Application No.: Exhibit No.: Witnesses: A.08-03- SCE-04 Robert Thomas Steve Verdon Cyrus Sorooshian Lisa Vellanoweth (U 338-E) Phase 2 of 2009 General Rate Case Rate Design Proposal Before the Public Utilities Commission of the State of California Rosemead, California March 4 2008
SCE-04 Rate Design Proposal Table Of Contents Section Page Witness I. COMMON PRICING CRITERIA...1 R. Thomas A. Introduction...1 B. The Revenue Requirements Subject To SCE s Rate Design Proposals...1 C. Common Pricing Proposals...2 1. Customer Charge...2 2. Energy Charges...4 3. Peak Demand-Related Charges...5 4. Time-Related Demand Charges on TOU Schedules...6 5. Seasonal Rates...7 6. Supply-Side Alternative Capacity Valuation Methodology...8 7. Peak Time Rebate PTR and Critical Peak Pricing (CPP) Rates...8 D. Nuclear Decommissioning and Public Purpose Program Charges...10 E. Default TOU Rates for Customers with Demands Greater Than 20 kw and Less Than 200 kw...11 F. Super Off-Peak (SOP) Rate Schedules...12 G. Interruptible and Air Conditioning Cycling Programs...13 H. Power Factor Adjustment...14 I. Voltage Discounts and Phase of Service...15 J. Level Pay Plan...16 K. Municipal Surcharges...17 II. DOMESTIC RATE GROUP...18 -i-
SCE-04 Rate Design Proposal Table Of Contents (Cont d) Section Page Witness A. Introduction and Summary of Proposals...18 R. Thomas B. Basic Charge...20 C. Tiered Energy Charges...20 D. Baseline Allowances...21 E. Master-Meter Adjustments...22 1. Description of Master-Metered Schedules...22 2. Diversity and Submetering Discounts...22 3. Basic Charge Applicability To Master Metered Schedules...22 F. Minimum Average Rates for Submetered Schedules...23 G. Schedule D-APS...24 H. DE Discount...24 I. DS, TOU-D and TOU-EV Rate Schedules...24 J. Medical Baseline...25 III. LIGHTING, SMALL AND MEDIUM POWER CUSTOMER GROUP...26 A. Introduction and Summary of Proposals...26 B. GS-1 Rate Group...26 1. Schedule GS-1...26 2. Schedule TOU-GS-1...27 3. Schedule GS-1-APS...27 4. Schedule TOU-EV-3...28 C. GS-2 Rate Group...28 1. Schedule GS-2...28 -ii-
SCE-04 Rate Design Proposal Table Of Contents (Cont d) Section Page Witness D. TOU-GS-3 Rate Group...30 R. Thomas 1. Schedule TOU-GS-3...30 2. Schedule TOU-GS-SOP...31 3. Schedule TOU-EV-4...32 E. TC-1 Rate Group...32 1. Schedule TC-1...32 IV. LARGE POWER CUSTOMER GROUP...34 A. Introduction and Summary of Proposals...34 B. Large Power Rate Design...34 1. Schedule TOU-8...34 2. Schedule TOU-8-BU...36 3. Schedules I-6 and TOU-BIP...37 4. Schedules RTP-2...37 C. Power Factor Adjustment Rate...38 V. AGRICULTURAL & PUMPING CUSTOMER GROUP...39 A. Introduction and Summary of Proposals...39 B. PA-1 Rate Group...40 1. Schedule PA-1...40 C. PA-2 Rate Group...41 1. Schedule PA-2...42 D. AG-TOU Rate Group...42 1. Schedule TOU-PA...42 2. Schedule TOU-PA-SOP...44 -iii-
SCE-04 Rate Design Proposal Table Of Contents (Cont d) Section Page Witness E. TOU-PA-5 Rate Group...44 R. Thomas 1. Schedule TOU-PA-5...44 F. Schedule AP-I...46 G. Schedule TOU-PA-7...46 VI. STREET AND AREA LIGHTING CUSTOMER GROUP...48 A. Introduction and Summary of Proposals...48 B. Rate Design Methodology...49 C. Street Lighting Facilities Costs...51 D. Differential Facilities Rate...51 VII. STANDBY RATES...53 A. Background...53 B. SCE s Proposal for Standby Rate Design...54 C. Development of the Standby Charge...55 D. Compliance with D.01-07-027...56 Appendix A Glossary... Appendix B Rate Comparison... Appendix C Bill Impact Frequency Distribution... Appendix D Dynamic Pricing Options... Appendix E Power Factor Adjustments... Appendix F Baseline Allowances... Appendix G Methodology For Determining Voltage Discounts... Appendix H Master Meter Adjustments... Appendix I Study Supporting Elimination of Schedule TOU-PA-7... R. Thomas R. Thomas R. Thomas S. Verdon R. Thomas S. Verdon S. Verdon R. Thomas -iv-
SCE-04 Rate Design Proposal Table Of Contents (Cont d) Section Page Witness Appendix J Avoided Capacity Valuation Methodology... Appendix K Residential Class Rate Equity... Appendix L Proposed Tariffs and Tariff Changes... R. Thomas C. Sorooshian L. Vellanoweth -v-
SCE-04 Rate Design Proposal List Of Tables Table Page Table I-1 Proposed Customer Charges ($/Customer-Month)...4 Table I-2 Critical Peak Period Pricing and Credits...10 Table VII-3 Effective Demand Factor for Capacity for Capacity Reservation Charge Determination...56 -vi-
1 2 I. COMMON PRICING CRITERIA 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 A. Introduction This chapter describes the rate design proposals common to more than one rate group. Chapters II through VI describe the specific pricing proposals for the Domestic; Lighting, Small and Medium Power, Large Power, Agricultural & Pumping, and Street and Area Lighting rate groups, and proposed changes in rate structure and applicability. B. The Revenue Requirements Subject To SCE s Rate Design Proposals SCE s rate design proposals in this proceeding apply to SCE s proposed revenue requirements for Delivery and Generation services. As noted in Exhibit SCE-3, SCE is proposing illustrative rates set at the full marginal cost-based levels. SCE expects to update both the forecasted 2008 sales and revenue requirement assumptions in its June 2008 update. At that time, SCE will also evaluate the necessity of capping revenue requirement increases to individual rate groups or, alternatively, limiting the movement toward cost based rates for individual rate groups. SCE s proposals do not apply to the rates authorized for the recovery of the California Department of Water Resources (DWR) revenue requirement 1 or to SCE s transmission revenue requirement as authorized by the Federal Energy Regulatory Commission (FERC). 2 DWR s total revenue requirement will be reflected in separate charges in SCE s tariffs and will be recovered in three components: (1) a Bond Charge required for repayment of power procurement costs incurred by DWR in early 2001, (2) a Power Charge required to recover DWR s going-forward power procurement costs applicable to bundled service customers, and (3) the Direct Access (DA) Cost Responsibility Surcharge (CRS) applicable to DA customers. The Bond Charge applies to the total kwh usage of customers who are subject to the Bond Charge. The Power Charge, however, only applies to that portion of the customer s total energy requirements that DWR provides, 1 SCE s customers share of the authorized DWR revenue requirement is recovered based on the currently-effective DWR rate of 8.875 cents-per-kwh. However, the DWR procures only a portion of the power required to meet SCE s bundledservice sales, and the amount of energy provided by the DWR to SCE s bundled-service customers varies monthly. 2 Except to the extent SCE is proposing modifications to certain rate groups which will require a temporary adjustment to how FERC rates are applied. This is discussed in greater detail in Exhibit SCE-3 and in Chapter 3. -1-
