San Francisco Public Utilites Commission. Retail Electric Rate Study

Transcription

1 San Francisco Public Utilites Commission Retail Electric Rate Study December 30, 2010

2 TABLE OF CONTENTS EXECUTIVE SUMMARY... 2 OVERVIEW OF UTILITY RATE SETTING PRINCIPLES... 4 DEVELOPMENT OF THE REVENUE REQUIREMENTS COST OF SERVICE ANALYSIS RATE DESIGN TECHNICAL APPENDIX

3 Executive Summary Introduction Montague DeRose and Associates, LLC ( MDA or Consultants ) was retained by the San Francisco Public Utilities Commission ( SFPUC ) to conduct an independent analysis (the Analysis ) of the current and ten-year projected revenue requirement for the Power Enterprise of the SFPUC as required by City Charter Section 8B.125. The ten-year projected revenue requirement is based, in part, on the Commission s ten-year Financial and Capital Plans. After determining the revenue requirement, an average embedded cost of service analysis (COSA) model was constructed and a COSA study was performed. The COSA provides a benchmark to compare expected rate class revenues to their respective cost to serve. This study is the first independent analysis of rates and cost of service for retail electric service required by the Charter. This Analysis includes a recommendation for residential and commercial rates for future retail power sales of the Power Enterprise, which will first include customers in the Hunter s Point redevelopment area. The recommended rates are illustrated below and compare favorably with PG&E s current residential and commercial rates. Recommendations Based on our analyses, we make the following recommendations: 1. Rates should be adopted for residential and commercial customers located in redevelopment areas that produce sufficient revenues to meet the share of the Power Enterprise s five-year average annual revenue requirement allocated to each class of service. 2. The rate for residential service should include a fixed monthly service charge and a three-tier energy charge. The monthly charge should be $4.00 per account per month. The energy charge during the winter months from November 1 to April 30 should be $ per kwh for the first 357 kwh per billing month, $ per kwh for the next 143 kwh per billing month, and $ per kwh for all additional energy use. During the summer months from May 1 to October 31, the energy usage allowed in each tier should be eighty-five percent (85%) of that allowed in the winter months. 3. The rate for commercial service should include a fixed monthly service charge that is differentiated for single phase service and poly phase service, and a uniform energy charge. The month charge for single phase service should be $5.00 per account per month and for poly phase service should be $12.00 per month. The energy charge during the winter months from November 1 to April 30 should be 2

4 $ for all energy use and during the summer months from May 1 to October 31 should be $ for all energy use. 4. Although the scope of this study did not explore rate design for Municipal customers, it is important to assign appropriate cost responsibility and charge cost based rates to provide a suitable price signal for the wise use of a limited resource. While the Power Enterprise has completed the necessary Revenue Requirement Analysis for all power enterprise operations, Municipal customers are assumed to continue receiving subsidized service at the General Fund rate of $ per kwh. 5. The Power Enterprise needs to regularly measure and manage key risks. The financial model and decision structure developed for this study is an excellent tool for that purpose. The Power Enterprise should develop a comprehensive risk management strategy. City Charter Requirements The City Charter (Section 8B.125) establishes a number of goals and objectives for setting retail utility rates. A summary of the major goals and objectives appears below: Provide sufficient revenues for the operation, maintenance and repair of the enterprise consistent with good utility practice; Provide sufficient revenues to improve or maintain the financial condition and bond rating at or above levels equivalent to highly-rated utilities of each enterprise; Meet requirements and covenants under all bond indentures; Set rates based on cost of service; Investigate and develop capacity fees for new development; Investigate and develop rate-based conservation incentives; and Investigate and develop affordability programs for low-income customers. Organization of Report The report is organized as follows: The first section of the report will discuss utility rate setting principles. The second section will discuss the revenue requirement on which the COSA was based. The third section provides a description of the COSA and the final section will discuss the rate design process and the recommended retail rates. 3

5 Overview of Utility Rate Setting Principles INTRODUCTION The setting of electric utility rates that are fair and sufficient to fund all operating and capital requirements is a dynamic and complex process. The process is guided by generally accepted methodologies that can be used as a guide in developing the SFPUC s electric rates. At the same time, there are often a number of financial principles and policy guidelines that must be taken into consideration during this process. Therefore, electric rates are best determined by using accepted methodologies while considering the financial and policy objectives of the SFPUC. The following paragraphs provide a brief overview of the fundamentals of developing electric rates. From this foundation, more insight and understanding can be obtained from the following sections of the report which discuss the specifics of the development of the SFPUC s rates. A reference for COSA and rate setting issues utilized in this study is Retail Rate Design For Publicly Owned Electric Systems by Edward A. Cecil & Phillip Euler, American Public Power Association, The COSA methodologies utilized in this report are consistent with this reference. PRINCIPLES OF UTILITY RATE SETTING As a practical matter, there should be a general set of principles around which rates will be set. These types of principles are generally used by all utilities in the development of their rates. Basic principles around which we recommend that the SFPUC should strive to set retail electric rates include: Rates should be cost-based and set at a level such that they are expected to recover the full revenue requirements of the utility, both under a projected case scenario and a reasonable range of alternative scenarios; Rates should be just, reasonable and not unduly discriminatory or preferential; Rates should promote economically efficient use of electricity; Rates should be easy to understand and administer; Rates should be relatively stable, in both their ability to provide adequate revenues to meet the utility s financial requirements, and in the customer s perception of the level of the rates from year to year; and Rates should meet all legal requirements and the goals stated in the City s Charter. 4

