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HomeMy WebLinkAboutRESO 9595160613 jb 6053718 Resolution No. 9595 Resolution of the Council of the City of Palo Alto Approving the FY 2017 Gas Utility Financial Plan 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. The Council of the City of Palo Alto does hereby RESOLVE as follows: SECTION 1. The Council hereby adopts the FY 2017 Gas Utility Financial Plan. SECTION 2. The Council hereby approves the transfer of $1.5 million in FY 2016 from the Rate Stabilization Reserve to the Operations Reserve, as described in the FY 2017 Gas Utility Financial Plan approved via this resolution. / / / / / / / / / / // // DocuSign Envelope ID: 2B6E9E20-D99E-4CA6-86AC-57806FC2D54B 160613 jb 6053718 SECTION 3. The Council finds that the adoption of this resolution does not meet the 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: 2B6E9E20-D99E-4CA6-86AC-57806FC2D54B FY 2017 GAS UTILITY FINANCIAL PLAN FY 2017 TO FY 2026 (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 2 | P a g e GAS UTILITY FINANCIAL PLAN FY 2017 TO FY 2026 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 Reserve Proposals ........................................................ 6 Section 3A: Rate Design ............................................................................................................... 6 Section 3B: Current and Proposed Rates..................................................................................... 6 Section 3C: Bill impact of Proposed Rate Changes...................................................................... 8 Section 3D: Proposed Reserve Transfers ..................................................................................... 8 Section 4: Utility Overview.................................................................................................... 9 Section 4A: Gas Utility History..................................................................................................... 9 Section 4B: Customer Base ........................................................................................................ 10 Section 4C: Distribution System ................................................................................................. 11 Section 4D: Cost Structure and Revenue Sources...................................................................... 12 Section 4E: Reserves Structure................................................................................................... 12 Section 4F: Competitiveness ...................................................................................................... 13 Section 4G: Gas Supply Rates.................................................................................................... 14 Section 5: Utility Financial Projections ................................................................................. 15 Section 5A: Load Forecast .......................................................................................................... 15 Section 5B: FY 2011 to FY 2015 Cost and Revenue Trends ........................................................ 16 Section 5C: FY 2015 Results ....................................................................................................... 17 Section 5D: FY 2016 Projections ................................................................................................ 18 Section 5E: FY 2017­FY 2026 Projections ................................................................................... 18 Section 5F: Risk Assessment and Reserves Adequacy ............................................................... 19 (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 3 | P a g e Section 5G: Alternate Scenarios................................................................................................. 21 Section 5H: Long­Term Outlook ................................................................................................. 22 Section 6: details and assumptions ...................................................................................... 24 Section 6A: Gas Purchase Costs ................................................................................................. 24 Section 6B: Operations .............................................................................................................. 25 Section 6C: Capital Improvement Program (CIP)....................................................................... 26 Section 6D: Debt Service............................................................................................................ 28 Section 6E: Equity Transfer ........................................................................................................ 29 Section 6F: Revenues ................................................................................................................. 29 Section 6G: Communications Plan............................................................................................. 30 Appendices ......................................................................................................................... 32 Appendix A: Gas Financial Forecast Detail................................................................................ 33 Appendix B: Gas Utility Capital Improvement Program (CIP) Detail......................................... 34 Appendix C: Gas Utility Reserves Management Practices......................................................... 36 Appendix D: Description of Gas Utility Cost Categories ............................................................ 40 Appendix E: Gas Utility Communications Samples.................................................................... 41 (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 4 | P a g e SECTION 1: DEFINITIONS AND ABBREVIATIONS ABS:Acrylonitirile butydene styrene, a plastic gas main material CARB:California Air Resources Board CIP: Capital Improvement Program CNG:Compressed Natural Gas CPAU:City of Palo Alto Utilities Department CPUC: California Public Utilities Commission Cross­bore:A cross­bore exists when one utility line has been drilled or “bored” through a portion of another line. Gas cross­bores can occur in sewer lines as a result of “horizontal boring” construction practices. Distribution: transportation of gas to customers. GMR Program:Gas Main Replacement Program Local Transportation:transportation of gas to Palo Alto across PG&E’s distribution system from PG&E City Gate. Malin: a delivery hub referred to in gas purchase contracts and located in Malin, Oregon, where the northern end of PG&E’s Redwood Transmission Pipeline is located. MMBtu: Millions of British thermal units, a unit of gas measurement equal to ten therms. Commonly used for high volume gas measurement. Wholesale purchases of gas from suppliers are typically measured in MMBtu. O&M: Operations and Maintenance PE or HDPE: Polyethylene, a gas main material (more specifically, High­Density Polyethylene) PG&E:Pacific Gas and Electric PG&E Citygate, or Citygate: a delivery hub referred to in gas purchase contracts. Any gas delivered to PG&E’s distribution system (such as gas delivered at the southern end of PG&E’s Redwood Transmission Pipeline) is said to have been delivered at PG&E Citygate. PVC: Polyvinyl chloride, a plastic gas main material Summer: April 1 to October 31 Therms: The standard unit of measurement for natural gas sales to customers, equal to 100,000 British thermal units. Therms measure the heating value of the gas, rather than its volume. Transmission: transportation of gas between major gas delivery hubs via a gas transmission pipeline, such as PG&E’s Redwood pipeline. UAC: Utilities Advisory Commission, an appointed body that advises the City Council on CPAU issues. Winter: November 1 to March 31 (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 5 | P a g e SECTION 2: EXECUTIVE SUMMARY AND RECOMMENDATIONS This document presents a Financial Plan for the City’s Gas Utility for the next ten years. This Financial Plan provides revenues to cover the costs of operating the utility safely over that time while adequately investing for the future. It also addresses the financial risks facing the utility over the short term and long term, and includes measures to mitigate and manage those risks. SECTION 2A: OVERVIEW OF FINANCIAL POSITION From FY 2017 through FY 2026, non­commodity costs are projected to increase at roughly 3.5% per year. In the short term, some of these costs are related to the cross­bore inspection program, as well as cap­and­trade allowance purchase costs. In addition, capital improvement program (CIP) costs have increased as the economy has improved, and CPAU is also planning new gas main replacement projects after completing a large multi­year gas main replacement project. The Gas Utility expenses over the period of this financial plan are shown in Table 1 below. Table 1: Gas Utility Expenses for FY 2015 to FY 2026 (Thousand $’s) Expenses ($000) FY 2015 (act.) FY 2016 (est.) FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Commodity costs 10,519 9,258 12,337 13,293 13,770 14,338 14,834 15,380 16,013 16,600 17,178 17,613 Operations 18,529 19,738 21,792 22,443 23,541 23,548 24,535 25,553 26,631 27,755 28,929 30,257 Capital Projects 1,832 6,889 6,305 5,985 6,115 6,301 6,488 6,680 6,879 7,083 7,293 7,509 TOTAL 30,881 35,886 40,434 41,721 43,426 44,188 45,857 47,613 49,522 51,438 53,400 55,380 To ensure that revenues cover these rising costs, the financial plan includes the rate trajectory shown in Table 2. There was no rate increase in FY 2016 since new gas main replacement projects were not added in FY 2014 and FY 2015 in order to complete a multi­year project to replace the last of the ABS plastic mains in Palo Alto. An 8% increase is projected for FY 2017, followed by 9% and 7% increases for FY 2018 and FY 2019. An 8% increase in FY 2017 is equivalent to $2.52 per month for the median residential customer’s monthly gas bill, based on commodity