4. Discussion

4.1. Introduction

A proposed settlement is now before us that would resolve all of the issues in this proceeding. The settlement is supported, or is unopposed, by all the parties who actively participated in this proceeding.

In evaluating whether the Commission should adopt or reject a settlement, we rely on the settlement rules set forth in Rules 12.1 to 12.7 of the Commission's Rules. In particular, Rule 12.1(d) provides that: "The Commission will not approve settlements, whether contested or uncontested, unless the settlement is reasonable in light of the whole record, consistent with law, and in the public interest."

4.2. Comparison of the Parties' Original Positions to the Settlement

In deciding whether the settlement meets the criteria for Commission approval, it is useful to compare the prominent features of the settlement with the original positions of the parties. Such a comparison allows us to gauge the compromises that each party made in reaching the settlement.

The original proposal of SDG&E reflects one possible outcome that could have occurred had it prevailed on all of its issues. The original positions of the other parties reflect other possible outcomes had those parties prevailed.

On the revenue allocation of the distribution and commodity revenue requirements, DRA and UCAN both proposed differing allocations which were premised on marginal cost results that used the "new customer only" methodology, instead of the "rental" or RECC methodology that SDG&E used. UCAN concluded that SDG&E's allocation of the revenue requirement to the residential class was $71 million too high. UCAN asserted that SDG&E's calculation of the marginal demand distribution costs was too low, and that SDG&E's calculation of marginal customer costs was too high.

CAL-SLA and the Farm Bureau²² supported DRA's methodology for calculating the marginal customer costs. According to the Farm Bureau, DRA's methodology results in an estimated marginal cost of $112.46 compared to SDG&E's methodology which results in an estimate of $319.07. Other parties, such as California Large Energy Consumers Association (CLECA) and the Federal Executive Agencies, supported SDG&E's methodology for calculating the marginal customer costs.

To avoid hearings on the marginal customer costs, and how the revenue allocation should be carried out, the parties agreed in the settlement to specific and separate allocation factors for the distribution and generation revenue requirements. These allocation factors, as applied to SDG&E's GRC Phase 1 request, are reflected in Attachment C of the settlement.²³ Under the settlement, the revenue allocation to the residential and small commercial customers decreases from what SDG&E had proposed in its application, while the allocation to the medium and large C&I customers increases by approximately $61 million. In addition, the settlement reduces the allocation to lighting customers by $2.3 million, as compared to SDG&E's original position. For agricultural customers, the settlement reduces the allocation by $234,000.

In addition to the overall impact on the revenue allocation to each customer class, the settlement resolved many of the rate design differences between the parties with respect to the various customer classes. These differences included, among other issues, the various demand charge and energy charge proposals, and the shifting of the month of October from a winter to a summer rate period.

For residential customers, SDG&E agreed as part of the settlement to withdraw its proposal to limit the discounts and exemptions applicable to CARE customers. The parties agreed in the settlement that the total rate levels applicable to CARE customers will remain unchanged.

The settlement also addressed the TRAC proposal of SDG&E. The parties agreed to the implementation of the TRAC, but the associated credits and charges will not be shown as a separate line item on residential customer bills. Instead, the TRAC charges will be included as a component within the PPP charges for billing purposes and remain a separate line item in SDG&E's tariffs. The TRAC will be the mechanism for capping residential rates and for recovering the associated revenue shortfalls. We clarify that existing direct access customers, which are exempt from paying the RDSC adopted in D.05-12-003, will likewise be exempt from the TRAC.

For the five tier residential rate structure, the parties agreed in the settlement to consolidate the Tier 4 and Tier 5 rates into a singleTier 4 rate. The parties also agreed that the total rate differential between Tier 3 and Tier 4 will be at least 2 cents per kWh until addressed in a future rate design proceeding.

SDG&E had proposed that all residential rates, including the rates applicable to usage up to 130% of baseline, be adjusted to recover the residential allocation of the CSI costs. The parties agreed in the settlement that the methodology for including the CSI costs into residential rates will be similar to what was adopted for PG&E in D.07-09-004. In that decision, the residential Tier 1 and Tier 2 rates were increased by the difference between the new CSI rate component and the previous component of solar costs that was in the SGIP costs collected in residential Tier 1 and Tier 2 rates.

