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Home My WebLink AboutRESO 9762DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60861389168E Resolution No. 9762 Resolution of the Council of the City of Palo Alto Approving the Fiscal Year 2019 Electric Utility Financial Plan RECITALS 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. The Council of the City of Palo Alto does hereby RESOLVE as follows: SECTION 1. The Council hereby approves the FY 2019 Electric Utility Financial Plan. SECTION 2. The Council hereby approves the amended Electric Utility Reserves Management Practices included in the FY 2019 Electric Utility Financial Plan. II II II II II II II II II II II II II II II II 6055013 DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60861389168E FY 2019 ELECTRIC UTILITY FINANCIAL PLAN FY 2019 TO FY 2028 DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60861389168E FY 2019 ELECTRIC UTILITY FINANCIAL PLAN FY 2019 TO FY 2028 'TABLE OF CONTENTS Section 1: Definitions and Abbreviations ................................................................................ 4 Section 2: Executive Summary and Recommendations ........................................................... 5 Section 2A: Overview of Financial Position .................................................................................. S Section 2B: Summary of Proposed Actions .................................................................................. 6 Section 3: Detail of FY 2019 Rate and Reserves Proposals ....................................................... 6 Section 3A: Rate Design ............................................................................................................... 6 Section 3B: Current and Proposed Rates ..................................................................................... 6 Section 3C: Reserves Management Practices .............................................................................. 7 Section 3D: Proposed Reserve Transfers ..................................................................................... 8 Section 4: Utility Overview .................................................................................................... 9 Section 4A: Electric Utility History ............................................................................................... 9 Section 4B: Customer Base ........................................................................................................ 11 Section 4C: Distribution System ................................................................................................. 11 Section 4D: Cost Structure and Revenue Sources ...................................................................... 12 Section 4E: Reserves Structure ................................................................................................... 13 Section 4F: Competitiveness ...................................................................................................... 14 Section 5: Utility Financial Projections ................................................................................. 15 Section SA: Load Forecast .......................................................................................................... 1S Section SB: FY 2013 to FY 2017 Cost and Revenue Trends ........................................................ 17 Section SC: FY 2017 Results ....................................................................................................... 18 Section Sf?: FY 2018 Projections ................................................................................................ 19 Section SE: FY 2019 -FY 2028 Projections ................................................................................ 19 21 Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60B613B9168E Section SF: Risk Assessment and Reserves Adequacy ............................................................... 21 Section SG: Long-Term Outlook ................................................................................................. 26 Section 6: Details and Assumptions ..................................................................................... 29 Section 6A: Electricity Purchases ............................................................................................... 29 Section 68: Operations .............................................................................................................. 31 Section 6C: Capital Improvement Program (CJP) ....................................................................... 32 Section 6D: Debt Service ............................................................................................................ 33 Section 6E: Equity Transfer ........................................................................................................ 34 Section 6F: Wholesale Revenues and Other Revenues .............................................................. 34 Section 6G: Sales Revenues ....................................................................................................... 35 Section 7: Communications Plan .......................................................................................... 36 Appendices ......................................................................................................................... 37 Appendix A: Electric Utility Financial Forecast Detail ................................................................ 38 Appendix 8: Electric Utility Reserves Management Practices ................................................... 42 I Appendix C: Description of Electric utility Operational Activities .............................................. 47 Appendix D: Samples of Recent Electric Utility Outreach Communications .............................. 48 3I Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60B613B9168E SECTION 1: DEFINITIONS AND ABBREVIATIONS CAISO CARB CIP CPAU CPUC CVP GWh kWh kW kV MWh MW PG&E REC RPS California Independent System Operator California Air Resources Board Capital Improvement Program City of Palo Alto Utilities Department California Public Utilities Commission Central Valley Project 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. a kilowatt-hour, the standard unit of measurement for electricity sales to customers. 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. 