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 i.e., power requirements in excess of those SCE provides from its retained generation assets and power contracts. SCE estimates that the TOU-GS-3 and TOU-8 DA (Large Group) customer groups undercollection amount will be fully recovered by June 2009, prior to the effective date of rates proposed herein. SCE estimates that the capped CRS and UC will continue to apply to all other DA customer groups until late 2010. As a result, the proposed DA CRS for the capped groups will continue to reflect the current capped rate of 2.7 kwh, while the amount for the large group will no longer reflect the UC amount. In both cases, DA CSR charges reflect SCE s CTC amount, the DWR Bond Charge, and the DWR Power Charge Indifference Amount (PCIA). A comparison of expected rates for April 2008 with proposed full-cost based rates is included in Appendix B of this Exhibit. 3 In order to assess the impact of SCE s rate design proposals in conjunction with DWR charges, the proposed rates shown in Appendix B incorporate illustrative DWR charges assuming 27.85 percent of bundled service customer s sales are provided by DWR. 4 Moreover, because FERC establishes SCE s transmission revenue requirement and associated rate design, the retail transmission rates reflected in this testimony are provided solely for the purpose of illustrating total rates. C. Common Pricing Proposals 1. Customer Charge Generally, SCE proposes to establish monthly customer charges to recover all or a portion of customer-related distribution costs. The customer-related portion of the distribution marginal costs consists of the cost of connecting a customer to the system, i.e., the cost of the final line transformer, service drop, metering and billing. Although a charge set at the full Equal Percentage of Marginal Cost (EPMC) 5/ level for all rate schedules is preferable in terms of economic efficiency, SCE 3 Only the main rate groups are shown in the illustrative rate comparison. 4 SCE has assumed the current Bond Charge of 0.477 /kwh and Power Charge of 8.875 /kwh as proxies for 2009 for its bundled service customers. SCE will incorporate the Commission-approved levels of these charges when rates proposed in this application are implemented in October 2009. 5 EPMC charges result from adjusting the marginal costs to recover the revenue requirement allocated to each rate group. -2-
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 is proposing instead to limit monthly customer charges for certain rate groups to minimize potentially adverse bill impacts. SCE proposes to set the monthly customer charges on all commercial and industrial TOU schedules with demands greater than 200kW at the full EPMC level. An increase to current monthly fixed charges is unlikely to impact the total monthly bill for large customers, and fully recovering fixed costs in this way reduces distortions in variable charges offered under TOU schedules. Because smaller agricultural service customers may still take service on TOU rate schedules, SCE will not propose at this time to move customer charges for service on agricultural TOU schedules to full EPMC levels, but will instead propose a percentage increase consistent with non-tou schedules. For most non-tou rate groups SCE proposes to increase current customer charges 40% towards their full-epmc levels. To mitigate the impact of AB1X restrictions on upper tier rates, SCE is proposing to adopt a Residential monthly customer charge set at roughly 40% of the full-epmc level. SCE is also proposing to set the monthly customer charge for schedules GS-1, TC-1 and Street and Area Lighting customers to the full EPMC level, because these group s customer charges are already within 20% of their full-epmc levels. Proposed customer charges, based on the retail distribution revenue allocation shown in Exhibit SCE-3, Table I-5 are shown in Table I-1 below. 17-3-
Table I-1 Proposed Customer Charges ($/Customer-Month) Current Full Cost Proposed Domestic 0.88 14.26 6.00 GS-1 17.09 25.47 25.50 TC-1 12.47 23.30 23.25 GS-2 94.11 190.99 113.50 TOU-GS-3 364.94 438.81 438.75 TOU-8-Sec 455.44 536.16 536.25 TOU-8-Pri 274.12 287.82 287.75 TOU-8-Sub 2,413.46 2,207.03 2,207.00 PA-1 29.85 87.11 41.25 PA-2 58.57 139.84 74.75 AG-TOU 83.26 239.25 114.50 TOU-PA-5 84.57 209.98 109.75 Street Lights 9.22 28.11 28.00 1 2 3 4 5 6 7 8 2. Energy Charges SCE will charge bundled service customers for energy provided by both SCE and DWR. However, as stated above, the rates designed here are for the recovery of SCE s CPUC-authorized revenue requirements only. Rates designed to recover the DWR and FERC revenue requirements are the subject of other proceedings. 6 SCE proposes to establish energy charges on a per-kwh basis to recover the following: (1) a portion of SCE s retained generation, power contracts, and other fuel and purchase power costs; (2) peak demand-related distribution costs for non-demand metered rate groups; (3) nuclear decommissioning costs; (4) public purpose program costs; and (5) the New System 6 SCE proposes to design generation rates to recover the combined URG and DWR generation revenue requirements applicable to bundled service customers. The authorized DWR power charge is then subtracted from the total generation energy charge to produce, the SCE Generation energy charge. -4-
