3. Description of the Application and the Settlement
3.1. SDG&E's Application
SDG&E's application addresses the cost allocation and rate design proposals associated with SDG&E's electric revenue requirement for its 2008 through 2010 GRC. SDG&E proposed increases to its electric distribution and commodity revenue requirements in Phase 1 of its GRC.
In support of its proposals, SDG&E sponsored testimony on its sales forecast,7 the marginal cost methodology used to derive the allocation of costs, and the rate design for the various customer classes.8 In addition, SDG&E sponsored testimony in support of its application that addresses dynamic pricing, including CPP rates. The application also proposes a roll off mechanism to gradually move residential rates towards actual costs, instead of continuing the rate freeze structure imposed by AB1X.
SDG&E's application is linked to the goals in the Energy Action Plan (EAP). The EAP was approved by the Commission and by the Energy Commission on May 8, 2003, and the subsequent EAP II was approved on September 21, 2005. One of the goals of the EAP is to "create more transparency in consumer electricity rates," and to "adopt rates based on clear cost-causation principles." (EAP II, p. 9.) The EAP also highlighted the need for capital investments in the electric infrastructure, and encouraged energy efficiency and demand response. (EAP II, p. 7.) The application supports the goals of the EAP by proposing that: the revenue allocations be based on cost causation; and rate mechanisms for customers be linked to usage and costs through dynamic pricing, such as CPP, peak time rebates (PTR), and time of use (TOU) rates.
Advanced Metering Infrastructure (AMI) plays an integral role in the CPP proposals because it allows electricity customers to track their electricity usage on a real time basis and to respond to price signals through the use of automated technology and meters. We approved the widespread deployment of AMI technology for SDG&E in D.07-04-043.
Revenue allocation is the process whereby the proposed or authorized revenue requirement is allocated among the different rate classes using the marginal costs of those classes. The various marginal costs by customer classes are multiplied by the applicable determinant to calculate the revenue that would be collected were unit marginal costs used as rates. In this proceeding, the revenue allocation is calculated for the distribution function and for the commodity function. The marginal cost revenues by customer class are then reconciled to the authorized revenue requirement to derive the proposed customer class revenue requirements.
The distribution function and the commodity function are two of the ten components which comprise SDG&E's total electric revenue requirements. The allocations for the other eight revenue requirement components are determined in other regulatory proceedings. The distribution function covers the costs of delivering electricity to customers such as poles, lines, substations, customer billing, and accounting. The commodity function covers the costs of the DWR electricity purchases that are assigned to SDG&E, and the costs of utility-retained generation (URG).
SDG&E's application proposes revisions to the distribution and commodity functions. The allocation proposals are based on an Equal Percent of Marginal Cost (EPMC) methodology. The proposed EPMC revenue allocations reflect the use of updated marginal cost of service studies for distribution and generation/commodity, and test-year 2008 sales.
With certain variations, SDG&E's revenue allocation methodology for distribution is consistent with the methodology that it proposed in its most recent Rate Design Window (RDW) proceeding and which was implemented in D.05-12-003.
SDG&E's revenue allocation methodology for generation/commodity is similar to the methodology that it proposed in its most recent RDW proceeding. However, this proposed methodology differs from the methodology that was ultimately adopted in D.05-12-003 as a result of a settlement.
SDG&E's generation/commodity marginal capacity costs are based on the capacity costs of a combustion turbine peaking unit. SDG&E proposes a value of $76.40 per kW based on a real economic carrying charge (RECC) approach. According to SDG&E, this RECC approach is consistent with its past marginal cost-of-service studies and complies with D.05-12-003. SDG&E proposes that generation capacity costs be allocated to customer classes based on the top 100 hours of system load, using the results for three years of load data.
SDG&E proposes rate design changes to the categories of distribution, generation/commodity, and the Competition Transition Charge (CTC). These proposed changes balance SDG&E's objective of moving toward cost-based rates with the competing objectives of rate simplicity, rate continuity, increased customer understanding of rates, and legislative or Commission-directed mandates.
SDG&E's rate design proposals are not dependent on the deployment of AMI. However, as described later, SDG&E's proposals related to dynamic pricing are dependent on AMI deployment.
