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HomeMy WebLinkAboutRESO 9593160330 jb 6053708 Resolution No. 9593 Resolution of the Council of the City of Palo Alto Approving the FY 2017 Electric Utility Financial Plan and Amending the Electric Utility Reserves Management Practices R E C I T A L S A. Each year the regularly assesses the financial position of its utilities with the goal of ensuring adequate revenue to fund operations. This includes making long­term 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. The City intends to make changes to its Electric Utility Reserves Management Practices to amend the management practices of the Electric Program (CIP) Reserve. The Council of the City of Palo Alto hereby RESOLVES as follows: SECTION 1. The Council hereby approves the FY 2017 Electric Utility Financial Plan, including the amended Electric Utility Reserves Management Practices. These Reserves Management Practices replace the Reserves Management Practices previously approved for the Electric Utility as part of the FY 2016 Electric Utility Financial Plan (Resolution 9521). SECTION 2. The Council hereby approves the transfer of $5.6 million in FY 2016 from the Hydro Stabilization Reserve to the Supply Operations Reserve, $2.0 million in FY 2016 from the Supply Operations Reserve to the Distribution Operations Reserve, the transfer of $5.6 million in FY 2016 from the CIP Reserve to the Distribution Operations Reserve, the transfer of $5.4 million from the Supply Rate Stabilization Reserve to the Supply Operations Reserve in FY 2017, up to $9.0 million from the Hydroelectric Stabilization Reserve to the Supply Operations Reserve in FY 2017, and up to $4.5 million from the Supply Operations Reserve to the Distribution Operations Reserve in FY 2017, as described in the FY 2017 Electric Utility Financial Plan approved via this resolution. / /  / /  / /  DocuSign Envelope ID: 8A4AF1DA-6454-453A-8C9F-535546D6739F 160330 jb 6053708 SECTION 3. The Council finds that the adoption of this resolution does not meet the California Environmental Quality Act (CEQA) definition of a project under Public Resources Code Section 21065, and therefore, no environmental assessment is required. INTRODUCED AND PASSED: June 13, 2016 AYES: BURT, DUBOIS, FILSETH, HOLMAN, KNISS, SCHARFF, SCHMID, WOLBACH NOES: ABSENT: BERMAN ABSTENTIONS: ATTEST: City Clerk Mayor APPROVED AS TO FORM: APPROVED: Senior Deputy City Attorney City Manager Director of Utilities Director of Administrative Services DocuSign Envelope ID: 8A4AF1DA-6454-453A-8C9F-535546D6739F FY 2017 ELECTRIC UTILITY FINANCIAL PLAN FY 2017 TO FY 2023 (SGY7MKR)RZIPSTI-(%%*(%%'*(* 2 | P a g e FY 2017 ELECTRIC UTILITY FINANCIAL PLAN FY 2017 TO FY 2023 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 .................................................................................. 6 Section 3: Detail of FY 2017 Rate and Reserves Proposals ....................................................... 7 Section 3A: Rate Design ............................................................................................................... 7 Section 3B: Current and Proposed Rates..................................................................................... 7 Section 3C: Reserves Management Practices, Proposed Change ................................................ 7 Section 3D: Proposed Reserve Transfers ..................................................................................... 8 Section 4: Utility Overview.................................................................................................. 10 Section 4A: Electric Utility History ............................................................................................. 10 Section 4B: Customer Base ........................................................................................................ 12 Section 4C: Distribution System .................................................................................................12 Section 4D: Cost Structure and Revenue Sources...................................................................... 13 Section 4E: Reserves Structure................................................................................................... 14 Section 4F: Competitiveness ...................................................................................................... 15 Section 5: Utility Financial Projections ................................................................................. 16 Section 5A: Load Forecast .......................................................................................................... 16 Section 5B: FY 2009 to FY 2015 Cost and Revenue Trends ........................................................ 18 Section 5C: FY 2015 Results ....................................................................................................... 19 Section 5D: FY 2016 Projections ................................................................................................ 19 Section 5E: FY 2017 – FY 2023 Projections ................................................................................ 20 (SGY7MKR)RZIPSTI-(%%*(%%'*(* 3 | P a g e Section 5F: Risk Assessment and Reserves Adequacy ............................................................... 22 Section 5G: Long­Term Outlook.................................................................................................26 Section 6: Details and Assumptions ..................................................................................... 29 Section 6A: Electricity Purchases ............................................................................................... 29 Section 6B: Operations .............................................................................................................. 31 Section 6C: Capital Improvement Program (CIP)....................................................................... 32 Section 6D: Debt Service............................................................................................................ 33 Section 6E: Equity Transfer ........................................................................................................ 34 Section 6F: Wholesale Revenues and Other Revenues .............................................................. 35 Section 6G: Sales Revenues .......................................................................................................35 Section 7: Communications Plan .......................................................................................... 36 Appendices ......................................................................................................................... 37 Appendix A: Electric Utility Financial Forecast Detail ................................................................ 38 Appendix B: Electric Utility Reserves Management Practices................................................... 42 Appendix C: Description of Electric utility Operational Activities .............................................. 47 Appendix D: Samples of Recent Electric Utility Outreach Communications.............................. 