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Generation Charge (NSGC). For rate schedules where the monthly customer charge is not set at the full- EPMC level, the energy charge will include the balance of customer-related distribution costs. As described in Exhibit SCE-3, bundled service generation and fuel and purchased power revenue requirements (SCE and DWR) are allocated to rate groups based on marginal generation costs. Marginal generation costs consist of marginal energy and capacity costs. These marginal costs reflect the increased cost of generating an additional kwh of energy and adding a kw of generation capacity, respectively. 7 For non-demand metered rate schedules, SCE proposes to recover its generation and fuel and purchased power revenue requirements through energy ( /kwh) charges. For customers served on demand-metered rate schedules, demand charges will be developed to recover the capacity-related portion of generation costs. For these schedules, SCE divides the total allocated generation revenue requirement for each rate group into energy and capacity-related components based on the associated marginal costs. Generation revenues to be recovered through energy charges are established by multiplying the allocated generation revenue requirement by the ratio of energy-related marginal generation costs to total (energy- plus capacity-related) marginal generation costs. The remaining generation revenues are recovered through demand charges. Energy charges designed to recover the DWR power charge and bond charge, FERC Transmission (for non-demand metered customers), Distribution, NDC, PPPC and NSGC revenue requirements are added to the energy charge described above to produce the total energy charge, or charges for Time-of-Use (TOU) rate schedules. 3. Peak Demand-Related Charges SCE s distribution costs that are not reflected in the full-epmc customer charge are by definition demand-related, because they increase as kw demand placed on distribution circuits increases. These costs relate primarily to transformers and substation facilities at the distribution level and will be recovered, on demand-metered schedules, through a kw demand charge applied to customers monthly maximum demand. SCE has analyzed when its distribution circuits peak in order to 7 The development of marginal generation costs is described in Exhibit SCE-2. -5-
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 determine if this demand charge should apply to a billing demand other than the monthly maximum demand, such as maximum demand during a particular TOU period or summer months only. As discussed in Exhibit SCE-2, distribution circuits may peak during different seasons and at different times. In general, based on the data available, there is no predominant TOU or seasonal pattern to justify a billing demand measure other than the monthly maximum demand. For those rate schedules that do not require demand meters but reflect a customer s connected load (e.g., Schedule PA-1), the demand charge will be applied to the account s horsepower (HP) of connected load. For other rate schedules that do not require demand meters, including all Domestic rate group and Street and Area Lighting rate group schedules as well as Schedules GS-1 and TC-1, the demand-related costs of service on the distribution system are recovered through per kwh energy charges. Peak demand-related distribution costs are recovered by a peak demand-related charge from demand-metered customers. With the elimination of the ratchet provision in D.05-03-022, this charge is applied to the customer s maximum demand for each billing cycle. 4. Time-Related Demand Charges on TOU Schedules Currently, SCE has a number of TOU rate schedules with relatively high on-peak 8 demand charges. These charges were originally designed based on pre-restructuring marginal generation costs and the loss of load probability (LOLP) models which assigned most of the marginal generation costs to the summer on-peak period. SCE s generation costs consist of capacity-related and energy-related costs for URG assets, which include SCE-owned generation, QF contracts, interutility contracts, and fuel and purchased power costs. As described in Exhibit SCE-2, SCE proposes to assign generation capacity-related marginal costs to TOU periods based on the likelihood that additional generation capacity would be required. Updated LOLP percentages were used in the current GRC to determine demand charges for TOU schedules. These percentages are, to some extent, still included in 8 The on-peak period on most TOU schedules includes the hours of noon to 6 p.m. in the months of June through September. The on-peak period on the Super Off-Peak (SOP) schedules is limited to the hours of 1 p.m. to 5 p.m. during the months of July through September. -6-
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 TOU demand charges today and reflect the probability of a capacity shortage in every hour summed across established TOU periods. For rate design purposes, SCE proposes to assign generation capacityrelated costs to TOU periods based on factors similar to LOLP developed as part of SCE s marginal cost of service study presented in Exhibit SCE-2. As described in the Energy Charges section, a portion of the SCE generation revenue requirement allocated to each rate group is energy-related and recovered through energy charges. The remaining portion is, by definition, capacity or demand-related. For demand-metered rate schedules, SCE develops TOU demand charges based on the weighted marginal generation capacity costs described above. Marginal cost revenues for generation capacity are developed, by rate group, by multiplying the marginal cost of capacity by each rate group s coincident peak demand. The ratio of this capacity-related marginal cost to total generation marginal cost is then multiplied by the total allocated SCE generation revenue requirement, and TOU demand charges are then developed to recover this portion of the generation revenue requirement. 5. Seasonal Rates SCE proposes to seasonally differentiate its demand charges, as was done for the coincident portion of generation, transmission and distribution (T&D) capacity costs in the past. However, SCE proposes to retain the seasonality, and in some cases the time differentiation, in the design of generation component of these demand rates only, with no seasonal or TOU differences in the T&D components. 9 Seasonal TOU demand charges that recover a portion of T&D revenues were an artifact of pre-restructuring fully bundled rates, and a seasonal component was retained for Distribution demand charges pursuant to the Settlement Agreement in the 2003 GRC. As discussed in Exhibit SCE-2, the correlation between distribution circuit loading and season is not particularly strong. About one-third of SCE s sample circuits experience significant loading in winter, instead of summer. As such, for customers connected to these circuits, seasonally 9 Transmission demand charges, applied to peak demand only, were approved by the FERC and implemented in 2003. -7-