prices as of February 2016. Table 2: Projected Gas Rate Trajectory for FY 2017 to FY 2026 Projection FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Current Financial Plan 8% 9% 7% 4% 1% 1% 1% 1% 1% 1% FY 2016 Financial Plan 7% 4% 4% 4% 3% 3% N/A N/A N/A N/A The Gas Rate Stabilization Reserve is used to smooth rate increases over several years. This Financial Plan projects that these reserves will be exhausted by the end of FY 2017. The Gas CIP Reserve can be used to offset one­time unanticipated capital costs. Table 3 shows the projected reserve transfers over the forecast period. (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 6 | P a g e Table 3: Transfers To/(From) Reserves for FY 2016 to FY 2026 ($000) Reserve FY 2016 FY 2017 FY 2018 to FY 2026 Rate Stabilization (1,531) (5,275)­ Operations 1,531 5,275 ­ SECTION 2B: SUMMARY OF PROPOSED ACTIONS Staff proposes the following actions for the Gas Utility in FY 2016: 1. Amend the $3.4 million transfer proposed in the FY 2016 Gas Financial Plan to $1.5 million, based on ending Operations Reserve levels. Staff proposes the following actions for the Gas Utility in FY 2017: 2. Increase rates as shown in Section 3B: Current and Proposed Rates. These changes are projected to increase rates by 8%, assuming monthly commodity prices are constant. However, should commodity prices rise, relative bill increases will be higher, and conversely lower if commodity prices should fall. 3. Transfer $5.3 million from the Rate Stabilization Reserve to the Operations Reserve. See Section 3B: Current and Proposed Rates for more details. SECTION 3: DETAIL OF FY 2017 RATE AND RESERVE PROPOSALS SECTION 3A: RATE DESIGN The Gas Utility’s rates are evaluated and implemented in compliance with cost of service requirements. The Gas Utility’s current rates are based on the methodology from the April 2012 Gas Utility Cost of Service Study completed by Utility Financial Solutions 1. Staff tentatively plans to review this cost of service study in the next year or two unless any major changes occur to the utility’s operations or customer base that would necessitate an earlier study. Before any such update, staff will review current rates and the scope of the study with the UAC and Council to determine UAC and Council policy priorities. SECTION 3B: CURRENT AND PROPOSED RATES On July 1, 2012 CPAU restructured its rates so that the commodity component varied monthly to match changes in gas market prices 2. In addition, monthly service charges were increased to recover the cost of providing gas service to customers. In January 2015, the Council adopted a new rate component to collect the costs of purchasing allowances for the purpose of compliance with the State’s cap­and­trade program 3. This component will change depending on the cost of allowances and gas demand. At the same time, two bill components (Local 1 Staff Report 2812, 5/17/ 2012 http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395 2 Staff Report 2812, 5/17/2012: http://archive.cityofpaloalto.org/civica/filebank/blobdload.asp?BlobID=31395 3 Staff Report 5397, 1/26/2015: https://www.cityofpaloalto.org/civicax/filebank/documents/45537 (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 7 | P a g e transportation and Administration) were collapsed into the Distribution rate to streamline bill presentation. CPAU has four rate schedules: one for separately metered residential customers (G­1), one for small commercial and master­metered multi­family residential customers (G­2), one for customers using over 250,000 therms per year (G­3) and a specific schedules for the Compressed Natural Gas station (G­10). All customers pay a monthly service charge, which represents meter reading, billing, and other customer service costs, as well as a portion of operations and maintenance cost. All customers are also charged for each therm of gas used. Separately metered residential customers are charged on a tiered basis, differentiated by season. During the Winter months, the first 2 therms per day (60 therms for a 30 day billing period) are charged a base price per CCF, and all additional units charged a higher price per therm. During the Summer months, the first tier level is 0.667 therms per day, or 20 therms for a 30 day billing period. Commercial customers pay a uniform price for each therm used. Table 4 shows the current and proposed monthly service charges for all rate schedules. Table 5 shows the consumption charges related to distribution charges. As mentioned earlier, commodity charges change monthly. Some recent commodity price history is discussed in Section 6A: Gas Purchase Costs. Table 4: Current and Proposed Monthly Service Charges Rate Schedule Monthly Service Charge ($/month) Change Current (7/1/12) Proposed (7/1/16) $/mo % G­1 (Residential) $9.88 $10.32 $0.44 4.5% G­2 (Small Commercial) $74.86 $78.23 $3.37 4.5% G­3 (Large Commercial) $361.18 $377.43 $16.25 4.5% G­10 (CNG) $50.65 $52.93 $2.28 4.5% Table 5: Current and Proposed Gas Distribution Charges Current (7/1/12) Proposed (7/1/16) Change $/Therm % G­1 (Residential) Tier 1 Rates 0.4392 0.5021 0.0629 14.3% Tier 2 Rates 0.9546 1.0407 0.0861 9.0% G­2 (Residential Master­Metered and Small Commercial) Uniform Rate 0.6147 0.6855 0.0708 11.5% G­3 (Large Commercial) Uniform Rate 0.6071 0.6775 0.0704 11.5% G­10 (Compressed Natural Gas) Uniform Rate 0.0509 0.0963 0.0454 89.2% [AmyB1] (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 8 | P a g e SECTION 3C: BILL IMPACT OF PROPOSED RATE CHANGES Table 6 shows the impact of the proposed July 1, 2016 rate changes on the median residential bill. The average increase is roughly 8% based on March 2016 commodity rates, but some customers may see slightly higher or lower increases due to slight changes in the composition of the utility’s costs, as well as prevailing market prices. Table 6: Impact of Proposed Gas Rate Changes on Residential Bills Usage (Therms/month) Bill under Current Rates Bill under Proposed Rates Change $/mo. % Winter (Using March 2016 commodity prices) 30 $ 29.67 $ 32.00 $ 2.33 8% 54 (median) 45.40 49.34 3.84 8% 80 72.96 78.89 5.94 8% 150 155.21 167.17 11.96 8% Summer (Using July 2015 commodity prices) 10 $ 17.70 $ 18.77 $ 1.07 6% 18 (median) 23.95 25.52 1.57 7% 30 38.49 41.05 2.56 7% 45 57.95 61.80 3.85 7% Table 7 shows the impact of the proposed July 1, 2016 rate changes on various representative commercial customer bills. Table 7: Impact of Proposed Gas Rate Changes on Commercial Bills (Using March2016 commodity prices) Usage (Therms/month) Bill under Current Rates Bill under Proposed Rates Change % G­2 (Residential Master­Metered and Small Commercial) 500 492 531 8% 5,000 4,250 4,608 8% 10,000 8,426 9,137 8% G­3 (Large Commercial) 25,000 21,049 22,825 8% 50,000 41,736 45,272 8% SECTION 3D: PROPOSED RESERVE TRANSFERS In the FY 2016 Financial Plan, several transfers between reserves were discussed for FY 2016. CIP related funds were transferred out of the Reappropriations Replacement into the CIP Reserve, and $3.4 million was proposed to be transferred from the Rate Stabilization Reserve into the Operations Reserve. (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 9 | P a g e As lower expenses in FY 2015 resulted in higher ending reserve balances than initially projected, staff recommends reducing the $3.4 million transfer from the Rate Stabilization Reserve in FY 2016 to $1.5 million, and proposes transferring $5.3 million in FY 2017. For FY 2016, staff proposes a $3.4 million transfer from the Rate Stabilization Reserve. This transfer will exhaust the Rate Stabilization Reserve, as planned for and discussed in Section 5E: FY 2017 – FY 2026 Projections, and is included in the financial projections in this Financial Plan. It will enable CPAU to maintain adequate Operations Reserve levels while moderating the pace of increase in gas rates. The impact of these transfers on reserves levels can be seen in Appendix A: Gas Utility Financial Forecast Detail. SECTION 4: UTILITY OVERVIEW This section provides an overview of the utility and its operations. It is intended as general background information and to help readers better understand the forecasts in Section 5: Utility Financial Projections and Section 6: Details and Assumptions. SECTION 4A: GAS UTILITY HISTORY On September 22, 1917, the City of Palo Alto issued a bond to purchase the property of Palo Alto Gas Company and continue it as a municipal enterprise. At the time, the system comprised 21 miles of mains, 1,900 meters, and was valued at $65,500. PG&E supplied the gas, which was synthesized from coal at its Potrero facility. Almost immediately the City faced challenges. Losses were at nearly 25% according to PG&E’s master meter, and PG&E had filed with the Railroad Commission (the forerunner to today’s Public Utilities Commission) to increase rates by nearly 72.5%. Despite these initial hurdles, Palo Alto’s system grew tremendously, and by 1924 revenues had exceeded those of the electric utility. Sales were such that the annual reports of the time noted gas usage “appears to be greater than that of any other city in the state, showing that gas is a very popular form of fuel in Palo Alto.” Just prior to the acquisition of the neighboring town of Mayfield’s gas system (centered around today’s California Avenue) in 1929, the miles of main in service and customers connections had doubled. Notable changes to the gas supply itself came in 1930, when PG&E ceased supplying purely manufactured (or coal) gas from its Potrero Hill facility in San Francisco and instead switched to natural gas. In 1935, a supplementary butane injection system (later retired) was purchased from Standard Oil to mitigate large wintertime peaks. Gas sales were at 248,658 million cubic feet (MCF) with 4,849 active services. Early gas mains in Palo Alto were made of steel, but in the 1950s, like many other utilities, CPAU switched to ABS plastic. CPAU switched to PVC plastic in the early 1970s, but around 100 miles of ABS mains had already been installed. A 1990 