10. Statewide Emergency and Price Responsive Programs
Several existing demand response programs are available in the territories of all three utilities; some of these programs are emergency-triggered and others are considered price responsive. This section addresses both types of programs that are available through all three utilities.
10.1. Emergency Programs
Statewide emergency programs include the Base Interruptible Program, the Optional Binding Mandatory Curtailment program, and the Schedule Load Reduction Program. These programs, like the utility-specific emergency-triggered programs discussed in Section 11, below, are evaluated based on the principles articulated in Section 9, above.
The Base Interruptible Program requires participants to reduce their electricity usage to a pre-determined base level when the program is called. In Resolution E-4220, the Commission authorized PG&E, SCE, and SDG&E to modify their Base Interruptible Program programs so that the Base Interruptible Program can now be called when CAISO provides notice that either a Stage 1 or Stage 2 Emergency is imminent. The Base Interruptible Program can still be triggered with Stage 1 or 2 alerts from CAISO.
PG&E proposes several changes to its Base Interruptible Program in 2009 through 2011. Specifically, PG&E proposes to realign the current Base Interruptible Program zones to coincide with the CAISO Local Capacity Areas to increase this program's compatibility with MTRU and more easily allow Base Interruptible Program resources to act as Participating Load or Proxy Demand Resource.50 PG&E also proposes eliminating Base Interruptible Program Option B, both because no participant has ever enrolled in this option, and because the features of Option B are similar to PG&E's existing PeakChoice program.51 PG&E does not plan to expand its Base Interruptible Program, and in fact proposes the possibility of transitioning Base Interruptible Program Option A participants into a similar option under its broader PeakChoice Program in 2011, and discontinuing the Base Interruptible Program as an independent program. 52 PG&E requests $1.2 million to fund administration of the Base Interruptible Program; incentives are addressed in another proceeding.
Unlike PG&E, SDG&E does not propose major changes to its Base Interruptible Program in 2009-2011. SDG&E seeks to expand its Base Interruptible Program during this period, and estimates that Base Interruptible Program will have 5 megawatts of capacity in 2010.53, SDG&E requests a budget of $1,657,067, a slight increase over 2008.
SCE is not proposing any modifications to its current Base Interruptible Program (formerly its I-6 tariff). SCE expects approximately 10% growth for this program and is requesting $5,068,756 in funding for the 2009-2011 period.54
DRA recommends that the Commission limit the Base Interruptible Program for all three utilities to one year of funding, and freeze enrollment at current levels.55 DRA also questions the PG&E claim that it can transition most of its Base Interruptible Program customers to PeakChoice; DRA notes a lack of evidence that PG&E has worked with its customers to educate them about this possible change or show them that customers are willing to make such changes.56
CAISO supports the DRA proposal to approve and fund the Base Interruptible Program for one year only.57 Additionally, CAISO urges the Commission to not approve any additional enrollment or recruitment into this program until the Commission makes a decision on how the Base Interruptible Program will be treated under the Commission's Resource Adequacy program.58 In response to DRA and CAISO, SCE states that "there is no legitimate support in the record of this proceeding for limiting Base Interruptible Program to only one year in duration or freezing current participation levels."59
CLECA expresses concerns about the PG&E proposal to transition participants in the Base Interruptible Program to a similar option as the PeakChoice program. Generally, participants in PeakChoice may choose to change certain terms of their demand response participation at intervals, sometimes as often as monthly. CLECA contends that PG&E's attempt to subsume Base Interruptible Program into PeakChoice will create customer confusion and "water down those elements of the [Base Interruptible] program which are its strength."60 CLECA argues that the Commission should not evaluate the Base Interruptible Program on the basis of its ability to be integrated into the CAISO's new markets.61 CLECA asserts that there are good reasons to maintain emergency programs such as the Base Interruptible Program and that the Commission should "resist the temptation to attempt a force fit of [the Base Interruptible Program] into MRTU."62 In support of its recommendation that the Commission maintain the Base Interruptible Program as a reliability program triggered by system emergencies, CLECA asserts that many of its members "are not particularly interested in tracking market prices for electricity or placing energy procurement above producing their product,"63 and might discontinue participation in demand response programs if the program requirements change.
