Phase 2 of 2018 General Rate Case Policy

Transcription

1 Application No.: Exhibit No.: Witnesses: A.1-0-XXX SCE-01 R. Garwacki A. Guilliatt R. Thomas (U -E) Phase of 01 General Rate Case Policy Before the Public Utilities Commission of the State of California Rosemead, California June 0, 01

2 SCE 01 - Policy GRC Phase Table Of Contents Section Page Witness I. INTRODUCTION...1 R. Garwacki A. Organization of this Volume... II. OVERALL POLICY OBJECTIVES... A. B. California s Clean Energy Goals and the Impacts to the Electrical System... Adherence to Established Rate Design Principles Cost of Service: Rate Structures Should Reflect the Costs of Providing Service to Different Customer Classes and Encourage Economically-Efficient Decision-Making While Avoiding Cross Subsidies... Affordable Electricity: Rate Structures Should Ensure that Customers Have Enough Access to Electricity to Ensure Basic Needs Are Met At An Affordable Cost...1 Conservation: Rate Structures Should Encourage Conservation and Energy Efficiency and the Reduction of Both Coincident and Non-Coincident Demand...1 Customer Acceptance: Rates Should Be Stable, Understandable, and Provide Customer Choice; Changes in Rates Should Consider the Resulting Bill Impacts and Customer Acceptance...1 Rate Simplification / Unification...1 III. COORDINATION WITH OTHER PROCEEDINGS...1 A. SCE s 01 Rate Design Window Application (A ) Background...1 Updated TOU Periods...0 -i-

3 SCE 01 - Policy GRC Phase Table Of Contents (Continued) Section Page Witness... Default CPP...1 RTP Tariff... Option R Enrollment Cap... B. TOU OIR (R ) Guiding Principles and Compliance... Grandfathering Provisions... Dead Band Tolerance Range Analysis... Coordination with the DRP (R ) and IDER (R.1--00) Proceedings... Coordination with Federal Energy Regulatory Commission (FERC) Proceedings... C. Residential Rate Reform (R ) Updates to Tiered, Non-TOU Rate Schedules... Residential TOU Pilots... Residential Default TOU Application (A )... Residential Fixed Charges...0 D. E. F. G. H Demand Response Programs Application (A )...0 Transportation Electrification (TE) Application (A )... Joint IOU Portfolio Allocation Methodology Application (A ) / PCIA OIR... GRC Phase 1 Application Related to Implementation of the CSRP (A )... Summary of Pending Proposals... -ii-

4 SCE 01 - Policy GRC Phase Table Of Contents (Continued) Section Page Witness IV. MARGINAL COST AND REVENUE ALLOCATION PROPOSALS...0 A. Alignment with Cost-Based Revenue Allocation and Pricing... V. RATE PROPOSALS... R. Thomas A. Residential Rate Proposals Baseline... R. Garwacki..... Time-Differentiated Distribution Energy Charges for Residential Customers Served on TOU Rates... Grandfathered Rate Options... Closing and Eliminating Existing Rates with Legacy TOU Periods... Establishing a New Optional TOU Rate Schedule TOU-D-C... Default TOU Rate for NEM.0 Residential Customers... R. Thomas B. Non-Residential Rate Proposals Consolidation of the Existing Option A and R Rates; Removal of the Option R Cap... Elimination of the Existing SOP Rate Options... Grandfathered Rate Options... Schedule TOU-PA- Eligibility Changes... Clarification of Terms General Water Pumping and Sewerage Pumping Related to Agricultural and Pumping Rates...0 New Distribution-Pole-Mounted Rate Option for Street Lighting Customers...0 -iii-

5 SCE 01 - Policy GRC Phase Table Of Contents (Continued) Section Page Witness... Modifications to Schedules LS- and AL- to Update the Pricing Structure and Implement On- Peak Usage Thresholds...1 Economic Development Rate... Food Bank Assistance Rate... Appendix A Alignment with the Vision and Continuing Elements Identified Within the Rates and Tariffs Group of the DER Action Plan... Appendix B Status of the DRP and IDER Valuation Methodologies and the Relationship of These Methodologies to the Data Presented in this Application... R. Garwacki A. Guilliatt -iv-

6 I. INTRODUCTION In Phase of Southern California Edison Company s (SCE) 01 General Rate Case (GRC), the California Public Utilities Commission (Commission or CPUC) will establish marginal costs, allocate revenues, and design rates that will ultimately be applied to SCE s authorized revenue requirements, which are determined in other proceedings, and that will become effective for approximately a threeyear period beginning in 01. The primary objective of this proceeding is to continue an efficient, cost-based, and equitable approach to revenue allocation and rate design, while keeping rates relatively stable and supporting the policy directives outlined by the recent adoption of Senate Bills (SB) (Pavley, 01) and 0 (De León, 01), and the Commission s endorsement of the November, 01 Distributed Energy Resources (DER) Action Plan. California is at the forefront of developing innovative energy policies geared towards a more sustainable environment, and SCE fully supports this goal. For example, as of May 1, 01, nearly,000 SCE customers had installed approximately 1,0 megawatts (MW) of customer-sited, behind-the-meter (BTM) renewable generation, 1 and over 0,000 light-duty electric vehicles (EVs) are currently located within SCE s service territory. In collaboration with cities, employers, apartment owners and other business site owners, SCE recently launched a $ million Charge Ready pilot project to deploy approximately 1,000 to 1,00 EV charging stations. Additionally, in January 01, in response to the directives in SB 0, SCE proposed a portfolio of near- and longterm programs, investments and commercial rates aimed at accelerating widespread transportation electrification (TE). SCE plans to connect at least 0 MW of energy storage to the grid by 0 by installing and contracting for power supplied from numerous energy storage systems. Given this rapid progress toward significant increases in DER adoption now and in the future in support of California s clean energy goals, a more forward-thinking rate design that provides accurate price signals to customers is critical. 1 See Advice 1-E, p.. 1

7 As discussed in more detail below, SCE s proposals build upon and continue SCE s efforts to maintain equitable and efficient retail rate designs and to provide accurate price signals that increasingly reflect new system conditions resulting from California s clean energy policy goals. SCE s proposals balance the need to reflect the impact of evolving system conditions with rate stability so that customers have a smooth transition to the new rate structures and pricing, and build upon the testimony submitted in SCE s 01 Rate Design Window (RDW) Application (A , or 01 RDW), where SCE proposed new time-of-use (TOU) pricing periods for the first time in over 0 years. The link between this Application and the 01 RDW and other open proceedings is discussed further in Chapter III. SCE s key proposals for the determination of marginal costs, revenue allocation and the resulting rate designs include: Establish Retail Generation Rates Based on Updated TOU Periods: SCE uses the updated TOU periods that SCE proposed in the 01 RDW along with 01 marginal generation energy costs, resulting in shifting TOU peak period pricing later in the day from p.m. to p.m., differentiated weekday/weekend pricing, and a daily low-cost matinee period during the winter season Inclusion of Flexible Generation Capacity: SCE incorporates flexible generation capacity, which allocates marginal generation capacity costs over the entire year not just in the summer peak periods as has traditionally been the case and similarly includes time-related generation capacity charges throughout the entire year instead of only in the summer. 0 1 Time-Differentiated Distribution: SCE allocates distribution design demand marginal costs between (1) peak-capacity-related costs that have been time-differentiated, and () Weekends are no longer entirely off-peak. Flexible capacity or ramping refers to the portion of the duck curve where the output from renewable resources decline or go away, while system load remains steady or increases. This type of generation capacity is becoming increasingly necessary to meet the steep ramp in late afternoon periods throughout the year as renewable generation tapers off and demand peaks. These costs relate to peak capacity needs that are based on the hours when the distribution infrastructure will experience peak load to and from customers.

