4. Settlement Agreements

4.1. Revenue Allocation Settlement Agreement

In its application, SCE proposed basing marginal customer costs on the real economic carrying charge (RECC) method. DRA and TURN proposed that marginal customer costs be based on the "new customer only" (NCO) method. As a result of reaching agreement on the allocation of SCE's total revenue requirement among the rate groups, the Settling Parties state that the need to litigate and resolve the differences regarding the various proposed marginal cost methodologies was rendered moot.⁴ Table 1 below compares marginal customer costs presented by SCE, DRA, and TURN with the marginal costs adopted in the revenue allocation (RA) settlement agreement:

TABLE 1 Marginal Customer Costs ($/customer-year)
	SCE RECC5	DRA NCO6	TURN NCO7	SETTLEMENT8
Domestic	$139.66	$96.19	$65.06	$117.96
GS-1	$249.52	$204.15	$124.79	$226.80
TC-1	$228.24	$134.03	$90.37	$181.08
GS-2	$1,870.97	$1,520.04	$739.30	$1,691.52
GS-3	$4,298.57	$3,659.11	$2,320.04	$3,978.84
TOU-8-Sec	$5,252.25	$2,846.39	$2,405.06	$4,049.28
TOU-8-Pri	$2,819.46	$1,787.90	$1,424.20	$2,303.64
TOU-8-Sub	$20,620.22	$7,356.79	$5,235.05	$14,488.56
PA-1	$853.29	$510.64	$260.08	$681.96
PA-2	$1,369.91	$813.91	$1,019.39	$1,087.92
TOU-PA-5	$2,343.76	$1,611.98	$1,102.02	$1,771.44
AG-TOU	$2,056.97	$1,404.38	$1,092.82	$2,013.72
Street Lights	$175.38	$102.59	$88.17	$189.00

The settlement agreement also includes generation marginal energy and capacity costs, and marginal distribution capacity costs.

The primary areas of dispute with respect to revenue allocation concerned whether there should be a cap or limit on the amount of SCE's revenue requirement that was allocated to any rate group and the allocation of certain revenue requirements among the rate groups. The RA settlement agreement caps revenue to each rate group so that no rate group shall receive an increase of more than 2.75% above the system average percentage change (SAPC), based on SCE's adjusted consolidated revenue requirement. The nonallocated revenues assigned to the Street Light rate group are further capped so that they shall not increase by more than 4.8% per year from the December 2008 level during the 2009 - 2011 GRC cycle. The settlement agreement also addresses the allocation of SCE's authorized revenue requirements among customer groups. Finally, the settlement agreement provides that any future changes to SCE's consolidated revenue requirement occurring after this decision is issued and before SCE's 2012 GRC Phase 2 application is implemented shall be allocated according to the functional character of the revenue requirement change on an SAPC basis.

The settlement agreement is based on SCE's December 2008 forecast estimated system revenue requirement of $12.234 billion, with a bundled-service system average increase of 13.4%. Based on this estimate, the proposed rates and percentage change over December 2008 average rates are as follows:

TABLE 29
	Dec. 2008 Avg. Rates (¢/kWh)	Proposed Avg. Rates (¢/kWh)	Percentage Change
Residential	14.91	17.32	16.1%
GS-1	16.93	18.72	10.6%
TC-1	15.14	17.58	16.1%
GS-2	14.51	16.85	16.1%
TOU-GS-2	13.22	14.35	8.6%
Total LSMP10	14.56	16.48	13.2%
TOU-8-Sec	12.37	13.62	10.1%
TOU-8-Pri	11.70	12.51	6.8%
TOU-8-Sub	7.63	8.86	16.1%
Total Large Power	10.79	11.87	10.1%
PA-1	18.60	19.88	6.9%
PA-2	13.01	14.80	13.8%
AG-TOU	9.71	11.27	16.1%
TOU-PA-5	9.51	11.04	16.1%
Total Ag.&Pump.	11.19	12.68	13.3%
Total Street Lights	18.63	20.66	10.9%
SYSTEM	13.73	15.57	13.4%

Transphase filed comments contesting adoption of the RA settlement agreement on numerous grounds. However, as discussed below, these arguments are without merit and fail to support Transphase's assertion that the RA settlement agreement should be rejected.