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 i_n the rest of the distribution system, and finally 120, 240, or 480 volts at the electric outlet. a megawatt-hour, equal to 1,000 kWh. Commonly used for measuring wholesale electricity purchases. a megawatt, equal to 1,000 kW. Commonly used when discussing maximum electricity demand for all customers in aggregate. Pacific Gas and Electric Renewable Energy Certificate 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. 41 Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-608613B9168E SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS This document presents a Financial Plan for the City's Electric Utility for the next ten fiscal years. 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 The Electric Utility's costs will increase substantially over the next few years, as shown in Table 1. Most of the increases are related to electric supply costs, which are increasing due to increased transmission costs and the cost of new renewable energy projects coming online. There are also inflationary increases in operations costs, and some above average capital investment costs in the short term. Table 1: Electric Utility Expenses for FY 2017 to FY 2028 Expenses FY 2017 FY 2018 FY FY FY FY FY FY FY FY FY ($000) (act.) (est.) 2019 2020 2021 2022 2023 2024 2025 2026 2027 Power Supply Purchases 80,467 83,506 91,925 94,233 95,111 98,655 98,668 99,059 102,252 103,535 103,178 Operations 53,034 53,881 54,757 56,293 57,053 57,839 59,600 60,146 56,720 57,677 58,660 Capital Projects 11,558 20,961 22,684 18,287 20,097 13,632 14,011 14,400 14,800 15,211 15,633 TOTAL 145,060 158,348 169,366 168,812 172,261 170,126 172,279 173,605 173,772 176,422 177,471 To cover these increases in costs, revenues (and therefore rates) need to increase over the next several years to balance costs and revenues, as shown in Table 2. The table also compares current rate projections to those projected in last year's Financial Plan. The rate projections are slightly higher over the forecast period than last year primarily due to lower actual and projected sales, increases to transmission cost projections and increases to capital investment spending. Table 2: Projected Electric Rates, FY 2019 to FY 2028 FY 2028 106,193 59,668 16,068 181,929 Projection FY 2019 FY 2020 FY2021 FY 2022 FY 2023 FY 2024 FY2025 FY2026 FY 2027 FY 2028 Current 6% 3% 2% 0% 1% 1% 1% 1% 1% 1% Last Year 7% 0% 0% 1% 2% 1% 1% 1% 1% N/A Table 3 shows the projected reserve transfers over the forecast period. The Supply Rate Stabilization Reserve is projected to be drawn down entirely by the end of FY 2018. Funds are also projected to be transferred from the Electric Special Projects (ESP) Reserve, and Council approved the withdrawal of $10 million as part of the FY 2018 Electric Financial Plan. Any transfers from the ESP Reserve require Council approval. Council also approved using all SI Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60861389168E remaining funds ($11.2 million) from the Hydro Stabilization Reserve, but ending reserves show that only $1 million is warranted at this point. Table 3: Reserves Transfers for FY 2018 to FY 2028 ($000) Reserve FY 2018 FY 2019 FY 2020 to FY 2028 Supply Reserves Electric Special Projects (6,000) (771) (1,780) Hydro Stabilization (1,000) -- Supply Rate Stabilization (9,011) -- Supply Operations 8,163 Distribution Reserves Capital Improvement Program - -- Distribution Operations 7,848 771 1,780 * SECTION 2B: SUMMARY OF PROPOSED ACTIONS Staff proposes the following actions for the Electric Utility in FY 2019: 1. Increase rates effective July 1, 2018 for a 6% increase in system average rates. 2. Approve a transfer of up to $771,000 from the Electric Special Projects Reserve for Smart Grid related funding. SECTION 3: DETAIL OF FY 2019 RATE AND RESERVES PROPOSALS SECTION 3A: RATE DESIGN The rates discussed in the previous section are based on the cost of service methodology established in "City of Palo Alto Electric Cost of Service and Rate Study"1 drafted by EES Consulting, Inc. in 2015/16. Staff provided EES with updated sales and budget projections, including projected transmission and distribution costs, power supply costs and billing data, in order for EES to update individual cost of service model components and determine the proposed rates. The COSA is based on design guidelines adopted by Council on September 15, 2015 (Staff Report 6061). SECTION 3B: CURRENT AND PROPOSED RATES The City adopted the current rates effective July 1, 2017, when CPAU increased electric rates by 14%. Table 4, below, summarizes the current and proposed rates for the four largest customer 1 Staff Report 6857 http://www.cityofpaloalto.org/civicax/filebank/documents/52274 6I Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60861389168E classes. The Electric Utility also has specialty. rates for smaller groups of customers. These include variations on its primary rates, such as time of use rates and solar net metering. Staff proposes a 6% overall increase in revenue. Different customer classes may see different percentage changes to their rates, based upon their usage of the system and co·st to serve each group. Table 4: Current and Proposed Electric Rates Proposed Rates Change Current Rates (7/1/18) $ % E-1 (Residential) Tier 1 Energy ($/kWh) 0.12159 0.12871 0.00711 5.8% Tier 2 Energy ($/kWh) 0.19001 0.19279 0.00277 1.5% Minimum Bill ($/day) 0.2938 0.3040 0.0102 3.5% E-2 & E-2-G (Small Non-Residential) Summer Energy ($/kWh) 0.18885 0.20090 001205 6.4% Winter Energy ($/kWh) 0.13267 0.13861 0.00594 4.5% Minimum Bill ($/day) 0.7328 0.7740 0.0412 5.6% E-4 & E-4-G (Medium Non-Residential) Summer Energy ($/kWh) 0.11673 0.12081 0.00408 3.5% Winter Energy ($/kWh) 0.08890 0.09297 0.00407 4.6% Summer Demand ($/kW) 21.05 24.11 3.06 14.5% Winter Demand ($/kW) 15.36 18.52 3.16 20.6% Minimum Bill ($/day) 14.8414 15.9946 1.1532 7.8% E-7 & E-7-G (Large Non-Residential) Summer Energy ($/kWh) 0.09802 0.10507 0.00705 7.2% Winter Energy ($/kWh) 0.07188 0.07449 0.00261 3.6% Summer Demand ($/kW) 23.84 26.77 2.93 12.3% Winter Demand ($/kW) 15.59 17.01 1.42 9.1% Minimum Bill ($/day) 42.3648 45.4758 3.111 7.3% These proposed rates were prepared in conformance with the "FY 2017 City of Palo Alto Electric Cost of Service and Rate Study," performed by EES Consulting (2016). SECTION 3C: RESERVES MANAGEMENT PRACTICES This financial plan proposes a change to Section 7 of the Electric Utility Reserves Management Practices (See Appendix B: Electric Utility Reserves Management Practices), detailing a procedure for calculating the amount of funds to transfer to or from the Hydroelectric Stabilization Reserve. 