TURN notes the low enrollment in SDG&E's Base Interruptible Program, and recommends maintaining the SDG&E program at its current level with a reduced budget of $993,000.
According to the cost effectiveness numbers provided by the utilities, the Total Resource Cost test results for the Base Interruptible Program are greater than one for all three companies.64 Based on these estimates, the Base Interruptible Program appears to be cost effective statewide. We decline to approve the expansion of the SCE and SDG&E Base Interruptible Programs, as requested. Though we are capping the enrollment in these programs at their current megawatt level, we approve some funding for program-specific marketing activities in order to allow utilities to replace megawatts lost through customer turnover.
PG&E's proposed transition of Base Interruptible Program participants into PeakChoice does not appear to be fully developed at this time. As noted by DRA, it is not clear whether PG&E has studied the willingness of its customers to enroll in PeakChoice. PG&E states that it will transition Base Interruptible Program resources "into the PeakChoice program (with similar options)."65 However, it is unclear from this statement if PG&E would transition Base Interruptible Program into a PeakChoice program in which the Base Interruptible Program would be triggered by non-emergency conditions, or whether Peak Choice would have a Base Interruptible Program option that retains its emergency-only trigger. For these reasons, we deny PG&E's request to transition Base Interruptible Program customers to PeakChoice at this time, and we also deny the PG&E request to be allowed to terminate the Base Interruptible Program via advice letter in the future. Given the size and importance of the Base Interruptible Program, any significant changes should be carefully reviewed though a formal Commission proceeding.
The Base Interruptible Program is not well integrated with the CAISO's new markets, though the recent change that allows it to be called in advance of a Stage 1 emergency does increase the flexibility of the program. Given that information on the optimal design of demand response programs under the CAISO's new markets is likely to develop gradually over the next several years, and that the amount of emergency demand response needed to ensure reliability has not yet been determined in Phase 3 of R.07-01-41, we see no benefit to requiring an additional review of the Base Interruptible Program before approving the program for years beyond 2009; it is reasonable to approve a three-year budget for this program for the complete 2009-2011 period. We establish the following budget amounts based on the lower of 2008 actual spending or 2009 proposed funding. We order PG&E to end its Base Interruptible Program Option B within 30 days of the effective date of this decision. The following total budgets for 2009-2011 are approved for the utilities' Base Interruptible Programs:
2009-2011 Requested Budget |
2009-2011 Authorized Budget | |
PG&E |
$1,242,000 |
$800,000 |
SDG&E |
$1,657,067 |
$1,475,423 |
SCE |
$5,068,756 |
$4,702,37466 |
These budgets and total budgets for 2009-2011 throughout this decision include the amounts authorized in the Bridge Funding decision and already spent during 2009.
The Optional Binding Mandatory Curtailment Program is a voluntary program that exempts participating customers from rotating outages if they commit to reducing power on a particular distribution circuit by at least 15% upon notification of a local or statewide electrical emergency. No financial incentives are paid to program participants
PG&E's requests that its Optional Binding Mandatory Curtailment Program and Pilot Optional Binding Mandatory Curtailment Program be consolidated into a single program, with a total budget of $138,000.
SCE proposes to maintain its current level of customer enrollment in the Optional Binding Mandatory Curtailment Program (currently 12 customers with an associated reduction of approximately 9 megawatts) and its current budget level for this program, $197,994.
SDG&E maintains an Optional Binding Mandatory Curtailment Program which currently has no participants enrolled. For this reason, SDG&E does not request a budget for the Optional Binding Mandatory Curtailment Program.
