 11.96 Energy Charge (per kWh) Peak $ 0.170380.120 20 $ 0.025380.026 36 $ 0.005490.00568 $ 0.201250.152 24 Mid-Peak 0.140410.152 04 0.025380.026 36 0.005490.00568 0.171280.184 08 Off-Peak 0.105560.092 29 0.025380.026 36 0.005490.00568 0.136430.124 33 Winter Period Demand Charge (per kW) Peak $ 1.301.83 $ 10.7311.63 $ 12.0313.46 Max DemandOff- Peak 1.301.83 10.7311.63 12.0313.46 MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-4 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-4-TOU-2 Supersedes Sheet No E-4-TOU-2 dated 7-1-20232 Effective 7-1-20243 Commodity Distribution Public Benefits Total Energy Charge (per kWh) Peak $ 0.119760.147 44 $ 0.025000.026 36 $ 0.005490.00568 $ 0.150250.179 48 Mid-Peak 0.09452 0.02500 0.00549 0.12501 Off-Peak 0.06525 0.12619 0.025000.026 36 $ 0.0054968 0.09574 0.15823 Minimum BillCustomer Charge ($/day) 3.739022.001 2 D. SPECIAL NOTES: 1. Calculation of Cost Components The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. 2. Definition of Time Periods SUMMER PERIOD (Service from May 1 to October 31): Energy Peak: 124:00 noonp.m. to 96:00 p.m. Monday through Friday (except holidays) Mid Peak: 28:00 pa.m. to 412:00 noonp.m. Monday through Friday (except holidays) 96:00 p.m. to 119:00 p.m. Off-Peak: 9:00 p.m. to 8:00 a.m.All other hours Monday through Friday (except holidays) All day Saturday, Sunday, and holidays Demand Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays) Max Demand: All other hours Monday through Friday (except MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-4 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-4-TOU-3 Supersedes Sheet No E-4-TOU-3 dated 7-1-20232 Effective 7-1-20243 holidays)Every day All day Saturday, Sunday, and holidays WINTER PERIOD (Service from November 1 to April 30): Energy Peak: 48:00 pa.m. to 9:00 p.m. Monday through Friday (except holidays) Mid Peak: 9:00 a.m. to 2:00 p.m. Monday through Friday (except holidays) Off-Peak: 9:00 p.m. to 8:00 a.m.All other hours Monday through Friday (except holidays) All day Saturday, Sunday, and holidays Demand Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays) Max Demand: All other hours Monday through Friday (except holidays)Every day All day Saturday, Sunday, and holidays TYPES OF DEMAND CHARGES: The Peak Demand Charge per kilowatt applies to the maximum peak-period demand during the time periods noted above. The Maximum (Max) Demand charge per kilowatt applies to the maximum demand at any time during the month. Both demand charges apply in each billing period, and the maximum peak-period demand and maximum demand may occur at different times in the billing period depending on customer usage patterns. SEASONAL RATE CHANGES: When the billing period includes use in both the Summer and the Winter periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Demand Meter MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-4 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-4-TOU-4 Supersedes Sheet No E-4-TOU-4 dated 7-1-20232 Effective 7-1-20243 Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive months, a Demand Meter will be installed as promptly as is practicable and thereafter continued in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it may be removed. The Billing Demand to be used in computing charges under this schedule will be the actual Maximum Demand in kilowatts taken during any 15-minute interval in each of the designated time periods as defined under Section D.2. 4. Power Factor Adjustment Time of Use Customers must not have had a power factor adjustment assessed on their Service for at least 12 months. Power factor is calculated based on the ratio of kilowatt hours to kilovolt- ampere hours consumed during the month, and must not have fallen below 95% to avoid the power factor adjustment. Should the City of Palo Alto Utilities Department find that the Customer’s Service should be subject to power factor adjustments, the Customer will be removed from the E-4-TOU rate schedule and placed on another applicable rate schedule as is suitable to their kilowatt Demand and kilowatt-hour usage. 5. Changing Rate Schedules Customers electing to be served under E-4 TOU must remain on said Rate Schedule for a minimum of 12 months. Should the Customer so wish, at the end of 12 months, the Customer may request a Rate Schedule change to any applicable City of Palo Alto full-service Rate Schedule as is suitable to their kilowatt Demand and kilowatt-hour usage. 6. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be offered, but the City is not required to supply Service at a particular line voltage where it has, or will install, ample facilities for supplying at another voltage equally or better suited to the Customer's electrical requirements, as determined in the City’s sole discretion. The City retains the right to change its line voltage at any time after providing reasonable advance notice to any Customer receiving the discount in this section. The Customer then has the option to change his system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kilovolt-ampere size limitation. MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-4 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-4-TOU-5 Supersedes Sheet No E-4-TOU-5 dated 7-1-20232 Effective 7-1-20243 7. Standby Charge a. Applicability: The standby charge, subject to the exemptions in subsection D(7)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue Meter and that occasionally require backup power from the City due to non-operation of the non-utility generation source. b. Standby Charges: Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $0.69 $15.23 $15.92 Winter Period $0.63 $9.04 $9.67 c. Meters. A separate Meter is required for each non-utility generation source. d. Calculation of Maximum Demand Credit. (1) In the event the Customer’s Maximum Demand occurs when one or more of the non-utility generators on the Customer’s side of the City’s revenue Meter are not operating, the Maximum Demand will be reduced by the sum of the Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero. (2) If the non-utility generation source does not operate for an entire billing cycle, the standby charge does not apply and the Customer shall not receive the Maximum Demand credit described in this Section. e. Exemptions. (1) The standby charge shall not apply to backup generators designed to operate only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases. (2) The standby charge shall not apply if the Customer meets the definition of an “Eligible Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4), as amended. MEDIUM NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-4 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-4-TOU-6 Supersedes Sheet No E-4-TOU-6 dated 7-1-20232 Effective 7-1-20243 (3) The applicability of these exemptions shall be determined at the discretion of the Utilities Director. {End} LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-7 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-7-TOU-1 Supersedes Sheet No E-7-TOU-1 dated 7-1-20232 Effective 7-1-20243 A. APPLICABILITY: This voluntary Rate Schedule applies to Demand Metered Service for non-residential Customers with a Maximum Demand of at least 1,000KW per month per site, who have sustained this Demand level at least 3 consecutive months during the last twelve months. In addition, this Rate Schedule is applicable for Customers who did not pay power factor adjustments during the last 12 months. B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh): Commodity Distribution Public Benefits Total Summer Period Demand Charge (per kW) Peak $ 11.283.86 $ 14.7111.08 $ 25.9914.94 Mid-Peak 1.13 11.08 12.21 Off-PeakMax Demand 1.451.13 14.7111.08 16.1612.21 Energy Charge (per kWh) Peak $ 0.180190.14 457 $ 0.003620.00075 $ 0.005490.00568 $ 0.189300.15100 Mid-Peak 0.148500.18 205 0.003620.00075 0.005490.00568 0.157610.18848 Off-Peak 0.111640.11 171 0.003620.00075 0.005490.00568 0.120750.11814 Winter Period Demand Charge (per kW) Peak $ 1.451.78 $ 12.999.22 $ 14.4411.00 Max DemandOff-Peak 1.451.78 12.999.22 14.4411.00 Energy Charge (per kWh) Peak $ 0.121040.09 $ 0.003540.00075 $ 0.005490.00568 $ 0.130070.10340 LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-7 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-7-TOU-2 Supersedes Sheet No E-7-TOU-2 dated 7-1-20232 Effective 7-1-20243 697 Mid-Peak 0.09552 0.00354 0.00549 0.10455 Off-Peak 0.065940.08 323 0.003540.00075 0.005490.00568 0.074970.08966 Minimum BillCustomer Charge ($/day) 17.122162.5539 D. SPECIAL NOTES: 1. Calculation of Charges The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. 