Transphase first contends that there is insufficient evidence to support approval of the proposed settlement agreement. Among other things, Transphase maintains that there is no evidence to support a flat and non-time differentiated Department of Water Resources (DWR) power charge nor the methodology for the blending of utility retained generation (URG) and the DWR power charge to achieve the on-peak and off-peak ratio. These arguments are without merit. This proceeding does not establish the DWR power charge. Rather, the DWR power charge is determined when the Commission adopts DWR's revenue requirement and allocates this revenue requirement among the three utilities and this allocation is a flat cents/kWh rate.¹¹ Further, the record supports the blended rates proposed in the settlement agreement. SCE witness Garwacki explains the rationale behind the blending of the DWR and URG rates.¹² Moreover, Exhibit 104 illustrates the blending of the two rates, while Appendix B of the RA settlement agreement shows the URG and DWR generation revenues allocated by rate group. Additionally, Exhibit 108 shows the URG and DWR generation revenues allocated to bundled service and direct access customers.¹³ Accordingly, the blended rates are adequately supported by the record.

Transphase also asserts that the marginal energy costs contained in the
RA settlement agreement are not supported in the record since SCE failed to include the necessary data inputs or computer models in the evidentiary record. Transphase maintains that by failing to do so, SCE has violated Pub. Util. Code § 1822 and Commission Rule 10.3. While Pub. Util. Code § 1822 and Commission Rule 10.3 require that computer models and databases be made available to parties, they do not require that these models and databases be made part of the record.¹⁴ Even though these models and databases are not part of the record in this proceeding, the record does provide sufficient evidence to determine the reasonableness of the marginal energy cost proposed in the
RA settlement agreement. For example, SCE's testimony includes discussion of the assumptions used in its marginal energy cost forecast.¹⁵ Additionally, both DRA and TURN filed testimony commenting on SCE's proposal and proposed adjustments to this cost.¹⁶

Transphase further argues that the settlement agreement amounts to price fixing among the Settling Parties due to a lack of regulatory oversight. We are unsure of the basis for this argument. The Settling Parties are not competitors and the settlement concerns allocation of SCE's revenue requirement among customer groups. The allocation is a zero-sum game, as any "benefit" obtained by one customer group will result in a "detriment" to another customer group. Furthermore, pursuant to our Rules of Practice and Procedure, a settlement agreement, even if uncontested, will not be approved unless it is found to be reasonable in light of the whole record, consistent with the law, and in the public interest. In this instance, the Commission has fully considered the record and the settlement agreement. Further, the ALJ not only conducted evidentiary hearings on the contested issues, but also held a hearing to consider the proposed settlement agreements. This included questions concerning various terms contained in the RA settlement agreement.¹⁷ Therefore, it is difficult to understand why Transphase would contend that there was a lack of active regulatory supervision in approving this settlement.

The record of this proceeding, consisting of prepared testimony, evidence presented in the course of hearings, and opening and closing briefs, supports a finding that the RA settlement agreement fairly resolves identified issues and is reasonable. The Settling Parties recognized that, based on the revenue requirement proposed in SCE's GRC Phase 1 application, all rate groups on average would receive substantial revenue increases when rates in this proceeding are implemented, as compared to the rates in effect as of December 2008. The RA settlement agreement avoids further litigation and mitigates potential adverse impacts on any particular rate group and moves towards cost based rates. This move is consistent with the goal of the State's Energy Action Plan (EAP)¹⁸ to "create more transparency in consumer electricity rates," and to "adopt rates based on clear cost-causation principles."¹⁹

We also find the RA settlement agreement is consistent with law. The process for conducting this settlement was in accordance with Article 12 of the Rules of Practice and Procedure. Further, as discussed above, Transphase has failed to demonstrate that the settlement agreement is contrary to the Public Utilities Code, prior Commission decisions or other applicable laws.

Finally, the settlement agreement represents a reasonable compromise of Settling Parties' respective litigation positions and is in the public interest. The settlement is in the public interest because it avoids the cost of further litigation, and conserves scarce resources of parties and the Commission. Further, the agreed-upon revenue allocation moves revenue responsibility closer to the cost of service while moderating adverse bill impacts on customers.

4.2. Residential and Small Commercial
Rate Design Settlement Agreement

The residential and small commercial (RSC) rate design settlement agreement²⁰ describes the manner in which rates for the customer class will be designed and includes the following provisions:

· The Basic Charges for residential service to single-family or multi-family residences that was effective as of December 2008 shall remain in effect.