TURN recommends that the Commission eliminate funding for the Optional Binding Mandatory Curtailment Program and close the program, or, if the program remains open, that administrative costs of the program should be borne by program participants. No other parties took a position on the Optional Binding Mandatory Curtailment Program for any utility.
All three utilities propose maintaining their Optional Binding Mandatory Curtailment Programs at their current, relatively low levels. TURN's recommendation that this program's administrative costs should be charged directly to program participants is inconsistent with our treatment of other demand response programs, and we decline to adopt it. Rather than require the utilities to transfer Optional Binding Mandatory Curtailment Program participants to another program, we authorize the continuation of this program at the requested funding levels. We also authorize PG&E to combine its Optional Binding Mandatory Curtailment Program and Pilot Optional Binding Mandatory Curtailment Program, as requested. The authorized budgets are as follows:
2008-2009 Requested Budget |
2008-2009 Authorized Budget | |
PG&E |
$138,000 |
$138,000 |
SDG&E |
$0 |
$0 |
SCE |
$197,994 |
$197,994 |
The Scheduled Load Reduction Program was established in January 2001, pursuant to legislation adopted by the state during the energy crisis. Program participants are allowed to choose time periods during which they will reduce their load by at least 100 kilowatts or 1%, and are paid an incentive for these reductions. This program is legislatively mandated and so cannot be discontinued.
PG&E includes the Scheduled Load Reduction Program with its Optional Binding Mandatory Curtailment Program, and does not request a separate budget for this program.
SCE and SDG&E list their Scheduled Load Reduction Program separately, but both state that they do not have participants currently enrolled in this program. SDG&E does not request funding for the Scheduled Load Reduction Program in this proceeding; a minimal budget for this program was approved in an earlier SDG&E rate case (see D.08-02-034). SDG&E also notes its intention to minimize expenditures while maintaining this program in the 2009-2011 period. SCE requests a minimal budget in this proceeding to continue to support the availability of this program in case there is future interest by customers.
No other parties took a position on the Scheduled Load Reduction Program for any utility.
All three utilities propose maintaining the availability of their Scheduled Load Reduction Program, in compliance with the legislative mandate for this program. There are no objections to continuing this program, and only SCE requests funding in this proceeding. We authorize the continuation of the Scheduled Load Reduction Program at the requested funding levels, as follows:
2008-2009 Requested Budget |
2008-2009 Authorized Budget | |
PG&E |
$0 |
$0 |
SDG&E |
$0 |
$0 |
SCE |
$52,995 |
$52,995 |
10.2. Price Responsive Programs
Price responsive programs are generally triggered by high temperatures or the wholesale market price of electricity. The utilities may notify customers that a program is being triggered one day in advance of the event day (day-ahead), or on the same day as the event (day-of). These programs include the Demand Bidding Program, the Capacity Bidding Program, the Critical Peak Pricing tariffs, and the Real Time Pricing tariffs. The Peak Time Rebate tariffs do not require funding in this proceeding and so are not discussed here.
Under the Demand Bidding Program, participating customers may submit bids to voluntarily reduce load when a Demand Bidding Program event is called, in return for payments if their bid is accepted and the load reduction is delivered.
PG&E proposes to end its Demand Bidding Program after 2009, and transition participating customers into a similar option under its PeakChoice Program. For this reason, PG&E requests a total of $1 million in funding for this program, for 2009 only. PG&E estimates the benefit to cost ratio of this program in its service territory using the Total Resource Cost test as being over 2, suggesting that the program is cost effective for PG&E.
SDG&E seeks to eliminate this program, which it finds to be duplicative and ineffective.67 SDG&E has 366 accounts enrolled in its Demand Bidding Program for a total load of approximately 11.5 megawatts as of December 2008. SDG&E plans to transition its Demand Bidding Program participants onto its default Critical Peak Pricing, and to hold a workshop for these customers to explain the transition. Because SDG&E requests to discontinue this program, it does not request funding for it during 2009-2011.