evaluation of the system found a steadily increasing rate of gas leaks associated with those mains, something that other gas utilities had also been experiencing. To reduce leaks, CPAU accelerated its main replacement program from 7,000 feet (1.3 miles) of replacements per year to 20,000 feet (3.8 miles) per year. This would enable the utility to replace all of its ABS and its most vulnerable steel and PVC mains with (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 10 | P a g e polyethylene (PE) mains over the course of the following 36 years.4 As of 2015 the Gas Utility had replaced approximately 99 miles of ABS, as well as some sections of steel where cathodic protection was not effective. Current main replacement projects will target the last ~800 feet of remaining ABS main as well as tackling PVC replacement. A PVC risk analysis to determine the appropriate footage of annual PVC replacement for future CIP projects is currently being conducted. This is an example of how local control of its Gas Utility has provided Palo Alto residents with substantial benefits. During the 1990s and 2000s, while CPAU was increasing its main replacement rate to ensure a robust gas distribution system, PG&E was underspending on safety­related infrastructure, according to a recent audit.5 In the 1990s, while grappling with the issues surrounding its distribution system, CPAU was also participating in major changes to the structure of the gas industry in California. Until 1988 CPAU had a formal policy of setting its rates equal to PG&E’s rates and successfully did so with the exception of one year in the mid­1970s. At times this led to inadequate revenue (1974 to 1981) as PG&E, the City’s only gas supplier, regularly filed requests with the CPUC to increase the wholesale gas supply rates charged to the Gas Utility. In the 1990s, as the CPUC began deregulating the natural gas industry in California, the Gas Utility began purchasing gas from suppliers other than PG&E. In 1997 the CPUC adopted the “Gas Accord,”6 which enabled the Gas Utility (along with other local transportation­only customers) to obtain transmission rights on PG&E’s Redwood transmission pipeline running from Malin, Oregon into California. In 2000/2001 the California energy crisis occurred, causing major disruptions to the Gas Utility’s supply costs. Wholesale gas prices rose over 500% between January 2000 and January 2001. The Council approved drawing down reserves to provide ratepayer relief and, for two years following the crisis, CPAU rates were above PG&E’s as reserves were replenished. In April 2001 the Council approved a hedging practice of buying fixed price gas one to three years into the future. After reaching a low point in October 2001, prices continued to rise, and as a result the CPAU hedging strategy frequently resulted in a wholesale supply cost advantage compared to PG&E until prices began to decline steeply in mid­2008. At that point the Gas Utility’s wholesale supply costs became higher than market gas prices due to fixed price contracts entered into prior to 2008. As a result the Gas Utility’s wholesale supply costs were higher than PG&E’s for several years. In 2012 Council approved a plan to formally cease the hedging strategy and purchase all gas on the short­term (“spot”) markets. As of July 1, 2012, the commodity portion of the gas rates changes every month based on the spot market gas price. SECTION 4B: CUSTOMER BASE CPAU’s Gas Utility provides natural gas service to the residents, businesses, and other gas customers in Palo Alto. Close to 23,400 customers are connected to the natural gas system, approximately 21,700 (93%) of which are residential and 1,700 (7%) of which are non­ residential. Residential customers consume about 10 to 12 million therms of gas per year, 4 Staff Report CMR:183:90. Infrastructure Review and Update, March 1, 1990 5 Focused Financial Audit of The Pacific Gas & Electric Company’s Gas Distribution Operations , Overland Consulting, made available through a CPUC Administrative Law Judge’s ruling on A12­11­009/I13­03­007 on 5/31/2013 6 CPUC decision 97­08­055. Since then, the Gas Accord has been amended four times, with the most recent being Gas Accord V, application A.09­09­013 (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 11 | P a g e roughly 45% of the gas sold, while non­residential customers consume 55% (about 14 to 15 million therms). Residential customers use gas primarily for space heating (46% of gas consumed) and water heating (42%), with the remainder consumed for other purposes such as cooking, clothes drying, and heating pools and spas 7. Non­residential customers use gas for space and water heating (73% of gas consumed), cooking (20%), and industrial processes (6%).8 The Gas Utility receives gas at the four receiving stations within Palo Alto where CPAU’s distribution system connects with Pacific Gas and Electric’s (PG&E’s) system. These receiving stations are jointly operated by CPAU and PG&E. CPAU purchases gas from a various natural gas marketers, with PG&E providing only local transportation service (transportation from the PG&E City Gate gas delivery hub to Palo Alto). CPAU also has transmission rights on PG&E’s transmission pipeline from Malin, Oregon to PG&E City Gate, allowing it to purchase lower priced gas at that location. CPAU does not produce or store any natural gas, and purchases gas in the monthly and daily spot markets. The cost of the purchased gas is passed through directly to customers through a rate adjuster that varies monthly with market prices. The cost of purchased gas and PG&E local transportation service accounts for roughly one third of the utility’s expenditures. SECTION 4C: DISTRIBUTION SYSTEM To deliver gas from the receiving stations to its customers, the utility owns 210 miles of gas mains (which transport the gas to various parts of the city) and 23,400 gas services (which connect the gas mains to the customers’ gas lines). These mains and services, along with their associated valves, regulators, and meters, represent the vast majority of the infrastructure used to deliver gas in Palo Alto. CPAU has an ongoing CIP to repair and replace its infrastructure over time, the expense of which accounts for around 15 to 20% of the utility’s expenditures. Costs for main replacements have been going up in recent years. In addition to the CIP, the Gas Utility performs a variety of maintenance activities related to the system, such as monitoring the system for leaks, testing and replacing meters, monitoring the condition of steel pipe, and building and replacing gas services for buildings being built or redeveloped throughout the city. The utility also shares the costs of other system­wide operational activities (such as customer service, billing, meter reading, supply planning, energy efficiency, equipment maintenance, and street restoration) with the City’s other utilities. These maintenance and operations expenses, as well as associated administration, debt service, rent, and other costs, make up roughly half of the utility’s expenses. In addition to these ongoing activities, CPAU has conducteda program to find and replace cross­bores over the last several years. 7 http://energyalmanac.ca.gov/naturalgas/overview.html 8 Source: Statewide Commercial End Use Study, California Energy Commission report, 2006. Statistics shown are for end users in PG&E Climate Zone 4 (the Peninsula) where Palo Alto is located. (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 12 | P a g e Figure 2: Cost Structure (FY 2015) 60% 34% 6% Operations Gas Purchases Capital Figure 1: Revenue Structure (FY 2015) 95% 5% Sales of Gas Other Revenue SECTION 4D: COST STRUCTURE AND REVENUE SOURCES As shown in Figure 1, the Gas Utility receives 95% of its revenue from sales of gas and the remainder from capacity and connection fees, interest on reserves, and other sources. Appendix A: Gas Utility Financial Forecast Detail shows more detail on the utility’s cost and revenue structures. As shown in Figure 2, in FY 2015, gas purchase costs accounted for roughly 34% of the Gas Utility’s costs. This percentage can vary widely from year to year, as this cost is based upon market purchases. Operational costs represented roughly 60%, and capital investment was responsible for the remaining 6%. The percentages for FY 2015 are skewed by the fact that CIP, which is normally about 20% of expenses, was reduced in FY 2014 and FY 2015 to allow for a backlog of projects to be completed. SECTION 4E: RESERVES STRUCTURE CPAU maintains six reserves for its Gas Utility to manage various types of contingencies. These are summarized below, but see Appendix C: Gas Utility Reserves Management Practices for more detailed definitions and guidelines for reserve management: Reserve for Commitments: A reserve equal to the utility’s outstanding contract liabilities for the current fiscal year. Most City funds, including the General Fund, have a Commitments Reserve. Reserve for Reappropriations: A reserve 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. Capital Improvement Program (CIP) Reserve: The CIP reserve can be used to accumulate funds for future expenditure on CIP projects and is anticipated to be empty unless a major one­time CIP expenditure is expected in future years. This CIP can also (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 13 | P a g e act as a contingency reserve for the CIP. This type of reserve is used in other utility funds (Electric, Water, and Wastewater Collection) as well. Rate Stabilization Reserve:This reserve is 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 (Electric, Water, and Wastewater Collection) as well. Operations Reserve:This is the primary contingency reserve for the Gas Utility, and is used to manage yearly variances from budget for operational gas costs. This type of reserve is used in other utility funds (Electric, Water, and Wastewater Collection) as well. Unassigned Reserve:This reserve is for any funds not assigned to the other reserves and is normally