8 grid-related costs. This bifurcation of distribution costs, which is similar to the allocation of generation energy and capacity costs, allows for rate designs that encourage more optimal utilization of the distribution system by both energy consumers and DER providers, while enabling SCE to recover its costs of service. These proposals improve the economic efficiency of SCE s rates and facilitate the adoption of DER technologies while maintaining cost causation principles. SCE also proposes (1) alternate rate options targeted specifically for customers adopting DER technologies and customers who are eligible for TOU period grandfathering, () to increase the baseline allocation to the statutory maximum of 0 percent for residential customers, () an updated economic development rate (EDR) to address the challenging business climate still faced by many of SCE s commercial and industrial (C&I) customers, and () a food bank assistance rate to comply with Assembly Bill (AB) 1 (Bradford, 01). Other rate proposals targeted to specific customers groups are summarized in Chapter V, below, and are more fully described in Exhibit SCE-0. SCE s rate design proposals have been enabled, to some extent, by the deployment of advanced metering infrastructure (AMI or smart meters ) to all customers. Prior to the implementation of smart meters, only larger C&I customers had access to meaningful interval data. Now, virtually all customers can easily access their interval usage data online. This allows customers to make informed decisions about electricity usage and costs, and provides the opportunity for customers to understand and to be able to respond to more dynamic and accurate price signals. Thus, customers can make informed decisions on how to optimize their electricity consumption and demand, ultimately reducing their bills. Moreover, because more accurate price signals can be provided to all customers at both the TOU and functional (i.e., distribution, generation) levels, many of the existing distinctions between rate These costs relate to a throughput or energy-based function that allow for a base amount of electricity flow to and from customers. In Exhibit SCE-0, SCE proposes to recover distribution costs via a new distribution time-related demand charge in the summer in addition to the traditional facilities-related demand charges and energy charges for non-residential customers, and via time-differentiated distribution energy charges for residential customers served on TOU rates.

9 classes have become unnecessary. As such, SCE proposes to modify how it recovers the costs of the final line transformer for customers with demands greater than 0 kw by utilizing both the grid portion of the distribution charge and the traditional customer charge, which will soften the changes in monthly bills that customers face when transitioning to a rate group with a higher peak demand threshold. This is SCE s first step in its rate simplification efforts (i.e., grand unification theory) whereby the historical and somewhat arbitrary rate group distinctions of the past (e.g., demand thresholds, end uses, etc.) become moot and customers are increasingly served on more similar cost-based rate structures irrespective of legacy rate group designations. A. Organization of this Volume Chapter II outlines the clean energy policies and objectives of the California state legislature and Commission related to electric service for customers. Chapter II further discusses how these clean energy policies and objectives must be balanced with the need to adhere to established rate design principles. Chapter II concludes with a discussion of SCE s plan for future consolidation and simplification of rate designs. Chapter III provides an overview of other proceedings that directly relate to this Application, including SCE s pending 01 RDW application because, for the purpose of SCE s proposed marginal costs, revenue allocation, and rate design proposals, SCE has applied the same TOU periods it proposed in its 01 RDW application. SCE also proposes to consolidate the timing of the implementation of rate changes reflecting updated marginal costs, revenue allocation and rate design from this proceeding with the TOU period changes adopted in SCE s 01 RDW. In SCE s 01 GRC Phase 1 Application, A , SCE proposed to replace its existing billing and customer care system with a more modern, stable, and agile customer technology platform, referred to as the Customer Service System Re-Platform, or CSRP. The CSRP project affects SCE s ability to implement significant changes to On June, 01, SCE served rebuttal testimony in the 01 RDW proceeding in which we supported the proposals by various intervening parties to consolidate the implementations of the 01 RDW and this case. SCE requires a timely decision in both proceedings to allow for a February 01 implementation due the constraints imposed by the CSRP.

10 its billing and customer care systems in the Q 01 through Q 00 timeframe, which necessitates a timely resolution of this case. For residential rate design, SCE has coordinated its proposals in this proceeding with its proposals and outcomes from Rulemaking (R.)1-0-01, commonly referred to as the Residential Rate OIR, or RROIR. Chapter III concludes with a discussion of the interplay between this Application and efforts underway in the following proceedings: TOU OIR (R ), the Joint Investor-Owned Utilities (IOUs ) Portfolio Allocation Methodology (A ) / PCIA OIR, SCE s 01-0 Demand Response Application (A ), and SCE s Transportation Electrification Application (A ). Chapter IV provides an overview of the marginal cost and revenue allocation proposals discussed in detail in Exhibits SCE-0 and SCE-0, and includes a summary of the overall impact to revenue allocation. Chapter IV also discusses how this Application continues the movement back toward cost-of-service revenue allocations, especially as it relates to intra-class revenue allocation. Finally, Chapter V provides a high-level summary of SCE s other rate design proposals for both residential and non-residential customers, including SCE s EDR and food bank assistance rate proposals. The IOUs include SCE, Pacific Gas and Electric Company (PG&E), and San Diego Gas & Electric Company (SDG&E).

11 II. OVERALL POLICY OBJECTIVES California is at the forefront of transforming the electric power system to include a cleaner, more diverse energy mix to reduce carbon emissions. With the profound changes currently underway in the electric power industry, today s customers are seeking more choices in how they manage their energy; customers are adopting DERs rooftop solar, onsite energy storage, EVs, and energy management systems to achieve cost savings, cleaner energy, conservation, and enhanced reliability. Equitable and efficient retail rate designs that reflect more accurate cost-of-service price signals driven by system conditions are needed to successfully achieve California s clean energy goals, while at the same time appropriately considering rate stability, customer understanding, and acceptance of revised rate designs. This chapter discusses key policy objectives and impacts related to: (1) both the California state legislature s and the Commission s clean energy goals, () adherence to established rate design principles, and () a fully deployed AMI. A. California s Clean Energy Goals and the Impacts to the Electrical System Recent actions by the California state legislature and Governor Brown illustrate California s commitment to reducing greenhouse gas (GHG) emissions and increasing the deployment of DERs. In 01 and 01, SBs and 0 were enacted to require reductions in GHG emissions by 0 percent below levels by 00, to increase the amount of electricity produced by renewable generation to 0 percent, to double energy efficiency (EE) targets, and to require long-term utility programs and investments to help accelerate widespread TE adoption. These goals are summarized in Figure II-1.

