3. Settlements
On behalf of the Settling Parties,4 PG&E filed four motions for adoption of settlement agreements. The first motion, filed on February 9, 2007, was for marginal cost and revenue allocation. The second motion, filed on March 16, 2007, was for residential rate design, streetlight rate design, and medium and large light and power rate design. The third motion, filed on April 27, 2007, was for small light and power rate design, and commercial building master metering. The fourth motion, filed on May 4, 2007, was for agricultural rate design. The five rate design settlement agreements and the commercial building master meter settlement agreement are supplemental to the marginal cost and revenue allocation settlement agreement filed on February 9, 2007. The rate design settlement agreements use the revenue allocation agreed to in the February 9 settlement and address rate design issues that were not resolved in that settlement.
The entirety of PG&E's request in this proceeding is resolved by the marginal cost and revenue allocation settlement agreement, the five supplemental rate design settlement agreements and the supplemental commercial building master meter settlement agreement. The commercial building master meter settlement agreement is contested by TURN. All other settlement agreements are uncontested.
The marginal cost and revenue allocation (MCRA) settlement agreement addresses three major issues. First, the Settling Parties agree that the primary purpose of determining marginal costs in this proceeding is to establish the cost of providing service by rate group for the generation and distribution functions. Since marginal costs were last adopted for revenue allocation and rate design purposes in 1993, the Settling Parties agree that this proceeding should result in updated marginal costs. While the Settling Parties disagree on the specific principles that should be employed to calculate marginal costs, the Settling Parties generally agree on the marginal cost values to be employed for the defined purposes described in this settlement agreement.
Second, the Settling Parties agree that electric revenue should be allocated on an overall revenue-neutral basis. This settlement agreement begins with the principle that generation and distribution revenue should be adjusted 85% of the way from then-current distribution and generation revenue to revenue at equal percent of marginal cost (EPMC), as defined in the settlement agreement. This settlement agreement includes additional key allocation principles and, as a final step, the Settling Parties agree that the annual average bundled rates will be limited by adjusting the generation allocation such that total bundled rates change as provided below, with any resulting shortfall to be collected from all other customer groups except Standby based on an equal percent of generation revenue.
· Residential Class: 2.8%
· A-10 Class: -5.0%
· E-19 Secondary (firm and non-firm combined): -9.0%
· Agricultural Class: 4.0%
· Streetlighting Class: -9.0%
· E-20 Transmission Firm: 0.0%
· E-20 Primary Firm: -2.0%
· E-20 Secondary Firm: -9.0%
Third, this settlement agreement addresses rate changes between GRCs. The Settling Parties agree that each customer group will be held responsible for approximately the same percentage contribution to each component of rates. This will be accomplished by implementing changes to the revenue requirement for each component by applying to each rate schedule the same percentage change to rates by component required to collect the revenue requirement for that component, with specific exceptions to this treatment set forth in the settlement agreement.
The residential rate design settlement agreement describes the manner in which residential rates will be designed and includes the following fundamental components:
· Total bundled residential California Alternate Rates for Energy (CARE) rates will remain unchanged subject to the provisions of the February 9 settlement.
· Residential baseline quantities will be revised in accordance with PG&E's testimony, subject to the Assembly Bill (AB) 1X restrictions on residential customers for usage up to 130% of baseline. Baseline quantities and revenue-neutral rate adjustments will be phased in beginning on May 1, 2008 for electric customers and April 1, 2008, for gas customers, subject to certain caveats.
· Total bundled rates for usage up to 130% of baseline will not be changed so long as AB 1X's rate restrictions are effective, subject to certain caveats. While such restrictions are effective, revenue increases to the residential class will be implemented as proportional changes to the generation surcharges in Tiers 3, 4, and 5, and revenue reductions to the residential class will be implemented by proportionally reducing generation surcharges in Tiers 3, 4, and 5.
· If a reduction to the residential class in excess of 3% is expected, PG&E will consult with DRA and TURN to determine the proper method of allocating that revenue between tiers, but rates for usage up to 130% of baseline will not be reduced.
· Distribution and generation rates for non-CARE residential rate schedules will be differentiated by tier, and distribution and generation revenue on non-CARE rate schedules will be collected in each tier in the same proportion as the generation and distribution revenue is allocated to each rate schedule, prior to determining rates for the California Solar Initiative (CSI).
· The CSI rate will be determined as an equal proportion of pre-CSI distribution revenue in each tier as required to collect the CSI revenue allocated to the non- CARE residential schedules. Special provisions apply to customers taking service on the Family Electric Rate Assistance (FERA) program.