The proposed distribution rates for the various customer classes are designed to recover the allocated class revenue requirements. SDG&E proposes that the distribution rates be set at the marginal costs of providing service.
For residential rates, SDG&E is proposing a new residential rate option that would apply to customers who install a SES. The proposed schedule, DR-SES, provides TOU pricing to these customers. The proposed schedule provides increased rate incentives for the installation of a SES for smaller usage residential customers, as compared to the incentives under Schedule DR-TOU which incorporates a baseline tier structure and the AB1X rate cap.
SDG&E proposes to continue the use of the Rate Design Settlement Component (RDSC), but that it be renamed the TRAC. Continuing the use of the TRAC will mitigate rate fluctuations by continuing the inverted rate structure and the AB1X rate capping that is currently contained in the RDSC rates.9
SDG&E also proposes other rate design changes for residential customers.
SDG&E proposes that the current five-tier residential rate be reduced to four tiers. This would be accomplished by pricing all usage in excess of 200% of baseline usage at the same rate. As a result, the current structure of applying slightly higher rates for usage in excess of 300% of baseline allowances (Tier 5) would be eliminated.
For the residential customers under the California Alternate Rates for Energy (CARE) program rate, SDG&E proposes that the discounts for high use CARE customers be brought in line with the discounts for low use CARE customers through the use of the four-tier rate structure. Net discounts would be reduced for large-use CARE customers with the proposed use of a four-tier inverted rate structure. CARE customers would continue to receive the legislated 20% line item discount on their bills, and the exemption from the CARE surcharge, California Solar Initiative (CSI) charges, and the DWR bond charge.
SDG&E is not proposing any changes to the baseline allowances. SDG&E contends that its study of current baseline allowances still closely match the target usage identified in D.02-04-026, which addressed baseline allowances in the context of AB1X.
For the rate design of medium and large C&I customers, SDG&E proposes that distribution revenue requirements in excess of the basic service fee revenue continue to be recovered primarily through non-coincident demand charges.
SDG&E is proposing a non-bypassable distribution charge, based on a $ per kilowatt hour (kWh) charge, that would apply to the C&I customers to recover the allocated revenue requirements associated with the: CSI program, Self-Generation Incentive Program (SGIP), hazardous substance cleanup costs, AMI infrastructure costs, and the Advanced Metering and Demand Response Program costs. These cost categories are currently recovered in the distribution rates of large C&I customers through demand charges. Currently, SDG&E's distribution demand charge structure is applicable only to C&I customers served at the primary and secondary service voltages. The new kWh-based distribution rate would enable recovery from all retail C&I customers, including customers at the transmission and substation service voltages.
SDG&E is also proposing to redesign the CTC for medium and large C&I customers from the current demand charge structure to an energy only ($ per kWh) charge. This redesign would have the overall effect of slightly reducing CTC rates for residential, small commercial, medium and large C&I, and agricultural classes.
Generation/commodity rates have been designed to more closely reflect SDG&E's marginal cost of providing service. SDG&E proposes that seasonal commodity rate differences be incorporated in Schedule EECC (Electric Energy Commodity Cost) for several rate schedules that are currently non-seasonal. SDG&E proposes that the current seasonal period definitions used for the distribution rate design also apply to the generation/commodity rate design.
SDG&E's current Schedule EECC rates are entirely energy based. SDG&E proposes that a generation demand charge be incorporated into the Schedule EECC rates for the medium and large C&I rate schedules. The demand charge will more closely reflect the costs of providing generation capacity. SDG&E proposes that the demand charge be phased in over the next several rate design proceedings, and that it be designed to recover the marginal generation capacity costs of $76.40 per kW based on a RECC approach. Due to the significant bill impacts that will result from using a generation demand charge, SDG&E proposes to mitigate the impact on customer bills by setting the rate at 50% of the marginal cost-based level in 2008.
To increase customer understanding of the new demand charge, the structure of the generation demand charge should be dependent on and consistent with the existing demand rate structure of each C&I tariff. For Schedules AL-TOU, AY-TOU and PA-T-1,10 the demand charge would be based on monthly summer on-peak demand, with no ratchet provision.11 For Schedule AD,12 which does not currently have an on-peak demand structure, the generation demand charge would be based on the customer's monthly maximum demand during each billing period. For Schedule A6-TOU,13 the demand charge would be based on the monthly system peak demand charge during the summer season.
