VI. Demand Response Proposals
A. Proposals Applicable to Multiple Utilities
1. BIP, Non-Firm Service Program, and I-6
The BIP is a demand response program offered to large customers who receive monthly incentive payments as compensation for their willingness to curtail load within 30 minutes during a Stage 2 power emergency. BIP customers that fail to curtail load according to the tariffs face substantial penalties. PG&E's Non-Firm Service Program is similar to the BIP program in that it provides incentives to large customers who agree to curtail load during a Stage 2 event. This program is no longer open to new subscribers. In D.05-04-053 the Commission ordered the utilities to transition existing Non-Firm rates into BIP.16 PG&E has proposed such a transition in its 2007 General Rate Case Phase 2, A.06-03-005, which would be effective January 1, 2008. On August 24, 2006 the Commission approved staff Resolution E-4018 , which granted PG&E's request to temporarily allow new customers to sign up for the Non-Firm program for 2006, as long as the customers enrolled by September 15, 2006. The question of whether 2006 enrollees will be allowed to remain on the program in 2007 was deferred to this proceeding. The resolution rejected PG&E request to reopen the program for 2007, and invited PG&E to submit the request again in this proceeding.17
PG&E proposes increasing BIP incentive payments as load reductions increase to encourage customers to maximize commitments of capacity. Current incentive payments are $7.00/kW of Potential Load Reduction (PLR), and PG&E proposes the following monthly incentives per kilowatt (kW) committed:
PLR |
Monthly Dollars per kW-hr PLR |
100 kW to 500 kW |
$8.00/kW |
501 kW to 1 MW |
$8.50/kW |
1 MW or greater |
$9.00/kW |
PG&E also believes that increasing incentives will ease the transition of customers from the Non-Firm program to BIP.
PG&E proposes to eliminate its BIP Option B, which permits customers to receive a longer notification period and shorter event duration in return for a smaller incentive. PG&E states no customer has signed up for Option B. PG&E instead proposes to introduce a new Option B that the utility says is modeled on successful programs in the NYISO and PJM control areas. Under the new Option B, participating customers would have the opportunity to receive a minimum energy payment during CAISO Stage 2 or 3 events or during local reliability emergencies if the program is called by PG&E. Customers would have four hours notice, would not be penalized for non-performance, and would not receive any capacity payment.
PG&E would set the minimum incentive payment at $0.50/kWh until the CAISO has implemented locational marginal pricing. Once locational marginal pricing is implemented, customers will be paid the higher of $0.50/kWh or the locational marginal price in the CAISO real time imbalance market that applies to the geographic location of the customer.
This option would be available to individual customers as well as aggregators. Aggregators may be paid a fee based on the amount of capacity they sign-up for. PG&E notes that aggregators are active in similar programs offered in the NYISO and PJM areas, and aggregators existing relationships with national companies could improve participation. PG&E is opposed to aggregator participation in the BIP Option A due to its similarities to the Capacity Bidding Program (CBP), which is open to aggregators.
PG&E believes that the success of programs similar to the proposed new option in other parts of the country indicates the potential for success in its territory. The utility projects that over a two to four year period the program could sign up as much as 100 to 200 MW.
PG&E also proposes to reopen its Non-Firm program in 2007. PG&E observes that when called in July 2006, participants' load reductions exceeded subscribed load.
PG&E estimates that its recommended changes to the BIP and Non-Firm programs would yield an additional 70 MW in 2007 and 25 MW in 2008 at an incremental cost of $2.5 million in 2007 and $0.8 million in 2008.18
CLECA/CMTA support PG&E's proposals to expand participation in BIP and reopen the Non-Firm program.19 Aglet objects to increasing funding for BIP and reopening the Non-Firm program, raising general concerns about cost-effectiveness.20 DRA recommends holding hearings on PG&E's proposed BIP Option B but does not explain the factual controversy that would be addressed in hearings. DRA opposes reopening the Non-Firm program because it is duplicative of BIP, and a temporary re-opening of the Non-Firm program may confuse customers.21 The demand aggregators would like to see PG&E's existing BIP Option A opened to aggregator participation. EnerNOC asserts that demand aggregators can bring in additional customers.22
We adopt PG&E's proposed increased incentive payments for BIP Option A as proposed. We agree with PG&E that increasing incentives and offering larger incentives for larger capacity commitments could attract more and larger capacity commitments. We also authorize PG&E to close the existing BIP Option B and adopt the new Option B proposed by the utility. The incentive rate for the proposed new Option B should be set at $0.60/kWh to be consistent with the day-of DBP incentive discussed below. The new Option B could be attractive to additional customers, and the fact that there are no ongoing payments to customers alleviates potential cost-effectiveness concerns.
We also require PG&E to open its Option A to third-party aggregators.
We share DRA's concerns that reopening Non-Firm program could confuse customers, especially since the program could be ended as soon as January 1, 2008. We prefer multi-year program changes that allow customers to plan and make investments that could increase their demand response on an ongoing basis. We therefore deny PG&E's request to permit new customers to sign-up for the Non-Firm program in 2007.