For residential customers who install a SES, the parties agreed in the settlement that 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 for 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 in order to use a TOU rate.

For small commercial customers, SDG&E had proposed to increase all basic service fees by 20% from their current levels to more closely reflect the fixed costs of providing service. DRA had proposed that these customers should not be subjected to an increase in the basic service fees. The parties agreed as part of the settlement that the basic service fees for the small commercial rate schedules will increase by no more than 5% from the current level.

The parties also agreed that current Schedule A for small commercial customers will be retained, instead of requiring these customers to go on a new rate schedule, Schedule AS-TOU, after AMI is implemented. In addition to withdrawing its Schedule AS-TOU, SDG&E agreed as part of the settlement to withdraw its proposal to shift Schedule A-TOU customers with demands between 20 kW and 40 kW to schedule AL-TOU.

For C&I customers, SDG&E had proposed to redesign the CTC in order to replace the existing CTC demand charges with kWh-based charges. FEA had recommended that shifts in CTC cost recovery be avoided and that the proportionality of the current CTC rates be maintained among the rate schedules. The parties agreed in the settlement that the CTC rate structure will remain unchanged.

SDG&E had proposed to implement a kWh-based charge to recover certain program costs that are currently allocated to the medium and large C&I class. FEA had objected to the recovery of these costs through a kWh-based charge. In the settlement, the parties agreed that a modified rate design approach will be applied to the distribution revenue requirement for these program costs.

For the rate design of the seasonal commodity rates applicable to Schedule PA for agricultural customers, the parties agreed in the settlement that the winter rates should remain at existing levels, and that the proposed charges of SDG&E would be applied to summer rates only.

For the rate design for street lighting, SDG&E had proposed that the rates be adjusted to recover the revenue allocated to the class using an EPMC methodology. CAL-SLA had questioned SDG&E's derivation of the customer costs for street lighting. In the settlement, the parties agreed that the distribution demand and customer cost per kW value in SDG&E's proposal will be replaced by the average of SDG&E's estimate and CAL-SLA's estimate.

For the dynamic pricing issues, the parties reached a number of compromises in the settlement.

SDG&E, DRA, UCAN and CLECA actively participated on the PTR issues. The settlement adopted DRA's proposal for a two-tier PTR credit to address the free rider problem that DRA and UCAN had raised. The two-tier PTR credit will reduce the cents per kWh credit to the free riders. Other PTR issues are addressed in Paragraphs 3 to 13 of the PTR portion of the settlement. The resolution of all the PTR issues in the settlement provides the framework for providing dynamic rates to residential and small commercial customers in the future as AMI meters are deployed.

A number of compromises and concessions were made by the parties regarding the CPP issues. SDG&E had proposed in its application that CPP apply to all C&I customers with demands equal to or greater than 20 kW. A number of the parties questioned various aspects of the CPP proposals. BOMA, the city of San Diego, and the Farm Bureau opposed the mandatory nature of the CPP proposals. BOMA was concerned about the impact of CPP on its members and their tenants. Others were concerned about the potential for cost shifting, and CMTA proposed that the large C&I customers should be divided into two rate groups.

As a result of the settlement discussions about the CPP issues, all of the parties agreed to support SDG&E's CPP proposal, as modified by the settlement. The specific modifications to SDG&E's CPP proposal are described in the settlement and in the testimony in support of the settlement. Some of the highlights of the settlement are summarized below. The CPP rates and bill impacts are shown in Attachments D and E of the settlement.

The parties agreed in the settlement that educational outreach begin on the default CPP rate no later than March 1, 2008, and that the CPP tariffs be implemented no later than April 1, 2008. The settlement provides for a 45-day period after the default CPP is implemented for customers to opt out of the CPP to the otherwise applicable tariff. Those customers who do not opt out of the default CPP will be covered by Bill Protection for the first 12 months of default CPP service. After the first 12 months on the default CPP rate, and on subsequent annual anniversaries, a customer will have a certain period of time in which to opt out of the default CPP.