2. Definition of Time Periods SUMMER PERIOD (Service from May 1 to October 31): Energy Peak: 412:00 pmnoon to 96:00 p.m. Monday through Friday (except holidays) Mid Peak: 2:00 p.m. to 4:00 p.m.8:00 a.m. to 12:00 noon Monday through Friday (except holidays) 9:00 p.m. to 11:00 p.m.6:00 p.m. to 9:00 p.m. Off-Peak: 9:00 p.m. to 8:00 a.m.All other hours Monday through Friday (except holidays) All day Saturday, Sunday, and holidays Demand Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays) Max Demand: All other hours Monday through Friday (except holidays) All dayAll hours Saturday, Sunday, and holidaysEvery day WINTER PERIOD (Service from November 1 to April 30): Energy LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-7 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-7-TOU-3 Supersedes Sheet No E-7-TOU-3 dated 7-1-20232 Effective 7-1-20243 Peak: 48:00 pa.m. to 9:00 p.m. Monday through Friday (except holidays) Mid Peak: 9:00 a.m. to 2:00 p.m. Monday through Friday (except holidays) Off-Peak: 9:00 p.m. to 8:00 a.m.All other hours Monday through Friday (except holidays) All day Saturday, Sunday, and holidays Demand Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays) Max Demand: All other hours Monday through Friday (except holidays) All day Saturday, Sunday, and holidaysAll hours Every day TYPES OF DEMAND CHARGES: The Peak Demand Charge per kilowatt applies to the maximum peak-period demand during the time periods noted above. The Maximum (Max) Demand charge per kilowatt applies to the maximum demand at any time during the month. Both demand charges apply in each billing period, and the maximum peak-period demand and maximum demand may occur at different times in the billing period depending on customer usage patterns. SEASONAL RATE CHANGES: When the billing period includes use in both the Summer and the Winter periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Request for Service Qualifying Customers may request Service under this schedule for more than one Account or one Meter if the Accounts are on one site. A site, for the purposes of this Rate Schedule, consists of one or more Accounts which cover contiguous parcels of land with no intervening public right-of- ways (e.g. streets) and which have a common billing address. 4. Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-7 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-7-TOU-4 Supersedes Sheet No E-7-TOU-4 dated 7-1-20232 Effective 7-1-20243 months, a Demand Meter will be installed as promptly as is practicable and thereafter continued in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it may be removed. The Billing Demand to be used in computing charges under this schedule will be the actual Maximum Demand in kilowatts taken during any 15-minute interval in each of the designated time periods as defined under Section D.2. 5. Power Factor Adjustment Time of Use Customers must not have had a power factor adjustment assessed on their Service for at least 12 months. Power factor is calculated based on the ratio of kilowatt hours to kilovolt- ampere hours consumed during the month, and must not have fallen below 95% to avoid the power factor adjustment. Should the City of Palo Alto Utilities Department find that the Customer’s Service should be subject to power factor adjustments, the Customer will be removed from the E-7-TOU rate schedule and placed on another applicable rate schedule as is suitable to their kilowatt Demand and kilowatt-hour usage. 6. Changing Rate Schedules Customers electing to be served under E-7 TOU must remain on said Rate Schedule for a minimum of 12 months. Should the Customer so wish, at the end of 12 months, the Customer may request a Rate Schedule change to any applicable City of Palo Alto full-service Rate Schedule as is suitable to their kilowatt Demand and kilowatt-hour usage. 7. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be offered, but the City is not required to supply Service at a particular line voltage where it has, or will install, ample facilities for supplying at another voltage equally or better suited to the Customer's electrical requirements, as determined in the City’s sole discretion. The City retains the right to change its line voltage at any time after providing reasonable advance notice to any Customer receiving the discount in this section. The Customer then has the option to change his system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kilovolt-ampere size limitation. 8. Standby Charge LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-7 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-7-TOU-5 Supersedes Sheet No E-7-TOU-5 dated 7-1-20232 Effective 7-1-20243 a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue Meter and that occasionally require backup power from the City due to non-operation of the non-utility generation source. b. Standby Charges: Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $0.84 $12.55 $13.39 Winter Period $0.72 $6.04 $6.76 c. Meters. A separate Meter is required for each non-utility generation source. d. Calculation of Maximum Demand Credit. (1) In the event the Customer’s Maximum Demand occurs when one or more of the non-utility generators on the Customer’s side of the City’s revenue Meter are not operating, the Maximum Demand will be reduced by the sum of the Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero. (2) If the non-utility generation source does not operate for an entire billing cycle, the standby charge does not apply and the Customer shall not receive the Maximum Demand credit described in this Section. e. Exemptions. (1) The standby charge shall not apply to backup generators designed to operate only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases. (2) The standby charge shall not apply if the Customer meets the definition of an “Eligible Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4) , as amended. LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-7 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-7-TOU-6 Supersedes Sheet No E-7-TOU-6 dated 7-1-20232 Effective 7-1-20243 (3) The applicability of these exemptions shall be determined at the discretion of the Utilities Director. {End} LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-7-G CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-7-G-1 Supersedes Sheet No E-7-G-1 dated 7-1-20232 Effective 7-1-20243 A. APPLICABILITY: This Rate Schedule applies to Demand metered Service for large non-residential Customers who choose Service under the Palo Alto Green Program. A Customer may qualify for this Rate Schedule if the Customer’s Maximum Demand is at least 1,000KW per month per site, who have sustained this Demand level at least 3 consecutive months during the last twelve months. B. TERRITORY: The rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: 1. 100% Renewable Option: Commodity Distribution Public Benefits Palo Alto Green Charge Total Summer Period Demand Charge ( per kW) $ 11.956.03 $ 28.4133.05 $ 40.3639. 08 Energy Charge (per kWh) 0.126590.13 917 0.003620.00 075 0.005490. 00568 0.0075 0.14320 0.15310 Winter Period Demand Charge (per kW) $ 2.793.46 $ 25.0018.25 $ 27.7921. 71 Energy Charge (per kWh) 0.078940.09 212 0.003540.00 075 0.005490. 00568 0.0075 0.09547 0.10605 Minimum BillCustomer Charge ($/day) 17.122162.5539 LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-7-G CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-7-G-2 Supersedes Sheet No E-7-G-2 dated 7-1-20232 Effective 7-1-20243 2. 1000 kWh Block Purchase Option: Commodity Distribution Public Benefits Total Summer Period Demand Charge (per kW) $ 11.956.03 $ 28.4133.05 $ 40.3639. 08 Energy Charge (per kWh) 0.126590.13 917 0.003620.00 075 0.005490.00568 0.13570 0.14560 Palo Alto Green Charge (per 1000 kWh block) $ 7.50 Winter Period Demand Charge (per kW) $ 2.793.46 $ 25.0018.25 $ 27.7921. 71 Energy Charge (per kWh) 0.078940.09 212 0.003540.00 075 0.005490.00568 0.08797 0.09855 Palo Alto Green Charge (per 1000 kWh block) $7.50 Minimum BillCustomer Charge ($/day) 17.122162.5539 D. SPECIAL NOTES: 1. Calculation of Charges The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. 