6 Currently, the municipal electric rates charged by the Power Enterprise are set consistent with SFPUC Resolution , adopted by the City on November 14, The resolution required two rate structures: one rate for Water Enterprise, Wastewater Enterprise, San Francisco International Airport, Port of San Francisco, certain enumerated municipal activities 1 and retail customers not governed by special contracts (referred to as the Enterprise rate), and another rate for other City departments and public agencies (referred to as the General Fund rate). The Enterprise rate is specified by the PG&E tariff for equivalent service approved by the California Public Utilities Commission ( CPUC ) and allows for rate adjustments consistent with changes to PG&E s rates authorized by the CPUC. The General Fund rate was to have been cost based and is currently set at $ per kilowatt hour (kwh). Neither the General Fund rate nor the Enterprise rates are linked directly to the Power Enterprise s actual cost of service. In 1999, the Power Enterprise retained an independent consultant to perform a General Fund Electric Rate Study in which a three step, phase-in of a cost of service rate was recommended for implementation. The first step was implemented effective July 1, However, the subsequent steps were not implemented. During the state-wide energy crisis in 2000 and 2001, the General Fund rate was raised on January 1, 2001 to today s current rate of $ per kwh. Furthermore, the strategy to match PG&E's rates also deviates from the cost to serve Enterprise customers. PG&E s cost structure and rate-setting procedures are very different from a public utility like the SFPUC. The Power Enterprise is operated on a non-profit basis. Whereas, PG&E is an investor owned utility which has a very different revenue requirement structure. A brief overview of the differences of an investor owned utility from a publicly owned utility is included in this report. OVERVIEW OF THE ELECTRIC RATE STUDY ANALYSES There are a number of generally accepted approaches for developing electric utility rates. However, all of these approaches share the same basic framework. That is, in developing electric rates, three separate yet inter-related analyses are generally performed. It is within these three analyses that different methodologies exist. The three analyses contained within the basic framework for setting electric rates are: Revenue Requirement Analysis Cost of Service Analysis Design of Rates 1 Includes Convention Facilities Management (Bill Graham Auditorium, Brooks Hall and Moscone Center), Candlestick Park, Yacht Harbor, Parking Authority, and Public Works Department (Street Repairs, Bridges, Tunnels, Underpasses, Traffic Engineering, and Street Environmental Services). 5

7 The revenue requirement analysis reviews the various operational - such as purchased power, transmission and distribution, and administrative and general expenses - and financial costs such as cash funded capital expenses and debt service - and revenue offsets to these costs. Revenue offsets are obtained from energy sales to Modesto and Turlock Irrigation Districts, Norris Industries and surplus energy sales in the wholesale electricity market. The difference between the costs and revenue offsets determines the net revenue requirement of the overall utility. From that analysis, a determination can be made regarding the adjustment to overall rate levels necessary to recover the net costs of the Power Enterprise. A comprehensive revenue requirement analysis was completed for the Power Enterprise in The cost of service analysis takes the results of the revenue requirement analysis and allocates the net costs to the various customer classes of service (e.g. residential, commercial, etc.) based on each class respective service requirements. This analysis provides a determination of the cost responsibility of each class of service and determines the adjustment required in each class revenue to meet the cost of service. Finally, once the adjustment for each class of service has been determined, a rate can be designed which considers other rate setting criteria other than simply cost of service. Other criteria that may be considered are the customer s ability to pay, and ease of administration, to name a few. Rate designs can take many different forms or structures, but each rate design has the stated goal of collecting the appropriate level of revenues as determined within the revenue requirement and cost of service analysis. TYPES OF UTILITIES As noted above, there are different methodologies used for setting electric rates. The first characteristic that is often considered when selecting a methodology is the type of utility for which the rates are being set. Utilities are divided into two groups based on ownership either publicly owned or investor owned utilities ( IOU ). Publicly owned utilities like the SFPUC are usually owned by a municipality, public utility district, cooperative, or county, and are often operated as non-profits. Publicly owned utilities are generally capitalized by issuing tax exempt debt and through use of revenues from customers. Publicly owned utilities are generally exempt from State and Federal income taxes although many publicly owned utilities make franchise or other payments in lieu of local income and property taxes. Finally, a publicly owned utility is usually regulated by a publicly-elected or appointed Council, Board of Supervisors, Commission, or Board of Trustees. In contrast, investor owned utilities are generally capitalized by issuing debt and equity stock. The owners of the private utility are its equity contributors, or shareholders. IOUs are taxable entities and are regulated by state public utility commissions. PG&E's rates 6