In addition to the above modifications to SDG&E's default CPP proposal, the parties agreed in the settlement to several other conditions. These conditions include the following. The CPP imbalances are to remain within the C&I customer class, and any over- or under-collection shall be allocated as described in the settlement. SDG&E also agrees to analyze the impact of splitting C&I customers into three classes by performing the Class Split Study. By November 15, 2008, SDG&E agrees to file an application to propose at least one additional split of the C&I customer classes, and that the Class Split Study be attached to the application.

The City of San Diego, FuelCell Energy, the Solar Alliance, and Vote Solar raised concerns about the demand charges that customers would have to pay under SDG&E's initial proposals regarding renewable customer-owned generation. As a result of the settlement discussions regarding SDG&E's proposals, the parties agreed in the settlement that a new voluntary tariff, Schedule DG-R, will be made available. This is a voluntary schedule that will be available to qualifying customers that install solar, fuel cells, and other renewable distributed generation. Schedule DG-R is designed to provide additional incentives, as compared to the otherwise applicable rate, through the conversion of demand charges into energy rates.²⁴

The proposed DG-R rates are shown in Attachment F of the settlement. The Schedule DG-R distribution and commodity rates will be updated once a final decision is adopted in SDG&E's GRC Phase 1. The cost shifts that result from the Schedule DG-R commodity demand charge exemptions will be retained in the total C&I commodity charges. The cost shifts that result from the Schedule DG-R distribution demand charge will be retained in the total C&I distribution charges.

4.3. Adoption of the Settlement

A review of all of the parties' testimony, and the comparison in the preceding sections, reveal that the parties have made a number of concessions in order to reach the compromises agreed to in the all party, all issue settlement. The parties who participated in this proceeding represent a broad spectrum of customer interests, and the issues raised by the parties and the resolution of those issues in the settlement reflect those interests and concerns.

The revenue allocation agreed to in the settlement balances the competing interests of the various parties. For example, in comparison to the revenue allocation under SDG&E's original proposal, the revenue allocation in the settlement to the medium and large C&I customers increased substantially, while the allocation to the street lighting customers is reduced and the allocation to residential and small commercial customers decreases. A number of cost-of-service and load studies will be undertaken by SDG&E, which may be used to justify future allocations. As described in Section 3.2.2 of this decision, many of the rate design issues of concern to residential customers, small commercial customers, medium and large C&I customers, agricultural customers and street lighting customers were resolved in a manner satisfactory to all of the parties. Had a settlement not been reached, the revenue allocation and rate design outcomes may have been dramatically different.

The compromises that were reached in the settlement regarding the PTR program and the CPP rates will enable dynamic pricing to be implemented in 2008 in conjunction with SDG&E's AMI deployment. While fulfilling the goals of the EAP II to provide for demand response through well designed dynamic pricing, customers will be able to experiment with the CPP rates using Bill Protection for the first year, or customers may choose to remain on their otherwise applicable tariff.

The adoption of the voluntary Schedule DG-R will facilitate the EAP II goal of encouraging the growth of renewable sources of energy in California.

As for the settlement's consistency with the law, there are two areas covered by the settlement which require a brief discussion. These concerns have to do with the provisions of the settlement which pertain to the installation of a SES, and the sub-metering of commercial buildings.

The settlement contains two provisions which pertain to a SES. For residential customers, the settlement addresses how these customers can obtain a TOU meter in order to use schedule DR-TOU or DR-SES. The other provision addresses the new, voluntary DG-R tariff, which qualifying customers with a SES can use.

Pub. Util. Code § 2851(a)(4) states:

(A) Notwithstanding subdivision (g) of Section 2827, the commission shall require time-variant pricing for all ratepayers with a solar energy system. The commission shall develop a time-variant tariff that creates the maximum incentive for ratepayers to install solar energy systems so that the system's peak electricity production coincides with California's peak electricity demands and that assures that ratepayers receive due value for their contribution to the purchase of solar energy systems and customers with solar energy systems continue to have an incentive to use electricity efficiently. In developing the time-variant tariff, the commission may exclude customers participating in the tariff from the rate cap for residential customers for existing baseline quantities or usage by those customers of up to 130 percent of existing baseline quantities, as required by Section 80110 of the Water Code. Nothing in this paragraph authorizes the commission to require time-variant pricing for ratepayers without a solar energy system.