· Energy rates for Schedule D, and other comparably-structured Residential Rate Group schedules, shall reflect five tiers of consumption. Pursuant to the residential rate protections enacted in Assembly Bill No. 1 during the First Extraordinary Session of 2001-2002 (AB 1X),²¹ total bundled rates for usage up to 130% of baseline (Tier 1 and Tier 2) will not be changed except to the extent recovery of the California Solar Initiative revenues were authorized for recovery by Resolution E-4167.²² There will be a differential of five cents per kilowatt hour (kWh) between the rates for Schedule D Tier 3 and Tier 5. However, if legislation modifying the AB 1X rate protection is enacted which allows at least a 3% annual increase in Schedule D Tier 1 and Tier 2 rates, SCE shall propose rates at the next regularly-scheduled rate change (Rate Design Window or GRC) so that there is a seven cents per kWh differential between the rates for Tier 3 and
Tier 5.²³

· Total bundled residential California Alternate Rates for Energy (CARE) rates will remain unchanged for usage up to 130% of baseline allocation (Tier 1 and Tier 2). The Schedule D-CARE Tier 3 rate shall provide a discount of 20% from the Schedule D Tier 3 rate, subject to a ceiling of 20 cents/kWh.

· SCE's baseline allowances shall be updated to reflect current usage levels and the baseline allocation percentages for each baseline zone shall be reduced to 50% of the average aggregate customer usage.²⁴ However, if legislation modifying the AB 1X rate protection is enacted which allows at least a 3% annual increase in Schedule D Tier 1 and Tier 2 rates, the allocation percentages for each baseline zone shall be set at 55% of the average aggregate customer usage of then-current baseline usage levels.

· SCE's six baseline zones shall be revised to align with the nine climate zones established by the California Energy Commission.²⁵ Customers currently residing in SCE's existing baseline zone 15 shall retain their currently designated baseline zone.

· The following demand response rates proposed by SCE will be available options for this customer class: Summer Discount Plan (SDP), Peak Time Rebate (PTR), Programmable Communicating Thermostat (PCT) and Critical Peak Pricing (CPP). The technology-enabled incentive for the PTR and PCT programs will be $1.25/kWh. Customers enrolled in CPP will not be eligible to participate in SDP or PTR.

· Schedules TOU-D-1 and TOU-D-2 will be closed to new customers and replaced with Schedule TOU-D-T. Schedule TOU-D-T is a 2-tiered time of use (TOU) rate structure with the same TOU periods as the current TOU schedules. Customers currently receiving service under Schedules TOU-D-1 and TOU-D-2 will be grandfathered on these rate schedules for the term of SCE's
2009 GRC cycle.

· Customers who provide submetered electric service and who are serviced on Schedule DMS-2 shall receive a net discount of
14.8 cents per space per day.

· There will be three electric vehicle (EV) rate schedules. Schedule TOU-TEV is a new rate option for customers who prefer single meter service for a primary residence with an electric vehicle load and has on-peak, off-peak and super-off peak TOU periods. Existing Schedules TOU-EV-1 (for low emissions vehicles) and TOU-EV-3 (for commercial electric vehicles) shall be modified to provide discounted off-peak charging rates subject to a price floor. On-peak energy charges for Schedule TOU-EV-3 shall be set in the same manner as TOU-GS-1 on-peak energy charges. Schedule TOU-EV-1 is to be effective immediately upon approval of the settlement, while Schedule TOU-TEV and modified Schedule TOU-EV-3 shall be effective no sooner than October 1, 2009.

· A CIA is adopted. The CIA restructures residential rates to reflect the rate differentials between tiers in the delivery component of those rates instead of the generation component.

· TURN's proposal for monthly and annual reports of residential arrearages and shutoffs is adopted.

· Customer charges for the GS-1 and TOU-GS-1 rate groups shall not increase from their then-current levels on October 1, 2009. Changes to the customer charges for these rate groups after that date shall be based on Functional SAPC Allocation of distribution revenue changes.

WRCOG filed comments in support of the revisions to the six baseline zones. It notes that it was not a party to the settlement agreement because the settlement concerned many issues outside of baseline, the only issue of interest to WRCOG.

SJVPA filed comments contesting adoption of the CIA as part of the
RSC settlement agreement. SJVPA states that with respect to the CIA, the settlement agreement did not represent a reasonable compromise of the parties' positions because none of the Settling Parties had opposed the CIA proposal. It notes that the two parties which had opposed the CIA proposal, SJVPA and AReM, were not parties to the settlement agreement and that the settlement agreement did not address or remedy the concerns raised by these two parties. SJVPA claims that by shifting costs from generation to delivery rates, the CIA shifts delivery costs significantly among communities within SCE's service territory. According to SJVPA, this shift in costs among communities is discriminatory, as the delivery revenue in higher-usage communities will be artificially higher than in lower-usage communities.