· The master-meter discount for Schedules ET and ES agreed to in PG&E's 2003 GRC Phase 2 proceeding will remain in place until a new electric master meter discount is adopted in another PG&E rate design proceeding.5
The residential settlement also includes provisions regarding the minimum average rate limiter for residential master-metered customers that receive a submeter discount; CARE customers taking direct access (DA) and community choice aggregation (CCA) service; ongoing time-of-use (TOU) meter charges for voluntary residential rate schedules; franchise fee surcharge calculation for DA and CCA service; time-variant tariffs for solar customers; time-of-use schedule for multifamily accounts currently eligible to take service under Schedules EM or EML; customers on submetered rate schedules and eligibility for CSI incentives; revisions to Schedule E-9 for electric vehicles; and timing of rate changes.
The streetlight rate design settlement agreement describes the manner in which rates for streetlight customers will be designed and includes the following fundamental components:
· Non-energy streetlight rates are set forth in Exhibits A and B to the settlement.
· A specific formula will be used to calculate the energy charge for streetlights.
· There will be an upper-most limit of 150 watts of non-conforming load on customer-owned streetlight circuits.
The streetlight settlement also includes provisions regarding Schedule TC-1 (traffic control service) and additional streetlight rate design matters as set forth in PG&E's direct testimony. The streetlight settlement includes attachments with draft tariffs required to implement the settlement's terms.
The medium and large light & power (MLLP) rate design settlement agreement describes the manner in which rates for the customer class will be designed and includes the following fundamental components:
· The basic rate designs for each of the applicable MLLP rate schedules will be updated upon settlement implementation using the methods underlying development of the illustrative settlement rates for Schedules A-10, A-10 TOU, E-19, E-20, and Standby presented in Exhibit A to the settlement.
· There will be one additional modification of PG&E's MLLP proposals to ensure that total bundled service volumetric rates by TOU period under Schedules E-19 and E-20 will vary at least in proportion to the variation in PG&E's marginal energy costs. That is, for service at transmission and primary distribution service voltages, Schedule E-19 and E-20 TOU generation energy charges will be set residually so that the sum of generation energy charges and those non-bypassable charges that do not vary by TOU period vary in direct proportion to the TOU profile established by the settlement generation energy marginal costs.
· PG&E's proposed customer charges for the MLLP rate schedules are reasonable, and the ongoing monthly TOU meter charges currently applicable for customers taking voluntary TOU service under Schedules E-19V and A-10 TOU should no longer be applied when the customer's existing TOU meter is replaced as part of the Advanced Meter Infrastructure (AMI) Project and the new meter is activated and used for billing.
· Rate Limiters for Schedules E-19 and E-20 will be modified so that summer season average rate limiters will continue for Schedule E-19 and E-20 customers taking service at secondary and primary distribution voltages (at revised levels set forth in Exhibit A to the settlement).
The MLLP settlement also includes provisions regarding standby service rates, non-firm customers transferring to base interruptible program Schedule E-BIP and enrolling on Schedule E-DBP (PG&E's demand bidding program), franchise fee surcharge calculation for DA and CCA customers, and timing of rate changes.
The small light & power (SLP) rate design settlement describes the manner in which rates for that customer class will be designed and includes the following fundamental components:
· Revenue neutrality will be established between Schedules A-1 and A-6 in two steps. In the first step, upon settlement implementation, Schedules A-6 and A-1 will move approximately two-thirds of the way toward full revenue neutrality. The movement toward full revenue neutrality will occur on January 1, 2010, and will be maintained until the next GRC Phase 2 proceeding. These adjustments will correct current inappropriate rate relationships whereby customers can realize significant bill savings simply by switching from Schedule A-1 to A-6 despite having poor TOU load profiles.
· The basic rate designs for each of the applicable SLP rate schedules will be updated upon settlement implementation using the methods underlying development of the illustrative settlement rates for Schedules A-1, A-6, A-15, and TC-1 presented in Exhibit B to the settlement.
· The maximum demand limit for up to a cumulative total of 20 megawatts of solar system capacity among participating Schedule A-6 customers who install a solar photovoltaic system will increase from 500 kilowatts to 1,000 kilowatts. This increase will allow a customer whose maximum billing demand has been between 499 and 999 kilowatts for at least three consecutive months during the most recent 12-month period, or who otherwise is currently taking service, or would be required to take service, on Schedule E-19 on a mandatory basis to voluntarily move to Schedule A-6, so long as the customer installs a solar photovoltaic system that meets at least 20% of the measured maximum demand. Current mandatory Schedule E-19 solar customers who meet these criteria will have a one-time option to switch to Schedule A-6 within 90 days of settlement implementation, and will count toward the 20 megawatt pilot program cap.
· The ongoing monthly TOU meter charges currently applicable for customers taking voluntary TOU service under SLP schedules will cease once the customer's existing TOU meter is replaced as part of the AMI Project and the new meter is activated and used for billing.
· The calculation of the CARE discount for commercial CARE customers under Schedule E-CARE shall be based on a rate per kWh discount, rather than the current methodology, which is tied to percentage discount, surcharges, and June 10, 1996 rates. The new methodology will improve customer understanding of the rate, simplify billing, avoid the current requirement to calculate a phantom bundled bill for DA commercial CARE customers, and maintain parity between residential and commercial CARE average discount percentages.