48 (SGY7MKR)RZIPSTI-(%%*(%%'*(* 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 gigawatt­hour, 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 kilowatt­hour, 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 mid­size 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 115­500 kV, and this is lowered to 60 kV in the subtransmission 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 megawatt­hour, 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 Subtransmission 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. (SGY7MKR)RZIPSTI-(%%*(%%'*(* 5 | P a g e SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS This document presents a Financial Plan for the City’s Electric Utility for the next seven 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 moderately [AmyB1]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 additional capital investment costs. Table 1: Electric Utility Expenses for FY 2015 to FY 2023 Expenses ($000) FY 2015 (actual) FY 2016 (est.) FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 Power Supply Purchases 80,022 75,705 86,378 88,524 89,131 90,304 89,637 88,543 89,919 Operations 47,611 52,170 52,923 53,922 54,579 55,277 56,076 56,898 58,696 Capital Projects 12,713 16,989 27,652 22,058 26,649 15,868 16,320 16,785 17,263 TOTAL 140,346 144,864 166,953 164,504 168,710 161,450 162,034 161,225 165,877 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 higher this year than last year primarily due to the continued drought that has required additional electric supply purchases to replace hydroelectric supplies. Table 2: ProjectedElectric Rate Trajectory for FY 2017to FY 2023 Projection FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 Current 11% 10% 3% 0% 1% 0% 2% Last Year 6% 6% 1% 1% 0% 0% 2% 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 2017. Funds are projected to be transferred from the Electric Special Projects (ESP) Reserve to the Operations Reserve to fund smart grid projects included in the long term CIP budget. Funds are projected to be drawn from the Hydro Stabilization Reserve in FY 2017 and FY 2018 due to lower than average hydroelectric generation, though this projection is subject to change with weather conditions. It should be noted that the smart grid costs included in the forecast are (SGY7MKR)RZIPSTI-(%%*(%%'*(* 6 | P a g e placeholders, as are the transfers from the ESP Reserve. Any transfers from the ESP Reserve require Council approval. Table 3: Reserves Transfers for FY 2016 to FY 2023 ($000) Reserve FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 to FY 2023 Supply Reserves Electric Special Projects (151) (333) (3,750)­ Hydro Stabilization (5,600) (9,000) (2,400)­ ­ Supply Rate Stabilization 9,000* (5,411)­ ­ ­ Supply Operations 3,600 14,562 2,733 3,750 ­ Distribution Reserves Capital Improvement Program (5,600) Distribution Operations 7,700 ­ ­ ­ ­ * A $9 million transfer from the Supply Rate Stabilization Reserve to the Supply Operations Reserve was approved by Council when it adopted the FY 2016 Electric Utility Financial Plan SECTION 2B: SUMMARY OF PROPOSED ACTIONS Staff proposes the following actionsfor the Electric Utility in FY 2016: 1. Complete the proposed FY 2016 reserves transfers described Section 3D: Proposed Reserve Transfers. Staff proposes the following actions for the Electric Utility in FY 2017: 1. Complete the proposed FY 2017 reserves transfers described in Section 3D: Proposed Reserve Transfers. 2. Increase rates effective July 1, 2016 to generate an 11% increase in sales revenues. 3. Amend the Electric Utility Reserves Management Practices to modify the minimums and maximums for the CIP Reserve. Note that while the projected rate increases and reserves transfers in this FY 2017 Financial Plan are adequate to recover costs over the forecast period, the Supply Operations Reserves are projected to be as much as $3.9 million below the minimum Supply Operations Reserve level for FY 2017 through FY 2020. Staff still recommends proceeding with this plan for two reasons: first, due to the presence of a strong El Niño condition in the Pacific Ocean, there is a chance of high spring rains that may change this forecast, resulting in higher reserves, and second, the presence of the Electric Special Projects Reserve with a balance of $51 million means that a small temporary shortfall in the Supply Operations Reserve should not affect the Electric Utility’s financial health and bond ratings. In the event drought continues, staff will re­ evaluate its projections for FY 2018 and may recommend additional rate increases or the adoption of a hydroelectric rate adjuster. (SGY7MKR)RZIPSTI-(%%*(%%'*(* 7 | P a g e SECTION 3: DETAIL OF FY 2017 RATE AND RESERVES PROPOSALS SECTION 3A: RATE DESIGN The Electric Utility’s current rate structure and methodology are consistent with the cost of service analysis (COSA) update in 2007 by Boris Metrics. Staff is completing a new COSA with revised rates to become effective July 1, 2016. The new COSA is based on design guidelines adopted by Council on September 15, 2015 (Staff Report 6061). SECTION 3B: CURRENT AND PROPOSED RATES The current rates were adopted on July 1, 2009, when CPAU increased electric rates by 10%. Table 4, below, summarizes the current rates for the four largest customer 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, the PaloAltoGreen rates, and solar net metering. Another specialty rate is the E­18 municipal electric rate. Table 4: Current Electric Rates (Adopted July 1, 2009) Rate Component Units E­1 (Residential) E­2 (Small Commercial) E­4 (Medium Commercial) E­7 (Large Commercial) Demand (Summer) $/kW N/A N/A 20.54 18.97 Demand (Winter) $/kW N/A N/A 13.84 11.54 Energy (Summer) Tier 1 $/kWh 0.09524 0.14045 0.08171 0.07808 Tier 2 $/kWh 0.13020 N/A N/A N/A Tier 3 $/kWh 0.17399 N/A N/A N/A Energy (Winter) Tier 1 $/kWh Same as summer energy 0.12661 0.07318 0.07209 Tier 2 $/kWh N/A N/A N/A Tier 3 $/kWh N/A N/A N/A Tier amounts: Tier 1 kWh/day 0­10 N/A N/A N/A Tier 2 kWh/day 11­20 N/A N/A N/A Tier 3 kWh/day >20 N/A N/A N/A Staff proposes an 11% overall increase in revenue along with changes in rate design and changes in the allocation of costs between customer classes to ensure that the rates are based on the cost of service for each customer group. These proposals are detailed in the consultant report titled “City of Palo Alto Electric Cost of Service and Rate Study,” by EES Consulting (2016). SECTION 3C: RESERVES MANAGEMENT PRACTICES, PROPOSED CHANGE Staff proposes one change to the Electric Utility Reserves Management Practices (See Appendix B: Electric Utility Reserves Management Practices) in this Financial Plan. Staff recommends (SGY7MKR)RZIPSTI-(%%*(%%'*(* 8 | P a g e revising the CIP Reserve minimum to be 60 days of capital expenses, with a maximum of 120 days of expenses, which aligns with the Government Financial Officers of America rule of thumb for operating reserves and the minimum and maximum guidelines for the Distribution Operations Reserve. Staff recommends transferring $5.6 million from the CIP Reserve to the Distribution Operations Reserve. Also see Section 3D: Proposed Reserve Transfers. SECTION 3D: PROPOSED RESERVE TRANSFERS In the FY 2016 Electric Financial Plan Council approved a $9 million transfer from the Supply Rate Stabilization Reserve to the Supply Operations Reserve. Staff proposes the following additional transfers in FY 2016: Transfer $5.6 million from the Hydroelectric Stabilization Reserve fund to the Supply Operations Reserve to cover additional costs associated with low hydroelectric generation due to the drought. Transfer $2.0 million from the Supply Operations Reserve to the Distribution Operations Reserve to ensure reserve adequacy in the Distribution Operations Reserve. Transfer $5.6 million from the CIP Reserve to the Distribution Operations Reserve as part of the change to Reserves Management Practices described above. For FY 2017, staff proposes the following transfers: Transfer $5.4 million from the Supply Rate Stabilization Reserve to the Supply Operations Reserve. This transfer is to enable the City to spread necessary long term rate increases over multiple years to reduce the short­term impact on ratepayers. Transfer up to $9.0 million from the Hydroelectric Stabilization Reserve to offset potential costs associated with low hydroelectric generation. Some or all of this transfer may be unnecessary if weather conditions change, but if drought continues, this transfer will enable the City to fund the associated additional energy costs. Transfer up to $4.5 million from the Supply Operations Reserve to the Distribution Operations Reserve if necessary to ensure reserve adequacy in the Distribution Operations Reserve. The impact of these transfers on reserves levels can be seen in Figure 8 (for Supply Fund Reserves) and Figure 9 (for Distribution Fund Reserves) in Section 5E: FY 2017 – FY 2023 Projections. Table 5 shows the projected balance of each of the Electric Utility reserves for the period covered by this Financial Plan. The projected