For agricultural distribution rates, SDG&E proposes a basic service fee increase of 20% for Schedule PA. For the Schedule A commodity rate, SDG&E proposes to implement a seasonal commodity rate consistent with the EECC energy charges.
For street lighting, SDG&E's rate design proposals were developed using the Lighting Rate Design Model that was part of the settlement adopted in D.05-12-003. The model was modified by using updated billing determinants, escalating updated lighting facilities and maintenance costs to 2008 dollars, and escalating the surcharges for series service to 2008 dollars. Street lighting consists of five different schedules, each of which offers a distinct set of services.
SDG&E's street lighting rate design proposals result in approximately a 13% increase in average rates for the lighting customer class. The primary reason for this increase is due to the increase in the distribution revenue requirement that is allocated to street lighting customers.
Dynamic pricing refers to a rate design structure in which electric use is priced according to the time of day and the response of electric customers to those rates.14 SDG&E refers to these rates as time-differentiated rates or CPP rates. The CPP energy rate is calculated to ensure the recovery of the CPP marginal capacity cost revenues during CPP event hours, in addition to the on-peak marginal energy cost. The intent of these rates is to send customers a price signal to encourage them to curtail usage when a CPP event is triggered. These proposed rates appear in the attachments to the prepared testimony of James R. Magill in Exhibit 10.
CPP rates work in conjunction with SDG&E's AMI deployment plan.15 With the implementation of AMI, all SDG&E customers will eventually have the advanced metering equipment needed to implement CPP rates. It is expected that all of the AMI meters will be installed by the end of 2010. SDG&E is proposing CPP rates for all customer classes in accordance with its AMI meter deployment schedule as shown in Table EF 9-1 in Exhibit 9. SDG&E requests that the proposed CPP rates go into effect in the summer of 2008 for those customers who have AMI meters.
For residential rates, SDG&E proposed a PTR in its AMI proceeding, A.05-03-015. The PTR program provides a monetary incentive to encourage customers to reduce demand during the highest system demand days. In the AMI decision, the Commission adopted a settlement which provided, among other things, that the PTR, CPP, and AMI related dynamic rates are to be decided in this proceeding. (D.07-04-043, p. 14.)
SDG&E proposed in A.05-03-015 that the PTR pay residential customers an incentive, i.e., a rebate, in an amount per kWh for the energy reduced below a customer specific reference level (CRL) during the PTR event hours. The CRL is established through historical usage and adjusted for the specific temperature forecasted for the event day.
SDG&E proposed in A.05-03-015 that small commercial customers with a demand of less than 20 kW, most of whom are on Schedule A,16 automatically convert to a three period TOU rate (AS-TOU) with a demand charge. The TOU rate would have a seasonal summer and winter component. These small commercial customers would also be eligible for a PTR during PTR events, similar to the PTR for SDG&E's residential customers. SDG&E proposes that Schedule A be phased out and that existing and new customers be converted to the new Schedule AS-TOU at the next billing period following 90 days after AMI is installed.
For its medium C&I customers (20 to 200 kW), SDG&E proposed in A.05-03-015 that these customers convert to the default CPP rate similar to that of large C&I customers. For the first 12 months under the default CPP commodity rate, these customers would have bill protection relative to their otherwise applicable rate.17 These customers would also continue to have the option of choosing various applicable demand response rates or interruptible programs. One such option is for these customers to pay a monthly capacity reservation charge (CRC) in the default CPP commodity rate, which allows the customer to choose a specific capacity level for a 12-month period, which cannot be reduced during CPP events. If the customer's usage does not exceed its capacity reservation, CPP commodity prices would not be applicable during the CPP event. Any usage above the customer's purchased capacity would be subject to the CPP rate.
For its large C&I customers (200 kW or more), SDG&E proposed in A.05-03-015 that these customers be subject to a default CPP rate beginning in 2008. For the first 12 months under the default CPP rate, these customers would have bill protection relative to their otherwise applicable rate. These customers could also choose to pay the CRC.
For agricultural customers, SDG&E proposed in A.05-03-015 that these customers be billed on the default CPP rate no sooner than 90 days after the installation of an AMI meter. Bill protection and the other rate and demand response program options, as offered to medium and large C&I customers, would also be available to these agricultural customers.