SCE proposes to continue its Demand Bidding Program through 2009 and into early 2010, and to then transition Demand Bidding Program customers to its Energy Options Program. SCE estimates that in 2009-2011, it will have over 1,000 customers enrolled in the Demand Bidding Program, for approximately 35 megawatts of load. SCE estimates the cost effectiveness of the Total Resource Cost test at approximately 0.81; this suggests that the program is close to being cost effective, but may not be at this time. To support the Demand Bidding Program, SCE asks for a total of $259,939 for 2009-2011, with $254,939 for 2009 and $5,000 for early 2010. After this, SCE does not anticipate the need to fund this program separately from Energy Options, to which former Demand Bidding Program participants would be transitioned.
In its testimony and briefs, DRA assigns the Demand Bidding Program Rank 2 in its ranking system described in Section 8.7, above. DRA suggests that the Commission approve the Demand Bidding Program for 2009-2011, but require all three utilities to file advice letters during this period to make it more uniformly cost effective across the state.68
PG&E's Demand Bidding Program has one of the highest estimated benefit to cost ratios of any price responsive programs. In addition, the proposed transition of Demand Bidding Program customers into PeakChoice raises some concerns with tracking the load impact and cost of each option. Because PeakChoice is a relatively new program and offers extensive flexibility by allowing customers to select from dozens of option bundles, it is complicated to analyze the program. Until more historical data are available for use in developing load impact estimates for PeakChoice, it is premature to transition Demand Bidding Program customers into PeakChoice. PG&E also has not provided a detailed plan for transitioning customers from Demand Bidding Program to PeakChoice, so it is unclear whether such a transition would be successful in maintaining the Demand Bidding Program's load impact. For these reasons, we do not authorize PG&E to discontinue this program at the beginning of 2010. The budget requested by PG&E for 2009 is comparable to the reported expenditures for 2008, and provides a reasonable annual amount for PG&E's Demand Bidding Program during 2009-2011. We adopt a three-year budget of approximately $3 million for this program, as specified below.
SDG&E seeks to eliminate this program, and has provided a plan for transitioning its participants to another demand response program, Default Critical Peak Pricing, in order to retain the load reduction currently available through the Demand Bidding Program. It is reasonable to approve the requested transition to take place on or before January 1, 2010. Because SDG&E's program is currently funded through D.08-12-038 on a month-to-month basis, some budget for this program will be necessary until the transition is completed, but funding will not be necessary during 2010 and 2011.
Unlike PG&E, the cost effectiveness estimate for SCE's Demand Bidding Program is less than one, implying that the program may not be cost effective in its current form. In addition, SCE has provided a plan for transitioning its participants into its Energy Options Program in order to retain the load reductions currently available through this program.
The proposed Energy Options Program is new and, like PG&E's cafeteria-style demand response program, it offers customer multiple options for certain terms. However, Energy Options has fewer possible options than PeakChoice, and appears easier to analyze. Given that we have fewer concerns about analysis of this program than PeakChoice, that SCE's Demand Bidding Program may not be cost effective in its current form, and that SCE has a plan for transitioning its customers into a new program while retaining their load reduction, it is reasonable to approve SCE's proposal to discontinue its Demand Bidding Program in early 2010. For this reason, we approve SCE's proposed budget for 2009 and 2010, and its proposal to transition participants into the Energy Options Program in early 2010.
DRA raises a concern that the cost effectiveness results for the Demand Bidding Program vary in different utility service territories. As DRA notes, this may be due to differences in cost effectiveness methodologies or in program design (such as differences in incentive levels) and administration, and could be addressed through increased reporting requirements and program improvements during the 2009-2011 period. We decline to adopt the DRA recommendation to require all three utilities to file advice letters detailing their progress in increasing the cost effectiveness of these programs and transitioning them to perform within the CAISO's new markets. This is unnecessary given that we are approving the SDG&E and SCE requests to transition their participants to other programs, and that the PG&E Demand Bidding Program appears to be cost effective based on current estimates.