12 Figure II-1 California Clean Energy Goals 1 AB (Perea, 01), enacted in 01, required reforms to utility distribution planning, investment, and operations to minimize overall system cost and maximize ratepayer benefits from investments in preferred resources, while advancing time- and location-variant pricing and incentives to support DERs. Additionally, in his 01 inaugural address, Governor Brown described the key role to be played by the electric grid in enabling California s realization of a clean energy future. Governor Brown described the transformation of the electric grid into a platform capable of supporting a wide range of initiatives: more distributed power, expanded rooftop solar, micro-grids, an energy imbalance market, battery storage, the full integration of information technology and electrical distribution and millions of electric and low-carbon vehicles. Public Utilities (PU) Code Section (c). Edmund G. Brown, Jr., Inaugural Address Remarks as Prepared January, 01, available at

13 To complement and effectuate California s clean energy policies, on November, 01, the Commission endorsed a DER Action Plan, with the goal of accomplishing four key objectives: 1. Provide a long-term vision for DER and supporting policies;. Identify continuing efforts in support of the long-term vision;. Assess and direct further near-term action needed to support the long-term vision; and,. Establish a DER steering committee responsible for sustained coordination of DER activities. In Appendix A, SCE includes an analysis of how the proposals made in this Application align with both the Vision Elements and Continuing Elements identified within the Rates and Tariffs section of the DER Action Plan. The movement toward a 0 percent Renewables Portfolio Standard (RPS), the use of DERs to reduce GHG emissions and the increased focus on facilitating customer choice has implications not only to the operation of SCE s electrical system, but also to the costs incurred to serve customers and the resulting retail rate designs. Historically, SCE has provided power at transmission voltages by managing one-way power flows from a relatively few large generators whose output was generally reliable and predictable. Today, and increasingly in the future, the grid is being transformed from a oneway centralized power delivery system to a multi-directional power delivery exchange to meet California s policy goals and to facilitate customer choice. This new delivery-exchange grid will utilize various technologies and assets, not all of which will be controlled by the utility, to serve customers load when generation output is no longer as reliable or predictable due to the intermittent nature of renewable resources. This transformation is underscored by the fact that solar production in California is expected to be the most prevalent source of renewable generation coming online through The DER Action Plan is formally titled California s Distributed Energy Resources Action Plan: Aligning Vision and Action and is available at ers/michael_j._picker/der%0action%0plan%0summary%0and%0highlights.pdf. 1 CPUC RPS calculator tool, available at

14 The result of this influx of renewables is a rather dramatic shift in the way in which resources are needed and used to meet and serve customer load. This impact is illustrated by the California Independent System Operator s (CAISO s) duck curve net load graph shown in Figure II-. 1 Figure II- CAISO s Duck Curve Showing Steep Ramping Needs and Overgeneration Risk The duck curve illustrates the following key changes to system operating conditions that must be managed as California moves towards a 0 percent RPS, which will increase the depth of the belly of the duck curve: Excess supply of energy during periods of high solar production and low system demands (i.e., matinee periods); 1 California ISO Fast Facts available at

15 Increasingly steeper ramp imbalance as renewable solar production tapers off during the late afternoon hours; Net load peaks shifting to later in the day when renewable production is largely offline; and, Grid congestion management and frequency modulation to reliably meet system demand B. Adherence to Established Rate Design Principles Achieving California s ambitious goals for GHG reductions and increased DER adoption requires rate structures that allow customers to see accurate prices that reflect the costs of electric service. Designing retail rates consistent with established rate design principles incentivizes customer behavior in a manner that most efficiently utilizes electric products and services. A fundamental premise of SCE s proposals is that rates should reflect and be designed to recover the fixed and variable costs that customers impose on the system. Rates should also be relatively stable and understandable. Additionally, customer choice will increasingly be a key consideration in rate design, as customers have more access to their energy usage data and can choose how they prefer to supply their energy needs. In developing its rate design proposals, SCE considered the rate design principles adopted by the Commission in Decision (D.) Table II-1, below, categorizes the RROIR rate design principles into four main criteria: (1) cost of service, () affordable electricity, () conservation, and () customer acceptance. 1 D , pp. -. Additionally, the DER Action Plan contains five Vision Elements within the Rates and Tariffs section that are akin to rate design principles. This Application s alignment with those Vision Elements is described in Appendix A.

16 Table II-1 Rate Design Principles 1 At the end of this section, SCE also discusses progress towards rate simplification and standardization as a fifth objective. 1. Cost of Service: Rate Structures Should Reflect the Costs of Providing Service to Different Customer Classes and Encourage Economically-Efficient Decision-Making While Avoiding Cross Subsidies PU Code Section 1 requires that the Commission establish rates that are just and reasonable. Traditionally, just and reasonable rates were designed based on the marginal costs of service components and the need to recover the utility s authorized revenues. 1 The costs of providing utility services vary with usage characteristics of customer groups and with the facilities needed to serve customers. For example, it costs SCE more to deliver a kilowatt-hour (kwh) of energy at low voltage to 1 See Bonbright, Danielson, and Kamerschen, Principles of Public Utility Rates, specifically, Chapter entitled Cost of Service as a Basic Standard of Reasonableness. See also D , fn.

17 a residential customer on a hot summer evening than it does to deliver a kwh at high voltage to a large industrial customer on a mild spring day. Rates should send appropriate price signals to customers to encourage efficient use of energy and the delivery system, based on the underlying marginal cost of providing these services. This is the foremost and fundamental objective of this Application. Per the General Rate Case Plan (D ), SCE is required to present testimony on unit marginal costs, marginal cost revenue responsibility, and revenue allocation. Almost 0 years ago, the California state legislature directed the Commission to investigate marginal cost pricing as one of six alternatives to then-existing rate structures. 1 After rigorous analysis by utilities, the Commission staff, the California Energy Commission (CEC) staff, and various interveners, the Commission adopted a general methodology for developing marginal costs, 1 emphasizing two points: (1) [a] general methodology for the calculation of marginal costs is necessary for use in proceedings before this Commission 1 (emphasis added); and () [t]he adopted methodology should not be the final statement on calculating marginal costs. 1 Cost-of-service studies have been the fundamental starting point for revenue allocation and rate design ever since. However, various methodological changes have occurred over the last 0 years, both in SCE s GRCs and in other utility proceedings. In addition, the Commission often moderates the bill impacts of a full equal percent of marginal cost (EPMC) revenue allocation. For example, in D.-0-00, the Commission capped the EPMC-based allocation of revenues to temper unduly detrimental bill impacts. 0 1 Assembly Concurrent Resolution No. 1, adopted August 1, 1. 1 D., OII, the investigation into the Marginal Cost Methodology for Electric Utilities. 1 Id., Finding of Fact (FOF). 1 Id., Conclusion of Law (COL) 1. 0 D.-0-00, p.1 and COL, which reads [m]ovement towards full EMPC, tempered with limits where bill impacts become significant, provides a reasonable balance between equity and efficiency in ratesetting. Many more recent decisions have also moderated these movements, largely as a result of all-party revenue allocation settlements (e.g., D.0-0-0, D and D ). 1

