11. Individual Utility Programs
In addition to the statewide programs discussed in Section 10, each utility has both emergency-triggered programs and price responsive programs that are approved to operate solely in their own service territory. Those programs are discussed below.
11.1. PG&E
SmartAC is an emergency-triggered program specific to PG&E; this program was formerly the Air Conditioning Direct Load Control Program. The SmartAC Program provides residential and small business customers with an incentive for temporary disconnection of their air conditioner's electrical load during peak periods. The SmartAC program and budget were approved by the Commission on February 14, 2008, in D.08-02-009, which approved a settlement agreement among PG&E, DRA, and TURN allowing PG&E to expand its SmartAC program to approximately 305 megawatts of load reduction by June 1, 2009. The estimated TRC benefit to cost ratio for this program is 1.53, implying the program may be cost effective. PG&E does not request program changes or budget for this program in this application. Rather than capping the SmartAC program at its current size in conformance with the policy adopted in this decision for other emergency-triggered programs, PG&E should adhere to the expanded size authorized and funded in D.08-02-009. In addition, we encourage PG&E to explore ways to begin transitioning this air conditioner cycling program to use more price responsive triggers.
The SmartRate Program is a price-responsive program similar in structure to the Critical Peak Pricing tariffs. SmartRate offers discounts to residential and small commercial customers during non-SmartRate event days in exchange for higher on-peak energy charges during the SmartRate high-price hours. PG&E may recruit SmartAC customers for the SmartRate program because the enabling technology used in SmartAC can be used as a tool to automate customers' participation in SmartRate events. The SmartRate program and budget were approved in July 2006 in D.06-07-027. The estimated TRC benefit to cost ratio for this program is 0.63, well below the cost effective level, but it is possible that enrollment of SmartAC customers in the SmartRate program may increase the load reductions due to the program along with the program's cost effectiveness. PG&E does not request program changes or funding for SmartRate in this application.
PG&E's PeakChoice program, formerly called the PG&E Cafeteria-style Menu Program, allows customers to choose from several program characteristics such as amount of load reduction, event window and duration, notification time, and number of consecutive events that may be called for the customer. This flexibility is intended to allow individual customers to tailor their demand response commitments to meet their own needs. In this application, PG&E proposes to modify event notification time of non-day-of options from 12 noon to no later than 2:00 p.m., the day preceding an event, one hour after the expected 1:00 p.m. CAISO price posting time, to align with CAISO markets.74 PG&E estimates the benefit to cost ratio of PeakChoice at 1.39. PG&E requests a total of $16.9 million for this program for 2009-2011.
TURN objects to the large increase in funding for this program compared to its funding in previous years, and particularly objects to the large amount of funding requested for administrative purposes.75 DRA classifies PeakChoice in its Rank 2 category, supporting its continuation with some restrictions. SF Power recommends that the Commission require PG&E to allow aggregators to enroll customers in PeakChoice, in order to provide customers with more flexibility than is currently offered in the main PG&E program open to aggregators, the Capacity Bidding Program.76
PG&E's PeakChoice program is quite complex to analyze, given the many options available to customers, and it is also fairly new, having been approved in Resolution E-4127 on February 28, 2008. Based on the preliminary estimates of cost effectiveness, it appears that PeakChoice may be cost effective, and PG&E is making changes to the program to enable it to function better within the CAISO's new markets. By design, different options under PeakChoice have different program characteristics, making the program fairly flexible and able to be called under a variety of circumstances. It is reasonable to continue the PeakChoice program for these reasons. We also approve PG&E's request to modify event notification time from 12 noon to no later than 2:00 p.m. the day preceding an event to align with CAISO markets.
The forecasted expenditures for PeakChoice in 2008 were approximately $2.8 million; as noted by TURN, total estimated costs of this program from its adoption in 2007 through the end of 2008 were approximately $4 million. These numbers are much lower than the $16.9 million requested by PG&E for this program in its application. PG&E does not provide sufficient rationale for such a large budget request.
Part of PG&E's planned expansion of this program was to transition participants in the Base Interuptible Program and the Demand Bidding Program into PeakChoice starting in 2010. In Section 10.2.1.3, we reject the requested transition, and increase the budget for the Demand Bidding Program by $2 million to reflect the ongoing costs of the Demand Bidding Program. It is reasonable to reduce the proposed PeakChoice budget by at least a commensurate amount.