empty. SECTION 4F: COMPETITIVENESS Table 8 presents winter and summer residential bills for Palo Alto and PG&E at several usage levels for commodity rates in effect as of July 2015 (to illustrate a summer month bill) and March 2016 (to illustrate a winter month bill). The annual gas bill for the median residential customer for calendar year 2015 was $420.86, about 15% lower than the annual bill for a PG&E customer with the same consumption. PG&E’s distribution rates for gas have increased substantially to collect for needed system improvements for pipeline safety and maintenance. The bill calculations for PG&E customers are based on PG&E Climate Zone X, an area which includes the surrounding communities. Table 8: Residential Monthly Natural Gas Bill Comparison ($/month) Season Usage (therms) Palo Alto PG&E Zone X % Difference Winter (March 2016) 30 31.25 40.23 ­22% (Median) 54 48.34 72.42 ­33% 80 77.16 117.37 ­34% 150 163.10 245.51 ­34% Summer (Jul 2015) 10 17.75 12.47 42% (Median) 18 24.04 22.60 6% 30 38.64 43.44 ­11% 45 58.18 69.50 ­16% Table 9 shows the monthly gas bills for commercial customers for various usage levels for rates in effect as of March 1, 2016. Bills for CPAU customers at the usage levels shown are around 9% lower for smaller commercial customers and 4 to 17% higher for larger commercial customers than for PG&E customers. This is a substantial improvement over the calendar year2013 bill comparison, when commercial gas bills for CPAU customers were 27% to 44% higher than for PG&E customers. This is primarily attributable to PG&E’s increased distribution rates as the (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 14 | P a g e commodity rates for CPAU and PG&E are very similar, both being based on spot market gas prices. Table 9: Commercial Monthly Average Gas Bill Comparison (for Rates in Effect Feb. 1, 2016) Usage (therms/mo) Gas Bill ($/month) % Difference Palo Alto PG&E 500 518 572 ­9% 5,000 4,510 4,953 ­9% 10,000 9,231 8,859 4% 50,000 44,711 38,104 17% SECTION 4G: GAS SUPPLY RATES Starting in July 2012, CPAU replaced a “laddering” hedging strategy for purchasing gas supplies with a strategy to buy gas on the short­term, or “spot” markets and pass the commodity cost to customers on a monthly basis. The actual commodity prices are shown in Figure 3. As shown, commodity prices have steadily fallen for the last two years. Figure 3: Gas Commodity Rates from July 2012 through March 2016 (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 15 | P a g e SECTION 5: UTILITY FINANCIAL PROJECTIONS SECTION 5A: LOAD FORECAST Gas usage in Palo Alto is volatile, varying with both economic and weather conditions. As shown in Figure 4, in the early 1970’s, gas purchases reached over 45 million therms per year. Usage dropped dramatically in the 1976/1977 drought when customers saved significant amounts of (hot) water by upgrading to efficient showerheads. During the 1980s and 90s average gas usage was around 36 million therms per year. Usage dropped again in the early 2000’s. In FY 2001, gas prices escalated during the California energy crisis and Palo Alto’s rates increased by nearly 200%. From 2003 to 2011, usage decreased by 2.3% mainly as a result of continued customer investments in energy efficiency. In FY 2015 an unusually warm winter, as well as ongoing drought, have again caused gas usage to tumble to historic lows. Gas usage was 25.6 million therms in FY 2015. Figure 4: Historic Gas Consumption 20 25 30 35 40 45 50 (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 16 | P a g e Gas consumption, as denoted by the dotted line in Figure 5, is projected to recover somewhat and stay stable over the forecast period, although changes such as replacement of gas appliances with electricappliances or customer behavior may result in lower long run usage. Figure 5: Forecast Gas Consumption SECTION 5A: FY 2011 TO FY 2015 COST AND REVENUE TRENDS Figure 6 and Appendix A: Gas Utility Financial Forecast Detail how costs have changed during the last five years as well as how they are projected to change over the next decade. The annual expenses for the gas utility decreased substantially between 2011 and 2015 due to lower gas sales. Market prices for gas supplies are shown in Figure 3 above. FY 2014 and 2015 were notable for a temporary hiatus in most CIP budgeting, to permit the completion of a backlog of projects which had previously been budgeted for. This budgetary hold allowed for backlogged gas main replacement projects to be started, which consumed capital reserves. Starting in FY 2012, additional funding for gas cross­bore inspections increased Operations costs. Revenues are below expenses, and the projected rate trajectory will bring revenues in line with costs by FY 2019. As shown in Figure 6 below, revenues were below cost in FY 2011 and FY 2013 and are projected to be below cost in FY 2016. Reduced budgeting for new CIP in FY 2014 and FY 2015, as well as the availability of relatively large reserves, forestalled the need for rate increases until now. However, since Rate Stabilization Reserves are projected to be depleted by FY 2017, the Gas Utility must increase rates to cover costs. As shown in Figure 6, the last gas rate adjustment was in July 2012 when rates were increased by 12%. However, this was at the same time that the commodity rates were changed to a market­based, monthly pass­through cost—and commodity rates (and usage) fell, so revenues actually declined in FY 2013 after the rate increase. 20 22 24 26 28 30 32 34 36 (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 17 | P a g e Figure 6: Gas Utility Expenses, Revenues, and Rate Changes: Actual Costs through FY 2015 and Projections through FY 2026 SECTION 5B: FY 2015 RESULTS Sources of funds for FY 2015 were lower than projected by $4.8 million, but expenses related to Purchases and Operations and Maintenance activities came in well below expected budget. Total FY 2015 expenses were $30.9 million compared to projections of $34.9 million in the FY 2015 Financial Plan. Table 10 summarizes the variances from forecast. Table 10: FY 2015, Actual Results vs. Financial Plan Forecast Net Cost/(Benefit) Type of change Sales revenues lower than forecast 5,427,000 Revenue decrease Other revenues and interest were higher than forecasted (628,000) Revenue increase Purchase costs lower than forecast (3,212,000) Cost savings Operations & maintenance, Customer service and other savings (760,000) Cost savings Net Cost / (Benefit) of Variances $827,000 (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 18 | P a g e SECTION 5C: FY 2016 PROJECTIONS Current projections indicate that sales revenues continue to be lower than forecast, at this time projected to be $4.7 million. However, Purchase cost reductions of $4.2 million offset most of this. Table 11 summarizes the current projected variances from FY 2016 Financial Plan. Table 11: FY 2016, Projected Results vs. Financial Plan Forecast Net Cost/(Benefit)Type of change Sales revenues lower than forecast 4,719,000 Revenue decrease Purchase costs lower than forecast (4,171,000) Cost savings Operations & maintenance, Customer service and other savings (1,843,000) Cost savings Capital improvement budgets higher 1,216,000 Cost increase Other revenues and interest lower than forecasted 611,000 Revenue decrease Net Cost / (Benefit) of Variances $531,000 SECTION 5D: FY 2017 ­FY 2026 PROJECTIONS As can be seen in Figure 6 above, costs for the Gas Utility are projected to rise in FY 2017, then are projected to increase at a bit less than 3.5% per year through FY 2026. In Operations, this is due to an additional $1 million for cross­bore inspections (this expense is projected to continue for at least three years), as well as general inflationary increases of around 2.6% per year. Salaries and benefits expenses are projected to rise at nearly 4% per year, per the City’s Long Range Financial Plan. CIP programs are projected to increase, then stabilize at around $6 million per year in FY 2018, then grow at around 2% per year thereafter. Gas commodity costs are the most variable component. At the time the budget was developed in December 2015, gas supply prices were projected to increase by around 3 to 4% per year, but recently gas prices have hit near record lows. Since this is a pass­through cost to customers, the risk of these costs being higher or lower than expected has a minimal impact on reserves. As shown in Figure 7, the Rate Stabilization Reserves are projected to be depleted by FY 2017. (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 19 | P a g e Figure 7: Gas Utility Reserves Actual Reserve Levels for FY 2011 and Projections through FY 2026 SECTION 5E: RISK ASSESSMENT AND RESERVES ADEQUACY The Gas Utility’s primary contingency reserve, the Operations Reserve, is projected to be right at the approved minimum guideline level in FY 2018 and FY 2019, barring either short­run budget savings and/or larger future increases. Figure 8 shows that the Operations Reserve recover to the target level by FY 2021 with the projected rate trajectory. (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 20 | P a g e Figure 8: Operations Reserve Adequacy Forecast Operations Reserve levels also exceed the short­term risk assessment for the Utility. Table 12 summarizes the risk assessment calculation for the Gas Utility through FY 2021. The same methodology is used for FY 2022 through FY 2026 as well. The risk assessment includes the revenue shortfall that could accrue due to: 1. Lower than forecasted distribution sales revenue; and 2. An increase of 10% of planned system improvement CIP expenditures for the budget year. Table 12: GasRisk Assessment ($000) FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 Total non­commodity revenue $21,587 $24,256 $26,956 $28,370 $28,781 Max. revenue variance, previous ten years 16% 16% 16% 16% 16% Risk of revenue loss $3,462 $3,890 $4,323 $4,549 $4,615 CIP Budget $5,076 $4,720 $4,811 $4,958 $5,105 CIP Contingency @10% $508 $472 $481 $496 $511 Total