8 are determined through regulatory proceedings at the California Public Utilities Commission. These differences in ownership and other characteristics often lead to two methods for reviewing revenue requirement needs. A more detailed discussion of the different methodologies that may be used is provided below. OVERVIEW OF REVENUE REQUIREMENT METHODOLOGIES By virtue of the differences noted above for a publicly-owned versus an investor owned utility, their respective revenue requirements are based upon different elements or methodologies. Most investor owned utilities use what is known as the accrual basis of determining revenue requirements or setting rate levels. This convention calculates a utility s annual revenue requirement by aggregating a period s operation and maintenance (O&M) expenses, taxes, depreciation expense and a fair return on investment. Operating expenses include the labor, materials, supplies, electricity, etc., which are needed to keep the utility functioning. IOUs also pay State and Federal income taxes, along with any applicable property, franchise, sales or other forms of taxes. Next, depreciation expense is a means of recouping the capital cost of in-service facilities, over the useful lives of those facilities and also a means of generating internal cash. Finally, the return portion of this type of revenue requirement pays for the utility s interest expense on various types of debt and preferred stock, provides funds for a return to the utility s equity holders in the form of dividends, and leaves a balance for retained earnings and cash flow purposes. For example, PG&E currently has an authorized rate of return of 11.35% on its equity funded portion of its rate base - which includes net plantin-service, and working capital and other allowances. In contrast, the cash basis method of determining annual revenue requirements is often used for publicly owned utilities like the SFPUC. As the name implies, a public utility aggregates its cash expenditures for a period of time to determine its total revenue requirements for a specified period of time. A major difference between the cash and accrual methods is the way in which capital costs are determined. Capital costs under the cash basis are calculated by adding (i) principal and interest payments (debt service) on debt instruments used to fund capital improvements, (ii) any reserve fund deposits required by bond or other debt indentures, and (iii) cash required to fund capital improvements that are not funded by debt. Typically, because utilities cannot debt finance all required capital investment, revenue requirements prepared on a cash basis include both debt service, reserve fund deposits and cash portions of the capital expenses. The table below details the comparison of the cash and utility revenue requirement conventions: 7

9 Revenue Requirement Comparison Cash Basis Utility (Accrual) Basis + O&M Expense + O&M Expense + Taxes/Transfers (special use) + Taxes & Franchise Fees + Cash Funded Capital Improvements + Depreciation Expense + Debt Service + Reserve Fund Deposits + Return on Investment (interest expense and return on equity) = Revenue Requirement = Revenue Requirement Again, the SFPUC is a cash basis utility for the purposes of this study. As described below, the SFPUC s revenue requirement includes revenue sufficient to cover projected capital expenditures, using a combination of cash and debt funding. OVERVIEW OF COST ALLOCATION PROCEDURES After the total revenue requirement has been determined, it is allocated to the various customer classes of service (e.g. residential, commercial, etc.) based upon a fair and equitable methodology that reflects the cost-causation relationships for the production and delivery of the services. This analytical exercise usually takes the form of a cost of service study. A cost of service study begins by categorizing a utility s revenue requirement into the primary functional components of utility operations. For an electric utility, the appropriate categories are power supply, transmission, distribution, and administrative and general. 8

10 Overview of Average Embedded COSA Functionalize Classify Allocate Supply Energy Residential Total Costs Transmission Distribution Capacity Customer Commercial Industrial A&G Direct Assign Street Lights The figure above conceptualizes the COSA process. Once the revenue requirement is properly functionalized, the study proceeds by classifying the functionalized revenue requirements as being related to amount of energy used, the maximum rate of use (i.e. capacity), number of customers serviced, or directly assignable to a specific customer group or class. Power supply and transmission have capacity and energy related costs. Capacity related costs are those that the utility incurs to meet a customer s maximum instantaneous usage requirements and is usually measured in kilowatts (kw). Energy related costs are those that vary directly with longer periods of consumption and are usually measured in kilowatt-hours (kwh). The distribution function has capacity, energy and customer related costs. Customer related costs such as services drops and meters vary with the number of customers. Administrative and general functions are not specifically related to a particular type of cost classification, but are typically classified on the basis of other costs. As previously mentioned, some costs which may be a function of supply, transmission, or distribution are assignable to a specific customer or class of customers. For example, the cost of the streetlight replacement project is directly assigned to the streetlight class. These four component costs are then allocated to each class of service based upon the most equitable method available for each specific cost. At that point, the revenue requirements have been allocated to each class of service and a determination of the necessary revenue adjustments between classes of service can be made. 9

11 RATE DESIGN The final step in the rate study process is to design rates for each class of service using the results of the revenue requirement and cost of service analyses. There is no universally preferred rate structure with fair and equitable rates taking many forms. Well designed rates should reflect the component costs that the utility incurs (demand, energy, customer and directly assigned costs) as well as collect the required amount of revenues. In addition to cost, there may be other policy considerations such as affordability, subsidization of municipal use, reserve policies and desired operating margins, which when legally permitted may also influence rate design. 10