SCE states that under its current rate design, only bundled-service customers receive conservation signals, since the rate differentials between tiers are reflected in the generation component of rates. It maintains that if the rate differentials between tiers were reflected in the distribution component of rates, then all residential customers, including those receiving electric service from direct access (DA) and Community Choice Aggregation (CCA) providers, would have an incentive to conserve. It refutes SJVPA's claim that there is a shift in cost among communities by stating that overall residential rates for bundled-service customers would be exactly the same, with or without the CIA.

We agree with SCE that adoption of the CIA is revenue neutral for residential customers. . Under SCE's proposal, implementation of the CIA does not change the overall allocation of generation and delivery revenues to be recovered from residential customers.²⁶ Instead, the CIA will shift the allocation of delivery revenues to be collected from the different tiers. While this shift will impact the amount to be collected from different tiers of CCA customers,
CCA customers as a group will still be paying the same total for delivery.

Further, the CIA is consistent with State policy. Pursuant to the EAP, energy conservation is one of the specific identified actions to eliminate energy outages and excessive price spikes in electricity or natural gas. Thus, signals to encourage conservation should be provided to all customers, regardless of their energy provider. As SCE notes, the purpose for the CIA is "to send a conservation signal and proper generation signal to all [ ] load-serving entities."²⁷ TURN echoes this purpose and states:

TURN felt that it was important to have the differential in the distribution rate because if it's in the generation rate, it creates perverse incentives for certain customers to adopt direct access or community choice aggregation solely because of the rate design.

So a customer that was high usage-if the tier differential was in the generation rate, they could switch away from bundled service solely to get a lower rate, and at the same time the low-usage customer would never want to leave bundled service because they would get a rate increase just by doing so.

So it really makes the rate design competitively neutral to the extent that there are alternatives like CCA out there for residential customers.²⁸

In comments to the ALJ's proposed decision, SCE requests that the CIA be implemented for residential customers concurrently with other rate adjustments it makes on an annual basis in its Energy Resource Recovery Account (ERRA) forecast proceeding. SCE states "It would be administratively convenient to consolidate any rate adjustment associated with over- or undercollections related to the CIA rate component when fuel and purchased power balancing accounts are reconciled in the annual ERRA forecast proceeding."²⁹ Further, it notes that none of the settling parties to the RSC settlement agreement oppose this proposed change. We find this request to be reasonable. Therefore, the settlement agreement shall be modified to incorporate this requested change.

The settlement agreement prohibits ratepayers who elect to enroll in CPP from also participating in SDP and PTR. However, this provision is potentially inconsistent with the proposed policy in a pending proposed decision in the Commission's Demand Response proceeding (A.08-06-001 et al.). Unlike the RSC settlement agreement, the pending proposed decision in A.08-06-001 would allow customers enrolled in SDP and PTR to also be eligible for service on CPP rates. We believe that the rate designs for the individual utilities should be consistent with the goals and overall policies ultimately adopted in the Demand Response Proceeding. Therefore, paragraph 4.b.viii of the RSC settlement agreement shall be modified to state that eligibility to participate in more than one demand response program shall be consistent with the decision ultimately adopted in A.08-06-001.³⁰ To the extent the decision ultimately adopted in
A.08-06-001 will require rate design changes to avoid duplicate payments or negative demand charges, SCE shall file a 2009 Rate Design Window Application proposing these changes.

We find that with the modifications discussed above, the RSC settlement agreement should be approved. The settlement, as modified, is reasonable in light of the record. Parties' testimonies demonstrate that there were numerous disputed issues and the settlement represents a reasonable compromise of these issues. The fact that SJVPA and AReM had filed protests to SCE's initial application, but did not enter into the settlement agreement, does not provide sufficient grounds to reject any portion of the settlement. As discussed above, the proposed CIA is reasonable and consistent with State policy.

We also find the RSC settlement agreement, as modified, is consistent with law. The process for conducting this settlement was in accordance with
Article 12 of the Rules of Practice and Procedure. Further, the settlement agreement is not inconsistent in any way with Public Utilities Code Sections, Commission decisions, or the law in general. Additionally, the modification to the RSC settlement agreement ensures that SCE's eligibility criteria for participation in more than one demand response program is consistent with the decision ultimately adopted in A.08-06-001.