SDG&E's CPP rate proposals do not impact street lighting customers because their usage usually occurs during the off-peak hours.
SDG&E proposes to conduct measurement and evaluation (M&E) activities for the default CPP rates, the small commercial TOU rate, and the PTR. The objective of this M&E effort is to provide the Commission and other interested parties with an evaluation of SDG&E's demand response implementation activities and the customer response to such activities.
3.2. The All Party All Issue Settlement
The all party, all issue settlement is appended to the November 1, 2007 motion as Attachment 1. The settlement was executed by SDG&E and by 12 of the active parties interested in the settled issues in this proceeding.18
The settlement was the result of discussions among the parties concerning the issues in this proceeding. A notice of settlement was sent to the service list, and the first settlement conference was held on August 29, 2007. At least ten additional all party settlement conferences were held, as well as a number of smaller group conferences. These meetings resulted in the partial settlement among 11 of the active parties, which was the subject of the September 25, 2007 motion for adoption of the partial settlement.
After further discussions, 13 of the active parties agreed to the all party, all issue settlement in mid-October 2007. SDG&E filed its motion on November 1, 2007 requesting that the Commission adopt the all party, all issue settlement.
The settlement resolves all of the issues in this proceeding, which are categorized into the four following areas:
1. Revenue allocation and rate design for all customer classes.
2. CPP for C&I customers.
3. PTR for residential and small C&I customers.
4. A new Distributed Generation-Renewable Tariff (DG-R Tariff).
The settlement, unless specifically addressed in the settlement, incorporates all of SDG&E's proposals on the issues as submitted in its application and the prepared testimony of the SDG&E witnesses.
On the revenue allocation and rate design issues, the parties have agreed to the following:
· SDG&E will perform and incorporate a number of studies and analyses, as listed in Attachment A to the settlement, in its next RDW application or GRC Phase 2 application.
· The avoided generation capacity is set at $67 per kW-year.
· SDG&E shall adopt a sub-metering program substantially similar to the program adopted in PG&E's GRC Phase 2 in D.07-09-004. To record the incremental costs related to implementing sub-metering, SDG&E shall establish a Memorandum Account.
· SDG&E will work with the California Farm Bureau Federation to help agricultural customers evaluate potentially better rate options.
· Revenue allocation is to be in accordance with Attachment C of the settlement. The present and proposed rate design as calculated under the settlement appear in Attachment B of the settlement, and the rates for residential customers are calculated assuming that SDG&E prevails in rolling off the AB1X rate caps.19 The residential rates are subject to adjustment based on the outcome of the decision on the AB1X issues.
· Hearings on the AB1X issues are waived, and the issues are to be addressed in briefs.
· SDG&E withdraws its CARE proposal for residential customers.
· The TRAC is eliminated as a separate line item on the residential customer bill, but will be included as a component within the Public Purpose Program (PPP) charges for billing purposes and will remain a separate line item in SDG&E's tariffs.
· The Tier 4 and Tier 5 residential rates will be consolidated into a single Tier 4 rate, with a differential between Tier 3 and Tier 4 of at least 2 cents per kWh.
· The methodology for inclusion of the CSI costs into residential rates will be similar to that adopted for PG&E in D.07-09-004.20
· On an as available basis, SDG&E will, without charge to the customer, install TOU meters that are available in current inventory, or will become available as a result of meter change-outs of residential customers who install a new SES after schedule DR-SES becomes effective. The TOU rate schedules DR-TOU or DR-SES will be available to SES customers. If no TOU meters are available for new SES customers, the customer may remain on the otherwise applicable tariff, or choose to pay for a new TOU meter to enable a TOU rate.
· The basic service fee for small commercial customers (less than 20 kW) will increase by no more than 5% from the current level, and SDG&E withdraws its proposal to create schedule AS-TOU and its proposal to shift schedule A-TOU customers with demands between 20 kW and 40 kW to schedule AL-TOU.
· The demand/energy rate structure applied to the CTC for C&I customers remains unchanged.
· For C&I customers, a modified rate design approach will be applied to the distribution revenue requirements associated with SGIP, CSI, the Annual Earnings Assessment Proceeding, demand response programs, and electric procurement administration costs.