18 Cost-based rates help prevent uneconomic decisions by consumers. If inappropriate price signals are sent to customers, uneconomic decisions about electricity consumption and related investments result. If price signals are too high, consumers will invest too much in processes and equipment to offset arbitrarily high price signals resulting in uneconomic bypass of the system. Alternatively, if price signals are set too low, there will be inadequate incentives to conserve or limited incentives for economic investment in EE or other technologies. To align with this first rate design principle, SCE proposes to refine its determination of generation marginal capacity costs by proposing a loss-of-load-expectation (LOLE) allocation that values and allocates capacity based on the capacity resource s ability to provide both peak and ramping/flexibility needs. SCE also proposes to refine the design demand component of distributional marginal costs by allocating design demand marginal costs between (1) peak-capacity-related costs that can be time-differentiated using a peak load risk factor (PLRF) methodology, and () grid-related costs. These refinements more accurately determine how various customer segments impact the key cost drivers used to provide electric service and will also enable new rate design structures that recover these costs while providing more accurate price signals to customers. Examples include a shift in the on-peak period to reflect higher marginal energy costs later in the day, a new super-off-peak period from a.m. to p.m. in the winter season to reflect low marginal energy prices during this period (with the goal of encouraging consumption to address oversupply conditions), new time-related demand charges in the winter season to provide appropriate price signals related to the incorporation of flex capacity as a cost driver, and time-differentiated distribution charges.. Affordable Electricity: Rate Structures Should Ensure that Customers Have Enough Access to Electricity to Ensure Basic Needs Are Met At An Affordable Cost As discussed in Sections IV and V below, SCE s refined revenue allocation and rate design proposals rely on marginal cost principles to allow for economically efficient price signals that are based on cost causation and that limit inter-class and intra-class cost-shifting. For the residential rate class, as more fully discussed in Exhibit SCE-0, SCE proposes to increase the baseline allocation for basic customers to the statutory maximum of 0 percent. This will 1

19 increase the amount of low cost energy available for use by the average residential customer. As residential customers transition to default TOU rates, an increase in the baseline allowance also tempers the bill impacts caused by the transition to more cost-based rates.. Conservation: Rate Structures Should Encourage Conservation and Energy Efficiency and the Reduction of Both Coincident and Non-Coincident Demand AMI has contributed to a change in SCE s ability to both consider and implement timedifferentiated pricing because customers can now evaluate their actual usage with the available interval data and make choices on how and when they use energy. SCE s proposed rate structures reflect this new reality, as well as the rapidly evolving system conditions. In general, SCE s proposed marginal energy costs (on a cents/kwh basis) correlate to the natural gas heat content needed to generate each incremental kwh of electricity. Higher prices in the proper time periods discourage electricity consumption during time periods where the generating resources are less efficient, with lower prices encouraging more efficient generation resources in other time periods. In the past, there has been a singular focus on energy conservation through use of higher prices, which is still important during periods when the system is most constrained (i.e., p.m. to p.m.). However, appropriate price signals that encourage consumption at certain times of the day and year (e.g., a.m. to p.m. in the winter season) are also necessary due to oversupply conditions created by more renewable resources connecting to the grid. Customers are increasingly using DERs to reduce both coincident and non-coincident demand. To encourage the adoption of DER technologies across a broader spectrum of customers and to balance the impact of demand charges on high- and low-load factor customers, SCE s proposed C&I default rate structure Option D recovers 0 percent of the distribution peak capacity costs through energy charges, with the balance recovered through both time-related and non-time-related demand charges. Additionally, because higher marginal energy costs have shifted to later in the day as reflected in SCE s rate design proposals, customers are incentivized to either modify consumption and/or invest in technologies to shift their energy consumption away from high-cost periods. Finally, in addition to its default C&I rate structure, SCE has also proposed various optional rates that encourage customers to 1

20 utilize the electric system more efficiently. For example, SCE s proposed Option E rates, which are tailored for lower load factor customers and customers utilizing DERs, recover time-related generation capacity and a greater portion of distribution costs from a time-differentiated energy price signal instead of a demand charge. Similarly, SCE s commercial EV rates incentivize TE by recovering generation costs and a portion of distribution costs in energy rates. SCE s real time pricing (RTP) rate recovers all generation costs via an hourly energy rate that is temperature-triggered. This enables customers to more precisely avoid high-cost periods and potentially shift usage to periods of generation oversupply, which helps SCE better manage the overall cost of service. To comply with D in the TOU OIR, SCE has proposed grandfathered rate options for eligible solar customers. SCE s concern with grandfathered rate options especially those that maintain outdated TOU periods through 0, as is the case here is that they do not send appropriate price signals to customers or encourage customers to invest in technologies or participate in DR programs that would provide a benefit to the grid. Therefore, while SCE has proposed these grandfathered rate options to comply with D , such structures are not cost-based, and do not encourage energy conservation or reduce coincident and/or non-coincident demand at the right times.. Customer Acceptance: Rates Should Be Stable, Understandable, and Provide Customer Choice; Changes in Rates Should Consider the Resulting Bill Impacts and Customer Acceptance There are many practical considerations when designing rates, including alignment to cost, billing system considerations, consistency across jurisdictions and customer comprehension. In SCE s 01 RDW, for example, when proposing new TOU periods, SCE tried to reflect an appropriate balance between cost alignment, simplicity, and customer preference. SCE did this by (1) proposing the same starting and ending hours for the summer peak and winter peak periods, which is easier for customers to understand and respond to; () retaining only two seasons (summer and winter), which are already familiar to customers; () limiting the number of TOU periods in each season; and, () using forward looking data to maintain TOU periods for at least six years. Appendix C of Exhibit SCE-0 1

21 includes the bill impacts of SCE s rate proposals for various customer classes, which SCE studies to find an appropriate balance in its proposed rate structures. With regard to customer choice, as discussed above and more fully in Exhibit SCE-0, SCE offers various rate options to customers in addition to the standard or default rate options. 1 However, SCE is working to limit the number of optional rates as too many or overly complex rate options can become overwhelming and undermine this objectives of rate design.. Rate Simplification / Unification In addition to the four categories of rate design principles illustrated in Table II-1, above, that affect the choices involved in rate design, there is also a need to simplify the number of existing rate options and better manage the rate offerings available to customers through consolidation and elimination of some rate schedules. The number of rate and service options available to customers has never been greater, and these options are becoming increasingly complex as the traditional role of the utility and the grid evolve. While having more choices can be beneficial, it can also be overwhelming, particularly for less sophisticated customers. Customers need to understand the rates and service options available to them in order to make informed decisions and respond appropriately to price signals. Effective communication and outreach on available rate options is also important to assist customers in making informed choices about their electric service. SCE has taken steps in past GRCs to simplify rate designs and to eliminate rate schedules that are no longer needed. In this Application, SCE proposes to consolidate its existing Option A and Option R rate structures for non-residential customers and offer a single Option E structure. SCE is also proposing to eliminate its existing super-off-peak (SOP) rate schedules since SCE s standard rate option now includes an SOP period. Information from AMI is beginning to render many of the existing distinctions among rate classes meaningless. Traditionally, SCE used load research samples of customers to provide 1 A discussion of the menu of rate options offered by SCE is included in Appendix A. SCE recognizes that the proposed SOP period does not align with existing SOP periods, and will work with parties during this proceeding to determine whether a unique SOP rate option for certain customers is still warranted. 1