balances are also provided in. Appendix A: Electric Utility Financial Forecast Detail (SGY7MKR)RZIPSTI-(%%*(%%'*(* 9 | P a g e Table 5: End of Fiscal Year Electric Utility Reserve Balances for FY 2016 to FY 2023 Ending Reserve Balance ($000)FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 Reappropriations ­ ­ ­ ­ ­ ­ ­ ­ Commitments 3,102 3,102 3,102 3,102 3,102 3,102 3,102 3,102 Underground Loan 730 730 730 730 730 730 730 730 Public Benefits 2,574 2,700 2,790 2,799 2,717 2,545 2,434 2,374 Special Projects 51,838 51,535 51,383 51,050 47,300 47,300 47,300 47,300 Hydro Stabilization 17,000 11,400 2,400 0 0 0 0 0 Capital 0 2,864 2,864 2,864 2,864 2,864 2,864 2,864 Rate Stabilization 14,411 5,411 0 0 0 0 0 0 Operations 22,498 22,734 22,015 22,281 24,814 27,033 30,783 34,269 Unassigned 0 0 0 0 0 0 0 0 TOTAL 112,153 100,476 85,284 82,827 81,528 83,574 87,214 90,639 (SGY7MKR)RZIPSTI-(%%*(%%'*(* 10 | P a g e 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 40­year 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 long­term 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 mid­80s. Palo Alto joined other NCPA members to invest in the construction and operation of the Calaveras Hydroelectric Project on the Stanislaus River in the Sierra­Nevada 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 (SGY7MKR)RZIPSTI-(%%*(%%'*(* 11 | P a g e 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 Utility1 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 managing 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 gas­fired 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 carbon­free hydroelectric supplies, purchases of long­term renewable energy supplies, and short­term renewable energy purchases (RECs) to meet the balance of its needs. 1 Implementation of Direct Access for Electric Utility Customers , CMR:460:97, December 1, 1997 (SGY7MKR)RZIPSTI-(%%*(%%'*(* 12 | P a g e Figure 1: Customer Base (FY 2015) Residential 16% Small Comm 8% Med Comm 32% Large Comm 41% Municipal 3% 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 roughly 29,300 customers connected to the electric system, 26,400 (90%) of which are residential and 2900 (10%) of which are non­ residential. Residential customers consumed 173 gigawatt­hours (GWh) in FY 2015, approximately 18% of the electricity sold, while non­residential customers consumed 82% or 763 GWh. Residential customers use electricity primarily for lighting, refrigeration, electronics, and air conditioning.2 Non­residential customers use the majority of their electricity for cooling, ventilation, lighting, office equipment (offices), cooking (restaurants), and refrigeration (grocery stores).3 As shown in Figure 1 large customer loads represent a larger proportion of sales for the Electric Utility than they do for the City’s other utilities. The largest customers (the 66 customers on the E­7 rate schedule) account for over 40% of CPAU’s sales. The next largest customer group (the 740 commercial customers on the E­4 rate schedule) represents another 32% of sales. In total, that means that less than 3% of customers account for nearly 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 470 miles of distribution lines, of which 223 miles (48%) are overhead lines and 245 miles (52%) are underground. The Electric Utility also maintains six substations, roughly 2,000 overhead line transformers, 1,075 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 2 Source: Residential Appliance Saturation Survey, California Energy Commission, 2010 3 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006. (SGY7MKR)RZIPSTI-(%%*(%%'*(* 13 | P a g e Figure 2: Cost Structure (FY 2015) Figure 3: Hydroelectric Variability (FY 2016) 0% 20% 40% 60% 80% 100% 120% 140% Low Hydro Average High Hydro Surplus Hydro (sales) Market Power/RECs Hydro Renewables Load Figure 4: Revenue Structure (FY 2015) other associated electric equipment, represent the vast majority of the infrastructure used to deliver electricity in Palo Alto. SECTION 4D: COST STRUCTURE AND REVENUE SOURCES As shown in Figure 2, electric commodity purchases accounted for roughly 55% of the Electric Utility’s costs in FY 2015. Operational costs represented roughly 31%, and capital investment was responsible for the remaining 10%. CPAU’s non­hydro long­term commodity supply is heavily dependent on long­term contracts which have little variability in price. On average, costs for these long­term 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. Commodity supply costs are projected to be roughly 47% of total costs in FY 2023. 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 costs under high, average, and low hydroelectric generation scenarios. Additional costs associated with a very low generation scenario can range from $10­12 million per year. For the current hydroelectric risk assessment see Section 5F: Risk Assessment and Reserves Adequacy. As shown in Figure 4 the Electric Utility receives 87% 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, and other sources. Some revenue sources are primarily accounting entries that reflect things such as CPAU’s participation in a pre­funding program associated with its contract with WAPA, as well (SGY7MKR)RZIPSTI-(%%*(%%'*(* 14 | P a g e as accounting entries associated with occasional sales of surplus hydroelectric energy during wet years. Without these entries sales revenues represent roughly 93% of total 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 800 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 25% of the utility’s revenue comes from peak demand charges on large commercial 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. It also maintains two funds, the Supply Fund and the Distribution Fund, to manage costs associated with electricity supply and electricity distribution, respectively. This separation of supply and distribution costs was established as the City prepared to allow its customers a choice of electricity providers (referred to as “Direct Access”) back 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 in case California ever decides to 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 various reserves are summarized below, 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, Proposed Change). 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 California­Oregon 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. (SGY7MKR)RZIPSTI-(%%*(%%'*(* 15 | 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. 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[AmyB2]. Any funds not expended in the current year are added to the Public Benefits Reserve for use in futureyears. 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 one­time expenditures. This type of reserve is used in other utility funds (Electric, Gas, andWastewater 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 2015 was $513.17 under current CPAU rates, 36% lower than the annual bill for a PG&E customer with the same consumption and 9% lower 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 January 1, 2016. Note that rates for PG&E customers increased substantially on that date, and with rates currently in effect, the bill for the median residential user is roughly 45% below PG&E’s rates. (SGY7MKR)RZIPSTI-(%%*(%%'*(* 16 | P a g e 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, 2016 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 1/1/16, $/mo) Season Usage (kwh)Palo Alto PG&E Santa Clara Winter (December) 300 28.57 54.45 34.16 (Median) 453 48.49 88.39 52.21 650 76.33 142.09 75.47 1200 172.03 333.61 140.38 Summer (July) 300 28.57 54.45 34.16 (Median) 330 32.48 62.05 36.65 650 76.33 148.02 75.47 1200 172.03 339.84 140.38 Table 7 shows the average monthly electric bill for commercial customers for various usage levels. Bills for small commercial customers in Palo Alto are 37% below what they would be in PG&E territory and 20% below what they would be in Santa Clara (Silicon Valley Power). For large commercial customers, rates are 30% to 35% below PG&E’s and are 4% to 10% lower than Santa Clara’s. Even with the proposed rate increases, Palo