We approve the following budgets for the Demand Bidding Program in 2009-2011:
2009-2011 Requested Budget |
2009-2011 Authorized Budget | |
PG&E |
$1,072,000 |
$3,216,000 |
SDG&E |
$492,000 |
$492,000 |
SCE |
$259,939 |
$259,939 |
Under the Capacity Bidding Program, participating customers commit to providing a particular amount of load reduction, which may vary each month, and receive capacity payments for the elected amount of load reduction. Participants also receive an energy payment based on the kilowatt-hour reduction during a called event. The capacity bidding program contains a day-ahead option, through which participants may nominate their load reduction for the next day, and a same day (referred to as "day-of") option, in which load is called the day of the event. Parties that do not deliver at least 50% of their elected load reduction under this program are subject to penalties, and, as with most demand response programs, participants must have appropriate metering to enroll.69
Currently, PG&E allows direct customer enrollment in its Capacity Bidding Program, in addition to customer participation through its aggregator managed contracts. PG&E proposes to discontinue direct customer enrollment in its Capacity Bidding Program, and continue this program only through its aggregator contracts. PG&E requests a total of $6.6 million for the Capacity Bidding Program during 2009-2011.70 PG&E currently has no participants enrolled in this program directly through the utility; all existing participants have been enrolled through aggregators. PG&E estimates the benefit to cost ratio of the day-ahead Capacity Bidding Program option as 0.50 and of the day-of notification option as 0.77, for an overall benefit to cost ratio of 0.61. By PG&E's report, this program provided approximately 18 megawatts of load reduction in 2008.
Like PG&E, SDG&E currently allows direct customer participation in its Capacity Bidding Program, as well as participation through a third-party aggregator. SDG&E recommends expansion of its Capacity Bidding Program during the 2009-2011 period. SDG&E estimates that the Capacity Bidding Program has a load reduction potential of approximately 21 megawatts, and requests approximately $6.8 million over the three-year cycle. SDG&E estimates the benefit to cost ratio of the day-ahead Capacity Bidding Program option as 1.45 and of the same-day notification option as 1.26.
SCE proposes to continue its Capacity Bidding Program through 2009 and into early 2010, and to then transition participating customers to its cafeteria-style program, the Energy Options Program. SCE asserts that combining this program into the Energy Options Program along with the Demand Bidding Program, described above, would provide customers with more flexibility and increase the program's compatibility with the CAISO's new markets. SCE requests a budget of $812,299 for 2009 and early 2010, with $638,299 for 2009 and $174,000 for 2010. SCE estimates the overall cost effectiveness of its Capacity Bidding Program is 0.86; SCE did not initially provide separate cost effectiveness analysis for its day-ahead and day-of options. After early 2010, SCE does not anticipate the need to fund this program separately from Energy Options, to which former Demand Bidding Program participants will be transitioned.
TURN argues that the Capacity Bidding Program should be discontinued for both SDG&E and PG&E. TURN notes the relatively low benefit to cost ratio of for PG&E (0.61 overall) in recommending that PG&E's Capacity Bidding Program funding request be denied. Both DRA and TURN suggest that the SDG&E estimate of potential load reduction through the Capacity Bidding Program is unrealistically high, and TURN recommends that we deny funding for SDG&E's program.
Like the Demand Bidding Program, the Capacity Bidding Program is currently offered statewide, and its enrollment, funding, and estimated cost effectiveness vary by utility service territory.