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 differentiated peak demand charges, with higher charges in the summer season, would provide poor price signals. 6. Supply-Side Alternative Capacity Valuation Methodology SCE used the Supply-side Alternative Capacity Valuation (SACV) methodology, developed as part of the DR cost-effectiveness proceeding (R.07-01-041), to determine capacity benefits for the various demand response and dynamic pricing schedules. The methodology compares the resource value of each program by applying a set of discount factors to SCE s line loss adjusted marginal costs, discussed in SCE-2. The factors reflect the relative value of the programs to a Combustion Turbine (CT) resource. This methodology is commonly called the AxB methodology, and is explained further in Appendix J. The A factor adjusts for event duration and call frequency. A program with unlimited calls and unlimited frequency of occurrence would have an A factor of 1.0 reflecting the fact that a program with these parameters has the same resource values as a combustion turbine resource. The B factor adjusts for notification lead time and total callable hours. Programs with day-of-notification have a value of 1.0, while programs with day-ahead notification have a value less than 1.0. In both cases, the B factor decreases as the number of callable hours. The Supply-side Alternative Capacity Valuation methodology also provides for Resource Adequacy Requirements (RAR) by applying a 15% reserve margin to the expected demand value. A distribution reliability component of $10/kW-yr is added to the capacity benefit of day-of programs that can be dispatched at a distribution grid level. An overview of SCE s dynamic pricing proposals is provided in Appendix D. 7. Peak Time Rebate PTR and Critical Peak Pricing (CPP) Rates SCE is proposing new dynamic pricing structures in the form of a Peak Time Rebate (PTR) program for residential customers and Critical Peak Pricing (CPP) rates for all customers. Both the PTR and CPP encourage customers to reduce load by responding to pricing signals during critical peak events. In the case of PTR, customers receive credits when they reduce usage below their customer specific reference level during a critical peak event. The CPP, on the other hand, charges a significantly higher capacity based energy charge during event periods, in exchange for lower rates for non-event period usage or demand. The incentives for both programs were determined based on the -8-
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 event triggers and periods using the SACV methodology. Because the SACV methodology is rooted in URG capacity costs, participation in the PTR and CPP programs will be limited to Bundled service customers. The PTR option will be offered as a default overlay to Schedules D and TOU-D-T customers who have received an SCE SmartConnect meter.. All bundled customers not participating on SDP or CPP are eligible for a PTR credit. Similarly, customers opting for service under SDP or CPP, would be excluded from participating the remaining options. The exclusions are a result of employing the SACV methodology to determine capacity benefits, which treats each demand response or dynamic price load reduction as a purchase of a capacity resource. Allowing customers to participate on multiple programs would be equivalent to paying multiple times for the same load reduction. Most program parameters for PTR and CPP are the same. Both programs will be called on a day-ahead basis and will only be called for a 4-hour period from 2:00 and 6:00 PM, on non-holiday weekdays. Event triggers and opt out provisions for CPP are described in Appendix D. As previously stated, the programs only differ in the way credits are provided. PTR credits will be provided when customers reduce their event period usage below a customer specific reference level. Consistent with SDG&E s proposal in its 2008 GRC, SCE will offer a two-tier incentive designed to encourage the use of enabling technologies and to reduce the affects of potential revenue imbalances, as discussed in SCE- 3. Customers who install enabling technologies, that can communicate with SCE s SmartConnect meters, will receive credits of $1.25/kWh for each kwh reduced below their customer specific reference level. Customers who do not employ enabling technologies will receive a credit of $0.75/kWh. CPP will be available to all customer groups. Customers with peak demands of 200 kw or greater will be placed on default CPP 10, while customers with peak demands less than 200 kw, including Residential and Agricultural and Pumping customers, will be offered CPP as an optional service. The capacity based peak period pricing for default and optional CPP will be charge on $/kwh basis, and reflect various service voltage levels. Offsetting reductions will be applied to non-event 10 Pursuant to Commission Decision (D.) 06-05-016, Ordering Paragraph 2. -9-