Finally, we find that the settlement agreement, as modified, is a reasonable compromise of Settling Parties' respective litigation positions. The settlement is also in the public interest because it avoids the cost of further litigation, and conserves scarce resources of parties and the Commission.

4.3. Medium and Large Power Rate Group
Rate Design Settlement Agreement

The medium and large power (MLP) rate group rate design settlement agreement³¹ describes the manner in which rates for the customer class will be designed and includes the following provisions:

· Certain common pricing criteria are adopted for the GS-2, TOU-GS-3 and TOU-8 rate groups. These include setting customer charges at the full equal percent of marginal cost (EPMC) level for customers with demands of 20 kilowatts (kW) or more who are served on TOU rate schedules, setting SCE's CPP tariff to allow no more than 15 but no less than 9 events a year, and providing bill protection during the first 12 months that a customer is taking service under the CPP tariff.

· The default tariff for commercial and industrial customers with demands greater than 500 kW shall be Schedule TOU-8 with the associated CPP components. Alternatively, these customers may elect to take service under Schedule TOU-8, Option A, if they employ Cold Ironing or Permanent Load Shift technologies, or Schedule TOU-8, Option B, if they opt out of the CPP overlay tariff.

· An experimental rate shall be offered as an optional rate schedule for customers with demands greater than 20 kW but not exceeding 4 megawatts (MW) and who employ Renewable Distributed Generation Technologies. Participation in Schedules TOU-8-R, GS-2-R and TOU-GS-3-R shall be limited to a cumulative installed distributed generation output capacity of 150 MW.

· The default tariff for customers with peak demands of 20 kW to 199 kW shall be the applicable non-TOU rate schedule, with eligibility to participate in a CPP tariff. These customers may also take service on a TOU rate schedule.

· The default tariffs for customers with peak demands of 200 kW to 499 kW shall be Schedule TOU-GS-3, with a CPP overlay. Customers may opt out of the default CPP tariff.

· An electric vehicle tariff, Schedule TOU-EV-4, will provide discounted off-peak charging rates, subject to a floor price.

The MLP settlement agreement states that customers enrolled in BIP and APS shall not be eligible for service on CPP rates. As with the RSC settlement agreement, there is a potential inconsistency between this provision and the pending proposed decision in A.08-06-001. Therefore, paragraph 4.a.8 of the MLP settlement agreement shall be modified to state that eligibility to participate in more than one demand response program shall be consistent with the decision ultimately adopted in A.08-06-001.³² To the extent the decision ultimately adopted in A.08-06-001 will require rate design changes to avoid duplicate payments or negative demand charges, SCE shall file a 2009Rate Design Window Application proposing these changes.

Transphase contests the MLP settlement agreement. It maintains that the settlement agreement should be rejected because the rate design is "irrational, arbitrary and unsubstantiated." Transphase's challenges focus primarily on the proposed energy and demand charges in Schedule TOU-8 and an alleged declining differential between on-peak and off-peak rates. We do not find any of these arguments to be persuasive or grounds to reject the settlement agreement. The proposed TOU-8 rates fairly represent a compromise of the Settling Parties' litigation positions. Moreover, Transphase urges the Commission to adopt the "rate design in effect as of February, 2006, along with a further modification to establish a time-differentiated DWR energy rate"³³ but fails to explain why that rate design is reasonable and should be adopted.

We find that with the modification discussed above, the MLP settlement agreement should be approved. Based on the evidentiary record of this proceeding, principally prepared testimonies, we find that the MLP settlement agreement fairly resolves identified issues and, as modified, is reasonable. As discussed above, Transphase has not presented any persuasive reasons the terms of the settlement agreement are unreasonable.

We also find the MLP settlement agreement is consistent with law. The process for conducting this settlement was in accordance with Article 12 of the Rules of Practice and Procedure. Further, the settlement agreement, as modified, is not inconsistent in any way with the Public Utilities Code, Commission decisions, or the law in general. Finally, we reject Transphase's contention that the proposed settlement agreement is contrary to California's energy policy objectives or discourages permanent load shifting (PLS). The settlement agreement adopts a default TOU schedule with CPP overlay for the customers with demands greater than 500 kW (Schedule TOU-8). This rate schedule is consistent with California's overall goals to encourage customers to reduce peak energy consumption by setting different rates during pre-defined time periods. The settlement agreement also adopts an alternative tariff specifically for customers with demands greater than 500 kW who employ cold ironing and
PLS technologies (Schedule TOU-8, Option A). We believe this schedule provides adequate incentive for the installation of PLS technology.³⁴

Finally, we find that the settlement agreement is a reasonable compromise of Settling Parties' respective litigation positions. Because the settlement avoids the cost of further litigation and conserves scarce resources of parties and the Commission, it is in the public interest.