SDG&E wishes to reduce the penalties for its BIP in order to attract more customers. Currently, Option A subscribers receive an incentive payment of $7/kW per month and are penalized $6/kWh for failure to reduce load, and Option B subscribers receive an incentive payment of $3/kW per month and are penalized $2.50/kWh for failure to reduce load. SDG&E proposes reducing the penalties for each option by 25 percent to $4.50/kWh for Option A and $2.50/kWh for Option B.23
SDG&E also proposes to add additional triggers to the program that would allow the program to be triggered during a CASIO Stage 2 Alert and when extreme temperature conditions impact system demand. Additionally, the utility would like to change BIP's Rule 29 language so that incentive and penalty payments for aggregated load will be calculated in aggregate using individual customer meter data. Also, SDG&E proposes to eliminate the BIP once SDG&E's new CBP is adopted and proposed to transfer all BIP customers to the CBP.24,25
DRA supports SDG&E's proposal to attract more participants in BIP by reducing penalties.26 EnerNOC supports SDG&E's proposed changes to Rule 29, but opposes the utility's plan to eliminate BIP and transfer participants to the CBP because BIP and CBP will appeal to different customers. EnerNOC additionally recommends that SDG&E allow aggregators to enroll customers with load reductions less than 100 kW and make monthly incentive payments based on the difference between aggregated Firm Service Level (FSL) and aggregated Monthly Average Peak Demand (MAPD).27
We will authorize SDG&E's proposal to reduce penalties, adopt additional triggers and change Rule 29. We also direct SDG&E to permit aggregators to sign up customers with less than 100 kW as long as the aggregated load exceeds 100 kW and to make monthly payments based on aggregated FSL and MAPD. We believe these changes will increase customer participation in BIP. We deny SDG&E's proposal to close the BIP program and transfer customers to CBP. BIP was created as a statewide program, in part so that it attracts customers in multiple service territories. We believe the program should be continued on a statewide basis.
SCE is opposed to reopening its I-6 interruptible program since customers can sign up for BIP, which offers similar incentives. SCE has proposed a new 15-minute I-6 and BIP option through Advice Letter 2032-E. The Commission has approved a staff resolution that adopts this option. Therefore, we do not discuss parties' comments on the 15-minute option here.
In response to the Administrative Law Judge's (ALJ) inquiry about whether aggregators should be able to participate in various demand response programs and a proposal by EnerNOC, SCE explains that its interruptible programs, I-6 and BIP, are not well-suited to aggregator participation. SCE believes that quick and effective response to calls for load reduction would be difficult and more complex if aggregators were involved, partly because SCE notifies and monitors customers through a particular communications network. It believes aggregators would complicate the program by introducing alternative technologies. SCE does suggest, however, that it might propose a new interruptible program, open to aggregators, in the near future.28
The CAISO questions SCE's reluctance to collaborate with aggregators and suggests that some of subscribed load lost since the pre-energy crisis period could be regained by engaging aggregators.29 EnerNOC also refutes SCE's assertion that aggregator will complicate the program without bringing any benefits. EnerNOC notes that it has demonstrated in northeastern markets that it can notify and monitor customer performance rapidly and in a variety of circumstances. SCE would only have to make minor changes to the program to allow for aggregation of portfolios.30
We agree with the CAISO and EnerNOC that allowing aggregators to participate in the BIP could increase available demand response. We therefore direct SCE to file an advice letter proposing changes to BIP that permit aggregation, similar to the SDG&E's BIP program.
Customers may want to increase or decrease their firm service level given the changes to PG&E's and SDG&E's BIPs adopted in this decision. PG&E and SDG&E are required to give customers 30 days from the date this decision is adopted to adjust their firm service levels for 2007.
The DBP permits subscribers to bid the amount of energy they are willing to drop in case of a demand response event. Subscribers receive payment only when the program is triggered. Because no incentive is paid unless an event is called, subscribers face no penalties if they fail to reduce demand.
PG&E proposes a number of changes to its DBP program as follows:
No-bid Option - PG&E proposes a "no bid" option to the DBP, which provides that that customers do not have to pre-subscribe to the program but may participate only if an event is called. Customers must provide a minimum 10% demand reduction. Incentives would be smaller and the event window would be narrower than those for other DBP options.
Trigger Change - PG&E proposes changing the DBP trigger because it believes program events are triggered even when there are sufficient reserves. The proposed "soft" trigger would correspond to system conditions rather than automatically adhering to preset criteria.
Bid Window - PG&E would widen the bid window to give customers additional time to make bids. Customer feedback has indicated that a wider bid window would make it easier for customers to participate, so this change would result in increased customer participation.
Incentive Increase - PG&E proposes to increase its "bonus adder" to $.20/kWh above the market price for energy. PG&E does not support changing the incentive to a flat rate structure as recommended by DRA because such a change would require remarketing and could be detrimental to 2007 program performance.31
CAISO Alert Bids - PG&E proposes adding an additional $0.10/kWh to the incentive when a DBP event is called during a CAISO Stage 1 or higher alert. Also during CAISO alerts, PG&E would pay customers for all load reductions, including that in excess of the normal 150% cap. These added incentives are intended to increase customer response during CAISO emergencies.
Budget - PG&E proposes to shift $3.743 million to its DBP program to reflect the cost of these changes, which its estimates will increase load reductions by 25 MW in 2007.
Aglet is opposed to increasing funding for the DBP because the costs exceed the payments that would be required for new generation.32 TURN raises concerns that there is little evidence to suggest that any of the utilities' DBP programs provide any demand response benefits due to the flawed baseline. TURN also suggests there is information in a 2006 report by Quantum Consulting indicating that the program may increase environmental pollution as subscribers turn on backup generators at their premises.33
DRA is not opposed to PG&E's proposal to increase incentives but suggests that the program could be made more customer-friendly by adopting a flat incentive such as that proposed by SCE and SDG&E. DRA does not support adopting the no-bid option at this time because the option could attract free riders.34 ECI and SVLG support PG&E's proposal to increase the bonus incentive.35
SDG&E proposes to join the Emergency DBP - a day-of reliability program - with the DBP program. SDG&E believes that providing both day-ahead and day-of options within the same program will make it easier to administer the program. SDG&E would increase incentives to $.50/kWh for the day-ahead program and $.60/kWh for the day-of program. Customers would be paid for reductions that are equal to or greater than the amount bid, with no limit. SDG&E also proposes several program changes designed to make it easier for customers to participate in DBP such as permitting customers to make standing bids, and simplifying enrollment.