1 2 3 4 5 usage energy or demand, depending on the relevant under-lying rate structure. Customers with default CPP (greater than 200kW, demand-metered) will receive reductions in Summer on-peak and mid-peak, and Winter mid-peak time differentiated demand charges ($/kw). Customers with optional CPP will receive energy credits on a $/kwh basis, that will apply to all non-event kwh usage. See Appendix D for more information regarding the PTR and CPP programs. Table I-2 Critical Peak Period Pricing and Credits Less then 200 kw (Day-ahead Program) 2 p.m. to 6 p.m. Critical Peak Period (CPP) Event URG Component Event Energy Charge - $/kwh 1.06 Non Event Energy Credit - $/kwh Domestic (0.0286) Small Commercial (0.0103) Medium Commercial (0.0096) Greater then 200 kw (Day-ahead Program) 2 p.m. to 6 p.m. Critical Peak Period (CPP) Event URG Component Event Energy Charge - $/kwh Secondary 1.06 Primary 1.04 Subtransmission 1.00 TOU-GS-3 and TOU-8 Secondary Non Event Credit - $/kw below 2 kv - Summer On Peak (6.96) Summer Mid - Peak (2.00) Winter Mid - Peak (0.46) TOU-8 Primary from 2 kv to 50 kv - Summer On Peak (6.76) Summer Mid - Peak (1.93) Winter Mid - Peak (0.43) TOU-8 Subtransmission above 50 kv - Summer On Peak (5.89) Summer Mid - Peak (1.59) Winter Mid - Peak (0.29) TOU-PA Agricultural and Pumping Summer On- Peak (4.44) Mid-Peak (1.08) Winter Mid-Peak (0.24) 6 7 8 9 D. Nuclear Decommissioning and Public Purpose Program Charges Pursuant to D. 00-06-034, SCE allocates the Public Purpose Program revenue requirement to rate groups based on the System Average Percentage (SAP) methodology and proposes to recover the revenues allocated to each rate group in a /kwh charge designated in SCE s tariffs as the PPPC. The -10-
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 SAP allocation factors are based on revenues produced from SCE s currently effective rates and forecasted 2009 retail (bundled-service and DA combined) sales. The nuclear decommissioning revenue requirement will be allocated to rate groups based on energy consumption by all retail customers and recovered as a /kwh charge designated in SCE s tariffs as the NDC. E. Default TOU Rates for Customers with Demands Greater Than 20 kw and Less Than 200 kw Starting in 2009, SCE will deploy SmartConnect communicating meters to customers with peak demands less than 200kW. The meters and associated dynamic pricing programs will help increase customer awareness with respect to energy usage on a time-of-use basis and with respect to demand response. SCE is proposing default time-of-use rates for customers with peak demands of 20 kw to 199 kw to facilitate customers adoption of TOU rate schedules with a resulting increase in demand response awareness. TOU pricing has the benefit of rewarding customers for demand response on a year-round basis relative to their otherwise applicable tariffs. Year-round price signals are an important step in bringing about permanent customer behavioral shifts and in bridging the gap between non-tou rates and dynamic pricing rates. SCE analyzed CPP on both a default and mandatory basis, for this class of customers, and determined default TOU with opt-in CPP would have less of an impact on customers as the transition towards dynamic pricing schedules progresses. The following considerations, from SCE s AMI Phase III filing, helped determine SCE s position: 20 21 22 23 24 25 26 (a) (b) Increased customer knowledge regarding energy efficiency and demand response opportunities. Default TOU ensures that all medium usage customers are exposed to dynamic pricing. Even customers opting back to their OAT will be exposed to the goals of dynamic pricing and energy efficiency. Awareness could potentially set the stage for future dynamic pricing changes and a conservation effect for this rate group. Preserves customer choice. Default TOU preserves customer choice by allowing customers the option of reverting back to their OAT. -11-
1 2 3 4 5 6 7 8 (c) Minimize adverse customer reactions. In consideration of customer concerns, the company would prefer to limit the use of mandatory programs. Rate changes inevitably lead to some customers reacting adversely to the new rate. In particular, mandatory rate changes, without the option of other rates, result in more inquiries and reactions from the affected customer group. A default TOU rate is estimated to provide significant demand response, yet provide the additional flexibility of enabling customer choice. Given the benefits of demand response, increased customer awareness, and customer choice, SCE will provide a default TOU rate for all medium C&I customers. 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 F. Super Off-Peak (SOP) Rate Schedules Standard rate schedules for SCE s largest commercial and industrial rate classes provide time differentiated demand and energy prices. These schedules are updated in this proposal to reflect the new marginal costs presented in Exhibit SCE-2 and updated load characteristics of the applicable rate groups. SCE will offer a range of optional and default rate schedules that provide for modified TOU pricing for SCE customers in most rate groups. The modified TOU pricing schedules are available to customers ranging from the Domestic and small commercial service, to the largest commercial and industrial service. Most of the schedules are designed to incorporate SCE s SmartConnect technologies into demand response and dynamic pricing goals set by the Commission. 11 SOP rate schedules are characterized by a combination of very high summer on-peak charges and low super-off peak charges. These rates were designed based on SCE s marginal generation costs when SCE was the sole provider of generation services. Based on SCE s marginal cost study presented in Exhibit SCE-2, these price differentials may no longer be justified on a cost basis. However, consistent with the rate design proposal adopted in D.05-03-022, SCE proposes to continue offering its optional SOP rate schedules for service to commercial, industrial and agricultural customers with peak demands less than 500 kw. Customers choosing SOP rate schedules commonly make significant infrastructure investments to allow them to take advantage of the extreme on-peak / super off-peak rate 11 R.02-06-001. -12-