Risk Assessment value $3,969 $4,362 $4,804 $5,045 $5,126 Finally, the CIP Reserve was created at the end of FY 2015 to act as a contingency reserve for capital improvement projects. Current guidelines state that the balance of this reserve should fall between 12 and24 months of budgeted CIP expense. (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 21 | P a g e At the end of FY 2016, the sum of the CIP Reserve and existing Commitments was a bit below $5 million, as shown in Figure 7. However, based upon FY 2016’s CIP budget, the minimum reserve level is $6.9 million. As such, this reserve is technically below the minimum level, but the Risk assessment reserve level for the Operations Reserve is also set to handle a 10% increase to CIP costs should that arise. As such, staff does not recommend an additional increase to rates to fund this reserve at this time. If any CIP funds budgeted in FY 2016 are not used or committed by the end of the fiscal year, those funds flow to the Operations Reserve and those funds could be used to fund the CIP reserve, so increasing rates for this contingency is premature. Staff is in the process of reviewing this reserve and the appropriateness of the current minimum and maximum guideline levels. SECTION 5F: ALTERNATE SCENARIOS At the UAC’s February 2016 meeting, it was suggested that staff prepare two alternate scenarios for rate increases. The first (“Target”) scenario keeps the Operations Reserve at or near the Target level throughout the forecast period as shown in Figure 8 below. The second (“Minimum”) has no rate change in FY 2017 and lets the Operations Reserve stay at minimum for five years as shown in Figure 10 below. Both options as well as the proposed rate adjustments are shown in Table 13. Table 13: Projected Gas Rate Trajectory for FY 2017 to FY 2026 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Proposed 8% 9% 7% 4% 1% 1% 1% 1% 1% 1% Target 8% 16% 2% 1% 1% 2% 2% 2% 2% 1% Minimum 0% 24% 1% 1% 1% 4% 3% 1% 1% 1% The Target scenario does not change the FY 2017 proposed rate increase, but a 16% rate increase in FY 2018 would be needed to bring reserves to target levels. Figure 9 shows that the Operations Reserve levels for the Target scenario. The Minimum scenario avoids a rate increase in FY 2017, but requires a significant increase in FY 2018 (24%). If sales are lower than expected or costs rise, then this rate increase would be even higher. Figure10 shows that the Operations Reserve levels for the Minimum scenario. Staff recommends an 8% gas rate increase in FY 2017 to moderate the rate increases that are projected in FY 2018 while keeping the Gas Operations Reserve at healthy levels. (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 22 | P a g e Figure 9: Operations Reserve at Target Figure 10: Operations Reserve at Minimum SECTION 5G: LONG ­TERM OUTLOOK In the longer term (5 to 35 years out) it is very difficult to predict the Gas Utility’s commodity costs. A variety of long­term trends could affect commodity costs either positively or negatively. Continuing improvement in gas extraction technology, such as fracking, could continue to create generous supplies of gas, but these technologies are also under greater scrutiny with respect to their environmental impacts. On the demand side, a continued shift from coal to natural gas for electricity generation or an increase in manufacturing in the U.S. might drive up (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 23 | P a g e natural gas prices, but other factors, such as generally more mild winters, might drive gas demand lower. It is also difficult to predict the magnitude of the additional cost impacts associated with the State’s cap­and­trade program over the long term. In the face of this uncertainty, CPAU is able to protect the financial position of the Gas Utility by continuing its current strategy of passing these costs directly to its customers via month­varying rate adjustment mechanisms. Future CIP investment needs for the Gas Utility may be lower than in the past, although costs per foot for main replacement may increase substantially. The Gas Utility has replaced all of its ABS gas mains and its most problematic steel and PVC mains as well. The PE pipe being used now is expected to have at least a fifty­year lifetime, and there is growing evidence that it may last much longer than that. This would result in lower CIP investment over the long term. CPAU is considering performing a study in the near future to develop its future main replacements priorities and strategy. Long­term state or local climate goals could also have a major impact on the Gas Utility. The Global Warming Solutions Act, Assembly Bill 32 (AB32), set a goal of reducing greenhouse gas (GHG) emissions to 1990 levels by 2020 and then maintaining those reductions. In its December 2007 Climate Protection Plan, the City set a goal of lowering emissions to 15% below 2005 levels by 2020. As a community Palo Alto achieved these goals in 2012 even with continued use of natural gas for heating, cooking, and industrial processes. If stricter goals are enacted at the state or local level, however, it could lead to “electrification”, or consumer switching from gas­ using appliances to electric­using appliances for heating, cooking and processes. If significant amounts of electrification occurred, stranded investment and higher rates could be required as the costs of the distribution system are recovered over a lower sales base. One example of a stricter standard has been stated by the Governor—reducing GHG emissions to 80% below 1990 levels by 2050.9 This goal, or less ambitious interim state goals, would require legislation to implement. But it is instructional that, in the recent discussion draft of its scoping plan update, CARB says, to meet those goals, natural gas use would have to be “mostly phased out.”10 Legislation has been recently passed addressing the Governor’s 2030 climate goals of 50% renewable generation, 50% reduction in transportation fuels, and a doubling of energy efficiency. A few bills have already been introduced on post­2020 GHG emission reduction goals and the GHG cap­and­trade market. As stewards of the Gas Utility, the City should continue to stay aware of developments in state climate planning, participate as a stakeholder, and consider these types of impacts and ways to mitigate them when developing its own sustainability goals. 9 Executive Orders S­3­05 and B­16­2012. 10 Climate Change Scoping Plan, First Update, Discussion Draft for Public Review and Comment , California Air Resources Board, October 2013, pg 88. (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 24 | P a g e SECTION 6: DETAILS AND ASSUMPTIONS SECTION 6A: GAS PURCHASE COSTS The Gas Utility purchases much of its gas for delivery at Malin, Oregon which is almost always cheaper than delivery at PG&E City Gate, even including the costs of transmission from Malin to City Gate. Gas is purchased on a month­ahead and day­ahead basis in the spot market. The last few years have seen gas prices in a relatively narrow but low band, and prices for the last year in particular have been lower than most projections. High levels of natural gas in storage, along with warmer than normal weather on the West coast has kept prices low, as shown in Figure 11. Figure 11: Gas Market Prices at PG&E Citygate Future gas commodity costs are expected to increase steadily over the next several years. Figure 12 shows the projected gas prices used to generate this forecast. Projections for transmission costs associated with transporting gas over PG&E’s Redwood transmission pipeline (from Malin, Oregon to the PG&E Citygate) are based on rates adopted in the most recent update to the Gas Accord. Local transportation costs decreased on January 1, 2015 due to the expiration of a temporary adder to PG&E’s local transportation rate,11 but in December 2014 PG&E applied to the CPUC to more than double local transportation costs. Staff is tracking PG&E’s application and, based 11 California Public Utilities Commission Advice Letter 3430­G, effective January 1, 2014. Also see CPUC Decision 12­12­30 regarding the Pipeline Safety Enhancement Plan Adder. (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 25 | P a g e on discussions to date, expects that nearly all of the proposed increase in local transportation costs will be approved. Staff projects these costs to escalate at 3% per year in subsequent years. As these charges are dictated by PG&E and are outside of Palo Alto’s control, staff may propose making these costs a pass­through charge, similar to the commodity charge, in FY 2018. Figure 12: Wholesale Gas Price Projections SECTION 6B: OPERATIONS Operations costs include the Customer Service, Demand Side Management, Operations and Maintenance (including Engineering), Resource Management, and Administration categories in Figure 13, below. Debt service, rent, and transfers are also included in Operations costs (excluding the General Fund equity transfer). Appendix D: Description of Gas Utility Cost Categories includes detailed descriptions of the activities associated with these cost categories. Operations costs are projected to increase by 2 to 4% per year. Salary and benefits, inflation, and other assumptionsmatch those used in the City’s long­range financial forecast. Operations costs for FY 2017 to FY 2019 include funding for the cross­bore program. In the 1970s CPAU, like many other utilities, adopted horizontal drilling as an alternative to trenching when installing new gas services. This created the possibility of cross­bores, which can happen when a gas service is bored through a sewer lateral. Though cross­bores are very rare, they can create a dangerous situation when a contractor attempts to clear a blocked sewer line, because if the cross­bored gas service is damaged during the line clearing it can result in a gas leak. CPAU has been inspecting new gas services since 2001, and in 2011 began video inspections of the sewer laterals at the location