71 Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60861389168E SECTION 3D: PROPOSED RESERVE TRANSFERS In the FY 2018 Electric Financial Plan, Council approved several proposed transfers for FY 2017 and FY 2018: • Transfer up to $911 thousand from the Supply Rate Stabilization Reserve to the Supply Operations Reserve. • Transfer up to $9.0 million from the Hydroelectric Stabilization Reserve to offset potential costs associated with low hydroelectric generation. • Transfer up to $4.5 million from the Supply Operations Reserve to the Distribution Operations Reserve to ensure reserve adequacy in the Distribution Operations Reserve. • Transfer up to $10 million from the ESP Reserve to the Distribution Operations Reserve. This transfer will be construed as a temporary transfer, to be repaid to the ESP Reserve within five years. Ending reserve balances for FY 2017 were higher than projected. Because of this, and to keep some funds in the Hydroelectric Stabilization Reserve in case of drought, staff only projects that $1 million will need to be transferred out of the Hydroelectric Stabilization Reserve in FY 2018. The Electric Special Projects (ESP) reserve in future years shows additional transfers of $2.5 million, to help cover the upgrade of the Electric metering system to AMI. This item has been discussed in prior years as a possible project to be funded from the ESP. Proposed transfers for FY 2019 will not be requested by resolution at this time, but will be requested as part of FY 2019 year-end should ending reserve balances require it. Figure 8 (for Supply Fund Reserves) and Figure 9 (for Distribution Fund Reserves) in Section SE: FY 2019 -FY 2028 Projections show the impact of these transfers on reserves levels. Table 5 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 Table 5: End of Fiscal Year Electric Utility Reserve Balances for FY 2017 to FY 2028 Ending Reserve FY 2017 FY FY FY FY FY FY FY FY FY FY Balance {$000) (Act.) 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Re-appropriations -- - - --- --- - Commitments 2,971 2,971 2,971 2,971 2,971 2,971 2,971 2,971 2,971 2,971 2,971 Underground Loan 730 730 730 730 730 730 730 730 730 730 730 Public Benefits 681 - - - --- - - - - Special Projects 51,838 45,838 45,067 42,757 43,247 42,847 42,847 42,847 42,847 42,847 42,847 Hydro Stabilization 11,400 10,400 10,400 10,400 10,400 13,900 13,900 13,900 13,900 13,900 13,900 Capital 880 880 880 880 880 880 880 880 880 880 880 Rate Stabilization 9,011 - - - - - - - - - - Operations 29,913 37,884 32,054 33,249 39,138 38,837 39,720 41,255 44,073 46,167 49,328 Unassigned -- - - - - - - - - - TOTAL 107,424 98,703 92,101 92,987 97,366 100,164 101,048 102,583 105,401 107,495 110,656 8I Page FY 2028 - 2,971 730 - 42,847 13,900 880 - 49,864 - 111,192 DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-608613B9168E 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 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 UCC was built to house the terminals for a new SCADA system, which 9I Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60B613B9168E 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 Utility2 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. 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 more actively manage its supply portfolio. CPAU began purchasing power from marketers and also 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 CPAU adopted a goal of achieving 20% of its energy supply from renewables by 2015. Subsequently CPAU 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 renewable energy purchases (RECs) to meet the balance of its needs. 2 Implementation of Direct Access for Electric Utility Customers, CMR:460:97, December 1, 1997 lOI Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-608613B9168E connection fe~s, interest on reserves, cost recovery transfers from other funds for shared services provided by the electric utility, and other sources. Some revenue sources are primarily accounting entries that reflect things such as CPAU's participation in a pre-funding program associated with its contract with WAPA, as well as accounting entries associated with occasional sales of surplus hydroelectric energy during wet years. Appendix A: Electric Utility Financial Forecast Detail shows more detail on the utility's cost and revenue structures. As discussed in Section 48: Customer Base, nearly three quarters of the utility's electricity sales are to the 900 largest customers, which provide a similar share of the utility's revenue stream. The utility's retail rate schedules have no fixed charges, although about 24% of the utility's revenue comes from peak demand charges on large non-residential custom_ers. 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. 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 may also be useful for rate design as the nature of utility services evolves in response to higher penetrations of distributed generation. 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 reappropriated by the City Council, nearly all of which are capital projects. Most City funds, including the General Fund, have a Reappropriations 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) R~serve: 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 Bl Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60B613B9168E fund projects with significant impact that provide demonstrable value to electric ratepayers. • 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. • 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 is used to provide working capital and contingency funds for the CIP program, as well as to accumulate funds for major future one-time expenditures. This type of reserve is used in other utility funds (Electric, 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 residential electric bill for calendar year 2017 was $589.02 under current CPAU rates, 38% lower than the annual bill for a PG&E customer with the same consumption and approximately 12% higher than the annual bill for a City of Santa Clara customer. The bill calculations for PG&E customers are based on PG&E Climate Zone X, which includes most surrounding comparison communities. Table 6 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 March 1, 2018. 