Alto’s commercial bills will remain substantially below PG&E’s, and below Santa Clara’s for most commercial customers. Table 7: Commercial Monthly Electric Bill Comparison (1/1/16, $/mo) Usage (kwh/mo) Palo Alto PG&E Santa Clara 1,000 134 212 167 160,000 18,364 27,221 19,228 500,000 43,319 66,152 47,913 2,000,000 216,594 311,640 234,322 SECTION 5: UTILITY FINANCIAL PROJECTIONS SECTION 5A: LOAD FORECAST Figure 5 shows a 40­year history of Palo Alto electricity consumption. Average electricity consumption grew from 1986 to 1998, then returned to 1986 levels by 2002. Since then (SGY7MKR)RZIPSTI-(%%*(%%'*(* 17 | P a g e 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. Figure 5: Historical Electricity Consumption Figure 6 shows the forecast of electricity consumption through FY 2023, as well as what electricity consumption would have been without energy efficiency rebates, appliance efficiency standards, stricter building codes, and rooftop solar photovoltaic (PV) generation. The forecast assumes that current trends continue and sales through the forecast period decline slightly. As of the end of December 2015, net metered PV installations in Palo Alto provided roughly 1% of the total electricity consumed in the City. The Council­adopted Local Solar Plan’s goal is to increase the energy generated by local solar to 4% of the City’s needs by 2023. (SGY7MKR)RZIPSTI-(%%*(%%'*(* 18 | P a g e Figure 6: Forecasted Electricity Consumption SECTION 5B: FY 2009 TO FY 2015 COST AND REVENUE TRENDS The annual expenses for the Electric Utility declined between FY 2009 and FY 2012, as shown in Figure 7 and the tables in Appendix A: Electric Utility Financial Forecast Detail . These decreases were partly related to declines in electricity market prices due to the impact of shale gas and partly due to above average output from hydroelectric resources. These factors are discussed in more detail in Section 6A: Electricity Purchases. Since FY 2012, total expenses for the utility have been increasing as renewable resources come online. In FY 2014 through FY 2015 costs were higher due to lower than average output from hydroelectric resources. Commodity costs are responsible for most of the changes in the utility’s expenses over the last six years. Operational costs and capital investment increased at less than 1% per year over that time. (SGY7MKR)RZIPSTI-(%%*(%%'*(* 19 | P a g e Figure 7: Electric Utility Expenses, Revenues, and Rate Changes: Actual Costs through FY 2015 and Projections through FY 2023 SECTION 5C: FY 2015 RESULTS In spring of 2014 staff recommended no rate change for July 1, 2014, the start of FY 2015. Although staff forecast a $5.7 million deficit for FY 2015 without a rate change, reserves were adequate to absorb this deficit. However, drought conditions worsened in the spring of 2014 and continued through the winter of 2014/2015, resulting in a deficit of $17.0 million for FY 2015. The increased deficit was entirely related to the low output from hydroelectric resources, which necessitated electricity market purchases to replace the lower than expected hydroelectric energy. SECTION 5D: FY 2016 PROJECTIONS In spring of 2015, staff recommended (and Council approved) no rate change for July 1, 2015, the start of FY 2016. Based on hydroelectric conditions at the time, staff forecasted a $10.3 million deficit for FY 2016. This deficit was primarily related to low hydroelectric output, and was to be funded from the Operations and Hydroelectric Stabilization reserves. Staff’s current (SGY7MKR)RZIPSTI-(%%*(%%'*(* 20 | P a g e forecast for FY 2016 is for a deficit of $20.1 million, $9.8 million more than forecasted in spring of 2015. This change is mainly related to two factors: 1) capital improvement program costs have increased by roughly $7 million, and 2) energy costs have increased by roughly $3 million due to continuing drought and resulting low hydroelectric generation. The $7 million increase in CIP costs is largely relatedto the delay of projects from previous fiscal years to FY 2016 rather than mid­year adjustments requesting new funding. Staff proposes partially funding this portion of the deficit using a $5.6 million transfer from the CIP Reserve, which contains $8.4 million collected in previous fiscal years to fund capital projects. The additional $3 million related to energy costs would be funded from the Hydroelectric Stabilization Reserve. These transfers are discussed in Section 3D: Proposed Reserve Transfers. SECTION 5E: FY 2017 – FY 2023 PROJECTIONS As shown in Figure 7 above, costs for the Electric Utility are projected to increase in FY 2017 and level off in subsequent years. Revenues will have to increase 11% in FY 2017 and another 10% in FY 2018 to keep up with these cost increases. The increases are primarily related to electricity purchase costs, which have been increasing since FY 2013 and will continue to increase through FY2018 as new renewable projects come online to fulfill the City’s environmental goals and as transmission costs increase. Operations costs are expected to increase substantially in FY 2017 to begin catching up on deferred maintenance, but subsequently are expected to increase at or below the inflation rate (2­3 %/year) through the forecast period. Projected capital expenses for FY 2017 through FY 2023 are $30 million higher than last year’s forecast due mostly to several large one­time projects, some customer driven, but also due to an increase in spending on system improvements. The increased costs are partially offset by $13.4 million in revenue from reimbursements associated with those projects. Aside from those one­time costs, capital expenses are projected to increase in FY 2017 and then stay roughly level through the forecast period. This forecast also assumes that smart grid costs are funded from the Electric Special Projects Reserves. Reserves trends based on these revenue projections are shown in Figure 8 (for Supply Fund reserves) and Figure 9 (for Distribution Fund reserves), below. The Supply Rate Stabilization Reserve is projected to be empty by the end of FY 2016. Assuming the projected increases in revenue, the Distribution Operations reserve will remain adequate through the forecast period, comfortably above minimum levels and adequate to meet all identified risks. The Supply Operations Reserve, however, is forecasted to be below minimum levels. This is discussed in more detail in Section 5F: Risk Assessment and Reserves Adequacy. With respect to the Hydro Stabilization Reserve, these projections assume average rainfall next winter, although hydro generation is still predicted to be below average due to low reservoir levels. The current forecast does not take into account potential rainfall associated with El Niño conditions in the spring of 2016, nor potential drought in the 2016/2017 year, which may follow the El Niño conditions of 2016. This scenario may help reserves, hurt reserves, or have little net effect depending on the associated rainfall levels. (SGY7MKR)RZIPSTI-(%%*(%%'*(* 21 | P a g e Figure 8: Electric Utility Reserves (Supply Fund): Actual Reserve Levels through FY 2015 and Projections through FY 2023 Figure 9: Electric Utility Reserves (Distribution Fund): Actual Reserve Levels through FY 2015 and Projections through FY 2023 (SGY7MKR)RZIPSTI-(%%*(%%'*(* 22 | P a g e SECTION 5F: RISK ASSESSMENT AND RESERVES ADEQUACY The Electric Utility currently has two contingency reserves, the Supply Operations Reserve and the Distribution Operations Reserve. This Financial Plan maintains reserves in excess of the reserve minimum for the Distribution Operations Reserve throughout the forecast period. Reserve levels also exceed the short­term risk assessment level for the Distribution Fund. The Supply Operations Reserve, however, may end up below minimum levels and below the short­ term risk assessment level. There are a variety of risks associated with the Supply Fund as are shown in Table 8. 