Aglet is opposed to increasing SDG&E's DBP incentives.36 TURN's critique of the DBP program in general applies equally to SDG&E's. DRA supports SDG&E's flat incentive proposal but prefers a slightly lower incentive of between $0.40/kWh and $0.45/kWh. DRA is concerned that SDG&E's proposed standing bid could encourage free riders.37
SCE proposes several changes to its DBP as follows:
Incentive Increase - SCE proposes increasing the incentive for summer 2007 to $0.75/kWh, believing the higher amount is required to motivate customer participation. SCE reports that its proposed incentive increase reflects what its customers say they require in order to offset the cost of reducing load.
Trigger Change - SCE proposes to modify the DBP trigger so that the DBP program is called only when needed, not simply in response to pre-determined criteria.
Program Administration - SCE proposes simplifying certain program elements in ways that should encourage participation without increasing program costs. For example, SCE proposes to streamline enrollment procedures, decrease the size of the minimum bid, and permit customers to make standing bids.
Aglet does not support increasing SCE's DBP incentives.38 TURN's general critique of the DBP program in general applies equally to SCE's. DRA agrees with SCE's emphasis on making the program more customer friendly by using a flat-rate incentive, but believes that SCE's proposed incentive level is too high. DRA instead recommends an incentive level between $0.40/kWh and $0.45/kWh.39 ECI and SVLG support SCE's proposal to increase incentives.40
We generally support the proposals by the utilities and other parties to make the DBP more customer-friendly in order to increase program participation and demand response. Accordingly, we approve the soft triggers proposed by PG&E and SCE and direct SDG&E to adopt a similar trigger; we approve PG&E's proposal to widen the bidding window, and direct SDG&E and SCE to do the same; and we approve the enrollment simplification proposed by SDG&E and SCE, and direct PG&E to do the same. SCE's and SDG&E's proposals to allow standing bids are also approved.
We agree with SDG&E and SCE that replacing the market based incentive with a flat incentive would make the program easier to understand and can facilitate simplifying enrollment. Therefore, we direct all three utilities to adopt a flat rate incentive. We will approve a flat incentive payment of $0.50/kWh for day-ahead calls and $0.60/kWh for day-of calls when a CAISO alert of Stage 1 or higher is called. The higher incentive levels should increase program participation and demand response. We also direct all three utilities to offer a day-of program similar to that proposed by SDG&E.
We do not approve PG&E's proposed no-bid program. It is unclear how this program would contribute to energy reductions. Since a customer who subscribes makes no commitment and its rates are not affected unless it voluntarily reduces load, it is not clear why this program would be more attractive to customers than the existing program. Some participants may be free riders if they are paid for demand reductions that were undertaken for business reasons rather than as program participants. The program may permit an expenditure of funds for energy reductions that would have been undertaken anyway. Accordingly, we reject PG&E's proposal for a no-bid option.
AC cycling provides a utility remote air conditioning controls at residential customer premises. On August 15, 2006, President Michael R. Peevey issued an Assigned Commissioner's Ruling (ACR) in R.05-12-013 and R.06-02-013 directing SCE, PG&E, and SDG&E to evaluate installing additional AC cycling in their service territories for the summer 2007 season. The ACR was served on the service list in this proceeding. The Commission considered SCE's AC cycling proposal on October 19, 2006 in Resolution E-4028. PG&E and SDG&E made proposals in this proceeding.
PG&E states its intent to use existing demand response funding to expand the pilot AC cycling program that was agreed to by the utility in the Amended Settlement adopted by D.06-03-024. The utility had agreed to sign up 2,000 total residential customers during 2007 and 2008, which would equate to about 2 MW. PG&E is now proposing to significantly expand the program for 2007 and fully roll-out the program starting in 2008.
PG&E proposes to commit $7.5 million and sign up about 5,000 customers by June 2007, with sign-ups continuing throughout the summer. That translates to 5 MW of load reduction by June 2007. The utility's program would include both a switch based direct load control (DLC) option and a Smart Thermostat option. Customers would have the option to choose from several DLC or Smart Thermostat options. The general program framework is described in the utility's August 30, 2006 filing.
PG&E's budget includes contractor costs, marketing and advertising, early signup incentives, consulting fees, labor, and one-time costs associated with setting up a new program including billing system modifications, creation of web enrollment, and program evaluation. In reply comments the utility notes that the requested funding could fund the installation of up to 15,000 switches, which roughly equates to 15 MW, if the Commission approves the future operating costs in the utility's yet-to-be-filed application. If the full deployment application is approved then the amount of money that the utility needs from the 2006-2008 demand response budget would be much less than $7.5 million.41
PG&E intends to file an application in November 2006 proposing a multi-year AC cycling program. In the meantime the utility requests that the Commission authorize its rollout strategy and general program design, authorize the shifting of $7.5 million, and provide for expedited approval of its advice letter implementing the 2007 program.
Aglet, CLECA/CMTA, and EUR generally support increasing funding for PG&E's AC cycling program.42 EUF argues that "all possible, cost effective AC Cycling programs should be implemented for Summer 2007 due to AC Cycling's proven benefits.43 CLECA/CMTA support PG&E's plan to initiate an AC cycling program and recommends that cost-effectiveness should be analyzed over the long-term.44
DRA states that the Commission should focus on reliability type programs first, and notes that SCE's AC cycling program is the most-subscribed reliability program available to residential and small commercial customers.45 DRA does not, however, take a position on PG&E's AC cycling proposal. Instead DRA says it will provide detailed comments once PG&E files its detailed proposals.46
TURN conditionally supports PG&E's AC Cycling proposal.47 However, TURN believes PG&E's proposal appears to be overly expensive and observes that SDG&E has a third-party AC Cycling arrangement that would cost $350,000 per year for 5 MW and $7 million per year for 100 MW. TURN also raises concerns that PG&E is seeking funding authority for a program for which there are very few details.48
We appreciate PG&E's response to our call for AC cycling program proposals and understand the difficulty of creating an elaborate plan on such short notice. While we generally prefer demand response programs that engage customers in managing their energy usage, AC cycling has proven to be a valuable reliability resource in SCE's service territory and is beginning to play an important role in SDG&E's territory. AC cycling can also result in concrete load reduction capability in PG&E's service territory. We approve in concept PG&E's proposal to install 5,000 switches in 2007 using the existing demand response budget and subject to advice letter review. We support PG&E moving forward with an AC cycling program for 2007 but need additional information to review the proposal. In the advice letter, PG&E should provide detailed budget information including the costs of installing the switches, incentives, and any other costs. We encourage parties interested in this proposal to review the advice letter. PG&E may move forward with its proposed RFP for competitive bids.