14 I Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60B613B9168E Over the next several years low usage customers in PG&E territory are expected to continue to see higher percentage rate increases than high usage customers as PG&E compresses its tiers from the highly exaggerated levels that have been in place since the energy crisis. This is likely to make the bill for the median Palo Alto consumer look even more favorable compared to most PG&E customers. Even with the compressed tiers, bills for high usage Palo Alto consumers are likely to remain substantially lower than the bills for high usage PG&E customers. The bill calculations show bills under the existing rates, not the proposed July 1, 2018 rates. However, even with the proposed rate increases, Palo Alto's residential bills will remain substantially below PG&E's current rates, but slightly above Santa Clara's. Table 6: Residential Monthly Electric Bill Comparison (Effective 3/1/18, $/mo) Season Usage (kwh) Palo Alto PG&E Santa Clara 300 36.48 63.51 35.18 Winter 453 (Median) 63 .50 104.49 53.78 (March) 650 100.93 159.64 77.73 1200 205.45 313.60 144.59 300 36.48 63.51 35.18 Summer (Median) 330 40.12 71.70 38.83 (July) 650 100.93 161.28 77.73 1200 205.45 315.24 144.59 Table 7 shows the average monthly electric bill for commercial customers for various usage levels. Even with the proposed rate increases, Palo Alto's commercial bills will remain substantially below PG&E's, and below Santa Clara's for some commercial customers. Table 7: Commercial Monthly Electric Bill Comparison (3/1/18, $/mo) Usage (kwh/mo) Palo Alto PG&E Santa Clara 1,000 161 245 181 160,000 23,732 30,413 20,850 500,000 62, 190 83,820 62,956 2,000,000 268,475 361,753 256,247 SECTION 5: UTILITY FINANCIAL PROJECTIONS SECTION SA: LOAD FORECAST Figure 5 shows a 33-year 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. 15 I Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60B61389168E SECTION SC: FY 2017 RESULTS Total cost of purchasing electricity was lower than the forecast by approximately $3.9 million. Capital improvement costs were lower than the forecasted level by $9.9 million. Sales revenues were higher than the forecast by $2.9 million, but there was also $4.8 million in surplus sales revenue beyond what was budgeted. While net revenues were still lower than cost by $3 million, the net reserve withdrawal was lower than originally anticipated ($25 million). The lower withdrawal in FY 2017 will allow for reserves to be used in future years. 18 I Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60B613B9168E Table 8 FY 2017, Actual Results vs. Financial Plan Forecast ($000) Net Cost/(Benefit) Type of change Sales revenues higher than forecast $(2,881) Revenue increase Wholesale and other revenues higher than (5,978) Revenue increase forecast Lower capital improvement costs (9,932) Cost decrease Lower purchased electricity costs (3,904) Cost decrease Higher operations costs 344 Cost increase Net Cost I (Benefit) of Variances $(22,352) SECTION SD: FY 2018 PROJECTIONS Last year, staff recommended (and Council approved) a 14% rate change for July 1, 2017, the start of FY 2018. Current sales revenue projections for 2018 are roughly $1.S million higher than expected in last year's financial plan. Based on current hydro conditions, wholesale costs are again expected to contribute to other revenues being higher by $S.S million. Purchased electricity cost projections for 2018 are anticipated to be $4.S million lower than in last year's financial plan. However, capital cost estimates and operations cost estimates (which includes other than purchased electricity costs) increased by $S.3 million and $3.8 million, respectively. Table 9 FY 2018, Change in Projected Results, 2018 Forecast vs. 2019 Forecast ($000) Net Cost/(Benefit) Type of change Sales revenues (1,454) Revenue increase Wholesale and other revenues higher than (5,476) Revenue increase forecast Capital improvement costs 5,388 cost increase Purchased electricity costs (4,481) cost decrease Operations costs 3,848 cost increase Net Cost I (Benefit) of Variances $2,175 SECTION SE: FY 2019 -FY 2028 PROJECTIONS As shown in Figure 7 above, staff projects costs for the Electric Utility to increase at a fairly steady rate through the forecast period. Revenue increases of 6% in FY 2019 and another 3% in FY 2020 are projected to bring revenues in line with expenses. Rising electricity purchase costs are the primary contributor to the increases. Electricity purchase costs have increased substantially since FY 2013 as new renewable projects have come online to fulfill the City's environmental goals, and as transmission costs have increased due to improvements being made to the California grid. Operations costs are expected to increase at or near the inflation rate (2-4 %/year) through the forecast period. Projected capital expenses for FY 2018 through FY 2023 are higher in FY 2018 through FY 2021 due to work on the Upgrade Downtown project, as well as anticipated AMI and smart grid implementation. Once these larger, one-time project 19 I Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60B613B9168E Table 10: Electric Supply Fund Risk Assessment Estimates of Adverse - categories of Electric Supply Cost Outcomes (M$) Uncertainties FY 2019 FY 2020 Notes 1. . Production from Hydroelectric 6.8 6.2 Lower than forecasted hydro Resources: \Nestern 2. Production from Hydroelectric 3.3 2.6 Lower than forecasted hydro Resources: Calaveras 3. Market Price (Energy) 2.2 0.8 Higher than forecasted market prices for energy 4. Transmission/CAISO 3.3 3.3 High-end transmission foreca.st scenario 5. Plant Outage 1.0 1.0 Uninsured losses from Calaveras plant outage 6. \Nestern Cost 3.5 3.5 Risk of rate adjustments from \Nestern 7. Regulatory and Legal 0.0 0.0 Risks associated with legislative uncertainties Electric Supply Fund Risks $19.9 $17.4 million million Projected Supply Operations + $65.6 $65.8 Hydro Stabilization Reserve million million Levels Of the risks faced by the Electric Utility's Supply Fund in FY 2019, the risk of a dry year with very low hydroelectric output is normally the largest, accounting for nearly half the total cost of all adverse outcomes. 