2. Seasonal Rate Changes The Summer Period is effective May 1 to October 31 and the Winter Period is effective from November 1 to April 30. When the billing period includes use both in the Summer and the Winter Periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Maximum Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-7-G CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-7-G-3 Supersedes Sheet No E-7-G-3 dated 7-1-20232 Effective 7-1-20243 consecutive months, a Maximum Demand Meter will be installed as promptly as is practicable and thereafter continued in Service until the monthly use of energy has dropped below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it may be removed. The Maximum Demand in any month will be the maximum average power in kilowatts taken during any 15-minute interval in the month, provided that if the Customer’s load is intermittent or subject to fluctuations, the City may use a 5-minute interval. A thermal-type Demand Meter which does not reset after a definite time interval may be used at the City's option. The Billing Demand to be used in computing charges under this schedule will be the actual Maximum Demand in kilowatts for the current month. An exception is that the Billing Demand for Customers with Thermal Energy Storage (TES) will be based upon the actual Maximum Demand of such Customers between the hours of noon and 6 PM on weekdays. 4. Request for Service Qualifying Customers may request Service under this schedule for more than one Account or one Meter if the Accounts are at one site. A site, for the purposes of this Rate Schedule, consists of one or more Accounts which cover contiguous parcels of land with no intervening public right-of-ways (e.g. streets) and which have a common billing address. 5. Power Factor For new or existing Customers whose Demand is expected to exceed or has exceeded 300 kilowatts for three consecutive months, the City has the option of installing applicable Metering to calculate a Power Factor. The City may remove such Metering from the Service of a Customer whose Demand has dropped below 200 kilowatts for four consecutive months. When such Metering is installed, the monthly Electric bill shall include a “Power Factor Adjustment”, if applicable. The adjustment shall be applied to a Customer’s bill prior to the computation of any primary voltage discount. The power factor adjustment is applied by increasing the total energy and Demand charges for any month by 0.25 percent or (1/4) for each one percent (1%) that the monthly Power Factor of the Customer’s load was less than 95%. The monthly Power Factor is the average Power Factor based on the ratio of kilowatt-hours LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-7-G CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-7-G-4 Supersedes Sheet No E-7-G-4 dated 7-1-20232 Effective 7-1-20243 to kilovolt-ampere hours consumed during the month. Where time-of-day Metering is installed, the monthly Power Factor shall be the Power Factor coincident with the Customer's Maximum Demand. 6. Changing Rate Schedules Customers may request a rate schedule change at any time to any applicable full service rate schedule as is applicable to their kilowatt-Demand and kilowatt-hour usage profile 7. Palo Alto Green Program Description and Participation Palo Alto Green provides for either the purchase of enough renewable energy credits (RECs) to either match 100% of the energy usage at the facility every month, or for the purchase of 1000 kilowatt-hour (kWh) blocks. These REC purchases support the production of renewable energy, increase the financial value of power from renewal sources, and creates a transparent and sustainable market that encourages new development of wind and solar. Customers choosing to participate shall fill out a Palo Alto Green Power Program application provided by the Customer Service Center. Customers may request at any time, in writing, a change to the number of blocks they wish to purchase under the Palo Alto Green Program. 8. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be offered, but the City is not required to supply Service at a qualified line voltage where it has, or will install, ample facilities for supplying at another voltage equally or better suited to the Customer's Electrical requirements, as determined in the City’s sole discretion. The City retains the right to change its line voltage at any time after providing reasonable advance notice to any Customer receiving the discount in this section. The Customer then has the option to change the system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kilovolt-ampere size limitation. 9. Standby Charge LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-7-G CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-7-G-5 Supersedes Sheet No E-7-G-5 dated 7-1-20232 Effective 7-1-20243 a. Applicability: The standby charge, subject to the exemptions in subsection D(9)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue Meter and that occasionally require backup power from the City due to non-operation of the non-utility generation source. b. Standby Charges: Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $0.84 $12.55 $13.39 Winter Period $0.72 $6.04 $6.76 c. Meters: A separate Meter is required for each non-utility generation source. d. Calculation of Maximum Demand Credit: (1) In the event the Customer’s Maximum Demand (as defined in Section D.3) occurs when one or more of the non-utility generators on the Customer’s side of the City’s revenue Meter are not operating, the Maximum Demand will be reduced by the sum of the Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero. (2) If the non-utility generation source does not operate for an entire billing cycle, the standby charge does not apply and the Customer shall not receive the Maximum Demand credit described in this Section. e. Exemptions: (1) The standby charge shall not apply to backup generators designed to operate only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases. (2) The standby charge shall not apply if the Customer meets the definition of an “Eligible Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4), as amended. (3) The applicability of these exemptions shall be determined at the discretion of the Utilities Director. LARGE NON-RESIDENTIAL GREEN POWER ELECTRIC SERVICE UTILITY RATE SCHEDULE E-7-G CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-7-G-6 Supersedes Sheet No E-7-G-6 dated 7-1-20232 Effective 7-1-20243 {End} LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-7 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-7-TOU-1 Supersedes Sheet No E-7-TOU-1 dated 7-1-20232 Effective 7-1-20243 A. APPLICABILITY: This voluntary Rate Schedule applies to Demand Metered Service for non-residential Customers with a Maximum Demand of at least 1,000KW per month per site, who have sustained this Demand level at least 3 consecutive months during the last twelve months. In addition, this Rate Schedule is applicable for Customers who did not pay power factor adjustments during the last 12 months. B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. UNBUNDLED RATES: Rates per kilowatt (kW) and kilowatt-hour (kWh): Commodity Distribution Public Benefits Total Summer Period Demand Charge (per kW) Peak $ 11.283.86 $ 14.7111.08 $ 25.9914.94 Mid-Peak 1.13 11.08 12.21 Off-PeakMax Demand 1.451.13 14.7111.08 16.1612.21 Energy Charge (per kWh) Peak $ 0.180190.14 457 $ 0.003620.00075 $ 0.005490.00568 $ 0.189300.15100 Mid-Peak 0.148500.18 205 0.003620.00075 0.005490.00568 0.157610.18848 Off-Peak 0.111640.11 171 0.003620.00075 0.005490.00568 0.120750.11814 Winter Period Demand Charge (per kW) Peak $ 1.451.78 $ 12.999.22 $ 14.4411.00 Max DemandOff-Peak 1.451.78 12.999.22 14.4411.00 Energy Charge (per kWh) Peak $ 0.121040.09 $ 0.003540.00075 $ 0.005490.00568 $ 0.130070.10340 LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-7 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-7-TOU-2 Supersedes Sheet No E-7-TOU-2 dated 7-1-20232 Effective 7-1-20243 697 Mid-Peak 0.09552 0.00354 0.00549 0.10455 Off-Peak 0.065940.08 323 0.003540.00075 0.005490.00568 0.074970.08966 Minimum BillCustomer Charge ($/day) 17.122162.5539 D. SPECIAL NOTES: 1. Calculation of Charges The actual bill amount is calculated based on the applicable rates in Section C above and adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement, the bill amount may be broken down into appropriate components as calculated under Section C. 2. Definition of Time Periods SUMMER PERIOD (Service from May 1 to October 