22 average cost profiles for distinct rate groups (e.g., residential, commercial, agricultural) with data for estimated coincidence and TOU cost elements assigned to the entire rate group. Prior to AMI deployment, customers in non-tou rate groups were assumed to have load profiles consistent with the load research sample average. This assumption resulted in customers with less costly load profiles subsidizing customers whose load profiles were more costly. Once AMI was deployed, however, defining the proper unit marginal costs (e.g., TOU energy) and charging customers accordingly removed the imprecision caused by applying the same average rate to all customers in a particular rate group. Each customer may and should now pay a rate based on its particular cost of service commensurate with its electrical usage pattern irrespective of the end use of the electricity. Rather than continuing arbitrary rate group designations, SCE is investigating the consolidation of its various C&I and agricultural and pumping (A&P) rate groups. The following examples describe the issue in practical terms. Example #1 The 1. kw TOU-GS-1 customer versus the 0.1 kw TOU-GS- customer: SCE received an inquiry from a customer whose demand reached 0.1 kw, thereby requiring the customer to be served on the TOU-GS- rate schedule. All else being equal, there is little difference in cost for SCE to serve this customer at 0.1 kw instead of 1. kw. However, because the TOU-GS- rate schedule is designed using certain average cost elements, most notably the transformer cost associated with an average TOU-GS- customer, the bill impact associated with moving this particular customer to TOU-GS- is significant. As discussed in Exhibit SCE-0, SCE proposes to help mitigate this issue by recovering a portion of the transformer costs through the facilities-related demand charge for customers with demands greater than 0 kw. The customer s historical demand typically only achieved 1. kw, allowing them to be served on the TOU- GS-1 rate schedule. Customers must not exceed 0 kw more than three time in a 1-month period to remain eligible for TOU-GS-1. 1

23 Example # Commercial Customers Desire to be defined as Agricultural: Due to the A&P class (primarily pumpers ) significant response to TOU pricing signals, SCE s cost studies have historically provided these customers with a reduced overall revenue allocation. As a result, some customers in the agricultural industry whose load profiles are more akin to commercial customers now receive reduced bills by virtue of legacy end-use rate group affiliations rather than because of any reduced cost to serve them. SCE is bringing attention to this issue now so that it can be discussed with parties and, if warranted, pursued further in SCE s 01 GRC Phase application. 1

24 III. COORDINATION WITH OTHER PROCEEDINGS This Chapter summarizes the alignment between SCE s proposals in this Application and other related proceedings. SCE offers this discussion for three reasons. First, the rates and bill impacts in Appendices B and C of Exhibit SCE-0 assume the Commission s adoption of SCE s proposals in A and A Second, it is helpful and necessary to review the proposals made in this proceeding in the context of other related proceedings to evaluate such proposals holistically. Third, in the unlikely event that the Commission ultimately elects not to resolve the related rate design issues in the proceedings discussed below, SCE reserves the right to submit supplemental testimony in this Application to not foreclose the opportunity to effect timely rate design changes without deferring such proposals for three years until SCE s next GRC Phase proceeding. A. SCE s 01 Rate Design Window Application (A ) 1. Background California s ongoing efforts to de-carbonize its electricity grid have important consequences for the appropriate pricing of electricity. According to the CAISO, the increase in intermittent, non-dispatchable energy from renewable generation sources is transforming the traditional electricity demand curve and causing oversupply conditions in periods that have historically been hours of high demand, and a steep ramp in demand during the hours when solar generation tapers off. Because the availability of renewable energy is not always correlated to the times when customers have the highest demand for electricity, the integration of increasing levels of renewable energy into the CAISO grid is changing the cost of electricity at different times of the day and at different times of the year. CAISO document available at 1

25 1 1 1 On September 1, 01, SCE filed A , making the following three proposals: (1) revised TOU periods based on forecast 0 marginal costs for non-residential customers; () implementation of default critical peak pricing (CPP) for more than 00,000 small and medium-sized C&I service accounts and more than 00 large A&P service accounts; and () revised RTP rates. A Scoping Memo was issued in the proceeding on March 1, 01, and provides for a proposed decision in the beginning of 01.. Updated TOU Periods In prepared testimony supporting the 01 RDW, SCE comprehensively analyzed its time-differentiated marginal energy costs (i.e., delivered electricity), generation capacity (i.e., the system s need to meet customers demand for energy during both peak and ramping periods), and certain distribution system costs. SCE determined that its marginal costs are now (and forecast to be) higher much later in the day than the costs reflected in the rate structure currently underlying the existing TOU periods, but that the current definition of summer and winter seasons should remain unchanged. Accordingly, SCE proposed the following TOU periods and seasons: The Commission approved a settlement agreement in D , which provided that SCE would file a RDW application by September 1, 01 and that SCE s RDW proceeding would consider, and SCE would propose (as warranted), new standard TOU periods for non-residential customers in that proceeding. The 01 GRC Phase settlement provided that the TOU periods proposed in the 01 RDW would not modify the revenue allocation among rate groups adopted in D In the 01 RDW, SCE introduced the concept of separating costs associated with the distribution system into fixed (i.e., grid) and peak-load costs. Though this bi-furcation of distribution costs between fixed and peak-load driven costs was only used to inform TOU periods, it has been further refined in this proceeding and incorporated into specific rate design elements to provide accurate price signals to both consumers and providers of energy. 0

26 Table III- SCE s Proposed TOU Periods and Seasons The revised TOU periods proposed in the 01 RDW serve as the basis for the marginal cost and revenue allocation studies in this proceeding, and the proposed rate designs using forecast 01 marginal costs. In rebuttal testimony filed on June, 01 in the 01 RDW, SCE proposed to extend the implementation of the 01 RDW proposals to February 01 to align with the implementation date proposed in this proceeding. This would result in the updated TOU periods being implemented simultaneously with the updated revenue allocation and rate design proposals in this proceeding.. Default CPP To more accurately assign energy and capacity costs to the few days and hours in each year with highest system load conditions, the Commission has established dynamic pricing rates, such as the CPP program. CPP is a dynamic rate that includes an excess energy charge that applies only during periods when wholesale market prices are high or emergency conditions exist on the grid. CPP rates are designed to encourage customers to reduce load during these critical periods, thus providing a measure 1