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 2019, $3.3 million is related to the projected costs if transmission cost increases are higher than staff's current forecast. $3.5 million is related to the uncertainty to Western's rates for Restoration costs. As shown in Figure 10, the Supply Operations Reserve was below the minimum reserve guidelines at the end of FY 2017. However, through reserve transfers and rate increases, staff projects the Supply Operations Reserve to stay within the reserve guideline levels throughout the forecast period. Figure 11 shows that the combined Hydro Stabilization and Supply Operations Reserves are projected to be above what is needed for the risk assessment level. 22 I Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60B613B9168E 2021 and the last in 2028. These three contracts, plus one more expiring in 2030, currently provide 17% to 18% of the energy for the utility's supply portfolio at prices under $65 per megawatt-hour (MWh). It is difficult to know what renewable energy prices will be when those contracts expire. Although recent prices have been in that range (or even lower), and costs may decrease in the future, current renewable projects also benefit from a wide range of tax and other incentives that may or may not be available in the 2020s and beyond. However, staff is in the process of procuring a replacement for the contract expiring in 2021 at a lower price than any of the City's current renewable contracts. The costs of the Calaveras hydro project will also change in the 2020s, with debt service costs dropping by half in 2025 as some of the debt is paid off, and all debt retired by the end of 2032 (assuming the Utility does not issue any new debt). The project will only be 40 years old at that time. 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 tong 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 through 2020. However, discussions at the state level are ongoing and will determine whether or not these allocations continue past 2020, as well as any restrictions CARB may wish to enact on 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 sates 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 t.o 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 will also begin the rollout of various smart grid technologies. The utility continues to monitor the growth of electric vehicle ownership and gas-to-electric fuel switching in Palo Alto. In the next 10 to 20 years, these factors may begin to create notable increases in electric consumption and have a variety of impacts on the distribution system. As housing stock is turned over, however, stricter building 27 I Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60B613B9168E codes may help to counteract load growth, as may increasing numbers of rooftop solar installations. 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, it is conceivable that electricity could replace natural gas and petroleum almost entirely. Many, if not most, vehicles would use electricity, though hydrogen is another potential fuel source under development and other technologies might be developed. Staff are undertaking initial analysis of these types of scenarios in the context of the Sustainability and Climate Action Plan (S/CAP) development process. These types of scenarios require careful planning for the associated load growth to make sure the distribution system does not end up overloaded, or conversely, to avoid over investment, and the evaluation of changes to utility distribution system management to accommodate integration of the various technologies involved in electrification. 28 I Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60861389168E SECTION GC: CAPITAL IMPROVEMENT PROGRAM (CIP) Staff projects CIP spending for FY 2019 through FY 2024 to be consistent with last year's forecast, though there is a slight shift in the funding by project category. There will be a reduction in capital cost and revenue related to the VA Hospital project as the VA will be responsible for the installation, and associated costs, of electric facilities; there will be a reduction in funding for Undergrounding as current projects are completed; there will be an increase in funding for Underground Rebuilding and 4/12kV Conversion as improvements are made to the system in portions of the Crescent Park/Duveneck/St. Francis/Community Center/Leland Manor/Garland neighborhoods to facilitate rebuild of the Hopkins Substation; and increase in funding for replacement of distribution system and substation facilities that are at the end of their useful life. Other significant projects still slated to continue are deteriorated wood pole replacements, pole relocations to facilitate the Caltrain Railway Electrification project, Smart Grid upgrades, and ongoing capital investment in the electric distribution system to maintain/improve reliability. This forecast assumes that the utility finances smart grid projects from the Electric Special Projects Reserve and with additional funding from the water and gas funds, but it would also be possible to use bond financing. Excluding the one-time projects listed above, the CIP plan for FY 2019 to FY 2023 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 (for smart grid). The details of the CIP budget will be available in the Proposed FY 2019 Utilities Capital Budget. Figure 17 shows the FY 2018 projected budget and the five year CIP spending plan, although these figures are preliminary pending budget discussions starting in May. The 'committed' column represents funds committed to contracts for which work has not yet ·been completed or invoices paid. Figure 15: Electric Utility CIP Spending ($000) Current Spending, Remain. Project Category Budget* Curr. Yr Budget** Committed FY 2019 FY 2020 One-nme Projects 5,021 (128) 4,893 123 1,400 1,300 Svstem Expansion 3,507 (27) 3,481 --- Reliability 3,711 (129) 3,582 153 1,067 317 Unden!roundinR 4,395 (40) 4,355 353 900 - 4/12 Kv Conversion 270 {1) 269 --1,750 Under11round RebuildinR 3,385 (3) 3,382 3 -2,656 Oni;ioinR Projects 6,714 {882) 5,832 3,255 3,145 3,625 Customer Connections (Fee Funded) 4,087 (1,149) 2,938 589 3,220 3,336 TOTAL 31,091 (2,359) 28,732 4,476 9,732 12,984 •includes unspent funds from previous years carried forward or reappropriated into the current fiscal year. ••Equal to CIP Reserves (Reserve for Reappropriations +Reserve for Commitments). FY 2021 FY 2022 FY 2023 10,750 5,000 5,000 --- 150 -- 2,000 2,250 500 800 -- 1,500 350 350 3,280 3,280 3,230 3,456 3,580 3,600 21,936 14,460 12,680 32 I Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60B613B9168E SECTION GD: DEBT SERVICE The Electric Utility's annual debt service is $100,000 per year. The Electric Utility currently makes payment on one bond issuance, the 2007 Efectric Utility Clean Renewable Energy Tax Credit Bonds, Series A. 