12 Development of the Power Enterprise Revenue Requirement INTRODUCTION The purpose of this section is to present the revenue requirement for the Power Enterprise. Simply stated, a revenue requirement analysis determines the costs to be recovered from rates charged to customers of the utility. After rates are set on customers, comparing the revenue requirement to the revenues determines the future adjustment to revenues and underlying rates required to ensure all costs are met. This section will discuss the basic methodology used to analyze the Power Enterprise s revenue requirement. REVENUE REQUIREMENT METHODOLOGY For purposes of this report, MDA investigated and analyzed recent financial and operational results, current budgets, capital spending projections, ten-year electric load forecasts, and estimates of revenues under existing rates. This analysis was conducted with particular emphasis on those items likely to have the greatest economic, financial, and operational impact on the Power Enterprise in its role as supplier of power and energy to customers within its service area. The SFPUC provided MDA with historical financial and operating data for the period beginning January 2004 and ending June 2010, as well as electric load and operating cost projections for the period beginning January 2010 and ending December Based on these data, and in consultation with SFPUC staff, MDA constructed a detailed financial model that estimates revenues and revenue requirements, including operation and maintenance costs, cash funded capital expenditures, debt service for capital expenditures funded by bonds or other debt and appropriate funding of cash reserves. The fundamental input by which the financial model determines revenues and revenue requirements begins with data provided by the Power Enterprise from its load and resource dispatch model (LTR). The LTR provides load requirements and resource (supply) projections for three basic hydrological scenarios wet, normal and dry. These load and energy supply projections are then used to project the variable and fixed costs to serve such loads. The estimated costs are based on historic actual costs, a forward electric price curve and the two-year adopted FY and FY Hetch Hetchy budget. The essential elements used in calculating the Power Enterprise s revenue requirements are summarized in the table below. 11

13 SFPUC s Revenue Requirements Operation and Maintenance Expenses Power Supply Costs Power Transmission and Distribution Expenses + Non-Operating Expenses Cash Funded Capital Expenditures 2 Rate Stabilization Reserve Funding Debt Service for Debt-Funded Capital Expenditures = Gross Revenue Requirements - Revenue Requirement Offsets Revenue from Irrigation Districts Surplus Sales Revenues Interest Earnings = Net Revenues Required From Rates GENERAL ASSUMPTIONS In developing revenue requirements, a number of assumptions must be made regarding the basic operations of the SFPUC system and intentions. These assumptions help minimize uncertainties and help establish the framework necessary for generating the revenue requirement. Many assumptions are based upon existing contracts, agreements, regulations, policies or laws that govern general consumer behavior, while others are based upon continued practices and precedents of the SFPUC. The following paragraphs summarize the key assumptions used in this study. 1. The rates used for Modesto and Turlock Irrigation Districts and General Fund customers remain consistent with existing agreements, as shown in the table at right. These rates provide a revenue offset against generation expenses. Assumed Rates $/MWh TID MID General Fund Forecasted electric load growth is based on SFPUC internal long-term plans and includes Hunter s Point and Treasure Island loads. Estimates of Shore-Side Power and Transbay Terminal loads were incorporated into the model by MDA. 2 Note SFPUC s capital plan includes amounts required for repair and replacement of existing investment, thus no separate depreciation expense is needed here (i.e., the capital plan addresses the need to fund replacement of depreciated assets). 12

14 3. The spot sales price for excess electricity (when SFPUC generation exceeds load) is based on the NP-15 forward price curve used by the Power Enterprise in its own projections. 4. The spot purchase price for required electricity (when loads exceed SFPUC generation) is based on the NP-15 forward price curve. 5. Transmission and distribution charges are split into categories and have the rates as shown in the adjacent table. These remain constant in accordance with a contractual agreement with PG&E through To project transmission and distribution charges after 2015, this report bases Transmission & Distribution Charges Charge ($/MWh) Primary Distribution Secondary Distribution Transmission its projections on a Hunters Point Wholesale Distribution tariff for Hunters Point, a Transmission Access Charge analysis prepared by the Power Enterprise and MDA projections. 6. Scheduling coordinator charges are estimated to be $0.385/MWh, which is consistent with the amount shown in the FY Hetch Hetchy budget. 7. Beginning in July 2011, Independent System Operator (ISO) charges are assumed to increase at 3% from their average projected costs from July 2010 through June Beginning in July 2011, A&G expenses are assumed to increase at 3% from their average projected costs from July 2010 through June Beginning in July 2011, O&M expenses (excluding spot electricity purchases) are assumed to increase at 4.5% from their average actual costs from July 2009 through June 2010 due to expenses incurred by the Hunters Point redevelopment project. 10. Projected capital expenditures range from $64 to $92 million over the forecast period. It is assumed $25-$30 million is cash funded each year, with the remainder funded through issuance of debt (either by private placement or by competitive sale). All capital expenditures are consistent with the adopted FY to FY ten-year Power Enterprise Capital Plan. The annual funding assumption (cash vs. debt) is summarized in the table below. 13