27 of DR. CPP rates often work in conjunction with TOU rate schedules, where the CPP rate is an overlay to the TOU rate. In the 01 RDW, SCE proposed to implement default CPP for eligible TOU-GS-1, TOU-GS-, and TOU-PA- customers, redefine the CPP event periods to align with the new proposed TOU periods, and redesign certain CPP program elements. In addition, based on recent developments and information concerning the cost and efficacy of default CPP, SCE set forth an alternate proposal to keep CPP as an opt-in program (as opposed to default) for its small commercial customers (i.e., TOU- GS-1).. RTP Tariff SCE also requested authority to simplify and revise its RTP tariffs to better align the price profiles of those rates to actual costs and to encourage greater customer participation. RTP tariffs provide customers with more accurate and granular energy price information, allowing customers to tailor their energy usage and save on energy bills by more precisely avoiding high-cost period usage and conversely, increasing usage during low-cost periods. To simplify the RTP rate structure and increase program enrollment, SCE proposed to reduce the current five-tier summer weekday prices into three day types. The proposed changes to SCE s RTP tariffs represent an appropriate rate design to absorb the oversupply condition identified by CAISO. Specifically, by updating the RTP hourly rates to reflect In 00, SCE s initiated its original optional CPP program designed for large C&I customers with demands greater than or equal to 00 kw. By October 00, eligible customers, including residential, A&P, and C&I customers with demands less than 00 kw, could choose optional CPP rates. In D.0-0-0, the Commission ordered default CPP rates for SCE s large power customers with demands 00 kw and above, and in D , the Commission directed SCE to propose (in SCE s 01 GRC Phase application) default CPP for C&I customers with demands less than 00 kw beginning January 1, 01, and default CPP for large A&P customers beginning February 1, 01. In SCE s 01 GRC Phase application, SCE proposed to transition these same customers to default CPP rates all at once in April 01 to help ensure that (1) all customers had at least two summers worth of TOU usage data, and () SCE would have adequate time to communicate rate impacts of the CPP migration (and customers opt-out rights) in advance of summer but not during the busy holiday season. In D , the Commission approved a settlement agreement, which provided that implementing default CPP for the same C&I and A&P customers should be delayed to coincide with the implementation of the revised standard TOU periods considered in the 01 RDW so as to avoid customer confusion and dissatisfaction.

28 the revised hourly marginal generation energy and capacity costs and by providing these customers with more accurate and granular energy price information, customers on the RTP rate are able to tailor their energy use by avoiding more precisely-defined high-cost periods and increasing usage during low-cost periods (which will now better coincide with periods of generation oversupply). Table V1-1 in Exhibit SCE-1 of A reflects the reduced rates offered to RTP customers during the matinee period in the middle of the day when oversupply conditions are most likely to occur.. Option R Enrollment Cap In the Scoping Memo issued for the 01 RDW, eliminating the cap on SCE s Option R tariffs was added to the scope of the proceeding. SCE s Option R rate schedules are available to C&I customers with demands greater than 0 kilowatts (kws) but not exceeding four MW who employ Renewable Distributed Generation Technologies. Option R was first adopted in D.0-0-0, which approved a settlement resolving SCE s 00 GRC Phase proceeding. As part of the settlement, subscription on Option R was limited to a cumulative installed distributed generation output capacity of MW for all eligible rate groups. The settlement in SCE s 01 RDW adjusted the level of this cap to 00 MW, and provided that the cap would remain at that level until the date on which SCE s tariffs implementing its 01 general rate case (GRC) Phase are effective. However, due to a protest filed by the California Solar Energy Industries Association (CALSEIA), who argued that the Option R cap would likely be reached well in advance of the implementation of SCE s 01 GRC Phase, the Commission included the elimination of the Option R cap as an issue in the 01 RDW proceeding. As discussed in Exhibit SCE-0, SCE proposes to replace Option R with the new Option E rate, which is not capped.

29 B. TOU OIR (R ) 1. Guiding Principles and Compliance In D , the Commission adopted a framework and guiding principles for designing, implementing and modifying the time intervals for the standard TOU rates (i.e., base rates) proposed by utilities in either a GRC Phase or RDW proceeding. The decision highlighted the importance of updating TOU periods to align with costs for the following reasons: By varying retail price signals in relation to utility costs, TOU rates better reflect cost causation and motivate customers to shift their usage to periods that promote more efficient use of the electrical system. This shift should assist in reaching state energy goals by minimizing costs, encouraging energy conservation at appropriate times, and increasing electric supply at times that best serve the needs of the electric grid. 0 The benefit of TOU rates, however, is that a large number of customers making small adjustments in time of energy use will have a significant impact on the load curve, which in turn benefit the grid and reduce systems costs overall. 1 Setting higher TOU rates during peak periods signals that electricity is more valuable at certain times of day and provides customers an incentive to reduce energy use or to generate on-site energy using renewable or other technologies at those times. Ordering Paragraph (OP) 1 of D required that any GRC Phase or RDW application filed after October 1, 01 include testimony in support of compliance with the guidelines adopted in the decision. Appendix A includes a matrix showing how this Application complies with D s guidelines.. Grandfathering Provisions D also provided limited grandfathering of existing TOU periods (i.e., legacy TOU periods) for existing behind-the-meter (BTM) solar customers, who would retain their legacy TOU Base or standard TOU periods, terminology used by the Commission in the Decision, refer to the TOU periods used for marginal cost and revenue allocation studies. TOU pricing utilizes a per-unit-of consumption rate structure that varies depending on the time of day during which energy is consumed, with higher per-unit rates applied during blocks of hours in which electricity demand or costs tend to be higher. 0 D , pp Id., p.. Id.

30 periods, but not rate levels, for a period of five (for residential) or ten (for non-residential) years from their individual interconnection dates (i.e., original permission to operate (PTO) dates). On March 0, 01, in compliance with OP of D , SCE filed Advice -E to set forth its administrative plan for implementing the grandfathering requirements adopted by D , and indicated that it would make such proposals in this Application. SCE s proposed grandfathered rate options for residential and non-residential customers are summarized in Chapter V below and described more fully in Exhibit SCE-0. Because D grandfathered only the TOU periods for eligible customers, SCE is not precluded from making other changes in rate design, including updating the underlying costs and/or modifying other elements, subject to the following: [T]he off-peak period for a legacy customer should continue to have a lower rate than the legacy peak period, but the differential should be modified when new TOU periods are implemented for other customers. This new differential should reflect the new marginal cost allocation, but the new electricity price for legacy peak period hours should not fall below the new price for legacy off-peak periods and the new electricity price for legacy off peak periods should not be increased above the price during legacy peak periods.. Dead Band Tolerance Range Analysis D also required SCE to file a Tier advice letter proposing a dead band tolerance range to determine if and when more frequent updates are needed to SCE s standard TOU periods. On March 0, 01, SCE filed Advice 1-E, proposing to establish a dead band tolerance range based on the results of a (a) top-0 and top-0 highest-cost hour assessment and (b) lowest 0 See FOF : The limited grandfathering adopted here for certain solar customers only applies to the definitions of the TOU periods, and not to the TOU period prices. The rate values within those fixed TOU periods, including methods for allocating costs to TOU periods and setting specific rate levels will be litigated in utility-specific rate proceedings. See also FOF : Grandfathering of TOU periods results in customers receiving incorrect time-variant price signals. ; and FOF : The impact of grandfathering on revenue collection is not transparent to participating or non-participating customers. SCE subsequently filed Advice -E-A on April, 01 to supplement Advice -E in its entirety to clarify that the specific rate design proposals for grandfathered customers would be addressed solely in SCE s 01 GRC Phase Application. D , p.. Id., at OP.