In addition, as TURN notes, PG&E's proposed administrative costs for this program are extremely high compared to the estimated costs of incentives under the program. As discussed above with respect to PG&E's Capacity Bidding Program, it is reasonable to expect that administrative expenses for a program should not be greater than the amount spent on incentives. We approve a total budget for 2009-2011 of $9 million, which allows for some growth of the program over 2008 forecast levels. Initial administrative costs for PeakChoice also included costs associated with developing a new program, including implementation of new information technology and other systems; such one-time startup costs should no longer be necessary, and the decreased budget both reflects and should encourage a decrease in future administrative costs compared to during program implementation.
In its application, PG&E does not suggest opening the PeakChoice program to aggregators. This is not consistent with SCE's request to open its Energy Options Program, and is not consistent with the current Commission policy decision allowing aggregators to participate in SCE's Capacity Bidding Program. In its comments on the proposed decision, PG&E objects to the possibility of opening this program to aggregators, estimating that doing so would cost approximately $2 million and take up to 12 months to implement. These numbers are not supported in the record, and the cost estimate for redesigning information technology and other systems is equal to the amount initially requested to develop information technology systems for the PeakChoice program as a whole. Still, it is not clear whether the benefits of a potential increase in enrollment from opening this program to aggregators would outweigh the costs required to modify the program to support this change. We decline to open this program to aggregators at this time, and will revisit this issue in our next evaluation of the PeakChoice program.
The Business Energy Coalition Program is targeted to "hard to reach" customers thought to be unlikely to enroll in other demand response activities. Consistent with past Commission guidance, PG&E is required to transition participants in the Business Energy Coalition Program to programs in which incentives are tied to performance, and recent changes in the Business Energy Coalition require that incentive payments made through this program are based on performance relative to the current program baseline. In the 2006-2008 time period, PG&E spent approximately $13 million on the Business Energy Coalition.
In the 2009-2011 time period, PG&E proposes splitting the Business Energy Coalition into two related programs. Under this proposal, PG&E would maintain the Business Energy Coalition outside of San Francisco with some minor modifications, and transition Business Energy Coalition participants within San Francisco into an Auto Business Energy Coalition (ABEC) program utilizing automated demand response capabilities to enable the program to provide immediate load reduction in response to localized system emergencies. The goal for ABEC is to gain an automated demand response capability to curtail 20 megawatts when the program is called in times of high temperatures within San Francisco. PG&E recommends the following modifications to the Business Energy Coalition and ABEC: the option of a different baseline for settlement, the option of a two-tiered load reduction commitment under ABEC (lower for mild event days, higher for severe weather days), the addition of a price trigger to both the Business Energy Coalition and the ABEC, and the ability to call the ABEC by local curtailment area. PG&E requests a budget of approximately $15 million for both the Business Energy Coalition ($5 million) and ABEC ($10 million) in 2009-2011.
PG&E estimates a benefit to cost ratio for Business Energy Coalition at 0.17 and for ABEC at 0.1. PG&E states that the Business Energy Coalition programs are worth continuing despite their low cost effectiveness estimates because they meet several of the other factors for program acceptance listed above, such as the programs' flexibility, locational value, customer acceptance, and environmental benefits.
DRA and TURN oppose the Business Energy Coalition and ABEC programs, largely due to their low benefit to cost ratios.77 DRA asserts that the Business Energy Coalition and ABEC provide few benefits beyond those captured in the cost effectiveness analysis ratios.78 TURN argues that any additional benefits "are not specific to the BEC program,"79 in other words, that other Demand Response programs offer the same advantages without the high costs.
SF Power argues that funding for the ABEC program should be conditioned on the load reduction for that program fully or partially replacing the generation capacity that would otherwise be needed from the Potrero Power Plant.80 Through this requirement, SF Power hopes to hasten the closure of that power plant.