15 Power Enterprise Capital Expenditure Summary Fiscal Year Cash Funded Debt Funded Total ($000s) ($000s) ($000s) ,746 38,619 64, ,048 40,572 67, ,835 44,753 74, ,450 64,051 91, ,376 61,544 87,920 Total 136, , , A Rate Stabilization Fund ( RSF ) will be established beginning in the FY and annual deposits to the Fund are included in the annual revenue requirement. Deposits to the RSF are to protect customers from a potential rate shock from increased revenue requirements associated with a seven-year drought which is the Power Enterprise s stress case for electric load and resource forecast modeling. To determine the size of the RSF, the change in revenue requirements in a seven-year drought scenario was compared to a seven-year normal hydrology scenario. The revenue requirement increased by approximately $160 million over this seven-year period. To fully fund the RSF annual deposits are projected to equal to 20 to 30% of the total operating costs in each year until the total fund target balance of $160 million is met. It is expected to take ten years under normal operating conditions to fully fund the RSF. Interest earnings on the Rate Stabilization Fund are assumed at 1% per year. Setting the target amount for the RSF for a new public utility will be part of the credit rating process for the Power Enterprise to receive long-term debt ratings from the rating agencies. The Power Enterprise should consider sizing the RSF at a level that results in investment grade ratings. As the rate-setting process was proven and after significant risks were mitigated the level of reserves required to support its investment grade rating will likely decrease. Below is a table of rate stabilization policies for comparable utilities. 14

16 Rate Stabilization Fund Comparisons Utility Percent of Operating Expenses S&P Rating Notes Roseville A+/Stable SMUD 7 A+/Stable Drought condition "pass-through" to increase rates Santa Clara A+ S&P reports cash reserves are often 500 days of expenses Palo Alto AA+/Stable S&P reports cash reserves are often 500 days of expenses Rate Stabilization Fund Summary Fiscal Year Beginning Balance Deposit Interest Earnings Ending Balance ($ 000s) ($ 000s ) ($ 000s) ($ 000s) , , ,631 23, , ,020 18, , ,334 16, , ,408 13, , A Public Goods Fund has been established and funded at 2.85% of Power Enterprise revenues, which is based on AB1890 the energy deregulation bill that went into effect in The Fund is currently financed through the revenue stream to cover costs related to services that a utility provides in the public interest. These services range from educational initiatives and funding for lowincome customers to environmental and efficiency programs. The capital improvement program already had in place several initiatives that would fall into the pubic goods category. 13. Bond funded capital expenditures are assumed to be funded with 30-year level debt service with an average interest rate of 5.5%. RESOURCES AND CUSTOMERS Today, the Power Enterprise customer electric load requirements are predominantly met with Hetch Hetchy hydroelectric generation. For FY 2011, Hetch Hetchy generation accounts for approximately 99% of the Enterprise s resource portfolio. The charts below 15

17 illustrate the Power Enterprise's current power supply portfolio and the projected power supply portfolio for Hetch Hetchy generation accounts for the majority of the Enterprise's resource needs, with Behind-the-Meter solar projects accounting for almost the entirety of the remaining supply deficit at 1%. The load and resource balance under drought condition is provided in the Appendix to this report. Assuming normal hydrologic conditions over the period and the Power Enterprise s ability to bank power, purchased power is not projected to be significant until the FY Power Supply 2011 (1,640 GWh) Power Supply 2016 (1,778 GWh) Projects Behind the Meter, 15, 1% Purchased Solar Renewables, 3, 0% Hydro, 1,622, 99% Projects Behind the Meter, 17, 1% Purchased Solar Renewables, 6, 0% Hydro, 1,622, 92% Purchased Power,, 0% (read as category, GWh, % of total) Purchased Power, 133, 7% [read as category, GWh, % of total] SFPUC Power Customers The Power Enterprise s municipal customer base is attractive from a load factor perspective. With significant baseload needs and rather small summer peaks, electrical service to these customers is relatively cost-effective. This customer base is one of the Enterprise s key assets. Currently, the municipal/retail loads fall into one of five customer billing classifications: General Fund and Other Public Agencies receive a subsidized rate. The largest General Fund rate customers are the San Francisco Municipal Railway (MUNI), Department of Public Health and Department of Recreation and Parks. Enterprise Customers and Specified Municipal Activities are billed at the comparable PG&E rate. The largest customers are Enterprise rate customers including the Public Utilities Commission (Water and Wastewater) and the Port of San Francisco which includes some Port tenants. 3 Currently, excess energy amounts are banked under an arrangement with PG&E to deposit the Enterprise s surplus energy with the ability to withdraw energy as needed. This reduces the need for purchased power. 16