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 of these adverse scenarios occurring simultaneously and to the degree described in Table 8 is very low. Table 8: Electric Supply Fund Risk Assessment Categories of Electric Supply Cost Uncertainties Estimates of Adverse Outcomes (M$) Notes FY 2017 FY 2018 1. Load Net Revenue 1.2 1.3 Revenue loss from load decreases (net of reduction in energy purchases) 2. Production from Hydroelectric Resources: Western & Calaveras 3.4 2.4 Lower than forecasted hydro 3. Renewable Production: Landfill & Wind 0.5 2.1 Additional cost of renewable output that is higher than forecasted 4. Carbon Neutral Cost 0.1 ­ Higher than forecasted market prices for RECs 5. Market Price (Energy) 1.1 0.5 Higher than forecasted market prices for energy 6. Local Capacity 0.4 0.7 Higher than forecasted market prices for local capacity 7. Transmission/CAISO 2.8 3.0 High­end transmission forecast scenario 8. Plant Outage 1.0 1.0 Uninsured losses from Calaveras plant outage 9. Western Cost 3.0 3.5 Risk of rate adjustments from Western Electric Supply Fund Risks $13.6 million $14.3 million Projected Supply Operations + Hydro Stabilization Reserve Levels $16.4 million $12.8 million Of the risks faced by the Electric Utility’s Supply Fund in FY 2016, 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. However, for FY 2017 and FY 2018, lower than average hydroelectric output is already expected, so the adverse risk is smaller than usual. Risks associated with hydroelectric output account for $3.4 million (25%) of FY 2017 contingencies. (SGY7MKR)RZIPSTI-(%%*(%%'*(* 23 | P a g e Of the remaining risks for FY 2017, $2.8 million (20%) is related to the projected costs if transmission cost increases are higher than staff’s current forecast. Another $3.0 million (22%) is related to the possibility of drought­related changes to Western rates for CVP hydropower, and $1.1 million (8%) is related to fluctuations in market prices for capacity, energy, and RECs. As shown in Figure 10, the Supply Operations Reserve will drop below the minimum reserve guidelines by as much as $3.9 million over the course of the forecast period. In addition, as shown in Figure 11, the combined hydro stabilization and supply operations reserves will drop below the risk assessment level. It is acceptable under the Electric Utility Reserves Management Practices to drop below minimum reserve guidelines so long as Council approves the Financial Plan. Staff recommends proceeding with this plan for two reasons: first, due to the presence of a strong El Niño condition in the Pacific Ocean, there is a chance of high spring rains that may change this forecast, resulting in higher reserves, and second, the presence of the $51 million Electric Special Projects Reserve means that a small temporary shortfall in the Supply Operations Reserve should not affect the Electric Utility’s bond ratings. In the event drought continues, staff will re­evaluate its projections for FY 2018 and may recommend additional rate increases or the adoption of a hydroelectric rate adjuster. Figure 10: Electric Supply Operations Reserve Adequacy (SGY7MKR)RZIPSTI-(%%*(%%'*(* 24 | P a g e Figure 11: Adequacy of Supply Operations and Hydro Stabilization Reserves, Combined Table 9 summarizes the risk assessment calculation for the Distribution Operations Reserve through FY 2021. As shown in Figure 12, the Distribution Operations Reserve will stay within the reserve guidelines 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 expendituresfor the budget year. Table 9: Electric Distribution Fund Risk Assessment ($000) FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 Total non­commodity revenue $49,651 $52,233 $52,275 $52,237 $53,804 Max. revenue variance, previous ten years 8% 8% 8% 8% 8% Risk of revenue loss $3,919 $4,122 $4,126 $4,123 $4,246 CIP Budget $27,652 $22,058 $26,649 $15,868 $16,320 CIP Contingency @10%$2,765 $2,206 $2,665 $1,587 $1,632 Total Risk Assessment value $6,684 $6,328 $6,791 $5,710 $5,879 (SGY7MKR)RZIPSTI-(%%*(%%'*(* 25 | P a g e Figure 12: Electric Distribution Operations Reserve Adequacy As shown in Figure 13, the CIP Reserve is projected to be well within the proposed revised minimum and maximum guidelines over the forecast period. While the Reserve is above maximum levels in later years, CIP Commitments are nearly impossible to project that far out, and adjustments to the reserve can be made in future years. (SGY7MKR)RZIPSTI-(%%*(%%'*(* 26 | P a g e Figure 13: Electric Distribution Operations Reserve Adequacy SECTION 5G: LONG ­TERM OUTLOOK This forecast covers the period from FY 2017 through FY 2023, but various long­term developments may create new costs for the utility over the next 5 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 long­term planning purposes. For the supply portfolio, the 2020s will see a number of notable events. The contract with Western for power from the CVP will expire in 2024. Determining the future 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 carbon­free electricity. The utility’s three earliest and lowest cost renewable contracts will also begin expiring around that time, with the first contract expiring in 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 megawatt­hour (MWh). It is difficult to know what renewable energy prices will be when those (SGY7MKR)RZIPSTI-(%%*(%%'*(* 27 | P a g e 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 no new debt is issued). 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 low­cost asset for the utility, providing carbon­free energy equal to 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 cap­and­trade program. It uses that revenue to pay for energy efficiency and to purchase renewable energy to support the utility’s Carbon Neutral Plan. That revenue source is expected to continue through 2020, but there is no provision for the continuation of these allocations past 2020. If the Electric Utility no longer received these allowances, 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 will also begin the rollout of various smart grid technologies. The utility continues to monitor the growth of electric vehicle ownership and gas­to­electric 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 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 long­term planning processes, but will need to continue to incorporate them into its planning methodologies. (SGY7MKR)RZIPSTI-(%%*(%%'*(* 28 | P a g e Looking out toward 2050 and beyond, if the State were to adopt climate goals consistent with Executive Orders S­3­05 and B­16­2012 (with a goal of reducing GHG emissions to 80 percent below 1990 levels by 2050), or if similar (or more aggressive) local goals were adopted, 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. Initial analysis of these types of scenarios is being undertaken 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 did not end up overloaded, or conversely, to avoid overinvestment. (SGY7MKR)RZIPSTI-(%%*(%%'*(* 29 | P a g e SECTION 6: DETAILS AND ASSUMPTIONS SECTION 6A: ELECTRICITY PURCHASES As shown in Figure 14 the utility gets roughly 50% of its energy from hydroelectric projects in a normal year (FY 2014 and FY2015 were dry). Contracts with renewable sources made up just over 20% of the portfolio in FY 2015, and are projected to rise to roughly 50% in FY 2017. The remainder comes from unspecified market sources. Under the City’s Carbon Neutral Plan, CPAU purchases RECs corresponding to the amount of market energy it purchases. Figure 14: Electricity Supply by Source (SGY7MKR)RZIPSTI-(%%*(%%'*(* 30 | P a g e Figure 15 shows the historical and projected costs for the electric supply portfolio,4 as well as average and actual hydroelectric generation.5 Electric supply costs decreased in FY 2010 and FY 2011 due to decreases in market prices related to shale gas. In addition, FY 2009 was a dry year with low hydroelectric production, so FY 2010 and FY 2011 looked better by comparison. Costs increased in FY 2013, FY 2014, and FY 2015 due to the drought, which reduced the amount of generation from hydroelectric resources. Costs are projected to decrease slightly in FY 2016 due to slightly higher hydroelectric generation, and may decrease substantially depending on rainfall. Even if hydroelectric generation returns to normal levels, costs will increase in FY 2017 due to increases in renewable energy costs as various renewable projects come online to fulfill the City’s carbon neutral and RPS goals. Transmission charges are also projected to increase as new transmission lines are built throughout California to accommodate new renewable projects. In total, electric supply costs are projected to increase to $75.2 million by FY 2018, at which point all currently contracted renewable projects will be online. Supply costs are only projected to change slightly in subsequent years. 