Overall, it appears that the Business Energy Coalition and ABEC programs do provide some benefits, but they do so at a very high cost. Even using very favorable assumptions for improved performance in 2009-2011, it is extremely unlikely that these programs would become cost effective over the next several years. The non-cost effectiveness benefits cited by PG&E in support of this program, such as locational value and flexibility, are not unique to the Business Energy Coalition programs, and are not sufficient to support continuation of these programs, which have had ample time to demonstrate their ability to provide benefits at a reasonable cost, and have failed to do so. PG&E's request to continue the Business Energy Coalition and ABEC programs is denied, along with all funding requested to support these programs, including their $15 million budgets and associated funding for evaluation, measurement, and verification of the programs beyond 2009. We direct PG&E to end this program 90 days from the effective date of this decision, and to provide notice to its customers of the program's ending. This notice should include information about other demand response programs and aggregator contracts for which the customer may be eligible. PG&E should work directly with affected customers to help them understand their options to continue in other programs or contracts with aggregators.
The Bridge Funding Decision A.08-12-038 authorized funding of $4,623,996 for the BEC in 2009; this previously approved budget should be more than sufficient to operate the program until its discontinuation before the end of 2009.
11.2. SCE
SCE's Summer Discount Plan is an emergency-triggered program formerly called the Air Conditioning Cycling Program, which is similar to PG&E's SmartAC program (discussed above) and SDG&E's Summer Saver Program (discussed below). Under this program, SCE installs radio-controlled switches in participants' central air conditioners, allowing SCE to interrupt the customer's air conditioning to drop load during times of peak electricity demand. As an incentive, participants receive credits on their summer electricity bills. In recent years, the Summer Discount Program has had a load impact of approximately 500 megawatts. SCE forecasts a budget of close to $41 million, excluding customer incentives, which are funded through the SCE General Rate Case, and proposes maintaining the program while transitioning the program to take advantage of Programmable Communicating Thermostats utilizing the two-way communications capabilities of the SCE advanced metering infrastructure system, SmartConnect. After this transition, the Summer Discount Program would utilize price responsive triggers for cycling, rather than the current emergency triggers utilizing one-way radio switches. SCE also requests some growth in this program between 2009 and 2011, with the addition of approximately 4 megawatts per year. The estimated cost effectiveness of this program is 1.03, meaning it may be marginally cost effective. Party positions on the Summer Discount Program largely reflect parties' positions on emergency-triggered programs in general.
Consistent with our treatment of other emergency-triggered demand response activities considered in these applications, we do not envision expanding the Summer Discount Program at this time, pending the outcome of Phase 3 of the Demand Response OIR. For this reason, we do not increase funding, nor do we to approve a market and outreach budget of over $3 million per year, as requested by SCE. In addition, the apparently marginal cost effectiveness of this program does not argue for expansion, and may be improved if SCE is able to maintain enrollment in the program with a decreased budget for marketing. We support SCE's efforts to transition this program to use more price-responsive triggers, and hope to see a progress in that transition over the next several years. We adopt total funding for this program of $9,778,000 per year, the amount requested for 2009 less the requested marketing and outreach; in order to maintain the program at its current size, we will approve a reduced marketing budget of $1 million to allow SCE to compensate for attrition in the program. This results in total funding for the Summer Discount Program from 2009-2011 of $30,334,000.
The Agricultural Pumping - Interruptible (AP-I) program is another emergency-triggered program specific to SCE. Through the AP-I program, SCE offers monthly energy credits for eligible agricultural pumping customers who allow the utility to interrupt their load during CAISO or local emergencies. The program has existed since the 1970s. It was closed to new enrollments in 1998 and reopened in 2001. In D.06-03-024, SCE was authorized to expand the marketing of the program during the 2006-2008 period. SCE proposes to further expand marketing of the program in 2009-2011; the utility estimates 57 megawatts of potential load reductions for this program by the end of 2011. SCE requests a total of $1,529,464 million for AP-I.81 Like the Summer Discount Program, the estimated benefit to cost ratio is 1.03. Party positions on the AP-I program reflect their general positions on emergency-triggered programs.
Consistent with treatment of other emergency-triggered demand response programs in this proceeding, we freeze the size and budget of the program for 2009-2011, pending a decision on the optimal load needed from emergency-triggered programs. In addition, as in the case of the Summer Discount Program, we exclude some of the requested marketing costs from this program's budget to discourage the expansion of this program. We approve annual costs of $466,000 for 2009 through 2011; this equals the average SCE funding request for 2009-2011, excluding. We adopt total funding for this program of $1.4 million for 2009-2011.