of horizontally­drilled gas services installed before 2001. This inspection program has cost roughly $1 million per year since FY 2012. While a majority of sewer laterals have been inspected, staff has come across several services which are not able to (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 26 | P a g e be scoped, either due to infiltration by roots or broken/collapsed pipe segments. Staff has included $3 million in additional funding between FY 2017 and FY 2019 for this program, but the program will likely require additional funding in future years to complete. Figure 13: Historical and Projected Operational Costs SECTION 6C: CAPITAL IMPROVEMENT PROGRAM (CIP) The Gas Utility’s CIP program consists of the following programs and budgets: The Gas Main Replacement Program, under which the Gas Utility replaces aging gas mains Customer Connections, which covers the cost when the Gas Utility installs new services or upgrades existing services at a customer’s request in response to development or redevelopment. The Gas Utility charges a fee to these customers to cover the cost of these projects. Ongoing Projects, which covers the cost of routine meter, regulator, and service replacement, minor projects to improve reliability or increase capacity, and other general improvements. Tools and Equipment, which covers the cost of capitalized equipment, such as directional boring equipment. One­time Projects, which represents occasional large projects that do not fall into any other category. (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 27 | P a g e Table 14 shows the current status of these project categories and future projectedspending. Table 14: Budgeted Gas CIP Spending The Gas Main Replacement (GMR) Program is in the process of reaching a major milestone, the replacement of the last gas mains made from ABS plastic. The program to replace ABS and other low­performing materials in the system started in the 1990s (see Section 4A: Gas Utility History for more detail). CPAU temporarily slowed down its new CIP appropriations in this category in FY 2014 and 2015 in order to finish the last major ABS main replacement project and to catch up on a backlog of projects that has accumulated due to staffing issues. With the replacement of all ABS mains with PE plastic, the material most at risk for failure is removed leaving only PVC plastic, steel (wrapped, with cathodic protection), and PE mains. The next focus of the GMR program will be PVC mains. CPAU is considering updating the Gas System Master Plan to determine which areas of the system to prioritize. The plan will help CPAU determine whether the pace of main replacement (approximately three miles of main each year, or 1.5% of the system) needs to be increased, decreased, or whether it needs to remain the same. The current budget for gas main replacement assumes the current pace of main replacement, but does not take into account the recent rise in costs for main replacement, which have increased from the levels seen during the recent recession. Several factors may be contributing to this. Economic recovery in the Bay Area, as well as a greater focus on infrastructure improvement by many municipal agencies and utilities could be creating high demand for contractors in these fields. Newer, more leak resistant pipe materials may have ongoing greater costs. CPAU has seen the replacement cost per linear foot increase by 25 to 50% over the last couple of years. Currently CPAU plans to complete as much main replacement as possible within its current budget, provided there are no safety concerns. However, if this trend of higher cost continues, the Gas Utility may require larger CIP budgets, and as a result, larger rate increases. Ongoing Projects, Tools and Equipment, and Customer Connections are projected to cost approximately $0.8 million in FY 2017 and increase by 3% per year through the end of the forecast period. In practice, these projects can fluctuate dramatically depending on system conditions and the pace of development and redevelopment in the city. It is worth noting that the Customer Connections program is paid for through fee revenue, so when costs go up, so does fee revenue. (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 28 | P a g e Aside from customer connections and some transfers from other funds, the CIP plan for FY 2017 to FY 2021 is funded by utility rates. The details of the plan are shown in Appendix B: Gas Utility Capital Improvement Program (CIP) Detail. SECTION 6D: DEBT SERVICE The Gas Utility currently makes debt service payments on one bond issuance, the 2011 Series A Utility Revenue Refunding Bonds. This bond issuance was to refinance the $18 million principal remaining on the Utility Revenue Bonds, 2002 Series A issued for the Gas and Water Utilities to finance various improvements to the distribution systems. $9.4 million of this issuance was secured by the net revenues of the Gas Utility. Debt service for this bond for the financial forecast period is shown in Table 15. Debt service on this bond will continue through 2026. Table 15: Gas Utility Debt Service FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 2011 Utility Revenue Refunding Bonds, Series A 803 802 800 800 802 804 805 803 800 803 The 2011 bonds include two covenants stating that 1) the Gas Utility will maintain a debt coverage ratio of 125% of debt service, and 2) that the City will maintain “Available Reserves”12 equal to five times the annual debt service. The current financial plan complies with these covenants throughout the forecast period, as shown in Table 16 and Table 17. Table 16: Debt Service Coverage Ratio ($000) FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Revenues 35,938 39,825 43,628 46,051 47,336 48,323 49,891 51,465 53,429 54,696 Expenses (Excluding CIP and Debt Service) ­33,310 ­34,933 ­36,511 ­37,086 ­38,566 ­40,128 ­41,838 ­43,552 ­45,307 ­47,068 Net Revenues 2628 4892 7117 8965 8770 8195 8053 7913 8,122 7,628 Debt Service 803 802 800 800 802 804 805 803 800 803 Coverage Ratio 327%610%890%1121%1094%1019%1000%985%985% 985% Table 17: Debt Service Minimum Reserves ($000) FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 Gas Utilitya 9,543 7,647 7,849 9,712 11,191 11,901 12,270 12,298 12,327 12,742 Debt Serviceb 803 804 803 802 801 801 802 803 800 803 Reserves Ratioc 12x 10x 10x 12x 14x 15x 15x 15x 15x 15x a) CIP, Rate Stabilization, Operations, and Unassigned Reserves b) Gas Utility’s share of the debt service on the 2011 bonds. c) Calculated using only Gas Utility reserves. The actual reserves ratio for the 2011 bonds is calculated based on the combined Electric, Gas, and Water Utility reserves and debt service and is higher than shown here. 12 Available Reserves as defined in the 2011 bonds include the reserves for the Water, Electric, and Gas Utilities (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 29 | P a g e The Gas Utility’s reserves and net revenue are also pledged as security for the bond issuances listed in Table 18, even though the Gas Utility is not responsible for the debt service payments. The Gas Utility’s reserves or net revenues would only be called upon if the responsible utilities are unable to make their debt service payments. Staff does not currently foresee this occurring. Table 18: Other Issuances Secured by Gas Utility’s Revenues or Reserves Bond Issuance Responsible Utilities Annual Debt Service ($000) Secured by Gas Utility’s: Net Revenues Reserves 1995 Series A Utility Revenue Bonds Storm Drain $680 Yes No 1999 Utility Revenue Bonds, Series A Wastewater Collection Wastewater Treatment Storm Drain $1,207 No Yes 2009 Water Revenue Bonds (BuildAmerica Bonds) Water $1,977* No Yes *Net of Federal interest subsidy SECTION 6E: EQUITY TRANSFER The City calculates the equity transfer from its Gas Utility based on methodology adopted by Council in 2009 that has remained unchanged since 13. Each year it is calculated according to the 2009 Council­adopted methodology, and does not require additional Council action. SECTION 6F: REVENUES The Gas Fund receives most of its revenues from sales of gas, but about 5% comes from other sources. The largest of these comes from service connection and capacity fees, followed closely by sales of allowances related to California’s cap­and­trade program. Another revenue item related to the cap­and­trade program is collected in customer’s bills. While the State provides CPAU with a certain number of free allowances each year, the Gas Utility is required to sell a portion of those in accordance with the regulations. In order to have enough allowances to cover customer’s natural gas emissions, CPAU must buy allowances at market, and subsequently passes through the cost of those allowances to customers. The regulations do not allow the revenue derived from the sale of the free allowances to offset allowance purchases, thus the pass­through rate component. Sales revenue projections are based on the load forecast in Section 5A: Load Forecast.Except where stated otherwise, these load forecasts are based on normal weather. Weather can vary substantially, however, and this can affect revenues substantially. Also, changes in customer behavior, as well as changes to more efficient gas appliances, or switching to electric 13 For more detail on the ordinance adopting the 2009 transfer methodology, see CMR 280:09, Budget Adoption Ordinance for Fiscal Years 2009 and 2010; and CMR 260:09, Finance Committee Report explaining proposed changes to equity transfer methodology. (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 30 | P a g e appliances, will modify these forecasts. Forecasts are continually evaluated to see when new trends emerge. SECTION 6G: COMMUNICATIONS PLAN The FY 2017 communications strategy covers four primary areas: operations, infrastructure, safety, efficiency, renewables and rates. Since moving to market pricing for commodity rates, changes to the commodity rates are posted monthly on the City’s website. Gas use efficiency incentives are