18 Shore-side ship service to the Port of San Francisco is provided at a reduced rate on an interruptible basis. San Francisco International Airport and its tenants are served at a discounted comparable PG&E rate in accordance with the terms of a 1987 settlement between the City and the airport tenants. This settlement expires in 2013 at which time this customer will be billed the comparable PG&E rate. The current discount is 74% and will remain at that level through the term of the settlement. Free Power: The customers in the Free Power billing classification include municipal streetlights and City Hall. SFPUC Deliveries (MWh) (MWh) (MWh) (MWh) (MWh) General Fund/Other Public Agencies 442, , , , ,418 Enterprise Customers 173, , , , ,299 Airport Tenants 367, , , , ,262 Redevelopment 9,544 15,213 16,296 15,242 15,242 Total 992,911 1,053,449 1,074,765 1,068,561 1,074,222 City municipal customers served by the Power Enterprise include all City and County of San Francisco departments and public agencies. The following table shows the amount of energy associated with the General Fund and Enterprise categories. Shore-side ship serve is included in the Enterprise category. Because of its size and the fact that it receives a discounted rate, the Airport is shown as a separate category. The Free Power rate customers are not broken out separately, but included inside the General Fund category. Hunters Point Shipyard Redevelopment Projected residential and commercial build out of the Hunters Point Ship Yard (HPS) will continue over the next six years. At present, residential development is in progress and will include approximately 1,400 homes. Plans are also being developed to install 900kW of rooftop customer-owned photovoltaic capacity at HPS. This potential resource has not been modeled and would significantly reduce the HPS load requirements if installed. 17

19 Modesto Irrigation District, Turlock Irrigation District and the former Norris Site: The Power Enterprise has supplied Hetch Hetchy generation to the Modesto Irrigation District (MID) and Turlock Irrigation District (TID) as provided for under the Raker Act of The Raker Act requires that energy surplus to municipal needs be sold at costs to meet the district s municipal and pumping requirements. Until recently, the Power Enterprise sold power to Norris Industries for the operation of an U.S. Army ammunition plant which is no longer operational. The City of Riverbank is planning to redevelop the site near Turlock as a commercial area. Because Norris Industries provided services to the Federal government, it received power from Hetch Hetchy at a subsidized rate. The Power Enterprise expects to continue to serve the site under the terms of a new agreement currently being negotiated. SFPUC Deliveries to Modesto and Turlock Irrigation Districts and former Norris site (MWh) (MWh) (MWh) (MWh) (MWh) MID 119, , , , ,335 TID 250, , , , ,397 Norris 8,542 8,585 8,628 8,671 8,714 Total 379, , , , ,446 18

20 2015 SFPUC Load: 1,428 GWh Former Norris Site, 8,714, 1% Airport Tenants, 395,262, 28% General Fund/Other Public Agencies, 477,418, 33% Modesto and Turlock Irrigation Districts, 344,731, 24% Redevelopment, 15,242, 1% Enterprise Customers, 186,299, 13% REVENUE REQUIREMENT RESULTS The revenue requirement analysis includes all costs directly associated with the Power Enterprise and also 55 percent of the joint costs associated with Hetch Hetchy operations. For FY , the Power Enterprise s adopted budget includes $55.2 million in operating expenses consisting of: (a) $17.7 million for transmission and distribution expenses; (b) $6.8 million for scheduling coordinator charges, CAISO charges, local capacity and risk management expenses; (c) $15.0 million for operations and maintenance costs, and (d) $15.1 million in administrative and general expenses. In addition, the revenue requirement used for this analysis includes $54.8 million in nonoperating expenses consisting of: (e) $23.5 million to begin funding a rate stabilization fund; (f) $2.5 million to fund a public goods fund; (g) $25.7 million to cash fund a portion of its capital needs, and (h) $3.1 million in debt service. Revenues available to reduce the net revenue requirement to municipal and other customers total $20.7 million. The revenues include $9.1 million from sales to the Modesto and Turlock Irrigation Districts, $11.1 million from market sales of surplus electricity and $383 thousand from sales at the former Norris Industries site. The net revenue requirement for FY is $89.3 million which is the sum of Total Operating Expenses and Total Non-Operating Expenses less Revenue Offsets. 19

21 For cost of service and rate design purposes, the test year revenue requirement is normally based on a consecutive twelve-month period. An historical period adjusted for known and measurable changes in costs or a future period reflecting an anticipated change in operations may be used as a test period. If the rates are intended to be in effect for more than one year, an average of the revenue requirements for the intended period can be used. In the case of the Power Enterprise, its costs, revenue offsets and electricity usage are expected to be relatively stable for the next five years. The Power Enterprise will likely issue debt to fund any capital improvement needs above its normal cash funding levels thus moderating peaks and valleys in year-to-year spending plans. Because of these factors, this report recommends using the average annual revenue requirement between FY through FY as its test period. Historical data as well as a ten-year revenue requirements projection is included in the Appendix of this report. The net revenue requirement for the Power Enterprise averages $94.8 million per year for the fiscal period from FY through FY The following table provides a complete summary of the Power Enterprise Revenue Requirement. 20