4.4. Agriculture and Pumping Rate Group
Rate Design Settlement Agreement

The agriculture and pumping (AP) rate group rate design settlement agreement³⁵ describes the manner in which rates for the customer class will be designed and includes the following provisions:

· Current rate structures will be retained for the PA-1, PA-2, TOU-PA, and TOU-PA-5 rate groups, except that Schedule PA-2 will now include a summer time-related demand charge. Customer charges will increase by a maximum of 20 percent above current levels, but shall not exceed the full EPMC level of Customer Charge based on SCE's RECC method.

· Customers with peak demand up to 199 kW will take service on a default basis on a non-TOU rate schedule. Customers with peak demand 200 kW or greater will take service on a default TOU rate schedule. Super off-peak and real-time pricing schedules shall remain available as options for customers who meet the eligibility criteria.

· CPP will be an optional rate for customers in this rate group, unless they are otherwise ineligible due to participation in other programs. The number of CPP events shall be no less than nine and no more than fifteen per year and may only occur during the time period from 2 p.m. to 6 p.m. Customers subject to the CPP tariff shall be provided one year bill protection.

· AECA's proposal to aggregate customer accounts will not be permitted. Instead, SCE will offer customers an hourly pricing schedule similar to the current PA-RTP schedule and work with AECA and other interested parties to identify energy cost management tools.

· SCE will meet with representatives of AECA and CFBF to review revenue allocation and rate design issues raised in protests and discuss potential joint studies to assist in addressing these issues. By starting this analysis well in advance of SCE's 2012 GRC Phase 2 application, the Settling Parties believe issues may be resolved prior to the next GRC filing.

· SCE will conduct a one-time review for TOU-PA-A, TOU-PA-B, and TOU-PA-SOP customer's annual bills to determine whether a customer on one of these rate schedules would achieve significant annual percentage bill savings by changing to an alternative rate schedule.

The AP settlement agreement provides that rate structures and rate designs for this customer rate group shall be consistent with SCE's proposals in SCE-04 (Exhibit 5). These proposals, however, would not allow customers participating in the TOU-BIP, agricultural and pumping interruptible (AP-I) or SDP programs from also participating in CPP. To ensure consistency with the decision ultimately adopted in A.08-06-001, paragraph 4.a.5 of the AP settlement agreement shall be modified to state that eligibility to participate in more than one demand response program shall be consistent with the decision ultimately adopted in A.08-06-001.³⁶ To the extent the decision ultimately adopted in
A.08-06-001 will require rate design changes to avoid duplicate payments or negative demand charges, SCE shall file a 2009 Rate Design Window Application proposing these changes.

We find that with the modification discussed above, the AP settlement agreement should be approved. Based on the evidentiary record of this proceeding, principally prepared testimonies, and the all-party status of the settlement, we find that the AP settlement agreement fairly resolves identified issues and is reasonable.

We also find the AP settlement agreement is consistent with law. The process for conducting this settlement was in accordance with Article 12 of the Rules of Practice and Procedure. Further, the settlement agreement, as modified, is not inconsistent in any way with the Public Utilities Code, Commission decisions, or the law in general.

Finally, we find that the settlement agreement is a reasonable compromise of Settling Parties' respective litigation positions. The settlement is also in the public interest because it avoids the cost of further litigation, and conserves scarce resources of parties and the Commission.

4.5. Street Light Rate Group
Settlement Agreement

The street light (SL) rate group settlement agreement³⁷ describes the manner in which rates for street light customers will be designed and includes the following provisions:

· Street light facilities charges shall increase by a targeted annual percentage of 4.8 percent for each street light rate schedule in 2009, 2010, 2011, and 2012.

· SCE and CAL-SLA shall work together on a joint study prior to SCE's 2012 GRC application to better understand the costs to construct, install, own, and maintain street light facilities and to identify the sources of revenues for recovery of these costs.

· Schedule AL-2, which is applicable to outdoor lighting loads other than street lights, shall be modified to include two options. Schedule AL-2, Option A, retains the same limits on incidental load and rate structure as Schedule AL-2. Schedule AL-2,
Option B, will allow incidental load up to 15 percent of the maximum monthly peak demand, to occur in the daytime or nighttime. The incidental daytime load under Option B may not exceed 20 kW and the tariff shall include on-peak and off-peak energy charges as well as a customer charge.