promoted year­round, but most heavily during winter months to impact heating activities. Promotional methods include community outreach events, print ads in local publications, utility bill inserts, messaging on the bills and envelopes, website pages, email blasts, videos for the web and local Comcast channels, Home Energy Reports and the use of social media. To keep customers apprised of the status and accomplishments of capital improvement projects, a network of project web pages are maintained. Traffic is driven to the website via print and digital ads, social media and email blasts. Safety topics are emphasized year­round. CPAU is engaging in several campaigns and programs in FY 2017 to promote gas utility efficiency and renewable energy. The Georgetown University Energy Prize competition is a friendly, national campaign to encourage communities to reduce energy use. Energy savings from reduced gas and electric consumption qualify to help Palo Alto compete for a $5 million prize at the end of a two­year campaign. Since adoption of a carbon neutral electric supply portfolio, CPAU launched a new voluntary renewable natural gas carbon offsets program, PaloAltoGreen Gas. Much of our programmatic promotional activity will center around customer education and encouragement to sign up for participation in PaloAltoGreen Gas. Other new programs include home efficiency services and online tools to help customers manage their energy use. Stepping up efforts to promote gas safety education, staff is focusing outreach around youth, the importance of calling USA (811) before digging for anyone who may excavate in and around Palo Alto, such as plumbers and contractors, potential sewer and gas line crossbores, keeping fats, oils and greases out of drains, and ensuring clear access to meters. For younger “customers­to­be,” CPAU created a Home Safety Detective campaign that includes special tool kits to help them identify home safety problems. Staff provides safety kits to youth and adults at school presentations, neighborhood safety and emergency preparedness fairs and other community outreach events. Meter access awareness is highlighted through use of materials featuring photos of some unusual ways people obstruct access to their meters, including using them as bike racks and building storage sheds around them. CPAU will continue to promote safety, infrastructure, operations, efficiency and rate adjustment messages through a variety of marketing and media channels. Every year, CPAU publishes an updated gas safety awareness brochure which is mailed to all customers in Palo Alto, as well as plumbers, contractors and excavators that may work in and around the area. Staff talks with business customers at special facilities meetings, attends neighborhood safety and emergency preparedness fairs and offers presentations to school and community groups. While print materials and website pages still feature prominently, CPAU is turning the outreach (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 31 | P a g e emphasis to direct mail, newspaper inserts, social media, online videos and cable TV. Copies of all outreach materials and logs of activities are saved in the Gas Safety Public Awareness Plan that is reviewed at least once per year by the Department of Transportation. (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 32 | P a g e APPENDICES Appendix A: Gas Financial Forecast Detail Appendix B: Gas Utility Capital Improvement Program (CIP) Detail Appendix C: Gas Utility Reserves Management Practices Appendix D: Description of Gas Utility Cost Categories Appendix E: Gas Utility Communications Samples (SGY7MKR)RZIPSTI-(&))()'%%'*'(& DocuSign Envelope ID: 2B6E9E20-D99E-4CA6-86AC-57806FC2D54B GAS UTILITY FINANCIAL PLAN APPENDIX A: GAS FINANCIAL FORECAST DETAIL , City of Pal o Alto Gas Utility ($'000) Fiscal Year 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 1 RATE CHANGE (%)" 0% 0% 12% 0% 0% 0% 8% 9% 7% 4% 1% 1% 1% 1% 1% 1% 2 SALES IN THOUSAND THERMS 30,914 30,447 28,901 28,117 28,881 27,261 28,653 28,680 28,711 28,743 28,511 28,412 28,461 28,522 28,590 28,658 N O O 0 N M a N N N CO O N N N 41. N N N CO CO N N Utilitie s Retail Sales 42,855 41,034 33,759 34,843 29,515 28,608 33,259 37,038 40,365 42,408 43,293 43,965 45,170 46,396 47,584 48,622 Service Connectio n&CapacityFees 516 592 731 654 602 655 1,017 1,048 1,079 1,110 1,145 1,145 1,145 1,145 1,145 1,145 Other Re ven ues&Transfersln 203 103 830 313 666 1,026 1,373 1,517 1,975 2,328 2,635 2,920 3,221 3,529 4,313 4,834 In te re st plu s Gain or Loss on Inv estmen t 821 1,119 (239) 706 450 376 288 223 210 205 264 293 355 396 387 368 To tal So urces of Funds 44,396 42,847 35,081 36,517 31,233 30,665 35,938 39,825 43,628 46,051 47,336 48,323 49,891 51,465 53,429 54,969 Pu rchases of Utilities: Su pply Commo dity 20,732 15,356 12,461 12,992 9,537 6,693 9,393 10,141 10,598 11,131 11,621 12,145 12,741 13,288 13,825 14,219 Su pply Tran sportation 706 879 994 1,333 982 2,566 2,944 3,152 3,172 3,207 3,213 3,234 3,272 3,312 3,353 3,394 Tota l Purc has es 21,438 16,235 13,455 14,325 10,519 9,258 12,337 13,293 13,770 14,338 14,834 15,380 16,013 16,600 17,178 17,613 Administratio n (CIP + Operating) 2,895 3,473 4,273 3,988 4,007 4,114 4,243 4,370 4,497 4,629 4,764 4,902 5,045 5,192 5,343 5,499 Customer Service 1,230 1,270 1,358 1,338 1,195 1,232 1,286 1,335 1,384 1,435 1,486 1,539 1,594 1,651 1,711 1,772 Deman d Side Management 563 614 630 438 632 648 665 683 701 720 739 759 779 799 821 842 Engineering (Operating) 280 333 340 352 369 380 396 411 425 440 455 471 487 504 522 540 Operatio ns and Maintenance 3,297 5,032 4,940 4,119 4,403 4,534 5,720 5,918 6,116 5,320 5,502 5,690 5,885 6,087 6,295 6,512 Resou rce Management 1,039 729 506 516 808 1,302 1,327 1,350 1,751 2,006 2,223 2,434 2,665 2,904 3,149 3,498 Debt Service Payments 488 406 296 805 804 804 803 802 801 801 803 804 805 803 800 803 Rent 230 230 219 419 431 443 455 467 480 492 505 519 532 546 561 574 Transfers to General Fund 5,304 6,006 5,971 5,811 5,730 6,126 6,722 6,945 7,220 7,535 7,883 8,255 8,653 9,078 9,533 10,019 Other Transfers Out 614 170 207 606 151 154 158 163 167 171 176 180 185 190 195 200 Capitallmpro vementPrograms 8,325 7,821 7,620 1,026 1,832 6,889 6,305 5,985 6,115 6,301 6,488 6,680 6,879 7,083 7,293 7,509 Total Uses of Funds 45,704 42,320 39,814 33,743 30,881 35,886 40,418 41,721 43,426 44,188 45,857 47,613 149,522 51,438 53,400 55,380 Into/ (O ut o f) Reserves (1,308) 528 (4,733) 2,773 352 (5,221) (4,480) (1,896) 202 1,864 1,479 710 369 28 29 (410) 29 30 Reappropriations + Commitments 17,174 19,211 19,363 11,305 6,491 6,491 6,491 6,491 6,491 6,491 6,491 6,491 6,491 6,491 6,491 6,491 31 Plan t Repla ceme nt 1,000 1,000 1,000 0 0 0 0 0 0 0 0 0 0 0 0 0 32 CIPRese rve 0 0 0 0 1,591 1,591 1,591 1,591 1,591 1,591 1,591 1,591 1,591 1,591 1,591 1,591 33 Rate Stabiliza tion 16,188 15,992 11,318 15,981 6,806 5,275 0 0 0 0 0 0 0 0 0 0 34 Operation s Reserve 0 0 0 0 10,847 7,158 7,952 6,056 6,258 8,121 9,600 10,310 10,679 10,707 10,736 11,151 35 Unassigned 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 36 Total Reserve s 34,362 36,203 31,681 27,286 25,735 20,514 16,034 14,138 14,340 16,203 17,682 18,392 18,761 18,789 18,818 19,233 37 38 Short Term Risk Assessment Value 1,226 3,789 3,969 4,362 4,766 5,005 5,085 5,134 5,247 5,365 5,487 5,612 39 40 O perations Reserv e Gu idelines 41 Min (60 Days Commodity +O&M) 5,620 4,772 5,618 5,889 6,090 6,151 6,368 6,599 6,851 7,103 7,361 7,603 42 Target (90Days Co mmodity +O&M ) 8,429 7,158 8,426 8,833 9,135 9,227 9,552 9,898 10,277 10,654 11,041 11,405 43 Max (120Days Commodity +O&M ) 11,239 9,543 11,235 11,778 12,180 12,302 12,736 13,198 13,703 14,206 14,721 15,207 44 April 12, 2016 33IPage DocuSign Envelope ID: 2B6E9E20-D99E-4CA6-86AC-57806FC2D54B GAS UTILITY FINANCIAL PLAN APPENDIX A: GAS UTILITY CAPITAL IMPROVEMENT PROGRAM (CIP) DETAIL Reappropriated / Carried Forward from Project # Pro ject Name Previ ous Years Current Year Funding Budget Amendments Remaining in Spending, CIP Reserve Current Year Fund C ommitments FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 ONE TIME PROJECTS GS -09000 Gas Station 1 Rebuild - - - - - - - - - - GS -08000 Gas Station 2 Rebuild - - - - - - - - - - GS -10000 Gas Station 3 Rebuild 4 - - - 4 - - - - - - GS -11001 Gas Station 4 Rebuild - - - - - - - - - - GS -13003 COBUG emissions equipment - - - - - - - - - - GS -15001 Security at Receiving Stations 150,000 150,000 (150,000) (9,459) 140,541 125,000 - - - - Subtotal, One-time Pro jects 150,004 150,000 (150,000) (9,459) 140,545 125,000 - - - - - GAS MAIN REPLACEMENT (GMR) PRO GRAM GS -08011 GMR - Project 18 GS -09002 GMR - Project 19 526,621 - (30,410) (68,899) 427 ,312 427,312 - - - - - GS - 10001 GM R - Project 20 2,311,602 - (13,981) (23,297) 2,274 ,324 2,274,325 - - - - - GS -11000 GM R - Project 21 867,159 - (20,512) (100,049) 746 ,598 832,416 - - - - - GS -12001 GMR - Project 22 295,985 4,033,001 (493,001) (175,008) 3,660,977 3,000 - - - - - GS -13001 GMR - Project 23 - 620,650 - - 620,650 42,500 3,550,650 - - - - GS -14003 GMR - Proje ct 24 - - - - - - 640,000 3,100,000 - - - GS -15000 GMR - Project 25 - - - - - - - 711,000 3,200,000 - - GS -16000 GMR - Pro je ct 26 - - - - - - - - 678,200 3,300,000 - GS -20000 GMR - Proje ct 27 - - - - - - - - - 700,000 3,400,000 GS -20001 GMR - Project 28 - - - - - - - - - - 721,000 Subtotal, Gas Main Replacement Pro gram 4,001,367 4,653,651 (557,904) (367,253) 7,729,861 3,579,553 4,190,650 3,811,000 3,878,200 4,000,000 4,121,000 TO OLS AND EQUIPMENT GS -13002 General Sho p Equipment/Tools 130,931 100,000 (113,062) (46,069) 71,800 - 100,000 100,000 100,000 100,000 100,000 GS -01019 Global Positioning System 73,578 - (70,768) (641) 2,169 - - - - - GS -02013 Directional Boring Machine - - - - - - - - - - - GS -03007 Directional Boring Equipment - - - - - - - - - - GS -03008 Polyethylene Fusion Equip. 