PG&E requests approval to cease enrolling customers directly in the Capacity Bidding Program, and to allow only third-party aggregators to enroll customers in its Capacity Bidding Program in 2009-2011. Given that all PG&E customers currently enrolled in this program have been enrolled through aggregators, it is reasonable to continue customer enrollment under the management of aggregators. As noted by TURN and DRA, the benefit to cost ratio of this program, and especially the day-ahead option, are far below one, so it does not appear that this program is cost effective for PG&E at this time. However, there is value to having this program or a similar option operate statewide, and we hope that the benefit to cost ratio may be improved in the future. Given the relatively low benefit to cost ratio of PG&E's program, however, it would not be reasonable to fully fund this program as requested by PG&E. Specifically, it is reasonable to expect that the funding spent on administrative expenses for a program should not be greater than the amount spent on incentives. For this reason, we will continue the PG&E program as an aggregator-managed program, but with a lower budget than proposed by PG&E. PG&E requests $4,623,609 for administrative activities, and $1,564,685 for incentives. We authorize a total funding of $3,615,076 for PG&E's Capacity Bidding Program for 2009-2011, as noted below.
SDG&E seeks to expand this program, and the benefit to cost ratios for both its day ahead and day of options are above one. It is not clear whether the estimates of program potential load impact for this program provided by SDG&E are realistic, but it is clear that both enrollment in this program and the load drop associated with it have increased in the recent past, and it appears that there is interest in this program among customers in the SDG&E service territory. For 2009 only, the estimated administrative costs for this program exceed the forecast incentives; this is not the case for the budget requests for 2010 and 2011. Consistent with our policy that the administrative costs should not exceed the incentive costs for a program in a given year, we reduce SDG&E's proposed budget for this program by approximately $400,000, the amount of the excess administrative costs for 2009. Given that this program appears to be cost effective, it is reasonable to approve the SDG&E request to expand this program. We authorize total funding of $6,426,173 for this program during 2009-2011, the full request less the excess administrative costs for 2009, as noted below.
SCE proposes to retain its Capacity Bidding Program only through early 2010, when it expects to transition its participating customers to its Energy Options Program. The cost effectiveness estimates for SCE's Demand Bidding Program are less than one, though they appear to be slightly higher than the ratios for PG&E's program. In addition, SCE has provided a plan for transitioning its participants into its Energy Options Program in order to retain the load reductions currently available through this program. As discussed above, the Energy Options Program is new but appears relatively easy to analyze. Given that the Capacity Bidding Program may not be cost effective in its current form, and that SCE has a plan for transitioning its customers into a new program while retaining their load reduction, it is reasonable to approve SCE's proposal to discontinue its Capacity Bidding Program in early 2010. For this reason, we approve SCE's proposed budget of $812,299 for 2009 and early 2010, and its proposal to transition participants into the Energy Options Program in early 2010.
In the future, all three utilities are required to report results separately for their day-ahead and day-of Capacity Bidding Program options. We approve the following budgets for the Capacity Bidding Program in 2009-2011:
|
2009-2011 Requested Budget |
2009-2011 Authorized Budget |
PG&E |
$6,600,000 |
$3,615,076 |
SDG&E |
$6,831,983 |
$6,426,173 |
SCE |
$ 812,299 |
$ 812,299 |
Critical Peak Pricing Programs, variations of which are available through all three utilities, applies an increased rate to electricity consumption during certain high usage period in which program events are called. During non-event periods, participants in Critical Peak Pricing receive a lower rate to offset the increased rate during events. 71 Events may be called on summer weekdays, and last from noon to 6:00 p.m. The higher event rate is intended to induce customers to lower their electricity use during these critical peak events. There is no penalty for failure to reduce usage during peak times other than the application of the high peak rate for the electricity used. Unlike some other demand response programs, customers receive the benefits of program participation directly through the tariffed rate applied during non-peak hours; for this reason, the Critical Peak Pricing Program does not require calculation of an estimated baseline and associated load drop during events for customer settlement purposes.72
PG&E's Critical Peak Pricing Program applies a high premium rate for energy usage from 3:00 p.m. to 6:00 p.m. on event days, and a slightly lower premium rate from noon to 3:00 p.m. on those days. PG&E may call a maximum of 12 events per year. In D.08-07-045, the Commission ordered PG&E to propose a default Critical Peak Pricing Tariff (the existing tariff is voluntary) to be in place by May 2010. In its application, A.08-06-001, PG&E proposes to continue this program with a budget of $3.5 million during 2009-2011. PG&E estimates the TRC Test benefit to cost ratio of its Critical Peak Pricing Program at approximately 1.31.