Based on the evidentiary record of this proceeding, principally prepared testimonies, and the all-party status of the settlement, we find that the
SL settlement agreement fairly resolves identified issues and is reasonable.

We also find the SL settlement agreement is consistent with law. The process for conducting this settlement was in accordance with Article 12 of the Rules of Practice and Procedure. Further, the settlement agreement is not inconsistent in any way with the Public Utilities Code, Commission decisions, or the law in general.

Finally, we find that the settlement agreement is a reasonable compromise of Settling Parties' respective litigation positions. The settlement is also in the public interest because it avoids the cost of further litigation, and conserves scarce resources of parties and the Commission.

4.6. Commercial Submetering
Settlement Agreement

On April 18, 2008, SCE filed Advice Letter (AL) 2234-E to amend Rules 1 and 18 of its tariffs to allow master-metered customers to submeter commercial tenants located on the same premises as the master meter.³⁸ AL 2234-E was protested by Simon Properties, which opposed SCE's limitation of commercial submetering to high-rise buildings. The Scoping Memo in this proceeding subsequently determined that SCE's proposed revisions to Rules 1 and 18 would be considered in this proceeding.

The Commercial Submetering settlement agreement³⁹ describes the proposed revisions to current Rule 18 and contains the following provisions:

· Commercial submetering will be allowed with no building height limitations. Customers who submeter will be allowed to recover their costs of metering, billing and information services according to the terms jointly agreed to by their tenants and as specified in leases.

· Rule 18.E.2 is revised to include consumer protection provisions similar to the ones approved by the Commission for Pacific Gas and Electric Company's (PG&E) customers in D.07-09-004.

· SCE will report on the impact of submetering on the usage of commercial tenants as part of its 2012 GRC application.

· The settlement agreement will be implemented prior to October 1, 2009.

WMA filed comments on the Commercial Submetering settlement agreement. WMA did not oppose the agreement, but noted that the settlement raises concerns about equitable treatment between master-metered customers who submeter their tenants and master-metered customers who submeter their residents. In particular, WMA points to revisions in Rule 18.E.2.f., which provides for the reconciliation of billing differences for each commercial master-metered customer. Therefore, WMA proposes to work with SCE during its next GRC cycle to bring more consistency among the two submetered customer groups. WMA may raise its concerns about consistency as part of SCE's next GRC cycle.

Based on the evidentiary record of this proceeding, principally prepared testimonies, and the all-party status of the settlement, we find that the Commercial Submetering settlement agreement fairly resolves identified issues and is reasonable.

We also find the Commercial Submetering settlement agreement is consistent with law. The process for conducting this settlement was in accordance with Article 12 of the Rules of Practice and Procedure. Further, the settlement agreement is consistent with the commercial submetering provisions adopted for PG&E's customers in D.07-09-004.

We further find that the settlement agreement is a reasonable compromise of Settling Parties' respective litigation positions. The settlement protects the interests of owners of commercial buildings and their tenants and provides incentives to tenants to manage their electric usage. Moreover, the settlement is also in the public interest because it avoids the cost of further litigation, and conserves scarce resources of parties and the Commission.

⁴ The Revenue Allocation settlement agreement may be found as Attachment B of this decision.

⁵ Exhibit 3, p. 4.

⁶ Exhibit 9, p. 2-2, Table 2-1.

⁷ Exhibit 11, p. B-2.

⁸ Attachment B, ¶ 5.ii. The settlement agreement presents marginal cost on a $/customer-month basis. These numbers were converted to $/customer-year by multiplying by 12.

⁹ Attachment B, Revenue Allocation Settlement Agreement, Appendix B. Numbers in this table are based on a December 2008 forecast of SCE's revenue requirement. On June 6, 2009, SCE filed a motion to update its revenue allocation and proposed rates to reflect more recent information regarding revenue requirement changes. The updated revenue requirement results in increases that are lower than the increases forecasted in December 2008. This motion, which is attached as Attachment I of this decision, includes a revised Appendix B which estimates that the system average rate increase for bundled-service customers over December 2008 rates is now projected to be 7.93%.

¹⁰ Lighting, Small and Medium Power.

¹¹ DWR's most recent revenue was allocated in D.08-12-006. In that decision, SCE's allocation was 8.451 ¢/kWh.

¹² Exhibit 100, p. 19.