We will address PG&E's long-term program costs when we have more information about its proposed program which can provide parties and the Commission a reasonable opportunity to evaluate it.
SDG&E proposes to expand its Summer A/C Saver program to include pool pumps and electrical water heating, renaming the program the Summer Saver Program. It would also provide residential customers a new 100% cycling option, in addition to the current 50% cycling option. Non-residential customers would be offered a new 30% option, in addition to a 50% option. Customers will also be able to sign up for weekend events. A third party, Comverge, administers this program and has agreed to the program changes.
Aglet supports SDG&E's proposed changes.49 DRA thinks that SDG&E's proposed changes are reasonable but reserves judgment until DRA has had an opportunity to review the contract with Comverge which will be included in SDG&E's advice letter.50
TURN generally supports this program but raises concerns that the requirement that customers make 100% of their air conditioning available for cycling may reduce customer acceptance of the program. TURN also believes SDG&E's website on this program does not provide enough information to motivate customer interest.51
The additional cycling options SDG&E proposes appear reasonable and likely to improve program participation. Therefore, we adopt them. The Commission previously approved contract amendments to include pool pumps and electrical water heating in Resolution E-3913. We will not reconsider that approval here. Including pool pumps and electrical water heaters in SDG&E's program could provide valuable information if the Commission or any utility considers these programs in the future. We also direct SDG&E to consider improvements to its website that would provide better customer information.
PG&E proposes to issue an RFP for demand response proposals for up to five summer periods. PG&E estimates that the innovative ideas that result from the RFP could result in PG&E signing contracts for up to 35 MW of additional load reduction in 2007 and 2008.
The RFP would focus on resources that can be provided in CAISO Stage 2 conditions for the summers of 2007 and 2008. Customers, aggregators, energy service providers and wholesale PG&E customers can bid. PG&E proposes to pay for the costs of any contracts through the Energy Resource Recovery Act (ERRA) account. It would submit contracts to the Commission by way of expedited advice letters. PG&E would spend $200,000 from its existing demand response budget in each of 2007 and 2008 for potential signing bonuses and customer incentives.
PG&E points to RFPs run by SDG&E and utilities in other states as examples that PG&E would build on.
SDG&E describes an all source Request for Offers that it recently completed which specifically requested demand response capacity offers. The utility is currently evaluating the conforming offers and expects to complete contracts by mid-November and bring the contracts to the Commission for approval. The six conforming bids represent a total of 50 MW of capacity.
In response to parties comments SCE proposes either initiate an RFP or seek bilateral arrangements to capture innovative demand response proposals. SCE suggests that it would file an advice letter to request Commission approval and any additional funding once specific programs have been selected.52
Aglet and EnerNOC recommend that PG&E and SCE be directed to pursue RFPs and bilateral demand response contracts.53 DRA supports cost-effective demand response contracts identified through RFPs and bilateral arrangements.54 TURN is concerned that the RFP process proposed by PG&E is too open-ended, and the advice letter process would not permit sufficient review.55
As with many parties who commented, we believe that seeking proposals directly from customers and aggregators could potentially unleash innovative and cost-effective demand response technologies and activities. On the other hand, we do not here pre-authorize yet-to-be identified contracts or specific cost-recovery mechanisms. Instead, we direct PG&E and SCE to move forward with their proposals to run an RFP or seek bilateral contracts. We agree with TURN that the advice letter process would not provide the Commission and intervenors an opportunity to evaluate proposals. Each utility should file an application with the Commission requesting approval for specific contracts by February 28,, 2007. Due to the emphasis on getting demand response capacity ready for the summer of 2007, the Commission will consider the applications expeditiously.
TA/TI funds can be used to provide energy audit services for customers and encourage customer adoption and installation of demand response measures. TA/TI can facilitate customer participation in various demand response programs.
PG&E proposes to increase the TA incentive level to $100/kW with a maximum incentive of $100,000, and increase the TI incentive to $250/kW, with an additional $50/kW for Auto DR. PG&E requests the flexibility to use funds to cover direct customer incentives, customer labor and site assessment support and the use of multiple technical and systems integration contractors, in addition to the contractor costs.56
SDG&E proposes retaining the 2006 incentive payment of $250/kW into 2007 for new technology installations. SDG&E proposes to establish a subset of the program focused on permanent load shifting. SDG&E is developing performance measurement criteria and a list of qualifying equipment for its permanent load shifting program.
SCE proposed to increase the available incentive from $100/kW to $250/kW specifically for Auto Demand Response (DR) technologies.
We believe that increasing TA and TI incentives will increase customer participation in demand response programs. We approve PG&E's to increase its TA incentive level to $100/kW. We also adopt PG&E's proposal to increase TI incentives to $250/kW and $300/kW for Auto DR. We direct SCE and SDG&E to implement to same higher TI incentives. We also agree with PG&E that allowing TA/TI funds to cover direct customer expenses will help the program, so we adopt PG&E's requested flexibility for all three utilities.
Auto DR, a research program managed by the Demand Response Research Center (DRRC), is designed to link facility energy management control systems with external utility-generated price or emergency signals. The use of this technology is integrated with various existing utility demand response programs, such as the critical peak pricing program.
In response to the Assigned Commissioner's ruling, PG&E proposes to spend $2 million a year in 2007 and 2008 to implement Auto DR using TA/TI funds. PG&E expects the participation of about 15 MW in each year. PG&E's incentives would apply to software, hardware, and programming in addition to equipment. PG&E raises concerns about full-scale rollout and wide customer acceptance and the availability of communication devices. It proposes third-party implementation as a way to ease these potential problems. PG&E would also increase the TI incentive to $300/kW and expand the use of TA/TI funds to include direct customer incentives, customer labor and site assessment support and the use of multiple contractors for different elements of the implementation. DRA objects to an increase in incentives until PG&E has presented the Commission with a detailed implementation plan.