4 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). 5 Average hydroelectric generation increased in January of 2015 due to an increase in the utility’s contractual share of the output of the CVP Federal hydropower project. (SGY7MKR)RZIPSTI-(%%*(%%'*(* 31 | P a g e Figure 15: 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 ResourceManagement Appendix C: Description of Electric utility Operational Activities includes detailed descriptions of the work associated with each of these activities. (SGY7MKR)RZIPSTI-(%%*(%%'*(* 32 | P a g e From FY 2009 to FY 2015, Operations costs increased by $2.2 million, or less than 1% per year on average. In 2013 there was a one­time increase in expenses associated with an adjustment to the value of the City’s investment portfolio. Excluding debt service and transfers, which stay relatively stable over time, costs increased roughly 2.5% per year over that time. In FY 2016, however, Operations costs increased $4.5 million (9.6%). This was primarily due to increases in overhead and salary and benefit costs. Operations costs are projected to increase by an additional $1M per year starting in FY 2017 as work is done to begin catching up on deferred maintenance that has accumulated due to difficulty filling certain maintenance positions. Aside from those increases, costs are projected to increase with inflation over the remainder of the forecast period. Figure 16: Historical and Projected Electric Utility Operational Costs SECTION 6C: CAPITAL IMPROVEMENT PROGRAM (CIP) CIP spending for FY 2017 through FY 2019 is projected to increase substantially, primarily due to major one­time projects, including service connection upgrades for a few major customers, pole replacements related to the Fiber to the Home project, and Smart Grid upgrades. Ongoing capital investment in the electric distribution system is also increasing. The one­time projects will mostly be funded by customer­specific fees and transfers from other funds. Only $3.4 million of the funding for the one­time projects is projected to come from utility rates. This forecast assumes that smart grid projects are financed from the Electric Special Projects (SGY7MKR)RZIPSTI-(%%*(%%'*(* 33 | P a g e Reserve and with additional funding from the water and gas funds, but it would also be possible to usebond financing. Excluding the one­time projects listed above, the CIP plan for FY 2017 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 2017 Utilities Capital Budget. Figure 16 shows the adopted / proposed / projected capital budgets as well as actual and projected capitalized administrative overhead associated with the program. Figure 17: Electric Utility CIP Spending SECTION 6D: 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 Electric 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 Electric Utility receives the RECs from these (SGY7MKR)RZIPSTI-(%%*(%%'*(* 34 | P a g e 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 service for this bond continues through 2021, and for the financial forecast period is as follows: Table 10: Electric Utility Debt Service ($000) FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 2007 Clean Renewable Energy Bonds 100 100 100 100 100 100 ­ ­ 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 Error! Reference source not  found..[AmyB3] The Electric Utility’s reserves and net revenue are also pledged as security for the bond issuances listed in Table 11, 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 foreseethis occurring. Table 11: Other Issuances Secured by Electric Utility’s Revenues or Reserves Bond Issuance Responsible Utilities Annual Debt Service ($000) Secured by Electric Utility’s: Net Revenues Reserves 1995 Utility Revenue Bonds, Series A Storm Drain $680 Yes No 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 SECTION 6E: EQUITY TRANSFER The City calculates the equity transfer from its Electric Utility based on a rate of return on the net book value of the utility’s capital assets. The Council adopted this methodology adopted by Council in 2009, and which it has remained unchanged since 6. Each year it is calculated 6 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. (SGY7MKR)RZIPSTI-(%%*(%%'*(* 35 | P a g e according to the 2009 Council­adopted 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 12% comes from other sources. Of these other sources, about a third represent wholesale “revenues” that is 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 services, and carbon allowance revenues associated with the State’s cap­and­trade program. In FY 2015 these sources represented roughly 50% of revenue from sources other than electricity sales. The remaining FY 2015 revenues consisted of a variety of one­time transfers. Revenues from connection fees have more than doubled since FY 2009. Revenue from these sources decreased slightly during the recession, but has increased substantially since then, peaking in FY 2014. Staff is forecasting slightly lower revenue from this source in subsequent years. Carbon allowance revenues are projected to stay stable through the forecast period, as is interest income. However, both of these revenue sources are subject to some uncertainty. The State’s cap­and­trade 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 post­2020 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 decreased (due to drought or a withdrawal from the ESP reserve for a major project), interest income would decrease. SECTION 6G: SALES REVENUES Sales revenue projections are based on the load forecast in Section 5A: Load Forecast and the projected rate changes shown in Figure 7. As discussed in Section 5A, 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. (SGY7MKR)RZIPSTI-(%%*(%%'*(* 36 | P a g e SECTION 7: COMMUNICATIONS PLAN 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.The FY 2017 Electric Utility communications strategy covers these primary areas: rates, drought impacts, efficiency, renewables, operations, infrastructure and safety. In FY 2017, CPAU is proposing an 11% increase in electric utility rates. Electric utility rates have not increased since 2009, as the City has been drawing down reserves from the Electric Fund. The rate increase is necessary this year, as these reserves are below the minimum reserve level. Communications will focus on the reasons why a rate increase is necessary, and why the percentage increase is higher than projected in past financial forecasts, particularly due to the impact of the drought. Palo Alto purchases a significant portion of its electricity from hydroelectric resources. Severe drought conditions over the past few years have reduced available hydroelectric supplies, requiring the City to purchase more costly replacement electric supplies. Reliability and safety are primary concerns for CPAU and City Council has placed increasing emphasis on capital improvement investments for utility infrastructure. In order to maintain system integrity, continued capital improvement costs are necessary. Deferring such costs to future years would not be prudent, as deferred investment in maintenance, operations and capital improvement upgrades could potentially jeopardize the safety and reliability of the electric utility system. Despite these costs and increasing rates, CPAU’s rates are far lower than PG&E’s. Keeping costs low is one of the benefits CPAU offers its customers as a public utility provider. CPAU will continue to communicate about 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 long­term energy