SDG&E has two Critical Peak Pricing Tariffs, its Default Critical Peak Pricing (CPP-D) and its Emergency Critical Peak Pricing (CPP-E). The Emergency Critical Peak Pricing program is discussed in Section 11.3.1, below. SDG&E expects participation in its CPP-D tariff to expand during 2009-2011, but does not request funding for this activity in this proceeding because its CPP-D is funded through the company's General Rate Case. SDG&E estimates that its CPP-D tariff will have a load reduction potential of approximately 60 megawatts in 2010, and reports the tariff's TRC benefit to cost ratio as 2.8.
SCE currently has two Critical Peak Pricing tariffs, one for customers with a demand between 200 kilowatts and 500 kilowatts (the CPP-Volumetric Charge Discount (VCD) tariff), and another for customers with demands of over 500 kilowatts (CPP-Generation Capacity Charge Discount (GCCD) tariff). In its recent general rate case, SCE requests to create a default Critical Peak Pricing tariff that would apply to all commercial and industrial customers with a demand of 200 kilowatts or more. In this proceeding, SCE requests $2,641,460 to cover expenses related to its Critical Peak Pricing tariffs during 2009-2011. SCE estimates the cost effectiveness ratio of this program at 0.69.
TURN questions the need for PG&E to receive Critical Peak Pricing funding in this proceeding, because PG&E has authority to record incremental costs associated with the implementation of dynamic pricing rates, including Critical Peak Pricing, in a memorandum account. If the Commission decides to authorize funding in this proceeding, TURN recommends authorizing a budget of $2.124 million for 2009-2011 to reflect the 2006-2008 recorded costs. PG&E did not address TURN's concerns related to Critical Peak Pricing funding in its briefs. No parties oppose the Critical Peak Pricing proposals of SCE and SDG&E, though CAISO suggests that the Critical Peak Pricing tariff should be transitioned from the current weather-sensitive design to a more price responsive design that varies prices based on electricity costs at different times.
Similar versions of Critical Peak Pricing are available statewide to customers of all three utilities. All three utilities propose to transition from offering these tariffs on a voluntary basis to making them the default for certain groups of customers, who could then opt out of the tariff if they choose to do so. The utilities in general propose making their Critical Peak Pricing tariffs more consistent with the CAISO's new markets. According to the cost effectiveness estimates, this tariff is cost effective for PG&E and SDG&E, though apparently not for SCE.
The Commission has expressed its support and preference for dynamic pricing in several decisions in the past four years. Default Critical Peak Pricing has already been ordered for PG&E and SDG&E, and is under consideration for SCE. It is likely that enrollment in these programs will increase as they become default tariffs for certain groups of customers. It is not necessary to approve funding for SDG&E in this proceeding, so we approve the continuation of its Critical Peak Pricing Program with funding authorized in its General Rate Case Decision, D.08-02-034. TURN's argument that funding for PG&E should not be authorized here for PG&E because it already has the ability to record costs for this program in a memorandum account is not persuasive; funding for Critical Peak Pricing has been authorized in the demand response-related proceeding in the past and is reasonably requested and authorized here for 2009-2011. This program appears to be cost effective for PG&E, and it is reasonable to avoid the funding uncertainty that would be created by deferring the decision on funding to another proceeding. At the same time, we recognize that the funding for Critical Peak Pricing authorized in this decision should be discontinued if a new default Critical Peak Pricing program is adopted in A.09-02-022. Until such changes may be made, however, we approve PG&E's request for $3.5 million for its Critical Peak Pricing tariff in 2009-2011; this funding will end if funding for Critical Peak Pricing is approved in A.09-02-022. The only Critical Peak Pricing Tariff that does not appear to be cost effective based on the information contained in these applications is that of SCE, but no parties have objected to the continuation of SCE's Critical Peak Pricing program or to the company's proposal to transition the program to a default tariff. We expect that this activity may become more cost effective for SCE as it becomes a default rate for many customers, and we approve the requested budget of $2.2 million for 2009-2011.