SCE currently has a pilot program and proposes to increase its Auto DR efforts with a 2007 budget of $1.79 million with a goal of commercializing Auto DR products in the near future. SCE would focus for the first year on identifying "key opportunities" and evaluating effectiveness and customer response. They would implement the program by working with the Demand Response Research Center (DRRC) to "bring functionality to a commercial level" using third party contractors. The program would provide automated notifications for participants in the CPP and DBP programs. It would increase the existing technology incentive to $250/kW with an expectation of motivating about 10 MW of additional load reductions.
SDG&E would implement its Auto DR through existing Emerging Technologies Program using the TA/TI incentive structure with incentives of $250/kW. DRA raises concerns that SDG&E has failed to present a specific implementation program.
When we directed the utilities on August 22nd to add Auto DR to the list of program elements to be included in their August 30th filings, we expected the proposals to lack some detail due to the short time available before the filing date. After reflecting on the variety of ideas proposed and concerns raised in comments, we provide some additional guidance. We approve these proposals-with some conditions-but direct the utilities to present detailed implementation plans to Energy Division as soon after this order is adopted as feasible. We specifically approve TI funds for $250/kW for all three utilities, as proposed by SCE and SDG&E but deny PG&E's request to increase their incentive to $300/kW. However, we do approve PG&E's request to expand the use of TA/TI funds to include customer costs and customer incentives for all three utilities and direct SDG&E and SCE to do the same. We also require the utilities to file proposals by October 31st, 2007 for continuation or modification of their Auto DR programs.
We have high hopes for Auto DR in facilitating demand response, but agree with PG&E's concerns about customer acceptance. We also agree with SCE's concern that additional pilot testing of the technology among a broad group of customers is warranted. Both of these concerns would point to a cautious approach; however, we also believe that we should maximize the impact of Auto DR for next summer. To resolve this apparent conflict, we direct the utilities to work with the DRRC to develop implementation strategies that will provide a high level of quality control as this technology goes through the early stages of commercialization while at the same time identifying key opportunities for maximizing the demand response impact. This may require focusing on building and customer types similar enough to the DRRC pilot participants that the shed strategies and technology installations are proven and relatively quick and easy to implement. It also may require that the programs focus on customers who can minimize the transaction costs involved in implementation and approval, such as chain stores where decision-making is centralized and where implementation strategies are, for the most part, replicable. We also have concerns, especially in light of the increased incentives being approved here, that customers receiving these incentives be obligated to provide demand response during critical events. If the utilities intend to provide Auto DR to customers participating in the DBP program, they should describe in their detailed proposals how those customers will be obligated to provide load reductions on critical days.
In their detailed implementation plans, each utility should describe in detail how they plan to work with the DRRC to take advantage of the knowledge they have gained in developing and pilot testing shed strategies and automated communications. Second, the utilities should each describe how they intend to train and monitor the third-party contractors implementing the program for quality control and customer satisfaction. Third, the utilities should describe how the TA/TI funds will be used for Auto DR. Fourth, the plans should include proposals for measurement and evaluation that provide real-time feedback to the program implementers as well as documentation of program impact and collection of information that will inform development of a long term commercialization strategy. Finally, the implementation plans should provide detailed budgets identifying administrative, evaluation, and incentive costs.
Permanent load shifting occurs when a customer moves energy usage from one time period to another on an ongoing basis. Existing time-of-use (TOU) rates encourage some permanent load shifting because customers can reduce their energy bills by shifting load from peak periods when rates are higher to off-peak periods when rates are lower. In some cases, investment in load shifting technologies can enable greater amounts of load shifting. Examples of permanent load shifting technologies include thermal energy storage, batteries, and the pumping and storage of water. Currently, customers do not have access to incentives from the utilities to lower the cost of installing permanent load shifting technologies, other than TOU rate differentials. The technologies are generally not considered energy efficiency programs if they do not reduce overall energy consumption. At the same time, they are generally not considered demand response programs if they are not dispatchable or price responsive on a day-ahead or day-of basis. Nevertheless, load shifting may reduce the need for capacity investments, reduce the likelihood of shortages during peak periods and lower system costs overall by reducing the need for peaking units. All three applicant utilities have stated their support for load shifting programs as a way of improving system stability and reducing system costs. SCE and PG&E state an interest in proposing permanent load shifting programs before the end of the year. TURN and the CAISO express strong support for such programs generally although both raise the concern that load shifting does not represent a dispatchable form of capacity and urge the Commission's policies and programs should be designed with that concern in mind. DRA supports load shifting but believes there are many issues that deserve exploration, such as what would constitute a "permanent" load shift, how incentives should be paid, and how to avoid free riders. Other parties advocate for an allocation of funds to specific programs, which are discussed below.
PG&E and SDG&E recommend that permanent load shifting be eligible for TA/TI funding, but they do not support the creation of a special TOU rate. SCE generally supports permanent load shifting as demand response and indicates it will provide a specific proposal for the Commission to consider.
Ice Energy proposes a specific load shifting program that would promote installations of ice storage air conditioning, a technology that creates and stores ice during off-peak periods so that air conditioning may be provided during peak periods with reduced electricity demand. The product Ice Energy proposes is referred to as "Ice Bear" and would be installed mostly in medium to large commercial buildings such as "big box" retail outlets. Ice Energy proposes upfront incentive payments for installation and ongoing incentive payments included in utility tariffs. Ice Energy proposes a program budget of $25 million for 2007 and estimates up to 12 MW of on-peak demand reduction. Over 15 years, it estimates 100 gigawatt-hours of peak energy would be shifted to off-peak periods and 15 gigawatt-hours of energy would be saved. Ice Energy provides evidence that the technology has been successfully applied in other utility territories, both within California and in other states.
