10. Tariff Revisions and Requirements
10.1. Opt-Out and Switching Proposals
PG&E has proposed default, opt-out provisions that comply with the dates and directions in D.08-07-045. Normally, customers will be given 45 days from the day they qualify for a default PDP rate to opt out of the PDP rate. If they do not opt out, they will be defaulted to PDP rates on their next billing period which is at least five days after the 45-day period. For the May 1, 2010 default date for large C&I customers, the opt-out period will begin 45 days before May 1, 2010. However, in the first year that default PDP is applicable to an individual customer, PG&E intends to allow the customer to opt out of PDP, if the customer has not previously taken any action that indicates it has made an affirmative choice relative to PDP.
In general, PG&E plans to let customers opt out of PDP during the first year beginning with the date they become eligible for default PDP, if the customer has not taken any affirmative action concerning PDP. After the customer's first year on PDP, the customer could opt out of PDP consistent with PG&E's normal rules governing customer switching from one rate schedule to another.
It is DRA's position that customers should be allowed to opt out of PDP rates to an applicable TOU rate schedule at any time, subject to a limit of one opt-out per season. Customers opting out during the summer season (May-October) would be required to repay any PDP credits they have received since May 1 of the year in which they opt out. Winter season opting out would carry no financial penalty.
DRA also recommends that customers opting in to PDP rates must provide updated contact information, or otherwise arrange with the utility for event notification. Customers should be allowed to opt in to PDP rates at any time during the summer season, provided they have not previously opted out during the same season. Such customers would receive PDP credits and be subject to PDP charges as of the effective date of beginning service under PDP rates. Customers should be allowed to opt in once during the winter season.
DRA states that its motivation is to allow customers greater flexibility to adapt to new rate designs and potential changes to business circumstances than allowed by PG&E's proposed 45-day opt-out period. The additional flexibility granted by DRA's proposed switching rules might prompt some customers to accept default PDP status when they might otherwise opt out due to PG&E's proposed 45-day provision. At the same time, DRA believes that customers, who are on PDP rates as of May 1 of a given year but opt out before October 31 of the same year, should pay a financial penalty. Further, the appropriate penalty would be forfeiture of PDP credits earned from May 1 until the opt-out date. This provision would discourage customer gaming by timing a decision to opt out in advance of a forecasted heat wave, thereby capturing partial summer PDP credits but avoiding late summer PDP costs.
EnerNOC recommends that, if PG&E's PDP proposal is approved, PG&E's PDP tariff should be modified to allow PG&E customers to opt-out of PDP at any time if they opt out to enroll in another DR program.
According to EnerNOC, such a change will not create any disruptions to the program, and customers will still have an incentive to modify energy usage behaviors to reduce peak usage or reduce the need to build additional generation capacity, whether they are on PDP or a DR program. EnerNOC adds that its proposed modification will benefit customers by providing them with a wider range of options, while, at the same time, maintaining the customer's commitment to DR and increasing customer satisfaction for customers who belatedly understand that PDP does not work well for them.
As a matter of principle, PG&E believes that EnerNOC's proposal has merit. However, according to PG&E, this functionality would not be available on May 1, 2010, and whether it could be available in 2011 is debatable.
For the first year under PDP rates, PG&E recommends that customers who affirmatively choose to be on such rates must remain on the rates for 12 months. Customers who did not affirmatively choose to be on PDP but who were defaulted onto such rates can opt out any time during the first year and would be afforded bill stabilization for the time they are PDP rates. After the first year, consistent with its current rules, customers would be limited to switching once a year.
We will extend PG&E's first year opt-out provision to all customers including those who affirmatively choose to opt in. We believe it is appropriate to provide the immediate opt-out provisions for customers who, for whatever reason, are on PDP and who, for whatever reason, realize that they no longer want to be on PDP. We believe this is reasonable for several reasons. Defaulted customers may experience significant bill increases just because they did not realize they were on PDP or realize what the effects might be. For customers who affirmatively chose to be on PDP, their analyses with respect to benefits and costs of being on PDP or their analyses and plans with respect to how their usage might be reduced or shifted may have been flawed to the degree that there may be significant adverse financial consequences by remaining on PDP. Even with first-year annual bill stabilization, such customers may want to immediately opt out of PDP for cash flow, convenience or other reasons. The imposition of PDP is significant and there is no good reason to require customers to remain on PDP just because they failed to make a decision or where they made the wrong decision.
Because of the first-year bill stabilization provisions, strict enforcement of a 12-month wait period would have no overall financial consequences with respect to how much a customer might actually pay during that time period. However, there is the potential downside of needless customer dissatisfaction related to wanting to change schedules but not being able to do so.
We believe that one year is sufficient for customers on PDP to realize that (1) they are on such a schedule, (2) there are consequences for using electricity during peak periods on PDP event days, and (3) there are options to mitigate bill increases. Customers would have experienced the monthly bill effects of between 9 and 15 PDP events in conjunction with whatever bill volatility protection they have and would have had the opportunity to react accordingly. At some point customers must make an informed choice and should be held responsible for that choice. The first year of experiencing the rate effects is a reasonable and appropriate timeframe for that to happen. After this first year, it is reasonable that customers should be limited to switching rate schedules once a year, which is consistent with PG&E's current rules on such switching.