22 SAN FRANCISCO PUBLIC UTILITIES COMMISSION REVEN UE REQUIREMEN T FISCAL YEAR ENDING JUNE 30 (DOLLARS IN THOUSANDS) Line Operating Expenses 2. Purchased Power $642 $1,535 $1,520 $1,504 $1, Transmission/ Distribution 17,711 18,770 19,156 19,044 19, Scheduling Coordinator ISO Charges Local Capacity Requirement 2,000 2,040 2,081 2,122 2, Risk Management 4,000 4,080 4,162 4,245 4, Operations & Maintenance 14,968 15,931 16,647 17,397 18, A&G: Power Operations 8,461 8,715 8,976 9,245 9, A&G: Planning A&G: Mgmt & Oversight 5,725 5,897 6,074 6,256 6, A&G: Customer Service Total Operating Expenses 55,229 58,739 60,430 61,664 63, Non-Operating Expenses 16. Rate Stabilization Fund 23,523 23,046 18,755 16,333 13, Public Good s Fund 2,484 2,629 2,676 2,656 2, Cash Funded Capital Expenditures 25,746 27,048 29,835 27,450 26, Debt Service 3,053 5,817 8,867 13,231 17, Total Non-Operating Expenses 54,806 58,540 60,132 59,670 59, Rate Revenue Offsets 23. MID&TID 9,147 8,826 9,005 9,374 9, Surplus Sales 11,143 13,250 14,425 15,372 16, Former Norris Site Total Revenue Offsets 20,673 22,469 23,834 25,163 26, Total Revenue Requirement 89,362 94,810 96,729 96,171 96, Billed Energy (MWh) 992,911 1,053,449 1,074,765 1,068,561 1,074, Effective Unit Cost (cents/kwh)

23 SYSTEM AVERAGE RATES As noted earlier, the Power Enterprise s net revenue requirement calculates to an allin cost of $0.09/kWh. These costs compare favorably to the rates of other public power entities, as presented in the table below. Comparable System Average Rates Fiscal Year PG&E LADWP SMUD City of Santa Clara SFPUC /kwh /kwh /kwh /kwh /kwh The General Fund rate of $ per kwh is not sufficient to recover costs incurred to serve General Fund customers. In addition, the Power Enterprise provides free electricity to certain customers resulting in higher rates on the remaining customers. Separating out loads and revenues from existing General Fund and Free customers, the table below illustrates the resulting adjusted average cost for non-general Fund customers. As shown in the table, the rate subsidy provided to General Fund customers effectively adds $0.02/kWh to the costs of all other customers. General Fund Rate and Rate for Remaining Load Fiscal Year Total Revenue Req. Revenue at GF Rate Retail Revenue Req. Retail Average Rate ($ 000s) ($ 000s) ($ 000s) /kwh ,362 9,628 79, ,810 10,155 84, ,729 10,355 86, ,171 10,304 85, ,680 10,360 86,

24 The adjusted system-average cost for other customers is $0.11 per kwh. This rate is still lower than PG&E s rate but it is also higher than many public utilities in the surrounding area. Although the municipal customer rate design is outside of the scope of this study, assigning appropriate cost responsibility and charging cost based rates can send a price signal for wise use of a limited resource. It is our recommendation that the Power Enterprise develop a rate design that reflects a cost of service approach for all customers including those served at the General Fund rate. SENSITIVITY ANALYSIS To test the robustness of the base case revenue requirement, a sensitivity analysis was performed under three likely stress conditions. Each condition tests the variation in the revenue requirement given specific changing conditions. The three stress conditions tested were: 1. 25% decrease in forward prices for electricity sold on the market during a normal year. 2. $5 million per year in additional cash used to fund capital expenditures, with corresponding reductions in amounts funded with debt. 3. The occurrence of a dry year. The results of the analysis are presented in the table below. Each scenario is independent from the others and the results are not cumulative. The results of the analysis indicates a favorable comparison with other investor owned and public power utilities as presented in the table on the previous page 4. Sensitivity Analysis Fiscal Year Normal Year Loads 25% decrease in forward prices (normal year) $5M add'l in cash capital funding (normal year) Dry Year /kwh /kwh /kwh /kwh Average Deposits into the RSF continue in the stress case scenarios. 23

25 The SFPUC needs to regularly measure and manage key risks. The financial model and decision structure developed in conjunction with this report is an excellent tool to measure and report on risk. The SFPUC should use this report to develop a comprehensive risk management strategy. Using the financial model to monitor risks, then develop and implement risk management policies and procedures will likely require additional staff and modeling resources beyond what is included in this study. It is important to note that PG&E has provided transmission and other services to the City since 1925 pursuant to various interconnection agreements. The City/PG&E Interconnection Agreement facilitates the transmission of Hetch Hetchy power from PG&E s Newark substation to San Francisco to serve City municipal load. After the agreement expires in July 2015, it is likely that the costs for transmission and other services provided under the interconnection agreement will increase. To project transmission and distribution charges after 2015, this report bases its projections on a Hunters Point Wholesale Distribution tariff for Hunters Point, a Transmission Access Charge analysis prepared by the Power Enterprise and MDA projections. 24