D.06-03-024 directed the applicant utilities to work with the state's water agencies to develop demand response products that would be cost-effective and attractive to water agencies. It directed the utilities to file advice letters to implement such programs in October. In this phase of this proceeding, ACWA reports that its client water agencies are unlikely to take advantage of the utilities' proposals. Following an inquiry to the ALJ, ACWA filed comments that explain the types of water agency operations that might be amenable to demand response programs and include proposals for water agency demand response programs.
ACWA believes water agency programs could provide up to 30 MW of demand reduction. It estimates an annual cost of $2.9 million split between the three utilities - 45% each for SCE and PG&E and the remaining 10% for SDG&E. Incentives would be up to $85/kW with no energy payment and each program would be open to aggregators and be technology-neutral. ACWA proposes two specific programs, one that would shift peak usage permanently and the other that would reduce demand during a utility event, similar to the CPP program. ACWA provides illustrative tariff language for these programs. It states the utilities must offer the programs by January 2007 for water agencies to take advantage of them in time for summer peak in 2007.
On November 3, 2006 PG&E, SDG&E, and SCE filed a Joint Motion requesting approval of a program called the "Statewide Water Agency Program Proposal," which is intended to comply with the Amended Settlement approved in D.06-03-024.
We are interested in pursuing permanent load shifting opportunities in time for the summer of 2007. These types of programs may reduce energy use during critical periods and in some cases conserve energy overall. While we defer the issue of how this or other permanent load shifting technologies should count toward demand response goals, we do recognize that new installations of permanent load shifting technologies will accomplish our goal of reducing peak demand for summer 2007 and so wish to encourage the IOUs to pursue permanent load shifting by allowing the use of TA/TI funds toward offsetting the initial costs of installation.
Ice Energy's proposal is interesting. However, we do not support allocating $25 million to a specific company or technology, such as the Ice Energy proposal, but prefer to initiate a more generic process.
Accordingly, we direct the utilities to pursue RFPs and bilateral arrangements by which they can solicit five-year proposals from third parties for permanent load shifting that can be implemented by summer 2007. We do not specify a preference for any particular technology, but the IOUs should consider cost-effectiveness, ease of implementation, the amount of load shifting that can be obtained by the summer of 2007, potential for growth and expansion, and the reliability of the technology. Each IOU is directed to file an advice letter with their proposals by February 28, 2007. PG&E, SDG&E, and SCE are authorized to shift up to $10 million, $4 million, and $10 million respectively of their existing demand response budgets, which is roughly in line with the size of the program proposed by Ice Energy.
We will not address the ACWA proposal and Joint Motion of the utilities in this decision. Instead the Assigned Commissioner will respond to the Joint Motion and ACWA proposal in a subsequent ruling.
The Commission strongly supports developing demand response programs that are tailored specifically toward water agencies. The Energy Action Plan II explicitly identified reducing water supply system electric load during peak hours as a key action.57 We intend to implement that key action in part by facilitating the development of water agency demand response opportunities by the summer of 2007.
B. PG&E Proposals and Budget
The E-CPP is available to customers on time-of-use rates with maximum demand greater than 200 kW. Subscribers receive a discounted rate for summer usage except when a critical peak event is called at which time a customer is levied higher on-peak energy charges. Critical peak events are called on a day-ahead basis and can be called between noon and 6:00 p.m., Monday through Friday during the summer months.
Currently, PG&E manages its CPP program in two identified zones, one along the coast where the climate is mild and the other comprising the rest of PG&E's territory, where temperatures tend to be substantially warmer in summer months. PG&E states the use of these zones has created confusion for its CPP customers, who may not know when they have been asked to reduce load. PG&E proposes to manage the program on a system wide basis, without breaking down its territory into zones. It believes it may be able to add 7 MW to the program as a result.
PG&E also proposes to modify the CPP program to provide customer notification at noon the day before an event rather than at 3:00 p.m. in order to provide customers additional time to plan for load reductions. PG&E does not anticipate significantly more participation because of this change but notes that it will increase customer satisfaction.
DRA does not object to these proposed program changes but believes the program would be more attractive if it employed "soft triggers" so that CPP events will only be called when load is really needed, rather than according to inflexible guidelines. SCE's program has flexible triggers, and SDG&E has proposed such flexibility in this proceeding.58
We will authorize the changes to the CPP program PG&E recommends, but decline to adopt soft triggers since changing the triggers could impact overall program design.
The SCAPP provides funding to San Francisco (SF) Power to sign up small and medium sized commercial customers located in Alameda, San Francisco, and San Mateo Counties in the CPA-DRP program.59 D.06-03-024 authorized funding SF Power's efforts for 2006 at a level of $250,000 and would award SF Power an additional $250,000 for 2007 if it signs up 1 MW by the end of 2006. PG&E would extend SF Power's 1 MW deadline until June 1, 2007, so that SF Power can continue its efforts past the end of the year even if it has not signed up 1 MW.60 SF Power says it has made good progress toward meeting its 2006 goals. Therefore, it requests additional funding-an additional $150,000 in 2007 once a second MW is signed up and $400,000 more in 2008 once 3 MW are signed up. SF Power's goal is to sign up 5 MW by May 2008. SF Power wants to expand its target area to include Contra Costa and Santa Clara counties. It also recommends pursuing 5 MW of permanent load shifting by June 2007 through a program targeted at pallet jack and forklift battery recharging, which was the subject of a CEC-funded study, at a cost of $125,000. Finally, SF Power proposes to permit the aggregation of submeters.61
PG&E supports SF Power's recommendations to expand its program provided that additional funding is contingent on meeting performance goals, and expanding the program into additional counties. The utility is not opposed to the permanent load shifting proposal. PG&E is, however, opposed to aggregating submeters, arguing that SF Power has overlooked costs required to upgrade electric panels.62
The costs of the SCAPP program are for marketing only and are therefore in addition to the incentives and some of the overhead costs incurred by PG&E for the CPA-DRP (or CBP starting May 2007). SF Power's proposal to extend the program to achieve 5 MW in demand response from a difficult to reach customer segment, and to tie program extension to megawatt goals is reasonable. We, therefore, adopt SF Power's proposed expansion. We will also permit SF Power to extend its program into the two additional counties listed above and move forward with the 5 MW permanent load shifting program that it proposes. We deny SF Power's request to aggregate submeters since we do not have sufficient information to fully evaluate costs and benefits.