31): Energy Peak: 412:00 pmnoon to 96:00 p.m. Monday through Friday (except holidays) Mid Peak: 2:00 p.m. to 4:00 p.m.8:00 a.m. to 12:00 noon Monday through Friday (except holidays) 9:00 p.m. to 11:00 p.m.6:00 p.m. to 9:00 p.m. Off-Peak: 9:00 p.m. to 8:00 a.m.All other hours Monday through Friday (except holidays) All day Saturday, Sunday, and holidays Demand Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays) Max Demand: All other hours Monday through Friday (except holidays) All dayAll hours Saturday, Sunday, and holidaysEvery day WINTER PERIOD (Service from November 1 to April 30): Energy LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-7 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-7-TOU-3 Supersedes Sheet No E-7-TOU-3 dated 7-1-20232 Effective 7-1-20243 Peak: 48:00 pa.m. to 9:00 p.m. Monday through Friday (except holidays) Mid Peak: 9:00 a.m. to 2:00 p.m. Monday through Friday (except holidays) Off-Peak: 9:00 p.m. to 8:00 a.m.All other hours Monday through Friday (except holidays) All day Saturday, Sunday, and holidays Demand Peak: 4:00 p.m. to 9:00 p.m. Monday through Friday (except holidays) Max Demand: All other hours Monday through Friday (except holidays) All day Saturday, Sunday, and holidaysAll hours Every day TYPES OF DEMAND CHARGES: The Peak Demand Charge per kilowatt applies to the maximum peak-period demand during the time periods noted above. The Maximum (Max) Demand charge per kilowatt applies to the maximum demand at any time during the month. Both demand charges apply in each billing period, and the maximum peak-period demand and maximum demand may occur at different times in the billing period depending on customer usage patterns. SEASONAL RATE CHANGES: When the billing period includes use in both the Summer and the Winter periods, the usage will be prorated based on the number of days in each seasonal period, and the charges based on the applicable rates therein. For further discussion of bill calculation and proration, refer to Rule and Regulation 11. 3. Request for Service Qualifying Customers may request Service under this schedule for more than one Account or one Meter if the Accounts are on one site. A site, for the purposes of this Rate Schedule, consists of one or more Accounts which cover contiguous parcels of land with no intervening public right-of- ways (e.g. streets) and which have a common billing address. 4. Demand Meter Whenever the monthly use of energy has exceeded 8,000 kilowatt-hours for three consecutive LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-7 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-7-TOU-4 Supersedes Sheet No E-7-TOU-4 dated 7-1-20232 Effective 7-1-20243 months, a Demand Meter will be installed as promptly as is practicable and thereafter continued in Service until the monthly use of energy has fallen below 6,000 kilowatt-hours for twelve consecutive months, whereupon, at the option of the City, it may be removed. The Billing Demand to be used in computing charges under this schedule will be the actual Maximum Demand in kilowatts taken during any 15-minute interval in each of the designated time periods as defined under Section D.2. 5. Power Factor Adjustment Time of Use Customers must not have had a power factor adjustment assessed on their Service for at least 12 months. Power factor is calculated based on the ratio of kilowatt hours to kilovolt- ampere hours consumed during the month, and must not have fallen below 95% to avoid the power factor adjustment. Should the City of Palo Alto Utilities Department find that the Customer’s Service should be subject to power factor adjustments, the Customer will be removed from the E-7-TOU rate schedule and placed on another applicable rate schedule as is suitable to their kilowatt Demand and kilowatt-hour usage. 6. Changing Rate Schedules Customers electing to be served under E-7 TOU must remain on said Rate Schedule for a minimum of 12 months. Should the Customer so wish, at the end of 12 months, the Customer may request a Rate Schedule change to any applicable City of Palo Alto full-service Rate Schedule as is suitable to their kilowatt Demand and kilowatt-hour usage. 7. Primary Voltage Discount Where delivery is made at the same voltage as that of the line from which the Service is supplied, a discount of 2 1/2 percent for available line voltages above 2 kilovolts will be offered, but the City is not required to supply Service at a particular line voltage where it has, or will install, ample facilities for supplying at another voltage equally or better suited to the Customer's electrical requirements, as determined in the City’s sole discretion. The City retains the right to change its line voltage at any time after providing reasonable advance notice to any Customer receiving the discount in this section. The Customer then has the option to change his system so as to receive Service at the new line voltage or to accept Service (without voltage discount) through transformers to be supplied by the City subject to a maximum kilovolt-ampere size limitation. 8. Standby Charge LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-7 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-7-TOU-5 Supersedes Sheet No E-7-TOU-5 dated 7-1-20232 Effective 7-1-20243 a. Applicability: The standby charge, subject to the exemptions in subsection D(8)(e), applies to Customers that have a non-utility generation source interconnected on the Customer’s side of the City’s revenue Meter and that occasionally require backup power from the City due to non-operation of the non-utility generation source. b. Standby Charges: Commodity Distribution Total Standby Charge (per kW of Reserved Capacity) Summer Period $0.84 $12.55 $13.39 Winter Period $0.72 $6.04 $6.76 c. Meters. A separate Meter is required for each non-utility generation source. d. Calculation of Maximum Demand Credit. (1) In the event the Customer’s Maximum Demand occurs when one or more of the non-utility generators on the Customer’s side of the City’s revenue Meter are not operating, the Maximum Demand will be reduced by the sum of the Maximum Generation of those non-utility generators, but in no event shall the Customer’s Maximum Demand be reduced below zero. (2) If the non-utility generation source does not operate for an entire billing cycle, the standby charge does not apply and the Customer shall not receive the Maximum Demand credit described in this Section. e. Exemptions. (1) The standby charge shall not apply to backup generators designed to operate only in the event of an interruption in utility Service and which are not used to offset Customer electricity purchases. (2) The standby charge shall not apply if the Customer meets the definition of an “Eligible Customer-generator” as defined in California Public Utilities Code Section 2827(b)(4) , as amended. LARGE NON-RESIDENTIAL ELECTRIC TIME OF USE SERVICE UTILITY RATE SCHEDULE E-7 TOU CITY OF PALO ALTO UTILITIES Issued by the City Council Sheet No E-7-TOU-6 Supersedes Sheet No E-7-TOU-6 dated 7-1-20232 Effective 7-1-20243 (3) The applicability of these exemptions shall be determined at the discretion of the Utilities Director. {End} STREET LIGHTS UTILITY RATE SCHEDULE E-14 CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No. E-14-1 Sheet No. E-14-1 dated 7-1-202219 Effective 7-1-20242 A. APPLICABILITY: This Rate Schedule applies to all street and highway lighting installations, which CPAU elects to operate and maintain. B. TERRITORY: Within the incorporated limits of the City of Palo Alto and on land owned or leased by the City. C. RATES: Per Lamp Per Month Class A: CPAU supplies electricity and switching service only. Lamp Rating: High Pressure Sodium Vapor Lamps 100 watts 5.60 6.21 200 watts 10.34 11.46 250 watts 12.70 14.08 310 watts 15.72 17.42 400 watts 20.24 22.43 STREET LIGHTS UTILITY RATE SCHEDULE E-14 CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No. E-14-2 Sheet No. E-14-2 dated 7-1-202219 Effective 7-1-20242 Per Lamp Per Month – Class C: CPAU supplies electricity and switching and maintains lighting system, including lamps and glassware. Lamp Rating: Mercury-Vapor Lamps 400 watts 32.33 35.83 High Pressure Sodium Vapor Lamps 70 watts 29.75 32.97 100 watts 31.17 34.55 150 watts 33.54 37.17 250 watts 38.27 42.42 Light Emitting Diode (LED) Lamps 70 watts-equivalent 26.60 29.48 100 watts-equivalent 27.68 30.68 150 watts-equivalent 28.66 31.77 250 watts 31.38 34.78 D. SPECIAL CONDITIONS: 1. Type of Service: This Rate Schedule applies to series, multiple, and single lamp street lighting systems to which CPAU delivers Service at secondary voltage. Unless a variation is approved by CPAU in its sole discretion, Service to street lighting systems will be delivered at 120/240 volts, three-wire, single-phase or 120/208 volt three-wire, single phase from star-connected poly-phase lines. Single phase service from 480-volt sources will be available in certain areas at CPAU’s discretion. All voltages stated herein are nominal, and reasonable variations may occur. New lights will normally be installed as multiple lamp systems with a single Service point or single lamp with and individual Service point. 