SCE's Rotating Outage Program generally supports communications to customers about policies and procedures related to rotating outages during declared electric emergency situations. SCE explains that the program has continued in "active maintenance mode," and proposes no changes for the 2009-2011 period. The utility forecasts expenditures of $408,738 for 2009-2011 for labor and communications.82
The communications supported by the Rotating Outage Program include both Commission-mandated notices and courtesy notifications intended to facilitate the administration of emergency rotating outages. No parties object to the continuation of these activities at the requested funding level, and we approve funding of $408,738 to support this program during 2009-2011.
SCE's Agricultural Pump Timer Program utilizes Time Management Load Control devices to allow customers to interrupt their equipment at peak times, in order to take advantage of low off-peak utility rates. Customers enrolling in this program pay for the initial installation of timer equipment, and any savings realized by customers are captured through lower utility bills due to enrollment in a tariff that rewards shifting of pumping away from higher-priced peak electricity hours. SCE requests $42,000 per year for this program over the 2009-2011 period, for a total budget of $126,019; this covers communications and general administration of the Agricultural Pump Timer Program only. Initial equipment costs under the program are paid by customers, and replacement equipment, when needed, is paid for out of general rate case funds. No parties object to the continuation of these activities at the requested funding level, and we approve funding of $126,019 to support this program during 2009-2011.
Energy Options is a new program SCE proposes to combine and replace its Capacity Bidding Program and Demand Bidding Program beginning in 2010. SCE's Energy Options Program would allow customers to choose among six existing Capacity Bidding Program options and an option similar to the Demand Bidding Program. The demand bidding option would utilize monthly load nominations rather than daily bids, and incentives would be calculated as they are currently, based on actual load drop.83 Energy Options would allow customers to switch among different options each month to allow customers to tailor their demand response commitments to meet their individual needs. Additionally, SCE intends the products to be scalable so that customers under 200 kilowatts who receive an Edison SmartConnect meter can also participate.
SCE expects minimal losses of Capacity Bidding Program and Demand Bidding Program customers during the transition to Energy Options, and expects an increase in the number of customers enrolled in Capacity Bidding products. SCE proposes that aggregators be able to participate in Energy Options and receive 100% of the capacity payment for Capacity Bidding Program type options, whereas directly enrolled customers would receive 80% capacity payment for Capacity Bidding Program options, as is currently the case in the capacity bidding program. The utility requests $5,703,864 for program development, administration, evaluation, measurement, and verification, information technology costs, marketing and meters.84 The estimated benefit to cost ratio for this program is not reported.
DRA supports the SCE proposal to transition Capacity Bidding Program and Demand Bidding Program into a new Energy Options Program starting in 2010. No party objects to this proposal.
SCE's Energy Options Program is likely to prove complex to analyze, and it is not clear whether the resulting program will be cost effective. As discussed above, the underlying programs (Capacity Bidding Program and Demand Bidding Program) do not appear to be cost effective in their current form. The availability of a program that offers more flexibility to customers may be more acceptable to customers and may both increase enrollment in demand response activities and make the program more cost effective. We approve the creation of this program and fund it at the requested level for the 2009-2011 period.
SCE's suggestion that aggregators be allowed to participate in the Energy Options program may increase participation in this program and the amount of demand response available at peak times. We approve this request. To ensure that we are able to evaluate and compare the different participation options available under this program, we require SCE to continue to report each type of notification (day ahead and day of) separately in its monthly report, as well as in its load impact and cost effectiveness analyses. Like other programs utilizing baselines approved in this proceeding, the Energy Options program will use the baseline described in Section 17, below.
11.3. SDG&E
SDG&E's Emergency Critical Peak Pricing program (CPP-E) is a voluntary program in which participants may be called on 30 minutes' notice when an immediate load reduction is necessary. SDG&E's CPP-E program is structured similarly to the price-responsive Critical Peak Pricing Tariffs of the three utilities, with higher rates during called event hours in return for lower rates during non-event hours. CPP-E events are called primarily when there is a statewide Stage 1 or 2 system emergency or a local system emergency. CPP-E events may be as much as six hours long on a particular day and may not exceed 80 event hours per year or 40 hours per month. SDG&E does not propose changes to this program. SDG&E requests a budget of $328,541 for CPP-E in 2009-2011, and the estimated TRC benefit to cost ratio is 2.8. SDG&E estimates the load reduction potential for this program at 2 megawatts. No parties object to the continuation of this program.