The BEC is a project in San Francisco designed to subscribe hard-to-reach customers into demand response programs. The program is currently targeting 15 MW in 2007 and 25 MW in 2008.
PG&E requests authority to expand the BEC program to motivate 50 MW of subscribed customer load by June 1, 2007. The expansion would include accelerating the 25 MW targeted for 2008 and adding an additional 25 MW. PG&E states it would provide details of this proposal, and a proposal to extend the program for seven years, in a subsequent request once PG&E signs an agreement with BEC. In PG&E's Opening Comments on the Proposed Decision, the utility clarifies that the expansion of the program to 50 MW in 2007 can be achieved within the existing budget.63
Because the BEC program targets hard-to-reach customers and was successful during July 2006, we authorize PG&E's proposal to expand the program in 2007. PG&E does not provide any details of its seven-year extension. Therefore, we decline to authorize the extension at this time and direct PG&E to file an application for approval of its expansion proposal once a new agreement has been signed.
PG&E proposes to spend about $15 million in 2007 and $15 million in 2008 to retrofit existing customer-owned diesel back-up generators to primarily run on natural gas. Diesel would still be used as a pilot fuel. The units would be available during Stage 2 alerts. PG&E would pay a customer up to $225.00 per kW in return for a commitment to upgrade the generator and operate on notice from PG&E. BUG owners would also be eligible for capacity payments and be subject to penalties for non-performance. PG&E believes the program would add up to 50 MW of load reduction potential in 2007 and an additional 50 MW in 2008. It states the generators would not be deployed unless they could operate in compliance with air quality requirements.
PG&E's proposal differs from a prior proposal rejected by the Commission in D.05-01-056 in which the utility proposed to add emissions control technologies to diesel engines. Here natural gas would be the primary fuel.
ECI, EnerNOC, and SVLG support the proposal.64 ECI comments that the health impacts of running generators for a few critical hours are probably small compared to the health and safety impacts of rolling blackouts. EnerNOC asserts that because BUGs are "behind the meter", they reduce load on the grid and should be considered demand response.65 Aglet also supports it but does not enunciate the reasons for its support. TURN opposes the program on the basis that it is a supply resource, not a demand response resource, and cannot be reasonably evaluated here.66 SCE is opposed to launching a BUG program for similar reasons.67
Our objective in funding demand response programs is to reduce system demand, not to substitute system electricity with electricity generated by off-grid natural gas facilities. We previously found in D.05-01-056 that back-up generation is not a true demand response resource. As TURN states, counting a BUG program as demand response would "turn the Commission's preferred resource loading order on its head."68 We, therefore, deny PG&E's request to initiate a BUG program.
PG&E requests $500,000 to extend the E3/SPP rate through June 2007 so that SPP customers can be smoothly transitioned to the residential CPP rate in Spring 2007. Maintaining continuity for SPP participants is important, so we approve PG&E's request.
The program enhancements and expansions we approve here can be funded by reallocating existing funds. We find it reasonable that PG&E does not seek additional funding for demand response efforts. We authorize necessary fund shifting, but do not need to authorize additional expenditures at this time.
PG&E tracks its actual expenses against the authorized revenue requirement in the Demand Response Expense Balancing Account (DREBA). The DREBA is a one-way balancing account that prohibits the utility from being compensated for spending more than a pre-approved budget. PG&E intends to update the demand response revenue requirement as appropriate when the utility files additional plans for expanded and new demand response programs, and record the associated expenses in the DREBA.
We encourage PG&E to look for opportunities to expand its demand response programs and create new programs. To the extent additional funding is needed to expand PG&E's efforts, the utility should seek approval from the Commission in advance. PG&E's intended accounting treatment is appropriate provided that the utility obtains Commission approval prior to recording expenses in the DREBA.
Finally, this order does not eliminate the cap on fund-shifting, as PG&E proposes. The cap was adopted in D.06-03-024 as part of the settlement presented in these proceedings. That cap provides adequate flexibility for PG&E to move program funds according to need while providing some protection for ratepayers against overspending on programs that might not be cost-effective. If PG&E wishes to reallocate additional funds to a program, it may seek such authority by advice letter, consistent with D.06-03-024, and should make a showing of the cost-effectiveness of such a reallocation.
C. SDG&E Proposals and Budget
SDG&E sought and received a variety of changes to its C&I Peak Day Credit Program by way of advice letter filed in July 2006. Those changes were authorized for 2006 only. SDG&E here seeks to extend most of the changes through 2008. Those program elements include allowing for incentive payments for load reductions between 10% and 20% and the softening of triggers so that SDG&E has the discretion to call an event. SDG&E believes these two elements together will improve management of the program and provide a more attractive product to customers. SDG&E does not propose eliminating the maximum number of events as was done in Resolution E-4011.
DRA and TURN object to SDG&E's proposal to extend this program into 2007, observing that the program is not cost effective and provides "virtually no value to ratepayers" because it is not dispatchable and does not result in any measurable load reductions.69
We believe that this program could contribute to reliability during peak periods. We acknowledge a need to evaluate this program in more depth with a cost-effectiveness model but in light of our goal to augment demand response for 2007, we approve SDG&E's proposal to extend the C&I peak day credit program through 2008.
SDG&E proposes to extend its Residential Smart Thermostat Program through 2007 with no changes. This AC Cycling type program would require about $385,000 in reallocation of budget funds. Aglet questions the program's cost-effectiveness70 Because it provided substantial "day-of" load reductions in 2006, we find the continuation of this program into 2007 to be reasonable.