2. Point of Delivery: Delivery will be made to the Customer's system at a Service point or at points designated by CPAU. CPAU will furnish the Service connection to one point for each lamp or group STREET LIGHTS UTILITY RATE SCHEDULE E-14 CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No. E-14-3 Sheet No. E-14-3 dated 7-1-202219 Effective 7-1-20242 of lamps, provided the Customer has designed the system to include the minimum number of delivery points. CPAU will make all underground connections to CPAU’s system at the Customer's expense. 3. Switching: CPAU will perform switching (on CPAU's side of the points of delivery) at no Charge, provided there are at least 10 kilowatts of lamp load on each circuit separately switched, including all lamps on the circuit whether served under this Rate Schedule or not. An extra charge of $2.50 per month will be made for each circuit separately switched unless such switching installation is made for CPAU's convenience. 4. Annual Burning Schedule: The rates in this Rate Schedule apply to lamps which will be turned on and off once each night in accordance with a regular burning schedule approved by CPAU and not exceeding 4,100 hours per year. 5. Maintenance: The Class C rates in this Rate Schedule include all labor necessary for replacement of glassware, including inspection and cleaning. Maintenance of glassware by CPAU is limited to standard glassware that is commonly used and manufactured in reasonably large quantities, as determined by CPAU in its sole discretion. The Class C rates include maintenance of circuits between lamp posts and of circuits and equipment in and on the posts, provided these are all of good standard construction as determined by CPAU. CPAU in its sole discretion may decline to grant Class C rates for maintenance of systems with non-standard glassware, or inadequate circuitry and equipment. Class C rates applied to any agency other than the City of Palo Alto also include painting of posts with one coat of good ordinary paint, as determined by CPAU to be needed to maintain good appearance. Maintenance does not include replacement of posts damaged by third parties or acts of nature. 6. System Owned In-Part by CPAU: If CPAU agrees to a Customer’s request for CPAU to install, own, or maintain any portion of the lighting fixtures, supports, and/or interconnecting circuits, the Customer shall be responsible for an extra monthly Charge of one and one-fourth percent of CPAU's contribution to the cost of the street lighting system. 7. Rates For Lamps Not on this Rate Schedule: In the event a Customer installs a lamp which is not represented on this Rate Schedule, CPAU will prepare an interim rate reflecting CPAU's estimated costs associated with the specific lamp. This interim rate will serve as the effective rate for billing purposes until the new lamp rating is added to Rate Schedule E-14. {End} NET METERING NET SURPLUS ELECTRICITY COMPENSATION UTILITY RATE SCHEDULE E-NSE-1 CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No. E-NSE-1 Sheet No. E-NSE-1 dated 07-01-20232 Effective 7-1-20243 A. APPLICABILITY: This Rate Schedule applies to eligible residential and small commercial Net Energy Metering Customers who, at the end of an annual settlement period, as described in Rule 29, are Net Surplus Customer-Generators of electricity who elect to receive monetary compensation as such preference is indicated on the net surplus electricity election form. This Rate Schedule only applies to Customers who participate in Net Energy Metering, and does not apply to Customers that take service under the City’s Net Energy Metering Successor Rate, as each of these terms are defined in Rule and Regulation 2. B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. RATES: Per kWh Net Surplus Electricity Compensation rate $ 0.1427 0.1535 D. SPECIAL CONDITIONS 1. Net Surplus Electricity Compensation Rate eligibility shall be determined as specified in Rule 29. Net surplus electricity, as specified in Rule 29, if applicable, will be multiplied by the above compensation rate to determine the Customer’s annual net surplus electricity compensation stated in dollars. 2. Additional terms, conditions and definitions govern Net Energy Metering Service and Interconnection, as described in Rule 29. {End} EXPORT ELECTRICITY COMPENSATION UTILITY RATE SCHEDULE E-EEC-1 CITY OF PALO ALTO UTILITIES Issued by the City Council Supersedes Sheet No. E-EEC-1 Sheet No.E-EEC-1 dated 7-1-20232 Effective 7-1-20243 A. APPLICABILITY: This Rate Schedule applies in conjunction with the otherwise applicable Rate Schedules for each Customer class. This Rate Schedule may not apply in conjunction with any time-of-use Rate Schedule. This Rate Schedule applies to Customer-Generators as defined in Rule and Regulation 2 who are either not eligible for Net Energy Metering or who are eligible for Net Energy metering but elect to take Service under this Rate Schedule. B. TERRITORY: This rate schedule applies everywhere the City of Palo Alto provides Electric Service. C. RATE: The following compensation rate shall apply to all electricity exported to the grid. Per kWh Export electricity compensation rate $ 0.1420 0.1685 D. SPECIAL CONDITIONS 1. Metering equipment: Electricity delivered by CPAU to the Customer-Generator or received by CPAU from the Customer-Generator shall be measured using a Meter capable of registering the flow of electricity in two directions (aka “bidirectional meter”). The electrical power measurements will be used for billing the Customer-Generator. CPAU shall furnish, install and own the appropriate Meter. 2. Billing: a. CPAU shall measure during the billing period, in kilowatt-hours, the electricity delivered and received after the Customer-Generator serves its own instantaneous load. b. CPAU shall bill the Customer-Generator consumption charges for the electricity delivered by CPAU to the Customer-Generator based on the Customer-Generator’s applicable Rate Schedule. c. In the event the electricity generated exceeds the electricity consumed and therefore is received by CPAU, the Customer will receive a credit for all electricity received by CPAU at the buyback Rate designated in section C above. {End} APPENDIX A: ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES The following reserves management practices are used when developing the Electric Utility Financial Plan: Section 1. Definitions a) “Financial Planning Period” – The Financial Planning Period is the range of future fiscal years covered by the Financial Plan. For example, if the Financial Plan delivered in conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019, FY 2015 to FY 2019 would be the Financial Planning Period. b) “Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers to the Utility’s Unrestricted Net Assets. c) “Net Assets” - The Government Accounting Standards Board defines a Utility’s Net Assets as the difference between its assets and liabilities. d)“Unrestricted Net Assets” - The portion of the Utility’s Net Assets not invested in capital assets (net of related debt) or restricted for debt service or other restricted purposes. Section 2. Supply Fund Reserves The Electric Supply Fund Balance is reserved for the following purposes: a) For existing contracts, as described in Section 4 (Reserve for Commitments) b) For operating budgets reappropriated from previous years, as described in Section 5 (Reserve for Reappropriations) c) For special projects for the benefit of the Electric Utility ratepayers, as described in Section 6 (Electric Special Projects Reserve) d) For year to year balancing of costs associated with the Electric Utility’s hydroelectric resources, as described in Section 7 (Hydroelectric Stabilization Reserve) e) For rate stabilization, as