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. The capacity of these projects totaled 250 kW. In exchange for funding part of the construction costs, the Electric Utility receives the RECs from these projects. The bonds were Clean Renewable Energy Bonds (CREBs), meaning they are interest free (the investors receive a tax credit from the federal government). This bond issuance is secured by the net revenues of the Electric Utility. Debt servic'e for this bond continues through 2021, and for the financial forecast period is as follows: Table 11: Electric Utility Debt Service ($000) FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 2007 Clean Renewable 100 100 100 100 --Energy Bonds The 2007 bonds include a covenant stating that the Electric Utility will maintain a debt coverage ratio of 125% of debt service. The current Financial Plan maintains compliance with these covenants throughout the forecast period, as shown in Appendix C. The Electric Utility also pledges reserves and net revenue as security for the bond issuances listed in Table 13, 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. Table 12: Other Issuances Secured by Electric Utility's Revenues or Reserves Bond Issuance Responsible Utilities Annual Debt Secured by Electric Utility's: Service ($000) Net Revenues Reserves 1995 Utility Revenue Bonds, Series A Storm Drain $680 Yes No 1999 Utility Revenue Bonds, Series A Storm Drain Wastewater Collection $1,207 No Yes Wastewater Treatment 2009 Water Revenue Bonds (Build Water $1,977* No Yes America Bonds) 2011 Utility Revenue Refunding Gas $1,457 No Yes Bonds, Series A Water *Net of Federal interest subsidy 33 I Page DocuSign Envelope ID: 97 A3E480-BE4A-4CA6-9007-60B613B9168E SECTION GE: 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.7 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 19% comes from other sources. Of these other sources, about 50 to 60% represents wholesale revenues of surplus energy sales included solely for accounting purposes. These revenues have offsetting electric supply purchase costs, and do not normally affect the utility's net position. Of the remaining revenues, the largest revenue sources are interest on reserves, connection fees for new or replacement electric service~, and carbon allowance revenues associated with the State's cap-and-trade program. In FY 2017 these sources represented roughly 28% of revenue from sources other than electricity sales. The remaining FY 2017 revenues consisted of a variety of one-time transfers. Revenues from connection fees have increased since FY 2009 varying from year to year. Revenue from connection fees decreased slightly during the recession, but has increased substantially since then, peaking in FY 2016 and declining somewhat in FY 2017. Staff forecasts slightly higher revenue from this source in 2018 through 2021 with revenue leveling out in subsequent years. 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. The State's cap-and-trade program regulations only describe the program through 2020. This forecast assumes the program will remain in place with similar program design following 2020, but that may not be the case. CARB is in the process of establishing post-2020 rules. 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. 7 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. 34 I Page DocuSign Envelope ID: 97 A3E480-BE4A-4CA6-9007-60B613B9168E SECTION 6G: SALES REVENUES The load forecast in Section SA: Load Forecast and the projected rate changes shown in Figure 7 provide the basis for sales revenue projections. As discussed in Section SA, sales revenues for this utility stay relatively stable due to the mild climate in Palo Alto. In addition, Palo Alto is a built out City, with incremental growth in population and relatively stable commercial customer loads. 35 I Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-608613B9168E SECTION 7: COMMUNICATIONS PLAN The FY 2019 Electric Utility communications strategy covers these primary areas: rates, efficiency, renewables, operations, infrastructure, safety, and changes to utility economic conditions in the wake of the drought. CPAU communication methods include use of the Utilities website, utility bill inserts, messaging on bills and envelopes, email newsletters, print ads in local publications, videos and participation in community outreach events. In FY 2019, CPAU is proposing a nine percent increase in electric utility rates. Prior to FY 2017, electric utility rates had not increased since 2009, as the City has been drawing down reserves from the Electric Fund. The rate increase will be necessary in FY 2018 and again in FY 2019, as these reserves drop below the reserve target level. Communications will focus on the reasons why a rate increase is necessary, due to an increase in transmission fees and new renewable projects coming online, rising operating and capital costs, and how drought affected the City's reserves. Palo Alto purchases a significant portion of its electricity from hydroelectric resources. Several-year drought conditions reduced available hydroelectric supplies, requiring the City to purchase more costly replacement electric supplies. Since the State may not received a great deal of precipitation in the latter part of FY 2018, communications staff will now focus messaging on how increased hydroelectric supplies could still impact and potentially change the forecast for electric rates moving forward, at least in the short-term. Despite these costs and increasing rates, CPAU's electric utility rates remain lower than the neighboring community average, including for municipal and investor-owned utilities (PG&E). Keeping costs low is one of the benefits CPAU offers its customers as a public utility provider. CPAU will continue to communicate about the environmental benefits of the City's carbon neutral electric supply portfolio. Outreach includes apprising the public of major renewable energy purchase agreements, which contribute toward Palo Alto's long-term energy security and commitment to sustainability. Recent power purchase agreements have allowed CPAU to procure long-term renewable electric supplies at low costs. While upfront capital