¹³ Generation revenues allocated to direct access customers are recovered through the Cost Responsibility Surcharge.

¹⁴ Transphase states that it had specifically requested SCE's database and models but that SCE did not provide them. However, Transphase's data requests entered into the record (Exhibits 219, 222 & 225) do not include a specific request for the database and models. At most, the record indicates that Transphase had requested that SCE discuss the "production cost model approach," which SCE did. (See Exhibit 225, Question 22.)

¹⁵ Exhibit 3, pp. 22 - 24 & Appendix D.

¹⁶ See, Exhibit 9, pp. 2-16 - 2-17; Exhibit 11, pp. 24 - 27.

¹⁷ See 7 RT, pp. 551 - 559.

¹⁸ 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.

¹⁹ EAP II, p. 9.

²⁰ See Attachment C.

²¹ Stats. 2001 (1^st Ex. Sess.), ch. 4. Relevant to this proceeding, AB 1X provides that "[i]n no case shall the commission increase the electricity charges in effect on the date that the act that adds this section becomes effective for residential customers for existing baseline quantities or usage by those customers of up to 130% of existing baseline quantities, until such time as the department has recovered the costs of power it has procured for the electrical corporation's retail end use customers as provided in [Division 27 of the Water Code]." (Water Code, § 80110, subd. (e).)

²² Pub. Util. Code § 2851(d)(2) authorizes the Commission to impose additional charges on customers subject to the AB 1X rate protections to fund the California Solar Initiative.

²³ There are two bills currently before the California State Legislature that propose to eliminate the 130% baseline rate protection in AB 1X - Senate Bill 695 (Kehoe) and Assembly Bill 413 (Fuentes). As currently proposed, both bills would limit any rate increases to residential customers with energy usage up to 130% of baseline to the annual percentage change in the Consumer Price Index from the prior year plus 1%, but not less than 3% and not more than 5% per year.

²⁴ SCE has testified that, pursuant to the limitations in AB 1X, any reductions in baseline quantifies for Tier 1 and Tier 2 residential customers shall not be below the baseline quantities in effect on February 1, 2001, as mandated under Water Code § 80110(e).
(7 RT, p. 539:14-20 (SCE/Garwacki).)

²⁵ The settlement agreement provides that "[t]he baseline kilowatt-hour allowance for each revised baseline zone based on the CEC climate zones shall not be less than the allowance in effect in the baseline zones that existed on February 1, 2001." This limitation is consistent with the provisions of Water Code § 80110(e).

²⁶ See, Exhibit 1, Appendix B.

²⁷ 7 RT, p. 544:16-18.

²⁸ 7 RT, pp. 544:25 - 545:12.

²⁹ SCE Opening Comments on Proposed Decision, p. 3.

³⁰ In response to an ALJ Ruling issued on July 31, 2009, SCE stated that it had contacted the settling parties concerning a modification to the RSC settlement agreement to allow customers who participate in CPP to also be eligible for SDP or PTR. SCE stated that each settling party who responded has agreed to the modification.

³¹ See Attachment D. Attachment D reflects changes made to settlement agreement during evidentiary hearings. (See 7 RT, pp. 549:21-551:1.)

³² In response to an ALJ Ruling issued on July 31, 2009, SCE stated that it had contacted the settling parties concerning a modification to the MLP settlement agreement to allow customers who participate in CPP to also be eligible for BIP or APS. SCE stated that each settling party who responded has agreed to the modification.

³³ Transphase Opening Brief, p. 32.

³⁴ Transphase argues, in part, that adoption of the settlement agreement would reduce the monthly savings of a customer with a thermal energy storage (TES) PLS system and alleges that SCE is attempting to make TES uneconomical. In designing a rate to provide incentives for PLS, however, the focus is on the entire customer group, not specific PLS technology. The fact that Schedule TOU-8, Option A may result in lower monthly savings for TES customers is not sufficient grounds to find that the settlement agreement is unreasonable or discourages PLS technologies.

³⁵ See Attachment E.

³⁶ In response to an ALJ Ruling issued on July 31, 2009, SCE stated that it had contacted the settling parties concerning a modification to the AP settlement agreement to allow customers who participate in current demand response programs (i.e., TOU-BIP, AP-I and SDP) to also be eligible for CPP. SCE stated that each settling party who responded has agreed to the modification.

³⁷ See Attachment F.

³⁸ SCE filed an amended AL 2234-E on April 25, 2008.

³⁹ See Attachment G.