· Schedule PA winter rates shall remain at existing levels, with all proposed changes applied to summer rates only.
· For street lighting, the Distribution Demand & Customer Cost per kW per year value in SDG&E's original proposal will be replaced by the average of SDG&E's estimate and CAL-SLA's estimate.
On the CPP issues for C&I customers, the settlement provides the following:
· SDG&E's CPP proposal is adopted, except as modified by the settlement, and is to be implemented as the default tariff no later than April 1, 2008.
· Customers may opt out of CPP as provided for in the settlement.
· Customers staying on CPP will have at least one year of Bill Protection.
· CPP customers shall be entitled to reserve an uncapped amount of capacity pursuant to the CRC parameters.
· Every two California Independent System Operator (CAISO) canceled alerts/false alarms shall count as one event toward the CPP annual event cap.
· If the Commission approves Bill Protection for the customers of SCE and PG&E for 2009, SDG&E shall seek Commission approval to extend Bill Protection through 2009.
· CPP imbalances shall be contained within the C&I customer class.
· SDG&E shall analyze the impact of splitting C&I customers into three classes (Class Split Study) of 20 kW to 200 kW, 200 kW to 500 kW, and over 500 kW.
· By November 15, 2008, SDG&E shall file an application that: a) proposes at least one additional split of C&I customer classes; b) includes the Class Split Study as an attachment or exhibit; c) includes, if indicated, an extension of Bill Protection for 2009; and d) incorporates all subsequently ordered Commission changes to SDG&E's CPP tariffs.
For the PTR issues, the settlement provides for the following:
· A two-level PTR incentive with a higher level payment for customers who reduce electric usage below an established CRL with enabling demand response technology, and a lower level payment to customers without such technology. The settlement describes how the CRL is to be calculated for residential and small commercial customers.
· The PTR incentive payment to residential and small commercial customers is designed on a cents per kWh basis that assumes nine event days and an on-peak period from 11:00 am to 6:00 pm. With the agreed avoided generation capacity of $67 per kW-year, this translates to an effective incentive of approximately 98 cents per kWh for the PTR incentive payment. A weighted average rate of 80 cents per kWh will be used as the basis to compute the higher PTR technology incentive payment and the PTR payment without technology. The reduction from 98 cents per kWh to 80 cents per kWh is intended to reduce the structural benefiter's incentive payout.
· All PTR customer incentive payments are paid in each billing cycle based on the customer's sum total event day CRLs and total event period reductions over the entire bill cycle.
· PTR incentive payments costs are to be recovered from the specific residential class and small commercial class that received such incentive payments via the Energy Resource Recovery Account.
· PTR administration, management, customer communications and education expenses are to be recovered via the cost allocation factors as indicated by the outcome of the general cost allocation and rate design adopted in this proceeding.
· M&E of PTR demand response impacts and benefits are to adhere to the M&E protocols, objectives, principles and methods that are expected to be established in the Demand Response Rulemaking (R.) 07-01-041 in early 2008.
· A PTR evaluation sub-committee will be established that will be comprised of representatives from the utilities (SDG&E, SCE and PG&E), the California Energy Commission, the Commission's Energy Division and DRA, and other interested parties. This subcommittee will operate under the Demand Response Measurement Evaluation Committee (DRMEC) that has been established since 2004.
· The PTR evaluation subcommittee will meet prior to the implementation of SDG&E's PTR program to develop a comprehensive evaluation plan that explicitly defines the M&E objectives. The evaluation plan will be submitted to the DRMEC for review. SDG&E will assume the lead role in the PTR evaluation subcommittee and be responsible for submitting the request for proposal and the selection of the contractor or contractors that will conduct the M&E work.
· SDG&E intends to file its PTR implementation plan, program description, and request for M&E funding in its next Demand Response program cycle filing (2009-2011), which is expected to be June 1, 2008 per D.06-03-024.21
Regarding the DG-R Tariff, the settlement provides for the following:
· SDG&E shall offer a new, voluntary tariff (Schedule DG-R) for customers with loads 2 megawatts (MW) and below, who own operational, distributed generation, and the capacity of that operational, distributed generation is 10% or greater of their peak annual load.