We approve the following budgets in this proceeding for Critical Peak Pricing in 2009-2011:
|
2009-2011 Requested Budget |
2009-2011 Authorized Budget |
PG&E |
$3,514,000 |
$3,514,000 |
SDG&E |
$0 |
$0 |
SCE |
$2,641,259 |
$2,641,259 |
SCE offers a program that it refers to as "Real Time Pricing." Under SCE's Real Time Pricing program, the price of electricity for specific times of day is set based on the maximum temperature recorded the previous day. The prices are not based on wholesale market prices. SCE requests approximately $70,000 in this proceeding to administer Real Time Pricing. SCE estimates the TRC benefit to cost ratio of its Real Time Pricing Program at 1.08, meaning that this program may be cost effective in the SCE service territory. PG&E and SDG&E do not request funding for a similar program.
DRA suggests that the SCE Real Time Pricing tariff is not cost effective, though it appears from the SCE analysis that it is cost effective under the analytical scenarios provided in the utility's testimony.73 As in the case of Critical Peak Pricing, CAISO suggests that the Real Time Pricing tariff should be transitioned from the current weather-sensitive design to a more price responsive design that varies based on electricity costs at different times.
Real Time Pricing has already been adopted by this Commission for SCE's service territory, and only SCE requests administrative funding within this proceeding. Real Time Pricing appears to be cost effective for SCE. It is reasonable to provide administrative support for Real Time Pricing as requested by SCE, and we approve the company's request for $70,000, as specified below:
|
2008-2009 Requested Budget |
2008-2009 Authorized Budget |
PG&E |
$0 |
$0 |
SDG&E |
$0 |
$0 |
SCE |
$70,419 |
$70,409 |
50 Exhibit 201, Chapter 2, pp. 6-7.
51 Exhibit 201, Chapter 2, p. 7.
52 Exhibit 201, Chapter 2, p. 3.
53 SDG&E Exhibit 102A, p. 31.
54 SCE Amended Testimony, p. 35.
55 DRA Opening Brief, p. 30.
56 DRA Protest, September 29, 2008, p. 8.
57 CAISO Reply Brief February 11, 2009, p. 2.
58 CAISO Comments to Utility Applications, July 9, 2008, p. 5.
59 SCE Reply Brief, p. 22.
60 CLECA Opening Brief, p. 5.
61 CLECA Reply Brief, p. 4.
62 CLECA Opening Brief, p. 6.
63 CLECA Opening Brief, p. 7.
64 Base Interruptible Program TRC results -- SCE: 1.11; PG&E: 1.03; SDG&E: 1.48.
65 Exhibit 201, Chapter 2, p. 7.
66 This number is based on the SCE 2008 total program expenditures included in the January 2009 monthly spending reports, with marketing costs removed.
67 SDG&E Opening Brief, p. 53.
68 DRA Opening Brief, pp. 31-32.
69 D.08-12-038 provides $128,000 for PG&E, $89,500 for SCE, and $77,000 for SDG&E for per month the Capacity Bidding Program until the end of 2009 or until a subsequent decision provides funding for the remainder of 2009-2011.
70 Aggregator managed portfolio contracts were approved in previous proceedings.
71 D.08-12-038, the Bridge Funding Decision in this proceeding, provides $102,000 for PG&E, $12,500 for SCE, and $15,000 for SDG&E for the existing Critical Peak Pricing programs per month until the end of 2009 or until a decision is reached providing funding for the remainder of 2009-2011.
72 Load Impact calculations for resource adequacy and other purposes are still required.
73 SCE Exhibit 1, pp. 219-220.