security and commitment to sustainability. Recent power purchase agreements have allowed CPAU to procure long­term renewable electric supplies at low costs. CPAU will highlight these environmental attributes and value in our communications. Throughout the year, communications staff promotes CPAU’s electric efficiency services, rebates and local renewable energy programs. Since January 2015, CPAU has been encouraging community participation in the Georgetown University Energy Prize competition, a friendly, national campaign for energy efficiency. This two­year campaign encourages the community to reduce energy use and compete for a $5 million prize. Just recently, CPAU launched new programs that will allow customers to better understand and manage their energy use. Such programs include a free utility bill analysis service with option for a subsidized in­depth home energy assessment, and an online utility portal for customers to view consumption history, learn about efficiency tips and CPAU programs they can take advantage of for home energy efficiency. (SGY7MKR)RZIPSTI-(%%*(%%'*(* 37 | P a g e APPENDICES Appendix A: Electric Utility Financial Forecast Detail Appendix B: Electric Utility Reserves Management Practices Appendix C: Description of Electric utility Operational Activities Appendix D: Samples of Recent Electric Utility Outreach Communications (SGY7MKR)RZIPSTI-(%%*(%%'*(* 6053706 APPENDIX A: ELECTRIC UTILITY FINANCIAL FORECAST DETAIL (SGY7MKR)RZIPSTI-(%%*(%%'*(* 6053706 (page intentionally left blank) (SGY7MKR)RZIPSTI-(%%*(%%'*(* DocuSign E 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 r 58 59 60 61 62 60537 nvelo pe ID: 8A4 AF1DA-6454-453A-BC9F-535546D6739F ill ELECTRIC LOAD Purchases (M Wh) Sale s (MWh) 1,040,851 995,811 1,019,788 965,048 978,833 946,518 969,519 942,562 976,319 946,841 980,894 950,784 979,005 936,773 977,292 946,996 993,844 963,035 997,125 966,215 998,260 967,314 997,531 966,608 997,596 966,670 999,464 968,481 986,864 956,271 BILL A ND RAT E CHA NGES System Average Rate ($/kWh) Change in System Av erage Rate Change in Average Residential Bill $ 0.1048 $ 0.1155 10% 11% $ 0 .1168 1% -5% $ 0.1156 -1% -1% $ 0 .1154 0% -4% $ 0.1164 1% -1% $ 0.1158 0% -5% $ 0 .1158 0% 10% $ 0.1274 11% 8% $ 0.1398 10% 10% $ 0.1435 3% 2% $ 0.1435 0% 0% $ 0 .1452 1% 1% $ 0.1452 0% 0% $ 0.1477 2% 1% 'STARTIN G R ESERV ES Reappropriations (Non-CIP) - - 2,760,000 343,000 1,886,000 305,000 - - - - - - - - - Commitments (Non-CIP) 2,241,000 1,916,000 1,463,000 1,593,000 2,737,000 3,528,000 3,164,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 Restricted for De bt Se rv ice - - - - - - - - - - - - - - - Emergency Plant Replacement 3,057,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 - - - - - - - - Central Valley Pro je ct Re se rve 22,000 153,000 306,000 305,000 314,000 313,000 329,000 - - - - - - - - Unde rground Loan Rese rve 709,000 717,000 731,000 736,000 742,000 738,000 734,000 730,000 730,000 730,000 730,000 730,000 730,000 730,000 730,000 Public Benefits Reserv es 2,109,000 4,280,000 3,750,000 3,139,000 1,149,000 2,197,000 2,064,000 2,574,000 2,700,394 2,790,356 2,799,046 2,717,399 2,544,810 2,434,376 2,373,578 Electric Special Projects Reserve 70,397,000 64,535,000 59,865,000 55,558,000 50,320,000 51,838,000 51,838,000 51,838,000 51,534,944 51,383,460 51,050,127 47,300,127 47,300,127 47,300,127 47,300,127 Hydro Stabilization Re se rve - - - - - - - 17,000,000 11,400,000 2,400,000 - - - - - Capital Reserves - - - - - - - - 2,864,000 2,864,000 2,864,000 2,864,000 2,864,000 2,864,000 2,864,000 Rate Stabilization Reserves 55,418,000 47,783,000 54,339,000 66,331,000 74,609,000 69,029,000 70,049,000 14, 411,000 5,411,000 - - - - - - Operations Rese rves - - - - - - - 22,498,000 22,733,825 22,014,607 22,281,475 24,814,237 27,032,576 30,783,222 34,269,008 Unassigned - - - - - - - - - - 0 - - - - TOTAL STARTING RESERVES 133,953,000 120,384,000 124,214,000 129,005,000 132,757,000 128,948,000 129,178,000 112,153,000 100,476,163 85,284,424 82,826,649 81,527,763 83,573,514 87,213,725 90,638,713 I REV ENUES Net Sales 105,312,712 113,129,269 111,948,267 109,309,318 109,974,337 110,301,711 108,674,986 109,644,507 122,721,963 135,111,161 138,828,086 138,726,658 140,313,744 140,576,542 141,259,300 Who les ale Revenues 10,618,388 7,903,940 8,443,016 7,189,218 6,635,790 6,010,409 6,267,000 6,763,000 11,732,580 13,249,634 14,128,345 15,816,411 16,063,130 15,367,103 15,992,486 O ther Revenues and Transfers In 11,744,330 8, 458,392 6,374,799 6,316,048 8,736 ,976 9,772,185 8,379,507 8,315,879 17,306 ,372 13,685,157 104,331 8,952,387 9 ,297,064 9,706,437 10,042,027 TOTAL REVENUES 127,675,429 129,491,602 126,766,082 122,814,584 125,347,103 126,084,305 123,321,493 124,723,385 151,760,915 162,045,951 169,060,763 163,495,456 165,673,937 165,650,082 167,293,813 I EX PENSES Electric Supply Purchases 82,348,075 68,714,475 61,247,248 58,724,136 61,313,637 68,785,977 80,022,010 75,705,000 86,377,737 88,523,524 89,131,094 90,303,886 89,637,135 88,542,665 89,918,517 Operating Expenses Administration Alloca te d Cha rges 3,585, 068 2,667,704 2,807,991 3,416,423 4,399,674 4,139 ,837 4,511,222 3,651,896 3 ,743,559 3,837,533 3,933,853 4,032,597 4,133,584 4,236,960 4,342,932 Rent 3,428,294 3,963,377 3,721,542 3,839,201 3,875,836 4,051,044 4,147,742 4,991,328 5,141,068 5,295,300 5,454,159 5,617,784 5,786,317 5,959,907 6,138,704 De bt Service 8,185,819 7,919,136 7,343,352 8,902,751 9,265, 736 9,020,651 9,037 ,000 9,139,768 8,953,886 8 ,955,164 8,808,619 8,818 ,349 8,783 ,507 8,792,388 9,624,493 Trans fers a nd Othe r Adju stme nts 13, 282, 668 10,860,269 13, 056,927 11, 603,695 16,797,054 11,385 ,421 10,789,119 11.,778,415 11 ,781,400 11,784 ,460 11 ,787 ,597 11,790,812 11 ,794 ,107 11,797,485 11,800 ,947 Subtotal, Administratio n 28,481,848 25,410,486 26,929,812 27,762,069 34,338,299 28,596,953 28,485,082 29,561,407 29,619,914 29,872,457 29,984,228 30,259,541 30,497,516 30,786,740 31,907,076 Resource M anagement 2,062,511 3,033,428 2,380,313 2,654,024 3,024,268 3,541,524 2,138,615 2,966,005 3,071,752 3,182,092 3,295,330 3,413,039 3,513,915 3,605,059 3,699,533 De mand Side Manageme nt 3,336,356 4,048,114 3,490,676 4,541,531 3,529,529 3,187,875 3,491,470 4,476,424 3,612,447 3,694,961 3,558,989 3,275,399 3,213,446 3,169,620 3,251,901 O perations and Mtc 8,975,462 8,892,002 9,339,340 9,288,490 9,601,481 9,488,627 10,716,881 12,216,961 13,621,453 14,075,224 14,540,523 15,022,687 15,450,353 15,847,643 16,258,382 Engineering (Operating) 879,303 1,094,766 1,070,441 1,057,783 1,114,945 1,102,008 1,230,160 1,929,843 1,981,771 2,035,192 2,089,931 2,146,191 2,201,598 2,257,007 2,313,920 Customer Service 1,650,731 1,896,956 1,881,881 1,908,493 2,007,322 2,032,231 1,548,851 2,348,349 2,436,928 2,529,629 2,624,844 2,724,064 2,806,984 2,880,302 2,956,458 Allowance for Unspent Bu dge t - - - - - - - (1,328,747) (1,421,462) (1,467,484) (1,514,688) . (1,563,571) (1,607,504) (1,648,717) (1,691,289) Subtotal, Operating Expenses 45,386,213 44,375,751 45,092,464 47,212,389 53,615,844 47,949,218 47,611,059 52,170,242 52,922,803 53,922,071 54,579,157 55,277,350 56,076,307 56,897,655 58,695,982 Capital Program Contributio n 13,510, 141 12,571, 376 15,635, 370 13,126,059 14,226,622 9,119, 111 12,713,425 16,988,980 27,652,114 22,058,131 26,649,398 15,868,470 16,320,285 16,784,774 17,262,590 TOTAL EXPENSES 141,244,429 125,661,602 121,975,082 119,062,584 129,156,103 125,854,305 140,346,493 144,864,222 166,952,654 164,503,726 170,359,649 161,449,705 162,033,726 162,225,093 165,877,088 I ENDING RESERV ES Reappropriations (Non-CIP) - 2,760,000 343,000 1,886,000 305,000 - - - - - - - - - - Co mmitments (Non-CIP) 1,916,000 1,463,000 1,593,000 2,737,000 3,528,000 3,164,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 3,102,000 Restricted fo r Debt Se rvice - - - - - - - - - - - - - - - Emergency Plant Replacement 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 - - - - - - - - - Central Valley Project Reserve 153,000 306,000 305,000 314,000 313,000 329,000 - - - - - - - - - Underground Lo an Re se rv e 717,000 731,000 736,000 742,000 738,000 734,000 730,000 730,000 730,000 730,000 730,000 730,000 730,000 730,000 730,000 Public Benefits Reserves 4,280,000 3,750,000 3,139,000 1,149,000 2,197,000 2,064,000 2,574,000 2,700,394 2,790,356 2,799,046 2,717,399 2,544,810 2,434,376 2,373,578 2,191,308 Electric. Special Projects Reserve 64,535,000 59,865,000 55,558,000 50,320,000 51,838,000 51,838,000 51,838,000 51,534,944 51,383,460 51,050,127 47,300,127 47,300,127 47,300,127 47,300,127 47,300,127 Hydro Stabiliz ation Reserve - - - - - - 17,000,000 11,400,000 2,400,000 - - - - - - Capital Reserve - - - - - - - 2,864,000 2,864,000 2,864,000 2,864,000 2,864,000 2,864,000 2,864,000 2,864,000 Rate Stabilization Reserve 47,783,000 54,339,000 66,331,000 74,609,000 69,029,000 70,049,000 14,411,000 5,411,000 - - - - - - - Operations Reserve - - - - - - 22,498,000 22,733,825 22,014,607 22,281,475 24,814,237 27,032,576 30,783,222 34,269,008 35,868,004 Unassigned - - - - - - - - - 0 - - - - - TOTAL ENDING RESERVES 120,384,000 124,214,000 129,005,000 132,757,000 128,948,000 129,178,000 112,153,000 100,476,163 85,284,424 82, 826,649 81,527,763. 