It is reasonable to continue this program pending the Commission's decision in Phase 3 of R.07-01-041 on the overall level of emergency-triggered demand response needed in the state and the potential need for changes to those programs. We approve SDG&E's request to continue the CPP-E program with total funding of $328,541.
SDG&E's Summer Saver Program (formerly its Air Conditioner Cycling Program) is a voluntary direct load control air conditioner cycling program available to residential, small business and other customers with central air conditioners. As a direct load control program, participants' air conditioning equipment is automatically controlled when necessary to reduce high electricity usage. Like the CPP-E program, SDG&E's Summer Saver may be triggered in a statewide Stage 1 or 2 system emergency or a local system emergency. Summer Saver is currently administered through a third-party aggregator under a contract approved by this Commission, and has a target load reduction of 42.2 megawatts. The estimated TRC benefit to cost ratio for residential customers enrolled in this program is 1.14, and for commercial customers the estimated ratio is 1.48; these results imply that the program may be cost effective in its current form. SDG&E does not request program changes or funding for SmartRate in this application. SDG&E asserts that sufficient funding for the program to operate in 2009-2011 has already been authorized. We authorize the continuation of SDG&E's summer saver program, as requested. In addition, we encourage SDG&E to explore ways to begin transitioning this air conditioner cycling program to use more price responsive triggers.
SDG&E seeks to eliminate its existing Peak Day Credit Program, which offers customers a bill credit ranging between 10% and 20% for load reduction during events called under the program. D.08-12-029 approved a budget of approximately $300,000 for this program in 2009. SDG&E asserts that, like its Demand Bidding Program, the Peak Day Credit Program is no longer needed. No parties object to the elimination of this program. Given the relatively small size of the Peak Day Credit Program and the availability of other options for customer enrollment in demand response activities, we approve SDG&E's request to discontinue this program within 30 days of this decision. SDG&E will provide enrolled customers with reasonable notice of the program's discontinuation and information on other demand response activity options.
11.4. Miscellaneous Supportive Activities
All three utilities propose additional demand response-related activities. PG&E requests a total of $29,483,000 for an InterAct/Demand Response Forecasting Tool, Demand Response On-Line Enrollment, a Legacy Demand Response Conversion, a Marketing Decision Support System upgrade, and Interval Meters; SCE requests $13,258,420 for a Demand Response Forecasting System, a Demand Response Resource Portal, and Demand Response System Infrastructure; and SDG&E requests $600,000 for development of Demand Response Codes and Standards.
Several of these items, including PG&E's Legacy Demand Response Conversion, a Marketing Decision Support System upgrade, and Interval Meters and SDG&E's Codes and Standards are not sufficiently supported by information in the utilities' applications, and may be duplicative of activities already funded in these utilities' AMI, energy efficiency or other proceedings. We do not approve additional funding for these efforts, which are not justified by supportive information in the applications. We approve the following selected projects supportive of demand response at the requested budgets:
2008-2009 Requested Budget |
2008-2009 Authorized Budget | |
PG&E InterAct/Demand Response Forecasting Tool |
$10,413,000 |
$10,413,000 |
PG&E Demand Response On-Line Enrollment |
$ 6,489,000 |
$ 6,489,000 |
SCE Demand Response Forecasting System |
$ 1,102,453 |
$ 1,102,453 |
SCE Demand Response Resource Portal |
$ 2,535,000 |
$ 2,535,000 |
SCE Demand Response System Infrastructure |
$ 9,520,967 |
$ 9,520,967 |
74 Under the new market rules, the CAISO will be posting the day-ahead prices by 1:00 p.m.
75 TURN Opening Brief, p. 73.
76 SF Power Opening Brief, pp. 5-9.
77 DRA Ex. 314; TURN Ex. 418, pp. 11-12.
78 DRA Reply Brief, p. 12.
79 TURN Reply Brief, p. 12.
80 SF Power Opening Brief, pp. 10-13.
81 SCE Amended Testimony, Volume 1, pp. 31-32.
82 SCE Exhibit 1, p. 43.
83 SCE Exhibit 1, p. 21.
84 SCE Exhibit 1, p. 23.