31 and lowest 0 cost hour assessment. If the results showed that less than percent of the top 0 and the top 0 highest cost hours fall within the current on-peak period, the dead band tolerance range is exceeded and a more frequent update to the TOU periods may be warranted. Similarly, if less than percent of the lowest 0 and lowest 0 cost hours fall within the current off-peak (or super-off-peak) period, the dead band tolerance range is exceeded and a more frequent update to the TOU periods may be warranted. In compliance with D , Appendix D of Exhibit SCE-0 includes an assessment of whether SCE s existing TOU periods and those proposed in the 01 RDW and used in this Application fall within SCE s proposed dead band tolerance range.. Coordination with the DRP (R ) and IDER (R.1--00) Proceedings In D , the Commission required that SCE include information on the status of DER valuation methodologies being developed in the Distribution Resources Plan (DRP) (R ) and Integrated Distributed Energy Resources (IDER) (R.1--00) proceedings. The purpose of this is to avoid creating multiple separate valuations for DER and distribution level load shifting. This information is included in Appendix B.. Coordination with Federal Energy Regulatory Commission (FERC) Proceedings In D , the Commission also required that, in its next filed GRC Phase, SCE provide any TOU information included in its transmission filings at the FERC or adopted in FERC transmission rate proceedings. 0 SCE does not provide any specific TOU information in its FERC filings. Consistent with the cost allocation mandates and guidance from FERC, SCE allocates transmission cost and revenue responsibility to rate groups based on each rate group s average 1-month D , p. requires that [i]n each IOU s GRC phase proceeding, a comparison should be made between the adopted forecasts and corresponding updates in the actual data supporting the adopted Base TOU time periods. While Advice 1-E is still pending approval by the Commission, SCE s assessment is based on its proposal as filed in Advice 1-E and may be updated if the Commission orders modifications to SCE s proposed dead band tolerance range methodology. D , at OP. Id., p.. 0 Id., at OP.

32 coincident peak (1 CP) contribution. CP data is filed for cost allocation purposes in both SCE s formula transmission rate annual updates 1 and reliability services rate annual filings. C. Residential Rate Reform (R ) The Commission initiated residential rate reform in R In that proceeding, the Commission directed the IOUs to examine residential electric rate design, and ways to implement time variant and dynamic pricing. In October 01, the California state legislature passed AB. Among other provisions, AB (and later SB 0) codified revisions made to PU Code Section, which established certain conditions before residential customers could be subject to default TOU rates. The following sections provide an overview of these residential rate design implementation efforts and proposals. 1. Updates to Tiered, Non-TOU Rate Schedules For the tiered, non-tou residential rates, in 01 and 01, SCE will continue to modify these rates based on the adopted glidepath and advice letter procedure from the RROIR, reflecting any applicable changes to adopted residential revenue requirements, including any changes resulting from updated marginal costs and revenue allocations discussed in Exhibits SCE-0 and SCE-0 and adopted in this proceeding.. Residential TOU Pilots D directed, among other things, the IOUs to begin designing TOU pilots (Optin TOU Pilot in 01 and Default TOU Pilot in 01) to investigate and evaluate PU Code Section restrictions on default TOU in preparation for widespread transition to default TOU in See FERC Docket ER-. See FERC Docket ER1-. For example, increasing the baseline allowance to 0 percent, as proposed in this proceeding, places upward pressure on all rate levels of approximately. percent at a given revenue requirement. This results from billing more kwh lowest tiered rates. To recover the allocated revenue requirement, rate levels must be increased proportionately to maintain the glidepath ratios. However, the change proposed to the baseline allowance is not expected to take place until after SCE achieves its final glidepath tiered rate ratios on January 1, 01. See also Exhibit SCE-0, Appendix F.

33 On December, 01, SCE filed its Opt-in TOU Pilot Plan via Advice -E. The Commission approved Advice -E on March 0, 01. SCE s Opt-in TOU Pilot launched on June 1, 01 and will run through December 01. As designed, the Opt-in TOU Pilot is expected to yield results with respect to hardship imposed on economically vulnerable customers and senior citizens in hot climate zones before the Commission can order or authorize default TOU. On April 1, 01, SCE served its opening testimony in the Section Track in R , sharing the interim evaluation results of its Opt-in TOU Pilot and explaining how these interim results inform the identification of customer groups to be potentially excluded from default TOU under Section. After holding workshops and a limited evidentiary hearing, this matter is currently in the briefing stage with a Commission decision expected later in 01. SCE filed its Default TOU Pilot Plan via Advice 1-E on December 1, 01 and provided supplemental information in Advice 1-E-A on February, 01. The Commission approved Advice 1-E/E-A on May, 01. SCE s Default TOU Pilot targets 00,000 eligible, randomly-selected customers and will default participating customers to one of two default TOU rates. SCE expects to begin mailing Default TOU Pilot communications in December 01, with the earliest customer defaults beginning in March 01. Any customers who are defaulted to, or elect to enroll in, one of the two Default TOU Pilot rate options will be eligible to receive up to one-year of bill protection. SCE proposed to make both of these Default TOU Pilot rates available as optional TOU rates for all customers beginning January 1, 01, as part of A (see below). All efforts related to the Opt-In TOU Pilots should be completed by the time SCE s 01 GRC Phase implements. Therefore, SCE is not addressing anything related to Schedule TOU-DPP, Time-of-Use Domestic Pilot Program, in this Application. PU Code Section (c) states that the commission may require or authorize an electrical corporation to employ default time-of-use rates for residential customers provided that [t]he commission shall ensure that any time-of-use rate schedule does not cause unreasonable hardship for senior citizens or economically vulnerable customers in hot climate zones. See Resolution E-.