29,168 - - - 29,168 - - - - GS -14004 Gas Distribution System Model 140,742 87,690 (87,690) (29,544) 111,198 - - - - - Subtotal, Tools and Equipment 374,419 187,690 (271,520) (76,254) 214,335 - 100,000 100,000 100,000 100,000 100,000 April 12, 2016 341Page DocuSign Envelope ID: 2B6E9E20-D99E-4CA6-86AC-57806FC2D54B GAS UTILITY FINANCIAL PLAN Gas Utility Capital Improvement Program (CIP) Detail (continued) Reappropriated / Carri ed Forward from Project # Project Name Previous Years Current Year Funding Budget Amendments Remaining in Spending, CIP Reserv e Current Year Fund Commitments FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 ONGOING PROJECTS GS -11002 Gas System Improvements GS -03009 System Ext. - Unreimbursed GS -80019 Gas Meters and Regulators 151,021 284,821 736,596 292,669 192,675 344,690 (66,397) (284,095) (733,487) (114,635) (35,809) (42,523) 262,658 157,592 305,276 76,036 - - 231,913 198,500 355,030 238,870 204,455 365,681 246,036 210,590 376,652 253,417 216,908 387,952 261,020 223,415 399,591 Subtotal, Ongoing Projects 1,172,438 830,034 (1,083,979) (192 ,967) 725,526 76,036 785,443 809,006 833,278 858,277 884 ,025 CUSTO MER CONNECTIONS (FEE FUNDED) GS -80017 Gas System Extensions (252,428) 950,000 255,428 (575,893) 377,107 37,880 1,228,500 1,265,355 1,303,315 1,342,415 1,382,688 Su btotal, Customer Connection s (252,428) 950,000 255,428 (575,893) 377,107 37,880 1,228,500 1,265,355 1,303,315 1,342,415 1,382,688 GRAND TOTAL 5,445,800 6,771,37S (1,807,97S) (1,221,826) 9,187,374 3,818,469 6,304,593 5,985,361 6,114,793 6,300,692 6,487,713 Funding So urces Connection Fees Utility Rates 639,600 6,131,775 255,428 (2,063,403) 1,017,000 5,287,593 1,047,510 4,937,851 1,078,935 5,035,857 1,111,303 5,189,389 1,144,642 5,343,070 CIP-RELATED RESERVES DETAIL 6/30/2015 (Actual) 9/30/2015 5,076,093 4,720,006 4,811,478 4,958,277 5,105,025 Reappropriations Commitments 2,100,800 3,345,000 5,368,905 3,818,469 April 12, 2016 351Page GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 36 | P a g e APPENDIX B: GAS UTILITY RESERVES MANAGEMENT PRACTICES The following reserves management practices shall be used when developing the Gas Utility Financial Plan: Section 1. Definitions a) “Financial Planning Period” – The Financial Planning Period is the range of future fiscal years covered by the Financial Plan. For example, if the Financial Plan delivered in conjunction with the FY 2015 budget includes projections for FY 2015 to FY 2019, FY 2015 to FY 2019 would be the Financial Planning Period. b) “Fund Balance” – As used in these Reserves Management Practices, Fund Balance refers to the Utility’s Unrestricted Net Assets. c) “Net Assets” ­ The Government Accounting Standards Board defines a Utility’s Net Assets as the difference between its assets and liabilities. d) “Unrestricted Net Assets” ­ The portion of the Utility’s Net Assets not invested in capital assets (net of related debt) or restricted for debt service or other restricted purposes. Section 2. Supply Fund Reserves The Gas Utility’s Supply Fund Balance is reserved for the following purposes: a) For existing contracts, as described in Section 4 (Reserve for Commitments) b) For operating and capital budgets re­appropriated from previous years, as described in Section 5 (Reserve for Re­appropriations) Section 3. Distribution Fund Reserves a) For existing contracts, as described in Section 4 (Reserve for Commitments) b) For operating and capital budgets re­appropriated from previous years, as described in Section 5 (Reserve for Re­appropriations) c) For cash flow management and contingencies related to the Gas Utility’s Capital Improvement Program (CIP), as described in Section 6 (CIP Reserve) d) For rate stabilization, as described in Section 7 (Rate Stabilization Reserve) e) For operating contingencies, as described in Section 8 (Operations Reserve) f) 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 9 (Unassigned Reserves) Section 4. Reserve for Commitments At the end of each fiscal year the Gas Supply Fund and Gas Distribution Fund Reserve for Commitments will be set to an amount equal to the total remaining spending authority for all contracts in force for the Wastewater Collection Utility at that time. Section 5. Reserve for Reappropriations At the end of each fiscal year the Gas Supply Fund and Gas Distribution Fund Reserve for Reappropriations will be set to an amount equal to the amount of all remaining capital and (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 37 | P a g e non­capital budgets, if any, 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. 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 12 months of budgeted CIP expense Maximum Level 24 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 Council approval to hold funds in this reserve in excess of the maximum level, if they are held for a specific future purpose related to the CIP. Section 7. Rate Stabilization Reserve Funds may be added to the Rate Stabilization Reserve by action of the City Council and held to manage the trajectory of future year rate increases. Withdrawal of funds from the Rate Stabilization Reserve requires Council action. If there are funds in the Rate Stabilization Reserve at the end of any fiscal year, any subsequent Gas Utility Financial Plan must result in the withdrawal of all funds from this Reserve by the end of the Financial Planning Period. (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 38 | P a g e Section 8. Operations Reserve The Operations Reserve is used to manage normal variations in costs and as a reserve for contingencies. Any portion of the Gas Utility’s Fund Balance not included in the reserves described in Section 4­Section 7 above will be included in the Operations Reserve unless this reserve has reached its maximum level as set forth in Section 8 d) below. Staff will manage the Operations Reserve according to the following practices: a) The following guideline levels are set forth for the 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 O&M and commodity expense Target Level 90 days of O&M and commodity expense Maximum Level 120 days of O&M and commodity expense b) Minimum Level: If, at the end of any fiscal year, the funds remaining in the 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, and the Council may adopt, an alternative plan that takes longer than one year to replenish the reserve. c) Target Level: If, at the end of any fiscal year, the Operations Reserve is higher or lower than the target level, any Financial Plan created for the Gas Utility shall be designed to return the Operations Reserve to its target level by the end of the forecast period. d) Maximum Level: If, at any time, the Operations Reserve reaches its maximum level, no funds may be added to this reserve. Any further increase in the Gas Utility’s Fund Balance shall be automatically included in the Unassigned Reserve described in Section 9, below. Section 9. Unassigned Reserve If the Operations Reserve reaches its maximum level, any further additions to the Gas Utility’s Fund Balance will be held in the Unassigned Reserve. If there are any funds in the 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 Gas 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 2015, and the next Financial Planning Period is FY 2016 through FY 2020, the Financial Plan shall include a plan to return or assign any funds in the Unassigned Reserve by the end of FY 2016. Staff may present an alternative plan that retains these funds or returns them over a longer period of time. (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 39 | P a g e Section 10. Intra­Utility Transfers Between Supply and Distribution Funds The Gas Utility records costs in two separate funds: the Gas Supply Fund and the Gas Distribution Fund. At the end of each fiscal year staff is authorized to transfer an amount equal to the difference between Gas Supply Fund costs and Gas Supply Fund Revenues from the Gas Distribution Fund Operations Reserve to the Gas Supply Fund, or vice versa. Such transfers shall be included in the ordinance closing the budget for the fiscal year. (SGY7MKR)RZIPSTI-(&))()'%%'*'(& GAS UTILITY FINANCIAL PLAN A p r i l 1 2 , 2 0 1 6 40 | P a g e APPENDIX C: DESCRIPTION OF GAS UTILITY COST CATEGORIES This appendix describes the activities associated with the various cost categories referred to in this Financial Plan. Customer Service:This category includes the Gas 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 gas services. Resource Management: This category includes gas procurement, contract management, rate setting, and tracking of legislation and regulation related to the gas industry. Operations and Maintenance:This category includes the costs of a variety of distribution system maintenance activities, including: surveying the gas system (50% of the system each year) and repairing any leaks found; investigating reports of damaged mains or services and perform emergency repairs; building and replacing gas services for new or redeveloped buildings; and testing and replacing meters to ensure accurate sales metering. This category also includes a variety of functions the utility shares with other City utilities, including: the Field Services team (which does field research of various customer service issues); the Cathodic Protection team (which monitors and maintains the systems that prevent corrosion in metal pipes and reservoirs);and the General Services team (which manages and maintains equipment, paves and restores streets after gas, water, or sewer main replacements, and provides welding services, including certified gas line welding services) Administration: Accounting, purchasing, legal, and other administrative functions provided by the City’s General Fund staff, as well as shared communications services and Utilities Department administrative overhead and billing system maintenance costs. Demand Side Management: Includes the cost of administering gas efficiency programs and the direct cost of rebates paid. Engineering (Operating):The Gas 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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