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 differentials. In the interest of continuing to provide these customers a viable SOP rate alternative, SCE proposes to allow customers currently served on these SOP rate schedules to retain such service until a viable TOU alternative, which adequately reflects the unusual usage characteristics of these customers is developed in R.02-06-001. SCE will update its SOP energy and demand charges based on marginal costs as filed in this application and updated SOP load profile characteristics. SCE recognizes customers with demands greater than 500 kw may also represent opportunities for peak demand reduction through permanent load shifting. For this group of customers, SCE is proposing Schedule TOU-8-Option-A, where the URG demand cost recovery is reflected in volumetric charges rather than TOU demand charges. The proposed rate structure is similar to Schedule TOU-GS-3, Option A, where generation energy charges, on a /kwh basis, recover all energy and capacity-related generation costs. Transmission and Distribution demand charges will be maintained. The resulting structure will primarily benefit customers who shift load away from the on-peak period and customers who install solar generating systems. G. Interruptible and Air Conditioning Cycling Programs SCE has approximately 1,030 customers that are served on interruptible rate schedules (e.g., Schedule I-6, TOU-BIP, and AP-I) which provide for a prescribed load reduction by the customer and approximately 280,020 customers served on Automatic Power Shift (APS) schedules, which allow SCE to cycle on a prescribed schedule the air conditioning systems of the participating customers. SCE proposes to adjust the level of credit for customers served on interruptible rate schedules based on the Supply Side Alternative Capacity Valuation methodology described above, and to retain the current structure of applying credits based on the customers average demand. This rate design proposal is described in more detail in Chapter IV. Pursuant to Commission order in D.05-04-053, SCE will eliminate the Schedule I-6 service option by December 2006. 12 Interruptible customers receive a credit in exchange for their agreement to reduce their load upon request by SCE during local or statewide power emergencies. The capacity that these customers make available reduces the need for SCE to 12 Ordering Paragraph #10. -13-
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 purchase power during hours when conditions will likely have caused prices to rise significantly or may avoid controlled rotating outages. SCE proposes to maintain APS credits offered to residential and commercial customers at their current levels. Because all customers benefit from these programs, the cost of credits paid to participating customers is borne through an energy surcharge imposed on all customers. Pursuant to the Commission s decision in Phase 2 of the Post Transition Ratemaking proceeding, the surcharges paid by all customers for recovery of revenues attributable to interruptible and APS programs are to be reflected in the distribution component of customers rates. 13 In order to ensure that participating customers continue to pay for Delivery-related costs, SCE proposes to limit the overall credit provided to these customers to the distribution energy and generation components of the customer s otherwise applicable tariff. Because transmission and non-bypassable 14 costs are not reduced when SCE interrupts load or cycles the air conditioning load of the participants, these customers should continue to pay the related charges. H. Power Factor Adjustment Power factor is a measure of the efficiency of an electric system. When power factor is low, generation sources must provide a higher voltage to deliver the same number of watts, thus consuming more fuel. To improve power factor, SCE must install additional capacitors. The Power Factor Adjustment (PFA) rate is designed to recover the costs of these capacitors. As discussed in Appendix D, SCE proposes to revise the PFA rates to more closely reflect SCE s cost of correcting for poor power factor conditions. The associated revenue requirement is directly assigned to those classes responsible for the incurrence of power factor-related costs, and rates are designed to recover these revenues from the appropriate customers. 13 D. 00-06-034, p. 105, Ordering Paragraph 14. 14 Non-bypassable charges include NDC, PPPC, DWR Bond Charge, TTA (where applicable) and PUCRF. -14-
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 I. Voltage Discounts and Phase of Service SCE delivers power to its customers at various voltage levels. As discussed in Exhibit SCE-2, SCE s delivery system consists of four voltage levels for the purpose of deriving marginal costs, revenue allocation and rate design: 220 kilovolt (kv) or transmission, 66 kv or subtransmission, 12 kv or primary distribution, and 240 V (volts) or secondary distribution. Service at the transmission level is generally reserved for very large customers, such as wholesale customers. Most of SCE s customers take power delivery at secondary voltage, and a relatively small number of large customers take power delivery at the primary and subtransmission voltage levels. The Large Power customer group consists of three separate rate groups that are defined by delivery voltage levels. As a result, variations in SCE s cost of service resulting from differences in delivery voltage are captured in the revenue allocation process and reflected in the rate design for each Large Power rate group. All other rate groups also include customers who take power delivery at different voltages. For example, although most customers in the GS-2 rate group are served at secondary voltage, a small percentage (less than 1%) take power delivery at primary voltage, and a few customers take service at subtransmission voltage. For these rate groups, rates are designed to recover the costs of delivering power at the predominant voltage delivery level, i.e., the secondary voltage level. As the cost of service varies at different voltage levels, adjustments to rate components must be made for customers who take delivery at voltages different from the voltage typical for the rate group to which they belong. Differences in the cost of service at different voltage levels are caused by: (1) differences in line losses at different voltage levels; and (2) the fact that customers served at secondary voltage level access more of the delivery system than customers served at primary and subtransmission voltage levels. Customers served at secondary and primary voltage levels access the same portions of the delivery system except for final line transformers, which are included in customer-related costs. However, high-voltage metering results in other costs that tend to offset the savings from the final line transformer. Customers served at subtransmission voltage level require an adjustment to the demand- -15-