34 Residential Default TOU Application (A On April 1, 01, SCE filed A , Application for Approval of Its Proposal to Implement Residential Default Time-of-Use Rates. In this application, SCE proposed to implement default TOU rates for eligible residential customers beginning in the fourth quarter of 01 (Q 01) (Wave 1), with remaining eligible customers subject to TOU default beginning in Q 00 (Wave ). Only non-care and non-fera customers with twelve months of interval data and who reside in SCE s cool and moderate climate zones would be eligible for default TOU in Wave 1. For Wave, customers who did not meet the twelve-month interval data requirement before Wave 1 and new customer accounts who meet this requirement after Wave 1 is initiated will become eligible for default TOU. In addition, if other customers (economically vulnerable customers, customers with seniors permanently residing at a customer s premise, and CARE and FERA customers) are found eligible for default TOU as a result of the Commission s subsequent decision regarding PU Code Sections (c) () and (d), they will be included in the pool of customers that will be subject to default TOU in Wave. SCE also proposed two default TOU rates identical to those approved in SCE s Default TOU Pilot. The proposed rates are designed to reflect up-to-date TOU time periods in compliance with D SCE s proposed Default TOU Rate 1 has as five-hour weekday on-peak period from p.m. to p.m., and Default TOU Rate has a three-hour on-peak period from p.m. to p.m. Both default TOU rates have the same definition of summer and winter months, the same number of SCE filed a motion to consolidate A with R , either in Phase of R or a separate phase. This amounts to approximately 1. million residential customers being eligible for default TOU rates as part of Wave 1. See Advice 1-E. 0 In Advice 1-E, SCE proposed that the two default TOU rates be made available to all residential customers as optional rates beginning January 1, 01. Upon confirmation of the final default rate (expected in June 01), SCE would continue to offer the other default TOU rate as optional since it might better suit some customers lifestyles.

35 TOU periods in summer and winter, and a baseline credit. In addition, both default TOU rates were designed with the goal of minimizing bill impacts and seasonal volatility, while adhering to the rate design principles adopted in D SCE proposed to accomplish rate differentiation for TOU periods solely through its generation rate component, not through delivery charges, consistent with its Default TOU Pilot rates. However, in this Application, SCE proposes to implement time-differentiated distribution via the distribution component of the energy charge. While SCE proposed revised TOU periods for the new rate structures identified in A , updates to the underlying marginal costs for the default TOU rates are included in this Application, as outlined in Exhibit SCE-0. Additionally, as noted above, for all of SCE s existing and proposed residential TOU rate schedules, SCE proposes to implement time-differentiated distribution via the distribution component of the energy charge to provide more accurate price signals to customers related to the underlying costs of service.. Residential Fixed Charges Any new or revised fixed customer charge for the default TOU rate for residential customers will be separately considered in a 01 RDW application to be filed by SCE not later than January 1, 01. The Commission is also expected to issue a decision related to the cost components of any residential fixed customer charge sometime in 01 in the fixed charge track of PG&E s pending GRC Phase proceeding, A D Demand Response Programs Application (A ) On January 1, 01, SCE filed A , Application of Southern California Edison Company for Approval of Its 01 0 Demand Response Programs. In this application, SCE requested Commission approval of its DR programs, activities, and budgets for program years 01-0, as instructed in D In that decision, the Commission adopted an overarching goal that 1 In D.1-0-0, the Commission provided direction and guidance to focus on existing models of DR programs and activities and incorporate the full cost for program administration including incentive costs previously determined in other regulatory proceedings. 0

36 IOU DR programs shall assist California in meeting its environmental objectives, meet the needs of the grid, and enable customers to meet their energy needs at a reduced cost. SCE s DR portfolio achieves this goal by meeting system and local resource needs with preferred resources while enabling eligible customers to meet their energy needs at reduced cost through program incentives that lower participating customers overall energy costs. Similar to what SCE is proposing in Exhibit SCE-0 in this Application, for the purposes of determining the individual A-Factors assigned to specific DR programs, SCE also used the LOLE model in A (Exhibit SCE-1, Volume ) to determine which hours in the year SCE s grid is most likely to face a 1-in- capacity shortfall event for both peak and ramp since an SCE system shortfall could result from a lack of generation serving peak load or ramp in the future. The TOU definitions used in the design of the incentive rate structure for each DR program are based on SCE s proposed TOU periods in the 01 RDW. However, if needed, SCE intends to submit updated designs for the proposed incentive structures in the 00 mid-cycle review, in order to align rate structures with new TOU period rates scheduled for implementation as part of SCE s 01 GRC Phase proceeding. In D.1-0-0, the Commission instructed SCE to propose incentive levels for the Base Interruptible Program (BIP), Agricultural and Pumping Interruptible (AP-I) Program, and the Summer Discount Plan (SDP) via DR applications rather than in GRC Phase proceedings, as historically has been done. Therefore, SCE does not propose to recalculate the incentive levels based on the value of In D.1-0-0, the Commission set forth the following set of principles for all Commission-regulated DR programs: (1) DR shall be flexible and reliable to support renewable integration and emission reductions; () DR shall evolve to complement the continuous changing needs of the grid; () DR customers shall have the right to receive DR products through a service provider of their choice and the utilities shall support their choice by eliminating barriers to data access; () DR shall be implemented in coordination with rate design; () DR processes shall be transparent; and () DR shall be market-driven leading to a competitive, technology-neutral, open market in California. SCE incorporated these principles when developing its portfolio of DR programs. A at Exhibit SCE-01, p.. Id., Exhibit SCE-1, Volume, p.. 1

37 1 1 capacity or other key determinants presented in this proceeding. The illustrative BIP, AP-I and SDP credit levels shown in Appendix B of Exhibit SCE-0 retain the overall value proposed in A , but have been restructured to align with SCE s proposed Option D rates. E. Transportation Electrification (TE) Application (A ) On January 0, 01, SCE filed A , Application of Southern California Edison Company for Approval of its 01 Transportation Electrification Proposals. In the application, SCE described its vision for TE, which is to reduce GHG emissions and provide clean air and other benefits. SCE also proposed a portfolio of near-term, priority-review projects and longer-term, standard-review programs aimed at accelerating widespread TE adoption, and three new optional (non-residential) EV rates with up-to-date TOU periods that include more accurate price signals to reflect system grid conditions. Figure III- depicts SCE s proposed TOU periods for the new EV rates, which feature a SOP period of a.m. to p.m., every day, and a summer off-peak period for all hours except p.m. to p.m. A , Exhibit SCE-01, pp. 1-. The new EV rates include TOU-EV- (for EV load with monthly maximum demands of 0 kw and under), TOU-EV- (for EV load with monthly maximum demands of 1 kw to 00 kw), and TOU-EV- (for EV load with monthly maximum demand above 00 kw).

38 Figure III- Proposed Weekday TOU Periods for New Commercial EV Rates (Hour Beginning) 1 The TOU periods proposed above are consistent with what SCE proposed in the 01 RDW. The new optional EV rates include a five-year introductory period during which SCE will not assess monthly demand changes (instead, customers bills will consistent primarily of volumetric energy charges), a five-year intermediate period in which demand charges are phased in, and, finally, stable demand charges after years that will be lower than what new EV customers would pay on their otherwise applicable non-ev commercial rates today. SCE s current non-residential EV rate schedules (i.e., TOU-EV-, TOU-EV- and TOU-EV-) include a feature that limits demand charges on the EV account when the EV account is located on the same premises as a non-ev host account. For both the EV and host accounts, the customer is subject to transmission and distribution facilities-related demand (FRD) charges, except the customer is not responsible for paying the FRD charges registered on the EV account if the host account s monthly maximum demand is higher than the monthly maximum demand