· Customers who qualify for Schedule DG-R may opt to use Schedule DG-R or their otherwise applicable rate as the basis for shadow billing under the CPP bill protection proposal.
· Schedule DG-R shall recover all CTC costs through energy charges. The CTC costs recovered through time-variant demand charges shall be shifted to the CTC component of the energy charges and allocated to TOU periods in the same proportion as CTC energy charges.
· Schedule DG-R commodity costs shall be charged on a volumetric basis; no commodity demand charges shall apply.
· The distribution non-coincident demand charge (D-NCDC) for Schedule DG-R will be established as 50% of the as-settled Schedule AL-TOU D-NCDC of $5.36 per kW-month.
· No D-NCDC ratchet shall apply to Schedule DG-R.
· The on-peak distribution demand charges for Schedule DG-R will be recovered through a non-time variant distribution kWh-based charge.
· Cost shifts related to Schedule DG-R commodity demand charge exemptions shall be retained in total C&I commodity charges.
· Cost shifts related to Schedule DG-R distribution demand charge exemptions shall be retained in total C&I distribution charges.
In support of the settlement, SDG&E sponsored the testimony of Steve Rahon which was received into evidence as Exhibit 36.
7 SDG&E's application forecasts a total of 20,652 gigawatt hours (gWh) of electric sales in 2008.
8 The revenue allocation and rate design for the various customer classes are reflected in the attachments to the prepared testimony of Susan M. Claffey in Exhibit 6, and are described in the various exhibits of the SDG&E witnesses.
9 In section 4.2 of this decision, we clarify that existing direct access customers will continue to be exempt from the RDSC, which under the settlement is renamed the TRAC.
10 Schedule AL-TOU is available to all medium and large C&I customers. Schedule AY-TOU is an optional time-of-use rate that is applicable to medium and large C&I customers whose maximum annual demands do not exceed 500 kW. Schedule AY-TOU was closed to new customers as of September 2, 1999. Schedule PA-T-1 is applicable to agricultural customers with maximum monthly demands expected to exceed 500 kW and who meet other qualifying criteria.
11 Once advanced capability meters are implemented, determinants will become available to transition the demand charge to a coincident peak demand charge.
12 Schedule AD is a demand meter rate that has been closed to new customers.
13 Schedule A6-TOU is an optional time-of-use rate that is applicable to medium and large C&I customers whose maximum annual demand in any time period is 500 kW or greater.
14 SDG&E's testimony regarding dynamic pricing appears in Exhibits 9 through 14.
15 Before the AMI program was approved in D.07-04-043, only customers with demands greater than 200 kW had the appropriate interval metering equipment needed to implement CPP rates.
16 Schedule A is a flat rate schedule with a seasonal variation component.
17 The bill protection mechanism provides a guarantee that eligible customers will not be billed more, on an annual basis, for electric commodity service than they would have been billed on their otherwise applicable rate if they had not been placed on the default CPP commodity rate. This mechanism allows customers to gain experience with how their existing operations interact with the default CPP commodity rate without any risk.
18 In addition to SDG&E, the 12 active parties who signed the settlement are as follows: Building Owners and Managers Association (BOMA), California City-County Street Light Association (CAL-SLA), California Farm Bureau Federation (Farm Bureau), California Large Energy Consumers Association (CLECA), California Manufacturers and Technology Association (CMTA), City of San Diego, Division of Ratepayer Advocates (DRA), Federal Executive Agencies, FuelCell Energy, Inc. (FuelCell Energy), Solar Alliance, Utility Consumers' Action Network (UCAN), and Vote Solar Initiative (Vote Solar). The other active parties, Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE), and The Utility Reform Network are interested only in the AB1X roll off issues and do not oppose the settlement.
19 The proposed rates shown in Attachment B of the settlement did not use the bond charge and energy charge that we allocated to SDG&E in D.07-12-030. As a result, those charges will affect the illustrative rates shown in Attachment B of the settlement.
20 In D.07-09-004, residential Tier 1 and Tier 2 rates were increased by the difference between the new CSI rate component and the previously existing component of solar costs embedded in the SGIP costs collected in residential Tier 1 and Tier 2 rates.
21 In D.06-03-024 at page 20, the program cycle is described as 2009-2012.