(B) The commission may delay implementation of time-variant pricing pursuant to subparagraph (A), until the effective date of the rates subject to the next general rate case of the state's three largest electrical corporations, scheduled to be completed after January 1, 2009.

(C) If the commission delays implementation of time-variant pricing pursuant to subparagraph (B), ratepayers required to take service under time-variant pricing between January 1, 2007, and January 1, 2008, shall be given the option to take service under flat rate or time-variant pricing and shall be credited any difference between the time-variant rate and the otherwise applicable flat rate, provided there is a flat rate pricing schedule for which the ratepayer would qualify if the ratepayers had not installed the solar energy system.

The provisions in the settlement which pertain to customers with a SES do not conflict with Pub. Util. Code § 2851. The DR-TOU, DR-SES and DG-R schedules all have time-variant pricing. Pursuant to Pub. Util. Code § 2851(a)(4)(B), the Commission may, but is not obligated to delay the implementation of time-variant pricing for SDG&E. Since the SES tariffs in the settlement provide an incentive for the installation of such systems, a delay is not needed to implement time-variant pricing for SDG&E's customers.

With respect to the agreement in the settlement that SDG&E will adopt a sub-metering program substantially similar to what was adopted for PG&E in D.07-09-004, that raises the issue of whether this part of the settlement is inconsistent with the prior Commission decisions prohibiting commercial sub-metering. In D.07-09-004, the Commission addressed that concern and found that PG&E's sub-metering agreement was not inconsistent with the law, and that the prior decisions prohibiting commercial sub-metering were no longer applicable. (See D.07-09-004, pp. 45-54.) Since the sub-metering program agreed to in the settlement is to be patterned after the sub-metering program adopted in D.07-09-004, we do not see any conflict. Rule 19 of SDG&E's tariffs will need to be revised to reflect the sub-metering program allowed under the settlement.

As part of the settlement on sub-metering, SDG&E is to establish a Memorandum Account for incremental sub-metering costs. We will require SDG&E to file a tier 3 advice letter to recover any incremental sub-metering costs that are recorded to this Memorandum Account. Such a procedure will ensure that the sub-metering costs are indeed incremental, and will provide the parties and the Commission with an opportunity to review the costs recorded to this Memorandum Account.

We conclude that the settlement is consistent with the law.

The settlement is in the public interest because it resolves all of the issues among the active parties, except for the AB 1X issues. The agreement between all of the active parties on all of the issues in this proceeding helped to minimize the litigation resources that would have been required had a settlement not been reached. In addition, the settlement is in the public interest because of the compromises that each party made with outcomes that are fair and reasonable to all the parties.

We conclude that the settlement is balanced and reasonable in light of the whole record, consistent with the law, and in the public interest. Based on the above discussion, SDG&E's November 1, 2007 motion to adopt the settlement should be granted, and the terms of the settlement as appended to SDG&E's motion as Attachment 1 should be adopted by the Commission.

SDG&E is directed to file an advice letter with tariffs that conform to the settlement. In order to minimize rate volatility to customers, the effective date of the tariffs shall be May 1, 2008. The rates that are to become effective on May 1, 2008 may change depending on the decisions that are adopted on SDG&E's electric revenue requirement in A.06-12-009 and in this proceeding on the AB1X issues.

²² The Farm Bureau believes that certain corrections to DRA's methodology need to be made.

²³ The revenue allocation shown in Attachment C of the settlement is based on the revenue requirement that SDG&E had proposed in Phase 1 of its GRC. The actual revenue allocation changes will be different if the revenue requirement adopted in Phase 1 of the GRC is different from SDG&E's request.

²⁴ The offering of Schedule DG-R resolves a large part of the school districts' concerns with SDG&E's demand charge.