described in Section 1.d)1 (Rate Stabilization Reserves) f)For operating contingencies, as described in Section 12 (Operations Reserves) g) For tracking unspent or unallocated revenues from the sale of carbon allowances freely allocated by the California Air Resources Board to the electric utility under the State’s Cap and Trade Program, as described in Section 16 (Cap and Trade Program Reserve) f)h)For tracking funding of City buildings, appliance and vehicle electrification projects and programs, as described in Section 17 (Electrification Reserve) i)Any funds not included in the other reserves will be considered Unassigned Reserves and shall be returned to ratepayers or assigned a specific purpose as described in Section 13 (Unassigned Reserves). Section 3. Distribution Fund Reserves The Electric Distribution Fund Balance is reserved for the following purposes: a) For existing contracts, as described in Section 4 (Reserves for Commitments) b) For operating and capital budgets reappropriated from previous years, as described in Section 5 (Reserves for Reappropriations) c) As an offset to underground loan receivables, as described in Section 8 (Underground Loan Reserve) d) To hold Public Benefit Program funds collected but not yet spent, as described in Section 9 (Public Benefits Reserve) e) For cash flow management and contingencies related to the Electric Utility’s Capital Improvement Program (CIP), as described in Section 10 (CIP Reserve) f) For rate stabilization, as described in Section 11.d) (Rate Stabilization Reserves) g)For operating contingencies, as described in Section 12 (Operations Reserves) g)h)For tracking revenues earned via the sale of Low Carbon Fuel Credits allocated by the California Air Resources Board to the City, as well as expenses incurred, in accordance with California’s Low Caron Fuel Standard program, as described in Section 15 (Low Carbon Fuel Standard Reserve) i)Any funds not included in the other reserves will be considered Unassigned Reserves and shall be returned to ratepayers or assigned a specific purpose as described in Section 14 13 (Unassigned Reserves). Section 4. Reserves for Commitments At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund Reserves for Commitments will be set to an amount equal to the total remaining spending authority for all contracts in force for the Electric Supply Fund and Electric Distribution Fund, respectively, at that time. Section 5. Reserves for Reappropriations At the end of each fiscal year the Electric Supply Fund and Electric Distribution Fund Reserves for Reappropriations will be set to an amount equal to the amount of all remaining capital and non-capital budgets that will be reappropriated to the following fiscal year for each Fund in accordance with Palo Alto Municipal Code Section 2.28.090. Section 6. Electric Special Projects Reserve The Electric Special Projects Reserve (ESP Reserve) will be managed in accordance with the policies set forth in Resolution 9206 (Resolution of the Council of the City of Palo Alto Approving Renaming the Calaveras Reserve to the Electric Special Project Reserve and Adoption of Electric Special Project Reserve Guidelines). These policies are included from Resolution 9206 as amended to refer to the reserves structure set forth in these Reserves Management Practices: a) The purpose of the ESP Reserve is to fund projects that benefit electric ratepayers; b) The ESP Reserve funds must be used for projects of significant impact; c) Projects proposed for funding must demonstrate a need and value to electric ratepayers. The projects must have verifiable value and must not be speculative, or high-risk in nature; d) Projects proposed for funding must be substantial in size, requiring funding of at least $1 million; e) Set a goal to commit funds by the end of FY 2025; f) Any uncommitted funds remaining at the end of FY 2030 will be transferred to the Electric Supply Operations Reserve and the ESP Reserve will be closed; Section 7. Hydroelectric Stabilization Reserve The Hydroelectric Stabilization Reserve is used to manage the supply cost impacts associated with variations in generation from hydroelectric resources. Staff will manage the Hydroelectric Stabilization Reserve as follows: a) Projected Hydro Output: Near the end of each fiscal year, staff will determine the actual and expected hydro output for that fiscal year, compare that to the long-term average annual output level (495,957 MWh as of March 2018), and multiply the difference by the average of the monthly round-the-clock forward market prices for each month of the current fiscal year. b) Changes in Reserves. Staff is authorized to transfer the amount described in Sec. 7(a) from the Operations Reserve to the Hydroelectric Stabilization Reserve for hydro output deviations above long-term average levels, or transfer this amount from the Hydroelectric Stabilization Reserve to the Operations Reserve for hydro output deviations below long-term average levels. c) Implementation of HRA. The level of the Hydroelectric Stabilization Reserve after the transfers described above shall be the basis for staff’s determination, with Council approval, of whether to implement the Hydro Rate Adjuster (Electric Rate E-HRA) for the following fiscal year. d) Reserve Guidelines. Staff will manage the Hydroelectric Stabilization Reserve according to the following guideline levels: Minimum Level $3 million Target Level $19 million Maximum Level $35 million Section 8. Underground Loan Reserve At the end of each fiscal year, the Underground Loan Reserve will be adjusted by the principal payments made against outstanding underground loans. Section 9. Public Benefits Reserve The Public Benefits Reserve will be increased by the amount of unspent Public Benefits Revenues remaining at the end of each fiscal year. Expenditure of these funds requires action by the City Council. Section 10. CIP Reserve The CIP Reserve is used to manage cash flow for capital projects and acts as a reserve for capital contingencies. Staff will manage the CIP Reserve according to the following practices: a) The following guideline levels are set forth for the CIP Reserve. These guideline levels are calculated for each fiscal year of the Financial Planning Period and approved by Council resolution. Minimum Level 20% of the maximum CIP Reserve guideline level Maximum Level Average annual (12 month)1 CIP budget, for 48 months of budgeted CIP expenses2 b) Changes in Reserves: At the end of each fiscal year staff will transfer from the Distribution Operations Reserve to the CIP Reserve an amount equal to the amount of electric utility unspent CIP budget at the end of the fiscal year reduced by the amount of any contractual commitments and reappropriations. Any other additions to or withdrawals from the CIP reserve require Council action.Staff is authorized to transfer funds between the CIP Reserve and the Reserve for Commitments when funds are added to or removed from the Reserve for Commitments as a result of a change in contractual commitments related to CIP projects. Any other additions to or withdrawals from the CIP reserve require Council action. c) Minimum Level: i) If, at the end of any fiscal year, the minimum guideline is not met, staff shall present a plan to the City Council to replenish the reserve. The plan shall be delivered by the end of the following fiscal year, and shall, at a minimum, result in the reserve reaching its minimum level by the end of the next fiscal year. For example, if the CIP Reserve is below its minimum level at the end of FY 2017, staff must present a plan by June 30, 2018 to return the reserve to its minimum level by June 30, 2019. In addition, staff may present, and the Council may adopt, an alternative plan that takes longer than one year to replenish the reserve, or that does so in a shorter period of time. d) Maximum Level: If there are funds in this reserve in excess of the maximum level staff must propose in the next Financial Plan to transfer these funds to another reserve or return them to ratepayers in the funds to ratepayers, or designate a specific use of funds for CIP investments that will be made by the end of the next Financial Planning period. Staff may also seek City Council to approve holding funds in this reserve in excess of the maximum level if they are held for a specific future purpose related to the CIP. Section 11. Rate Stabilization Reserves Funds may be added to the Electric Supply or Distribution Fund’s Rate Stabilization Reserves by action of the City Council and held to manage the trajectory of future year rate increases. Withdrawal of funds from either Rate Stabilization Reserve requires action by the City Council. If there are funds in either Rate Stabilization Reserve at the end of any fiscal year, any subsequent Electric Utility Financial Plan must result in the withdrawal of all funds from this Reserve by the end of the Financial Planning Period. The Council may approve exceptions to this requirement, when proposed by staff to provide greater rate stabilization to customers. 