SDG&E proposes to modify its CPP program by softening the triggers for calling an event and increasing the maximum number of events to 15. For reasons discussed previously, these modifications appear reasonable and designed to improve customer participation, and we adopt them.
SDG&E proposes to implement a new program that will offer residential customers the installation of an in-home display device that will provide information to customers on their energy usage and potential cost by the hour, month and month-to-date. A participating customer will be provided educational material and will be asked to reduce his or her energy usage during identified peak periods. The program will be used to understand how customers modify their behavior in response to real-time information. The program will be offered to 300 customers in 2007 at a cost of about $430 thousand, including a significant measurement and evaluation component.
The testing of real-time in-home displays will provide valuable research about how residential customers respond to real-time information about their energy usage. The findings from this program could be used to enhance other demand response efforts targeted at the residential sector.
The program enhancements and expansions we approve here can be funded by reallocating existing funds. We find it reasonable that SDG&E does not seek additional funding for demand response efforts. We authorize necessary fund shifting, but do not need to authorize additional expenditures at this time.
Like PG&E, SDG&E proposes to eliminate limitations on shifting funds between programs, which D.06-03-024 set at 50% of program funds. It would seek Commission approval of other program changes, consistent with D.06-03-024. We are not prepared to permit SDG&E authorization to use program funds at its discretion, largely because we have no adopted cost-effectiveness test by which the Commission or the utility could judge such substantial deviations from the adopted program budget. The existing limitation provides adequate discretion for SDG&E to allocate funds between programs and according to program participation. We do authorize the fund shifting SDG&E proposes here. If SDG&E seeks authority beyond what is adopted here and what is contemplated by D.06-03-024, it should file an advice letter.
D. SCE Proposals and Budget
The program enhancements and expansions we approve for SCE discussed above can be funded by reallocating existing funds. We find it reasonable that SCE does not seek additional funding for demand response efforts. We authorize necessary fund shifting, but do not need to authorize additional expenditures at this time.
E. TURN's Proposal for Swimming Pool Pumps
TURN proposes that the Commission order the utilities to engage third-party contractors to install direct load control equipment on swimming pool pumps. TURN explains that swimming pool pumps can be deployed during off-peak hours without affecting health, safety or the economy. It proposes use of third parties so that the utilities do not need to develop infrastructure prior to implementing such a program.
PG&E opposed TURN's proposal for a variety of reasons. The utility questions TURN's premise that a significant number of pool pumps operate during peak hours. PG&E points out that almost all pool pumps except for those equipped with solar heating or energy efficiency filters are already equipped with timers and many probably do not operate during peak hours. 71
TURN's idea is interesting but we believe that the magnitude of the potential peak load reduction is unclear at the point. We decline to adopt TURN's proposal, but encourage the utilities to consider pool pumps in the context of demand response programs.
16 D.05-04-053 at 80.
17 Resolution E-4018 at 11.
18 PG&E Proposals at 36.
19 CLECA/CMTA Opening Comments.
20 Aglet Opening Comments at 4-5.
21 DRA Opening Comments at 12-13.
22 For example, EnerNOC Reply Comments at 3-4.
23 SDG&E Proposals at 17-18.
24 SDG&E Proposals, Attachment 1 at 23-24.
25 Resolution E-4020, adopted by the Commission on October 19, 2006, approved SDG&E's CBP.
26 DRA Opening Comments at 12.
27 EnerNOC Opening Comments at 14 and Reply Comments at 4-5.
28 SCE Opening Comments at 3-4.
29 CAISO Reply Comments at 5.
30 EnerNOC Reply Comments at 5-6.
31 PG&E Reply Comments at 9.
32 Aglet Opening Comments at 5 and Reply Comments at 2.
33 TURN Opening Comments at 15-16.
34 DRA Opening Comments at 10.
35 ECI Opening Comments at 2 and SVLG Reply Comments at 2.
36 Aglet Opening Comments at 7.
37 DRA Opening Comments at 11.
38 Aglet Opening Comments at 6.
39 DRA Opening Comments at 10-11.
40 ECI Opening Comments at 2 and SVLG Reply Comments at 2.
41 PG&E Reply Comments at 4-5.
42 Aglet Opening Comments at 4.
43 EUF Opening Comments.
44 CLECA/CMTA Opening Comments.
45 DRA Opening Comments at 8-9.
46 Id. at 14.
47 TURN Opening Comments at 6.
48 Id. at 6-7.
49 Aglet Opening Comments at 6.
50 DRA Opening Comments at 15.
51 TURN Opening Comments at 8-9.
52 SCE Reply Comments at 2-3.
53 Aglet Opening Comments at 2 and EnerNOC Opening at 19.
54 DRA Reply Comments at 8.
55 TURN Opening Comments at 11.
56 PG&E Reply Comments at 11.
57 "Identify opportunities and support programs to reduce electricity demand related to the water supply system during peak hours and opportunities to reduce the energy needed to operate water conveyance and treatment systems." (Energy Action Plan II at 5.)
58 DRA Opening Comments at 17.
59 On October 19, 2006 the Commission adopted Resolution E-4020, authorizing the Capacity Bidding Program as a successor program to CPA-DRP starting May 2007.
60 PG&E Opening Comments at 22.
61 SF Power Opening Comments.
62 PG&E Reply Comments at 15-16.
63 PG&E Opening Comments on Proposed Decision at 5.
64 ECI Opening Comments at 4, EnerNOC Opening Comments at 16-18, and SVLG Opening Comments.
65 EnerNOC Reply Comments at 7.
66 TURN Opening Comments at 15.
67 SCE Reply Comments at 8.
68 TURN Opening Comments at 15.
69 DRA Opening Comments at 21-22 and TURN Opening Comments at 14-15.
70 Aglet Opening Comments at 7.
71 PG&E Reply Comments at 14.