costs to bring these renewable projects online may initially contribute towards some increase in CPAU's electric rates, staff expect these higher costs to taper off once the projects begin commercial operations. CPAU will highlight these environmental attributes and value in our communications. Throughout the year, communications staff promote CPAU's electric efficiency services, rebates and local renewable energy programs. Within the past few years, CPAU has launched new programs that allow customers to better understand and manage their energy use. Programs such as the Home Efficiency Genie and commercial energy efficiency programs help residents and businesses better understand energy usage, activities and/or upgrades they can implement to improve efficiency and reduce utility costs. CPAU will be launching an upgraded version of its online utility account services portal (www.cityofpaloalto.org/myutilitiesaccount) this year, which can provide customers with direct access and more information about utility account and consumption data. 36 I Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60861389168E 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 37 I Page DocuSfgn Envelope 10: 97A3E480-BE4A-4CA6-9007-60B613B9168E APPENDIX A: ELECTRIC UTILITY FINANCIAL FORECAST DETAIL 6053706 DocuSign Envelope ID: 97A3E480-BE4A4CA6-9007-60B613B9168E (page intentionally left blank) 6053706 Oocu~n ~'!~9j.!?:SO..SE4A-4CA6-9007.oo8613.~91~ fY 2014 I PY 2115 11 py 201• I P12017 I f'Y 201a ti PY 2019 I PY 2020 I f'Y 2021 I F"f 2022 I l'Y 2023 I PY 2024 I flY 2021 I PY 202! I PY 2027 ,I rv 2928 I 3 necT111C·LOAD ---·---------- Purchases (MWh) Sales (MWh) 976,319 946,841 980,894 950,784 979,005 936,773 977,292 937,157 945,703 917,687 939,991 909,595 943,995 910,883 940,694 907,697 937,221 904,346 933,569 900,823 931,545 898,869 930,263 897,632 930,117 897,492 929,943 897,324 930,376 897,742 930,646 898,002 !lllU.ANDllATl!C~-------I I I I I I 8 System Average Rate ($/kWh) $ 0.1154 $ 0.1164 $ 0.1158 $ 0.1156 $ D.1249 $ 0.1421 $ D.1513 $ 0.1557 $ 0.1593 $ 0.1598 $ D.1609 $ 0.1625 $ 0.1634 $ 0.1650 $ 0.1666 $ 0.1683 9 Change In System Average Rate a.. 1¥1 °"' ~ 10¥1 14¥1 6'4ii J'ilt 2'4ii °"' 1¥. 1'ilt 1¥. 1'ilt 1¥. 1¥. 10 Chanoe ln Average Resklentlal 8611 "'4"Aio ·1 'ilt ·5¥. 3.. 11 't'. 11 ¥1 6.. 2'ilt 2'ilt 0.. 0.. 1 ¥1 0¥1 1 ¥. 1 "41 1 ¥1 11 12 !STAlmNll W ----------n-I I r---I -I I 13 Reapproprlatlons (Non-CIP) 14 Corrmltments (Non<IP) 15 Restncted for Debt Service 16 Emergency Plant Replacement 17 Central Valley Project Reserve 18 Underground Loan Reserve 19 Pubk Benefk.s Reserves 20 Bectnc Special Projects Reserve 21 Hydro stabMlzatkW'I Reserve 22 Capital Reserves 23 Rate stabMlzatlon Reserves 24 Operations Reserves 25 Unass~ned 26 TOTAL STARTING RESERVES 27 28 ltt!Vl!NUES 1,886,000 2,737,000 1,000,000 314,000 742,000 1,149,000 50,320,000 74,609,000 132,757,000 305,000 3,528,000 1,000,000 313,000 738,000 2,197,000 51,838,000 69,029,000 128,~8,000 3,164,000 1,000,000 329,000 734,000 2,064,000 51,838,000 70,049,000 129,178,000 3,102,055 730,000 2,574,000 51,837,855 17,000,000 14,410,840 22,497,607 112,152,357 3,777,205 729,000 1,839,000 51,837,855 11,400,000 9,010,840 21,850,187 100,444,086 2,970,955 730,147 681,330 51,837,855 11,400,000 879,964 9,010,840 29,912,981 107,424,072 2.970.955 730,147 45,837,855 10,400,000 879,964 37,184,461 98,703,382 2,970,955 730,147 45,066,855 10,400,000 879,964 32,053,564 92,101,•Ul5 2,970,955 730,147 44,756,855 10,400,000 879,964 33,249,1~ 92,987,115 2,970,955 730,147 43,246,855 10,•00,000 879,964 39,131,346 2,970,955 730,147 42,846,855 13,900,000 879,96-4 38,136,530 97,366,267 100,164,451 2,970,955 2,970,955 730,147 730,147 42,846,855 412,846,855 13,900,000 13,900,000 879,964 879,964 39,719,124 41,254,722 2,970,955 730,147 42,846,855 13,900,000 879,964 44,072,659 101,047,745 102,582,643 105,400,580 2,970,955 730,147 42,846,855 13,900,000 879,964 46,167,305 107,495,226 2,970,955 730,147 42,846,855 13,900,000 879,964 •9.327,672 110,655,593 29 Netsales 109,974,337 110,246,264 108,873,377 108,312,917 114,624,726 129,258,435 137,836,311 141,304,121 144,032,395 143,988,875 144,612,409 145,833,873 146,687,201 148,083,859 149,581,682 151,104,314 30 Wholesale Revenues 6,635,790 6,010,409 6,267,000 4,301,366 16,188,920 18,115,996 13,718,260 14,366,366 16,106,798 17,749,617 17,407,062 17,763,941 17,932,747 18,052,704 18,231,927 18,351,535 31 Other Revenues and Transfers In 9 624 213 13.669.1'15 ~ 11 714 494 11.225.911 lJ 776 378 12 781 199 15.649.312 18 168 427 12.895 834 12.896.707 13 341 185 13 815 444 14 273.124 14 759 484 15 001 446 32 TOTAL REVENUES 126,234,340 129,925,858 124,828,858 124,328,776 142,039,557 161,150,809 164,335,770 171,319,799 178,307,620 174,634,326 174,916,179 176,938,999 178,435,392 180,409,687 182,573,093 184,457,295 33 3•EJCPENSU 35 ElectliCSupply Purdlases 61,313,637 68,785,977 80,022,010 75,705,000 80,467,136 83,505,886 91,924,961 94,232,563 95,111,327 98,655,001 98,667,977 99,059,024 102,252,401 103,53"1,874 103,178,257 106,193,'402 36 Operatlno Expenses 37 Administration 38 A/IOCMed Charges 39 Rmt 40 ~Sft'lllce 41 Transfrrs and Other .Adjustments 42 subtotal, Administration 43 Resource Management 44 Demand Skie Manaoement 45 Operations and Mtc 46 Engineering (Operating) 47 Customer Service 48 Allowance for Unspent Budget "19 subtotal, OperatlnO Expenses SO Capital Program ContrlbuUon 51 TOTAL EXPENSES 4,399,674 3,875,836 9,265,736 ~ 34,338,299 3,024,268 3,529,529 9,601,481 1,114,945 2,007,322 53,615,8414 15,113,859 130,043,340 .f,139,817 .f,051,044 9.020,651 ~ 28,541,506 J,541,524 3,187,875 9,488,627 1,102,008 2,032,231 47,893,770 13,016,111 129,695,858 •,Sll,211 •,H7,U2 9,037,000 ~ 28,700,600 2,138,615 3,491,470 10,716,881 1,230,160 1,548,851 47,826,576 14,005,915 141,854,501 •,93•,195 ,,,997,101 8,885,994 .l.l.ZH.J.il 30,616,155 2,083,812 3,643,924 11,523,881 1,592,024 1,540,884 51,000,680 9,331,367 136,037,047 3,990,822 s.121.102 8,953,893 = 30,768,762 1,985,620 4,271,786 11,811,016 1,656,522 2,540,424 53,034,130 11,558,306 145,059,572 .f,JO.f,278 •.'fJ2,096 4,522,617 .if,6JS,777 .if,751,691 .if,870,Sll 4,991,101 5,1J7,1J6 5,2•5,093 5,18.if,977 5,.if.fJ,517 5,606,811 5,775,037 5,9.fB,288 6,116,717 6,310,519 6,499,855 6,694,851 8,955,166 8,808,619 8,818,349 8,783,507 8,792,388 9,62•,•93 9,159,611 •,898,677 .if,896,047 ~ ~ ~ ~ ...HJ.H.lJJl .J.LJJlZ.lll ...M..1JlZ.JZJI ....li.lJ.L.lW. ~ 31,586,G48 