1 Each month is calculated based upon 1/12 of the annual budget. 2 For example, in the Financial Plan for FY 2021, the 48 month period to use to derive the annual average is FY 2021 through FY 2024. In the FY 2022 Financial Plan, the 48 month period to use to derive the annual average would be FY 2022 through FY 2025 etc. Section 12. Operations Reserves The Electric Supply Fund and Electric Distribution Fund Operations Reserves are used to manage normal variations in the costs of providing electric service and as a reserve for contingencies. Any portion of the Electric Utility’s Fund Balance not included in the reserves described in Section 4 to 11 above will be included in the appropriate Operations Reserve unless the reserve has reached its maximum level as set forth in Section 12 (e) below. Staff will manage the Operations Reserves according to the following practices: a) The following guideline levels are set forth for the Electric Supply Fund Operations Reserve. These guideline levels are calculated for each fiscal year of the Financial Planning Period based on the levels of Operations and Maintenance (O&M) and commodity expense forecasted for that year in the Financial Plan. Minimum Level 60 days of Supply Fund O&M and commodity expense Target Level 90 days of Supply Fund O&M and commodity expense Maximum Level 120 days of Supply Fund O&M and commodity expense b) The following guideline levels are set forth for the Electric Distribution Fund Operations Reserve. These guideline levels are calculated for each fiscal year of the Financial Planning Period based on the levels of O&M expense forecasted for that year in the Financial Plan. Minimum Level 60 days of Distribution Fund O&M expense Target Level 90 days of Distribution Fund O&M expense Maximum Level 120 days of Distribution Fund O&M expense c) Minimum Level: If, at the end of any fiscal year, the funds remaining in the Supply Fund or Distribution Fund’s Operations Reserve are lower than the minimum level set forth above, staff shall present a plan to the City Council to replenish the reserve. The plan shall be delivered within six months of the end of the fiscal year, and shall, at a minimum, result in the reserve reaching its minimum level by the end of the following fiscal year. For example, if the Operations Reserve is below its minimum level at the end of FY 2014, staff must present a plan by December 31, 2014 to return the reserve to its minimum level by June 30, 2015. In addition, staff may present an alternative plan that takes longer than one year to replenish the reserve. d) Target Level: If, at the end of any fiscal year, either Operations Reserve is higher or lower than the target level, any Financial Plan created for the Electric Utility shall be designed to return both Operations Reserves to their target levels by the end of the forecast period. e)Maximum Level: If, at any time, either Operations Reserve reaches its maximum level, no funds may be added to this Reserve. Any further increase in that fund’s Fund Balance shall be automatically included in the Unassigned Reserve described in Section 13, below. Section 13. Unassigned Reserves If the Operations Reserve in either the Electric Supply Fund or the Electric Distribution Fund reaches its maximum level, any further additions to that fund’s Fund Balance will be held in the Unassigned Reserve. If there are any funds in either Unassigned Reserve at the end of any fiscal year, the next Financial Plan presented to the City Council must include a plan to assign them to a specific purpose or return them to the Electric Utility ratepayers by the end of the first fiscal year of the next Financial Planning Period. For example, if there were funds in the Unassigned Reserves at the end of FY 2016, and the next Financial Planning Period is FY 2017 through FY 2021, the Financial Plan shall include a plan to return or assign the funds in the Unassigned Reserve by the end of FY 2017. Staff may present an alternative plan that retains these funds or returns them over a longer period of time. Section 14. Intra-Utility Transfers between Supply and Distribution Funds Transfers between Electric Distribution Fund Reserves and Electric Supply Fund Reserves are permitted if consistent with the purposes of the two reserves involved in the transfer. Such transfers require action by the City Council. Section 15. Low Carbon Fuel Standard (LCFS) Reserve This reserve tracks revenues earned via the sale of Low Carbon Fuel Credits allocated by the California Air Resources Board to the City, as well as expenses incurred, in accordance with California’s Low Caron Fuel Standard program. At the end of each fiscal year, the LCFS Reserve will be adjusted by the net of revenues and expenses associated with California’s LCFS program. Section 16. Cap and Trade Program Reserve This reserve tracks unspent or unallocated revenues from the sale of carbon allowances freely allocated by the California Air Resources Board to the electric utility, under the State’s Cap and Trade Program. Funds in this Reserve are managed in accordance with the City’s Policy on the Use of Freely Allocated Allowances under the State’s Cap and Trade Program (the Policy), adopted by Council Resolution 9487 in January 2015. At the end of each fiscal year, the Cap and Trade Program Reserve will be adjusted by the net of revenues and expenses associated with the Cap and Trade program. Section 17. Electrification Reserve This reserve is used to track funding of City buildings, appliance and vehicle electrification projects and programs, including development and implementation costs and associated financial incentives, loans and rebates for participating customers. The reserve may be funded by any lawful source of funds available for such programs, including new or ongoing utility revenues derived from customer participation. The reserve balance shall be annually adjusted based on the net of revenues and expenses associated with the City’s building appliance and vehicle electrification projects and programs using this reserve. March 6, 2024 www.cityofpaloalto.org PROPOSED FY 2025 ELECTRICFINANCIAL PLAN AND RATE CHANGES Utilities Advisory Commission 2 FY 2025 proposal •Cost of Service Analysis completed February 2024 – requires rate changes varying by customer class and consumption pattern to match the cost to serve •8% ($6.20/month) increase for the median residential customer •0.5% increase in revenue – lower than last year’s 5% forecasted revenue increase •This is manageable due to large one-time electric supply revenues in FY 2024 – FY 2026 •Will mitigate the bill impacts of incorporating COSA changes Future years •5% rate increase per year projected for FY 2026-FY 2029 •Issue debt for Grid Modernization by end of FY25 •Reflects continuing transmission cost increases, other rising supply costs, grid modernization Electric Rate Proposal 3 Electric Utility Cost Structure (FY 2023) Electric Distribution costs (in green): $70 million 40% Electric Supply: The cost to buy electricity and transport it to Palo Alto, including operational overhead (e.g. energy scheduling) Electric Supply costs (in blue): $104 million 60% Electric Distribution: The cost to distribute electricity within Palo Alto, including: maintaining and replacing electric infrastructure, customer service, billing, administration, etc. 4 LONG TERM COST TRENDS Annualized Increase, FY20-FY25 Annualized Increase, FY25-FY29 Supply: 0.4%/yr (1) Distribution: 7%/yr (2) Supply: 8%/yr (1) Distribution: 4%/yr (2) (1)The annualized increase in supply costs is skewed by one-time supply revenues in FY 2025. The annualized change from FY 2020 to FY 2029 is projected to be 3% to 4% per year. (2)The annualized increase in distribution costs is heavily skewed by timing issues associated with major capital investments in FY 2024 and debt financing for those investments beginning in FY 2025. 