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 related charges because these customers use neither distribution circuits nor distribution substation facilities. Finally, customers served at either primary or subtransmission voltage levels require small discounts to distribution charges relative to customers served at the secondary voltage level to reflect the lower demand line losses resulting from deliveries at these higher voltage levels. To account for all differences in usage of distribution infrastructure, SCE proposes a discount to the Peak-Demand charge, for demand-metered schedules such as GS-2. Service voltage cost differences for non-demand-metered schedules will be reflected in the distribution energy rates. SCE further proposes to reflect decreased demand-line losses for service at higher voltage levels as a discount applied to the Peak-Demand charge or to the distribution energy charges, depending on the schedule. SCE proposes a second discount to reflect the difference in generation capacity costs for different voltage levels as a percentage discount to the generation component of the Time-Related Demand charge or to the generation energy charges depending on the schedule. Finally, differences in energy-line losses will be reflected as discounts to the generation energy rates for all schedules. Appendix F provides the computations for the various discounts. Finally, SCE provides a discount, or a surcharge, based on phase of service. Service is provided as either single- or three-phase, and is differentiated on a cost basis by the distribution facilities required by the customer. The service-phase discounts and surcharges are based on customer cost differentials. For rate groups predominantly populated by single-phase service customers, such as the GS-1 rate group, SCE has developed a surcharge for customers requiring three-phase service. In contrast, customers in the GS-2 rate group who take single-phase service are provided a discount because the customer charge for GS-2 customers is based on the assumption of three-phase service. SCE s methodology for calculating voltage discounts is discussed in greater detail in Appendix F to this exhibit. J. Level Pay Plan SCE currently offers a Level Pay Plan (LPP) program for its residential and small commercial customers. Participating customers pay a flat bill for 11 months with a true-up in the 12 th month to account for the difference between their actual and levelized bills over the year. SCE proposes to -16-
1 2 3 4 5 6 7 8 9 10 11 12 continue this program for residential and small commercial bundled service customers. Because most of the variability in customer bills results from the variations in energy prices, Direct Access customers are excluded from this billing option. This proposal is consistent with D. 00-06-034 where the Commission allowed the continuation of the existing LPP programs, but prohibited the expansion of these programs to other rate groups. 15 K. Municipal Surcharges Section 6353 requires the Energy Transporter to collect franchise fees for public entities based on the bundled bills, including energy costs, of all customers regardless of their Electric Service Provider (ESP). SCE proposes to continue the current practice for collection of franchise fees to satisfy this statutory requirement. For DA and CCA customers, SCE calculates the franchise fee amount as it would for a similarly situated bundled service customer, and includes the franchise fee as a separate line item on their bills. 16 15 D. 00-06-034, p. 104, Ordering Paragraph 6. 16 This approach is consistent with that adopted for Pacific Gas & Electric Company by the Commission in D. 00-06-066. -17-
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 II. DOMESTIC RATE GROUP A. Introduction and Summary of Proposals For residential customers, SCE makes the following proposals: Monthly Basic Charge (customer charge) for single-family will reflect the 50% of the full- EPMC level customer charge; Maintain a 5-tier rate structure with 5 /kwh differential between Tiers 3 and 5; Apply the overall rate level limitations for baseline allowances and up to 130% of the baseline allowance as established in Water Code Section 80110 and as proposed by SCE in A.05-03-018, except as modified by statute for CSI funding; Maintain the currently effective CARE discount structure; Modify the SCE Generation component for Schedule MB-E, Medical Baseline - Exemption, to provide for reduced rates for customers receiving medical baseline allowances; Retain existing schedules DM, DMS-1 and DMS-2, for master-metered and multi-family accommodations; Maintain existing optional seasonal and TOU pricing schedules DS, TOU-D-1, TOU-D-2, and TOU-EV-1; Replace Schedules TOU-D-1 and TOU-D-2 with a 5-tier TOU rate option (Schedule TOU- D-T); Introduce Peak Time Rebate (PTR) and Critical Peak Pricing (CPP) overlays for most Residential pricing schedules; Update baseline allowances to reflect current usage levels and set baseline allocations to 50% of the average usage for non-all electric customers; and Maintain Schedule DE for utility employees and retirees. The majority of customers in the Domestic rate group, both single-family and individually metered multi-family accommodations, take service under Schedule D, which serves as the basis for -18-