26 Cost of Service Analysis INTRODUCTION Cost of service analysis is concerned with the equitable allocation of the revenue requirement to the customer classes of service. This section of the report presents the results of the cost of service study conducted for SFPUC s electric customers and discusses the general approach used to develop the cost of service. OBJECTIVES OF A COST OF SERVICE STUDY The objectives of a cost of service analysis ( COSA ) study are different from those used to determine the revenue requirements for the utility. As discussed previously, a revenue requirement analysis is focused on comparing the projected operating revenues to projected operating and capital expenses for the utility to determine revenue sufficiency and any overall required adjustment to revenues. In contrast, a cost of service analysis is focused on the allocation of the total revenue requirements to the principal functions of the utility and then to each of the customer classes of service. The calculated unit cost of service for each customer class becomes the basis for subsequent rate design. The results of COSA are primarily used to develop cost-based rates for retail electric service to residential and small commercial customers in redevelopment areas at the former Hunters Point Naval Shipyard and on Treasure Island. Secondarily, since the COSA is based on the Power Enterprise s total revenue requirement it also reports the cost to serve existing customers. In the table below, existing municipal and other customers are grouped by customer type: (1) Municipal-Enterprise (2) Municipal-General Fund (3) Free Power (Street Lights) (4) Other Public Agencies and (5) San Francisco International Airport Tennants. While rates for these customer groups are not part of this study it is important to calculate the average cost to serve these groups in addition to the cost to serve retail customers. The cost to serve these customers is determined by allocating a portion of the revenue requirement to each class of service. The allocation process will be discussed later in this section. The table below displays the annual load in MWh for the two retail rate classes and the customer categories for the COSA study period of FY to FY

27 SFPUC Deliveries to COSA Categories Average (MWh) (MWh) (MWh) (MWh) (MWh) (MWh) Redevelopment (residential) 3,861 7,199 8,499 8,407 8,407 7,275 Redevelopment (small commercial) 5,683 8,014 7,797 6,835 6,835 7,033 Municipal-General Fund 256, , , , , ,950 Municipal-Enterprise 173, , , , , ,724 Other Public Agencies 152, , , , , ,107 Streetlights 33,182 35,006 35,693 35,521 35,715 35,023 Airport Tenants 367, , , , , ,671 Total 992,911 1,053,449 1,074,765 1,068,561 1,074,222 1,052,782 The municipal customers are grouped into five categories for the COSA. Commission Resolution No sets the rates for the Water Enterprise, the Wastewater Enterprise, the, the Port of San Francisco, and certain specific municipal activities based on the comparable rate charged by PG&E. These accounts are referred to as Municipal- Enterprise Rate customers. The rate charge to all other municipal activities is referred to as the Municipal-General Fund Rate. The current General Fund rate of $0.0375/kWh became effective in January The majority of the accounts served under this rate are General Fund departments. In addition to municipal departments, certain Other Public Agencies such as the San Francisco School District and the Community College District are served by the Power Enterprise and these other public agencies generally receive the General Fund rate. Although the Airport is an enterprise department and is charged a comparable PG&E rate, energy sales to the Airport include energy subsequently resold by the Airport to its tenants. The 1981 Settlement Agreement stipulates Airport tenants be charged a reduced percentage of the equivalent PG&E rate through the 2013 term of that agreement. Consequently, the Airport is shown as a separate class for the COSA. The final category of municipal accounts is Street Lights which is a free service provided to the City by the Power Enterprise. A list of the accounts corresponding to these categories appears in the Technical Appendix, COSA Results. The cost of service analysis also provides information that enables the Power Enterprise to price electric service as a set of unbundled products and services such as power supply, transmission, distribution and customer services so unbundled rates reflect the costs incurred by the utility for each function. This requires grouping costs by functions and in sufficient detail to permit the subsequent presentation of bundled costs. A cost of service study also insures that demand, energy and customer charges are allocated to system users based on their respective utilization of the electric system. This is accomplished, in part, by grouping costs into functions reflecting the design and 26

28 operation of the electric system demand, energy and customer. Demand costs include the costs for facilities sized to meet peak demands. Energy costs include those costs which vary with the quantity of energy delivered. Customer costs include those costs which vary directly with the number of customers served. The cost of service analysis performed herein separates costs by demand, energy, and customer cost components to fulfill this requirement. Only by pricing electricity in a manner reflecting how costs are incurred (e.g. demand, energy, customer, and direct assignment), will an equitable sharing of costs between and among customers occur. For example, two customer groups with similar energy requirements may have different demand or capacity requirements. The customer group with a higher load factor, i.e. more energy use per kw of demand, will be assigned less cost responsibility for demand costs than the customer group with a lower load factor which requires more generating capacity in relationship to its energy use. This information will be useful in designing appropriate cost based rates for residential and commercial customer classes. COST OF SERVICE PROCEDURES The cost of service study conducted for the SFPUC was performed in three steps. The first step was to functionalize the revenue requirement. Functionalization is the assignment of cost data to the functional activities performed in the operation of an electric system (e.g. power supply, transmission, distribution, customer and direct assignment). Functionalization was accomplished by converting the SFPUC s budgetary cost structure into a functionalized structure. The functions, as used in this study, are defined as follows: Power Supply: The power supply function includes SFPUC s Hetch Hetchy Generating Facilities, the PG&E storage agreement, and purchased power. Transmission: Transmission services also include all those non-avoidable services that a customer must purchase to deliver the purchased power supply to the service area of its utility. These also include costs for ancillary services such as load shaping and regulation. Distribution: Distribution services include all services required to deliver energy from the point of interconnection between the transmission system and the SFPUC s service area to the end user of the power. Administrative and General: A&G related costs include employee salaries and benefits not charged to a particular utility function. Also included are costs such as outside services, pensions and regulatory costs. 27