7% per year represents the change from FY 2020 to the average of FY 2024 and FY 2025 distribution costs. 4% per year represents the change from that average to FY 2029. The annualized change from FY 2020 to FY 2029 is projected to be 5% per yr Annualized Increase, FY20-FY29 Supply: 3% to 4% / year (1) Distribution: 5%/yr (2) 5 Supply Cost Drivers •FY 2024 / FY 2025 electric supply costs are very low due to one-time surplus energy, REC, and resource adequacy(1) sales •Transmission costs have been steadily increasing and this increase is projected to continue •Resource adequacy(1) costs are projected to increase through FY 2029 •Hydropower costs forecasted to decline through FY 2029 due to debt service retirement for the Calaveras project •But additional debt may be issued for dam improvements (1) Resource adequacy represents the cost of maintaining generating capacity to fulfill the California Independent System Operator’s capacity requirements assigned to the City. 6 LONG TERM COST TRENDS: SUPPLY Annualized Increase, FY20-FY25 Annualized Increase, FY25-FY29 Transmission: 6%/yr Generation: -3%/yr Transmission: 5%/yr Generation: 11%/yr Overhead: 6%/yr Overhead: 4%/yr 7 Distribution Cost Drivers •Construction inflation, other inflation, benefit costs •Overhead returning to historic levels as vacancies filled •Contract line crew cost for backfilling vacancies •Increased capital investment in the electric distribution system needed due to system age •Debt service for Grid Modernization Project to: •replace aging infrastructure, •modernize the grid to enhance reliability •increase capacity for electrification •Substantial one-time investments for Hanover Substation rebuild, Electric Utility share of Fiber Rebuild 8 LONG TERM COST TRENDS: DISTRIBUTION Annualized Increase, FY20-FY25: Annualized Increase, FY25-FY29: Operations: 6%/yr Capital+Debt: 8%/yr FY20-FY29(1) Operations: 2.9%/yr (1) FY 2024 and FY 2025 capital and debt service numbers skewed by the timing of major capital investments and the timing of debt service to be issued to fund them, so only FY 20 to FY 29 combined annualized increases are shown. 9 FY 2025 Preliminary: Electric Cost and Revenue Projections Co s t / R e v e n u e 10 Basic Cost of Service Methodology •First establish how much revenue you need •Then use consumption patterns to allocate costs among customer classes according to how they incur utility costs •CPA classes: E-1 (residential), E-2 (small non-residential), E-4 (medium non-residential), E-7 (large non-res) •Costs allocators include things like kWh used, peak kW demand, number of customers in class •Then design rates that provide prices that allocate costs to customers who consume in different ways. •Examples include tiered rates, seasonal rates, time of use rates, fixed charges, etc. 11 Prop 26 Considerations •Prop 26 (2010): State ballot initiative that amended the State Constitution •Gas and electric rates must represent the cost of service absent voter/ratepayer approval •Cost of service analysis is the record demonstrating that the rates are cost-based •Only applies to fees/charges imposed by local agencies (including gas/electric utility rates) – investor-owned utilities have all the latitude the CPUC will give them 12 Adopted Policy Guidelines (Nov 1, 2021) 1.Rates must be based on the cost of providing service. This is the overriding principle for the cost of service analysis (COSA); all other rate design considerations are subsidiary to this basic premise. 2.The effect of proposed rate design changes on low income customers should be considered, to the extent permissible within a cost-based rate structure. 3.Rates should ensure all value provided by building and vehicle electrification, including public vehicle charging, is reflected in the rates while remaining cost-based. 4.Rates should ensure all value provided by on-site generation and storage is reflected in the rates while simultaneously avoiding subsidies between customer classes and remaining cost based. 5.The COSA and rate design should support a transition to more time variant rates (such as TOU, seasonal, etc.) as AMI infrastructure is deployed. 6.The COSA should provide support for transition to fixed/minimum monthly charges. 13 Key Results from this COSA •No time of use (TOU) rates for E-1 (residential) and E-2 (small commercial) yet – likely July 1, 2026, will explore earlier options •Changing the time periods for existing medium commercial (E-4 TOU) and large commercial (E-7 TOU) time of use rates •Median residential bill increasing 8% due to three factors: •Residential class needs increase in revenue to meet cost of service while commercial classes need decreases •Addition of fixed charge •Flattening of tiers due to change in residential consumption •All three factors impact lower users most •Not increasing revenue this year to avoid larger impacts 14 Estimated Bill Changes 15 Residential Bill Changes by Usage Level ($/month) 200 kWh/mo 300 kWh/mo Median 650 kWh/mo 1200 kWh/mo $0.00 $5.00 $10.00 $15.00 -$5.00 -$10.00 -$15.00 -$20.00 Bill Change ($/mo) <200, 29% 200- 330, 17% 330- 500, 19% 500- 1000, 26% 1000- 1500, 6% >1500, 3% % of Accounts by Monthly Usage (kWh/mo) 16 Current Gas Bill Comparisons ($/Mo. or Yr.) Commercial Staff is in the process of doing a more extensive review of commercial competitiveness and will provide updates in the future Residential Palo Alto median residential bill was about 40% below PG&E’s for CY 2023, before the large PG&E January 1, 2024 rate increases. Now 50% to 60% below 17 Residential Bill Comparison by Usage Level 18 Electric Supply Operating Reserve Projections 19 Electric Supply Reserve Projections 20 Electric Supply Reserve Adequacy 21 Electric Distribution Operating Reserve Projections 22 Electric Distribution Reserve Projections 23 ELECTRIC RECOMMENDATION Staff recommends the UAC recommend that the City Council adopt a resolution: 1.Accepting the 2024 City of Palo Alto Electric Cost of Service and Rate Study (Exhibit 1) 2.Approving the FY 2025 Electric Financial Plan (Exhibit 2), which includes the following actions: a.Amending the Electric Utility Reserves Management Practices (Attachment B), to direct staff to transfer to the CIP reserve, at the end of each fiscal year, any budgeted capital investment that remains unspent, uncommitted, and which is not proposed for reappropriation to the following fiscal year and to clarify how the Cap and Trade Program Reserve is adjusted each year. b.Approving the following transfers at the end of FY 2024: i.Up to $20 million from the Electric Special Projects Reserve to the Supply Operations Reserve; ii.Up to $17 million from the Supply Operations Reserve to the Hydroelectric Stabilization Reserve; iii.Up to $58 million from the Supply Operations Reserve to the Distribution Operations Reserve; and c.Approving the following transfers in FY 2025: i.Up to $26 million from the Distribution Operations Reserve to the Supply Operations Reserve; ii.Up to $30 million from the Supply Operations Reserve to the Electric Special Projects Reserve; and iii.Up to $5 million from the Distribution Operations Reserve to the CIP Reserve; 24 ELECTRIC RECOMMENDATION (CONTINUED) Staff recommends the UAC recommend that the City Council adopt a resolution: 3.Amending the following rate schedules effective July 1, 2024 (FY 2025), (Exhibit 3): a.Changing retail electric rates E-1 (Residential Electric Service), E-2 (Small Non-Residential Electric Service), E-4 (Medium Non-Residential Electric Service), E-4 TOU (Medium Non-Residential Time of Use Electric Service), E -7 (Large Non-Residential Electric Service), and E-7 TOU (Large Non-Residential Time of Use Electric Service) by varying percentages depending on rate schedule and consumption with an overall revenue increase of 0.5% effective July 1, 2024; b.Decreasing the Net Surplus Electricity Compensation (E-NSE-1) rate to reflect 2023 avoided cost, effective July 1, 2024; c.Decreasing the Export Electricity Compensation (E-EEC-1) rate to reflect current projections of FY 2025 avoided cost, effective July 1, 2024; and d.Updating the Residential Master-Metered and Small Non-Residential Green Power Electric Service (E-2-G), the Medium Non-Residential Green Power Electric Service (E-4-G), and the Large Non-Residential Green Power Electric Service (E-7-G) rate schedules to reflect modified distribution and commodity components, effective July 1, 2024.