83,573,514 87,213 ,725 90,638,713 92,055,438 AmyB4] DOcuSign Envelo pe ID: 8A4 AF1 DA-6454-453A-8C9F-535546D6739F 2 FY 2010 FY 2011 FY 2012 FY 2013 FY 2.014 FY 201511 FY O16 Y 201L FY 2038 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023_1 3 I REVEN UES 4 Net Sales 5 Other Rev enue s and Transfers In 6 TOTAL REVENUES 7 8 EXPEN SES 9 Commodity Purchases 82% 87°7° 88% 89% 88% 87% 88% 88% 81% 83% 82% 85% 85% 85% 84% 18% 13% 12% 11% 12% 13% 12% 12% 19% 17% 18% 15% 15% 15% 16% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 56% 54% 46% 47% 46% 56% 51% 46% 46% 45% 47% 47% 47% 46% 10 Operating Expense s 11 A dministr ation 12 Allocate d Cha rges 3% 2% 2% 3% 3% 3% 3% 3% 2% 2% 2% 2% 3% 3% 3% 13 Rent 2% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 3% 4% 4% 4% 14 D ebt Service 6% 6% 6% 7% 7% 7% 6% 6% 5% 5% 5% 5% 5% 5% 6% 15 Transfers an d Oth er A djustments 9% 9% 11% 10% 1 8% 88 % 7% 7°7 ° 7% 7% 7 , 7% 7% 16 Subto tal, Administration 20% 20% 22% 23% 27% 23% 20% 20% 18% 18% 18% 19% 19% 19% 19% 17 Resource Manage ment 1% 2% 2% 2% 2% 3% 2% 2% 2% 2°/n 2% 2% 2% 2% 2% 18 Operations and Mtc 6% 7% 8% 8% 7% 8% 8% 8% 8% 9% 9% 9% 10% 10% 10% 19 Engineering (Operating) 1% 1% 1% 1% 1% 1% 1% 1% 1% 1% 1% 1% 1% 1% 1% 20 Custo mer Service 1% 2% 2% 2% 2% 2% 1% 2% 1% 2% 2% 2% 2% 2% 2% 21 Allowance for Unspent Budget 0% 0% 0% 0% 0% 0% 0% -1% -1% -1% -1% -1% _1% -1% -1% 22 Subtotal, Oper ating Expe nses 30% 32% 34% 36% 39% 36% 31% 33% 30% 31% 30% 32% 33% 33% 33% 23 Capital Program Contribution 10% 10% 13% 11 °2 11% 7% 9 % 12% 17% 13% 16% 10% 10% 10% 10% 24 TOTAL EXPENSES 95% 96% 93% 93% 96% 97% 96% 95% 92% 90% 90% 89% 89% 90 % 90% 25 26 R ISK A SSESSMENT D ETAIL SUPPLY FUND 27 28 29 30 3. Renewable Production: La ndfill & Wind & Solar 31 4. Ca rbon Neutral Co st 32 5. Market Price 33 6. Local Capacity 34 7. Transmission/CAISO 35 8. Plant O utage 36 9. Western Cost 37 10. Regulatory & Legal 38 11. Supplier Default 39 TOTAL Supply Operations + Hydro Stabilization 40 Reserves, % of Risk Assessment 41 42 43 44 45 46 47 48 49 44 FY 2009 FY 2010 Jar( 20141 W FY 2012 5' 20/52111 . FY 2014. FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 1. Load Net Revenue 2. Hydro Produ ction: We stern & Calav eras RISK A SSESSMENT DETAIL DISTRIBUTION FUND 77,428 9,314,822 375,755 331,630 909,196 475,962 4,555,915 1,000,000 3,130,000 652,853 9,050,313 743,945 303,022 775,584 408,388 3,741,647 1,000,000 2,704,738 1,208,477 3,397,119 539,073 114,983 1,138,589 446,695 2,806,120 1,000,000 2,973,619 20,170,708 19,380,490 13,624,674 196% 176% 179% FY 2009 MIME Wit 202 -BM pr FY 2012 = Y 201.9 j- FY 2014 FY 2015 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 Distribution Rev enue Variance 10% CIP Program Contingency Total Risk Asssessment Value Projec ted Operation s Re serve Operations Reserve, % of Risk Value 3,240,845 1,271,343 4,512,188 22,498,000 499% 3,290,258 1,698 ,898 4,989,156 22,733,825 456% 3,918,697 2,765,211 6,683,908 22,014,607 329% 4,122,469 4,163,694 2 ,205,813 2,664,940 6,328,282 6,828,634 22,281,475 24,814,237 352% 363% 4,160,651 1 ,586,847 5,747,498 27,032,576 470% 4,285,471 1,632,028 5,917,499 30,783,222 520% 4,293,497 1,678,477 5,971,975 34,269,008 574% 4,422,302 1,726,259 6,148,561 35,868,004 583% 'SU PPLY O PERATIO NS RESERVE 45 Min (60 days of no n -capital expe nse s) 46 Target (90 days of non -capital ex penses) 47 Max (120 days of non -capital expenses) 48 49 8,339,587 6,424,305 6,557,102 6,698,857 6,808,081 6,897,553 7,013,278 7,126,792 7,248,481 10,338,923 9,636,457 9,835,653 10,048,285 10,212,121 10,346,329 10,519,917 10,690,188 10,872,721 12,338,259 12,848,609 13,114,204 13,397,714 13,616,162 13,795,105 14,026,555 14,253,584 14,496,961 'DIS TRIBUT ION O PERA TIONS RESERVE 50 M in (60 days of non -capital ex penses) 51 Target (90 days of non -capital expenses) 52 Max (120 days of non -capital ex penses) 53 Risk Assessment Value 6053706 8,339,587 6,424,305 6,557,102 6,698,857 6,808,081 6,897,553 7,013,278 7,126,792 7,248,481 10,338,923 9,636,457 9,835,653 10,048,285 10,212,121 10,346,329 10,519,917 10,690,188 10,872,721 12,338,259 12,848,609 13,114,204 13,397,714 13,616,162 13,795,105 14,026,555 14,253,584 14,496,961 4,512,188 4,989,156 6,683,908 6,328,282 6,828,634 5,747,498 5,917,499 5,971,975 6,148,561 ELECTRIC UTILITY FINANCIAL PLAN J u n e 1 6 , 2 0 1 4 42 | P a g e APPENDIX B: ELECTRIC UTILITY RESERVES MANAGEMENT PRACTICES (This section includes the proposed amendments to this section. This section will be finalized following Council adoption of the final amended version.) 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 2015to FY 2019, FY 2015to 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) 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) (SGY7MKR)RZIPSTI-(%%*(%%'*(* ELECTRIC UTILITY FINANCIAL PLAN J u n e 1 6 , 2 0 1 4 43 | P a g e 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) 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 non­capital 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 high­risk in nature; d) Projects proposed for funding must be substantial in size, requiring funding of at least $1 million; e) The preferred projects to be funded by the ESP Reserve must be identified by end of FY 2015; f) Any uncommitted funds remaining at the end of FY 2020 will be transferred to the Electric Supply Operations Reserve and the ESP Reserve will be closed; and g) Funds may be used for analysis and pilot projects which would be the basis for planned large projects. Section 7. Hydroelectric Stabilization Reserve Supply cost savings and surplus energy sales revenue associated with higher than average generation from hydroelectric resources may be added to the Electric Supply Fund’s Hydroelectric Stabilization Reserve by action of the City Council and held to offset higher (SGY7MKR)RZIPSTI-(%%*(%%'*(* ELECTRIC UTILITY FINANCIAL PLAN J u n e 1 6 , 2 0 1 4 44 | P a g e commodity supply costs during years of lower than average generation. Withdrawal of funds from the Hydroelectric Stabilization Reserve requires action by the City Council. 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 6 months of budgeted CIP expense Maximum Level 120 days 12 months 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. 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 (SGY7MKR)RZIPSTI-(%%*(%%'*(* ELECTRIC UTILITY FINANCIAL PLAN J u n e 1 6 , 2 0 1 4 45 | P a g e 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 Section 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 (SGY7MKR)RZIPSTI-(%%*(%%'*(* ELECTRIC UTILITY FINANCIAL PLAN J u n e 1 6 , 2 0 1 4 46 | P a g e 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. Intra­Utility 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. (SGY7MKR)RZIPSTI-(%%*(%%'*(* ELECTRIC UTILITY FINANCIAL PLAN J u n e 1 6 , 2 0 1 4 47 | P a g e APPENDIX C: DESCRIPTION OF ELECTR IC 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 performingemergency 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. 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