31,970,028 33,138,304 33,388,889 33,691,098 34,824,738 34,769,822 30,727,521 31,052,439 3,446,889 3,569,550 3,697 ,054 3,806,324 3,905,053 '4,007,389 4,112,406 4,220,176 4,330,770 4,327,895 4,214,985 3,955,387 3,913,776 3,888,167 3,989,346 4,050,076 4,111,910 4,174,870 13,349,20• 13,790,502 14,247,795 14,653,401 15,030,198 15,419,751 15,819,400 16,229,407 16,650,041 1,963,752 2,016,569 2,070,856 2,124,317 2,177,782 2,232,696 2,288,996 2,346,715 2,405,890 2,253,647 2,338,475 2,426,869 2,500,743 2,566,062 2,633,909 2,703,550 2,775,032 2,848,403 (1523 291) 11 571 660) ~ (I 667 008) {l,709,687) (l,753,753) (I 798 955) (I 845,322) (1.892.885) 55,404,145 56,328,449 57,914,537 58,720,442 59,548,674 61,354,076 61,945,295 58,565,440 59,S69,529 20,961,467 22,684,258 18,287,069 20,096,699 13,632,467 14,010,831 159,871,498 170,937,668 170,434,169 173,928,468 171,836,142 174,032,085 14,399,781 175,404,101 14,799,614 15,210,638 175,617,456 178,315,041 5,376,249 6,895,697 4,89 .. ,784 uuuu 31,387,888 4,444,262 4,238,976 17,081,577 2,466,557 2,923,715 (I 941 675) 60,601,301 15,633,168 179,412,726 5,510,686 7,101,568 •,893,196 ~ 31,732,535 4,560,728 4,304,249 17,524,297 2,528,754 3,001,018 (I 991 722) 61,659,859 16,067,528 183,920,790 ~~ r.l!ND;;;;;~DHl...-;lll!SellV!S;;;;;;;;;;o;;-~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~ 54 Reapprop111Uons (Non-CIP) 55 Corrrnttments (Non-CIP) 56 Restricted for Debt Servke 57 Emervency Pb1nt Replacement SS Central Vatley Project Reserve 59 Underground Loan Reserve 60 Public Benefits Reserves 61 Electlie Special Projects Reserve 62 Hydro StabMlzatk>n Reserve " SS Capital Reserve 59 Rate stabNlzatlon Reserve 60 Operations Reserve 61 Unass~ned 62 TOTAL ENDING RESEP.V!S 30S,OOO 3,528,000 1,000.000 313,000 738,000 2,197,000 51,838,000 69,029,000 128,9-48,000 3,164,000 1,000,000 329,000 734,000 2,064,000 51,838,000 70,049,000 129,178,000 3,102,055 730,000 2,574,000 51,837,855 17,000,000 14,410,840 22,497,607 112,152,357 3,777,205 729,000 1,839,000 51,837,855 11,400,000 9,010,840 21,850,187 100,444,086 2,970,955 730,147 681,330 51,837,855 11,400,000 879,964 9,010,840 29,912,981 107 ,424,072 2,970,955 730,147 45,837,855 10,400,000 879,964 37,88'1,461 98,703,382 2,970,955 730,147 45,066,855 10,400,000 879,964 32,053,564 92,101,485 2,970,955 730,147 44,756,855 10,400,000 879,964 33,249,1~ 92,987,115 2,970,955 730,147 43,246,855 10,400,000 879,96• 39,138,346 97,366,267 2,970,955 730,147 42,846,85S 13,900,000 879,964 38,836,530 100,164,451 2,970,955 730,147 42,846,855 13,900,000 879,964 39,719,824 101,047,745 2,970,955 730,147 42,846,855 13,900,000 879,964 41,254,722 2,970,955 730,147 42,846,855 13,900,000 879,964 44,072,659 2,970,955 730,147 42,846,855 13,900,000 879,964 46,167,305 102,582,643 105,400,580 107,495,226 2,970,955 730,147 42,846,855 13,900,000 879,964 49,327,672 110,655,593 2,970,955 730,147 42,846,855 13,900,000 879,964 49,864,178 111,192,()99 ~ 1~o~l'l!M===1J0NS==""""'lll!SEIM!====-~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~-..l~~~~1~~~~1 ~~--.,r-~~-.-,~~----,1 65 Min (60 days of non-capita! expenses) 66 Target (90 days of non<apltal eirpenses) 67 Max (120 days of non-capltal expenses) 68 Rlsk Assessment Vak.11! 6053706 23,5'48,140 33,151,752 42,755,364 4,645,297 23,011,890 32,456,285 41,900,681 4,193,350 25,284,688 35,213,317 45,141,947 4,338,548 26,254,697 36,600,0'46 46,945,394 5,838,255 27,887,150 38,978,736 50,070,321 6,183,701 28,525,288 39,864,186 51,203,084 5,769,290 28,948,137 40,425,168 51,902,198 5,935,703 29,816,058 41,652,081 53,488,104 5,314,839 30,267,979 42,253,107 54,238,235 5,417,963 30,586,285 42,651,788 54,717,290 5,563,442 30,716,392 42,766,200 5'4,816,007 5,671,929 31,257,049 43,494,415 55,731,781 5,824,643 31,536,939 43,829,410 56,121,881 5,981,673 32,379,720 45,006,620 57,633,519 6,143,144 DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60B613B9168E ELECTRIC UTILITY FINANCIAL PLAN 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 1.d) (Rate Stabilization Reserves) f) For operating contingencies, as described in Section 12 (Operations Reserves) g) Any funds not included in the other reserves will be considered Unassigned Reserv.es 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) June 2018 42 I Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60B613B9168E ELECTRIC UTILITY FINANCIAL PLAN ------------------ h) 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 (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 and timelines 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 and timelines 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 2017; f) Any uncommitted funds remaining at the end of FY 2022 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. June 2018 43 I Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60B613B9168E ELECTRIC UTILITY FINANCIAL PLAN -------- 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 based on the levels of CIP expense budgeted for that year. Minimum Level 60 days of budgeted CIP expense Maximum Level 120 days of budgeted CIP expense b) Changes in Reserves: 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) Funds held in the Reserve for Commitments may be counted as part of the CIP Reserve for the purpose of determining compliance with the CIP Reserve minimum guideline level. June 2018 441 Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60B613B9168E ELECTRIC UTILITY FINANCIAL PLAN ii) 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, at any time, the CIP Reserve reaches its maximum level, no funds may be added to this reserve. If there are funds in this reserve in excess of the maximum level staff must propose to transfer these funds to another reserve or return them to ratepayers in the next Financial Plan. 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. 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 d) 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 Max.imum Level 120 days of Supply Fund O&M and commodity expense June 2018 45 I Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60B613B9168E ELECTRIC UTILITY FINANCIAL PLAN 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 f!scal 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. June 2018 46 I Page DocuSign Envelope ID: 97A3E480-BE4A-4CA6-9007-60B613B9168E ELECTRIC UTILITY FINANCIAL PLAN 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 provfded 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. June 2018 47 I Page