· Revised SLP TOU tariffs are deemed to fulfill the requirements of Senate Bill (SB) 1, Public Utilities Code Section 2851(a)(4), in terms of creating the maximum incentive for ratepayers to install solar systems, but settling parties are not restricted from taking positions they deem appropriate in a subsequent proceeding that addresses time-variant rates. However, prior to the next GRC Phase 2 proceeding, no settling party may argue that the SLP TOU rates do not meet the SB 1 requirement.
The SLP settlement also includes provisions regarding the SLP fixed monthly customer charge, the special facility charge related to direct current electrical service on Schedule A-15, and the franchise fee surcharge calculation applicable to DA and CCA service.
The agricultural settlement describes the manner in which agricultural rates will be designed and includes the following fundamental components:
· The basic rate designs for each of the applicable agricultural rate schedules will be updated upon settlement implementation using the methods underlying development of the illustrative settlement rates for Schedules AG-1, AG-R, AGV, AG-4, AG-5, and E-37 presented in Exhibit B to the settlement. These methods include a general widening of TOU energy charge differentials and mitigation of summer maximum demand charges where necessary.
· Customer charges for Schedules AG-A, AG-B, AG-C, AG-5B, AG-5C, and AG-4C will be increased as shown in Exhibit B to the settlement.
· The ongoing monthly TOU meter charges currently applicable to voluntary AG TOU rate schedules will no longer be applied as each customer's AMI meter is installed and used for billing.
The agricultural settlement also includes a provision regarding the franchise fee surcharge calculation applicable to DA and CCA service.
The commercial building master meter (MM) settlement agreement describes principles to govern the manner in which commercial building owners may allocate costs to their commercial tenants so that those tenants may receive price signals through the allocation of non-common master meter energy costs. The MM settlement includes the following fundamental components:
· The settling parties (PG&E and BOMA) agree that it is in the public interest that commercial building tenants receive price signals and have the opportunity to participate in dynamic pricing and energy conservation programs.
· PG&E and BOMA agree that it is in the public interest that building owners participate in dynamic pricing and energy conservation programs, and BOMA agrees to encourage its membership to do so, and to timely pass on to commercial tenants dynamic pricing and energy conservation options or incentives that may become available. Revisions to PG&E Electric Rules 1 and 18 designed to accomplish the goals of the MM settlement are attached to the MM settlement.
· Nothing in this MM settlement is intended to create or constitute evidence of a wholesale relationship between PG&E and commercial building owners, a commercial relationship between PG&E and tenants in commercial buildings, or a utility relationship between commercial building owners and their tenants.
· PG&E and BOMA agree that the cost of electricity allocated to commercial building tenants will, in total, be equal to the charges billed by PG&E to the building owners under the Commission approved rate schedule servicing the master meter.
· PG&E and BOMA agree that all attachments and devices on the customer's side of the master meter used to measure tenant electricity use for the purpose of taking advantage of dynamic pricing and energy conservation opportunities shall conform to all applicable safety rules, regulations, and general orders established by state and local governments.
The MM settlement also includes provisions further defining the applicability and limitations of the new rules, regarding participation in Commission proceedings addressing how dynamic pricing and energy conservation programs may be made available to commercial building tenants, and providing for the payment of the costs associated with implementation of the terms of this agreement.
4 The Settling Parties are the following: Agricultural Energy Consumers Association (AECA); Building Owners and Managers Associations of San Francisco, Greater Los Angeles, Orange County, and California (BOMA); California City-County Street Light Association (CAL-SLA); California Farm Bureau Federation (CFBF); California Large Energy Consumers Association (CLECA); California League of Food Processors (CLFP); California Manufacturers & Technology Association (CMTA); California Retailers Association (CRA); California Rice Millers (CRM); California Solar Energy Industries Association (CAL SEIA); Cogeneration Association of California (CAC); Direct Access Customer Coalition (DACC); DRA; Energy Producers and Users Coalition (EPUC); Energy Users Forum (EUF); Federal Executive Agencies (FEA); Indicated Commercial Parties (ICP); PG&E; PV Now; The Utility Reform Network (TURN); Vote Solar; and The Western Manufactured Housing Communities Association (WMA). All parties signed the marginal cost and revenue allocation settlement agreement. Each party signed only those supplemental settlement agreements that pertained to their specific interests.
5 By letter of June 27, 2007 to the Executive Director of the Commission, PG&E, on behalf of itself, TURN, WMA and DRA requested that the deadline for completing a new diversity benefit study, which will be used to determine a new electric master meter discount, be extended from July 1, 2007, to August 1, 2007. That request was reasonable, and since the study was filed by August 1, 2007, we consider the parties to be in compliance with the filing date requirements for the study.