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 development of most other optional rate schedules in the Domestic rate group. As such, changes to the structure of Schedule D will result in similar changes in most, if not all, other domestic rate schedules. Other rate schedules available to domestic customers include: Schedule D-APS, Automatic Powershift, which provides credits during the summer season to residential customers who agree to allow SCE to cycle off their air-conditioners under certain conditions 17 ; Schedule D-CARE, California Alternate Rates for Energy, which provides discounted rates for single-family or multi-family residences meeting certain household income criteria; Schedule DE, which provides discounted rates for utility employees and retirees. Schedule DM, which provides for Domestic service for master-metered multi-family accommodations, residential hotels and recreational vehicle parks. This schedule was closed to new customers on June 13, 1978. Schedule DMS-1, Multi-family Accommodations - Submetered, for Domestic service to master-metered, multi-family accommodations with separately submetered units. This schedule was closed to new customers on December 7, 1981. Schedule DMS-2, Mobile Home Park Accommodations- Submetered, for Domestic service to mobile home multi-family accommodations with separately submetered units. This schedule was closed to new customers for whom construction commenced after January 1, 1997. Schedule DMS-3, Qualifying RV Park Accommodations - Submetered, for Domestic service to single-family accommodations in an RV park with separately submetered units. Schedule DS, Seasonal, which provides for seasonally differentiated rates for residential service. 17 SCE will also offer an air-conditioner cycling program designed for SmartConnect enabled customers. The new program will rely on Programmable Communicating Thermostats (PCTs) to facilitate load reductions. Customers will be eligible to enroll in the new program once they have received a SmartConnect meter. Credits under SCE s proposed PCT program will be set at the same level as the technology enable PTR credit. -19-
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 New Schedule TOU-D-T, which replaces existing Domestic TOU schedules and provides seasonal tiered time-differentiated energy charges. Schedule TOU-EV-1, Electric Vehicle Charging, which provides time-differentiated energy charges for electric vehicle charging installations. SCE is proposing changes to the rates for all residential customers. These changes affect all rate schedules available to the Domestic rate group, primarily through changes made to the Schedule D. B. Basic Charge SCE is proposing to increase the Residential Single Family Basic charge to 42% of the full EPMC level. As discussed in SCE-1, the increase charge will provide greater rate equity to the Residential class by achieving a more even distribution of Residential revenue requirements across the Residential class. The non-care Multi Family basic charge will be set at 75% of the Single Family rate. Basic charges for CARE customers be discounted 20% relative to non-care rates. C. Tiered Energy Charges In response to the energy crisis, in May 2001 the Commission authorized a 5-tier rate structure for residential customers in an attempt to encourage conservation by high usage customers. 18 Water Code Section 80110 prohibits rate increases for usage up to 130% of the baseline allowance. The Commission also exempted CARE customers from rate increases. These policies and the change in rate 18 structure resulted in tier five energy charges in excess of 25 cents-per-kwh. SCE proposes to maintain 19 20 21 22 23 24 25 the current five-tier structure in its proposed rates. The differential between tiers 3 and 5 will be set at 5 /kwh to mitigate the affects of AB1X on upper tires. The current rate structure reflects a differential of 7 /kwh. SCE s proposed five-tier rate structure accommodates the requirements of both Public Utilities Code Section 739 and the restrictions imposed under Water Code Section 80110 in 2001. Under Water Code 80110, total rates for consumption up 130% of the baseline allowance cannot exceed the rate levels in effect on February 1, 2001 so long as the DWR remains responsible for procuring power for the 18 D.01-05-064, Finding of Fact No. 26. -20-
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 electric utilities customers. 19 Tier 1 and Tier 2 energy charges reflect the Residential Non-CARE and Non-FERA allocation of CSI funding. The methodology for allocating CSI revenue requirement to Tier 1 and Tier 2 is discussed in SCE-3. Tier 3, Tier 4 and Tier 5 energy charges will be increased accordingly so that the total revenue requirement allocated to the Domestic rate group is recovered. While the differential between Tier 1 and Tier 2 energy charges is fixed due to the requirements of AB1X, SCE has modified the differential between Tier 3 and Tier 4, and Tier 4 and Tier 5 to be consistent with an overall differential of 5 /kwh. Customers served under Schedule D-CARE currently pay rates that are, on average, 28% lower than standard residential service rates. As a result of the rate design adopted in the Settlement Agreement in Phase 2 of SCE s 2006 GRC, the discount varies by tier. The Tier 1 and Tier 2 energy charges are currently 28% and 22%, respectively, below the standard Domestic rate for usage up to 130% of the baseline allowance. The Tier 3 energy charge for CARE customers adopted in the Settlement Agreement is 23% below the Tier 3 charge under Schedule D for all usage over 130% of the baseline allowance. These percentage discounts reflect the fact that CARE customers are also not required to pay the CARE surcharge, which is designed to recover the CARE discount and is paid by all other retail customers except CARE and Street and Area Lighting customers, 20 the DWR Bond charge, or the CSI program costs. SCE illustrative rates reflect adjusted $/kwh CARE credits in the Distribution rate component at expected rate levels for October 2009. SCE will maintain the current CARE tier structure with a total of three usage tier levels. D. Baseline Allowances SCE proposes to modify baseline allowances to help mitigate the growing disparity between residential baseline and non-baseline rates. SCE proposes to establish baseline levels at 50% of average usage subject to the limitations imposed by AB 1X. 21 SCE contends that this proposal will help alleviate 19 Water Code Section 80110. 20 The CARE surcharge is included in the PPPC rate component. 21 AB 1X froze residential rates for the baseline quantities that were in place when the law was enacted on February 1, 2001. These quantities establish a minimum baseline amount or floor independent from the requirements of PU Code Section 739. -21-