In some respects, our determinations of being able to opt out any time during the first year and on annual basis thereafter are not too different from that proposed by DRA. Under DRA's proposal, customers would be able to opt in or opt out of PDP one time per season, although it is not clear how many times customers can opt in or opt out during a year. We do note DRA's recommendation for a financial penalty for those customers who are on PDP as of May 1 and opt out before October 31. We will not impose this provision at this time, because it is not clear that it is necessary. However, PG&E should monitor the situation, and if it is determined that there is a significant amount of customer gaming with respect to opting in or out of PDP, PG&E should propose a solution as proposed by DRA or alternatively determined in an appropriate future rate design proceeding.
Also, for the reasons cited by EnerNOC, we will adopt its recommendation that PG&E customers should be allowed to opt out of PDP at any time, if they opt out to enroll in another DR program. However, we will not hold up the May 1, 2010 implementation of PDP to accommodate this revision to PG&E's proposal, but will require that PG&E incorporate the change no later than May 1, 2011, the beginning of the second PDP program year.
10.2. Dual Participation in PDP and Demand Response Programs
The Commission addressed the general issue of dual participation in DR programs in D.09-08-027. That decision allows customers to participate concurrently in one program that provides an energy payment and one that provides a capacity payment. The decision also states it is reasonable to consider Critical Peak Pricing to be an energy payment program.20
Ordering Paragraph 30 of D.09-08-027 directs the utilities to file Tier 2 advice letters on dual participation, stating:
In the case of simultaneous or overlapping events called in two programs, a single customer enrolled in those two programs shall receive payment only under the capacity program, not for the simultaneous event for the energy payment program. Critical Peak Pricing shall be considered to provide an energy payment for the purposes of these dual program participation rules.
PG&E states that although D.09-08-027 treats CPP as an energy payment program, the details of PG&E's PDP rate as developed in compliance with D.08-07-045 were not included in the record for that decision. For example, while current CPP rates might possibly be identified as an "energy payment" program because CPP credits were applied only as energy credits (per kWh), even though a capacity valuation ($/kW-year) was originally used to establish these credits. However, D.08-07-045 called for the new PDP credits to be adopted here to be applied on a demand basis (per kW) for all rate schedules where generation capacity costs are currently recovered through demand charges. PG&E states that its PDP rate proposals were all developed in compliance with this requirement. It is PG&E's position that because the PDP credits are based on reduced generation demand charges, it is not accurate to characterize it as an energy payment program.
PG&E also states that it, along with CLECA and EUF/CMTA, recognizes that if dual participation in PDP and a separate capacity program is allowed, there is a dual incentive problem, because PG&E's proposed PDP rate provides a capacity incentive, rather than an energy incentive, and dual participation will result in double incentive payments.
PG&E requests that the Commission find in this case that PDP is a capacity payment program due to the way it treats demand charge revenues. In the event the Commission continues to treat PDP as an energy payment program, PG&E states it would need to redesign PDP to ensure the total amount of avoided generation capacity cost does not go below zero.
CLECA also believes that the Commission's decision is problematic in that while the PDP program expresses the incentive as an energy payment, it does so by grouping what are clearly generation capacity costs into a relatively small number of hours for recovery through the PDP energy rate. Expressing the generation capacity costs as an energy rate does not change their fundamental nature. Thus, a customer that participates in both base interruptible program (BIP) and PDP events at the same time will cause the utility to avoid one set of generation capacity costs, but could be compensated twice for the one set of costs.
While the Commission is clear that it will require the utilities to develop tariff provisions that ensure that such double recovery will not occur, CLECA states this is not easy to accomplish. CLECA adds that customers might have very little incentive to participate in both programs if the customer would either lose all of the PDP credits or lose all of the BIP credits in the event there were multiple PDP events and also a simultaneous BIP event. That is because participation in these events creates costs for customers - their businesses are disrupted and their production of goods is interrupted, sometimes for a longer period than the electric interruption. Thus, participation in dual programs could result in discounted incentives for participation and customers are unlikely to look upon that favorably.
EnerNOC states that the dual participation determination by the Commission in D.09-08-027 is consistent with the position that has been continuously taken by EnerNOC in Commission DR proceedings, including as a participant in the California Demand Response Coalition in A.08-06-001, et al. It is EnerNOC's position that PDP is compatible with mandatory capacity payments programs, and, as such, the Commission's findings in D.09-08-027 that dual participation should be allowed in such programs apply to PG&E's PDP proposed in this application. EnerNOC also asserts that the determination that CPP programs such as PDP are energy, rather than capacity, payment programs was fully and appropriately considered in D.09-08-027.
EnerNOC also states that it has also consistently advocated that a customer enrolled in both a dynamic pricing tariff like PDP and a dispatchable DR program should not receive an additional energy payment from the DR program on a day when events are called in both programs for the same hours. The Commission appropriately found in D.09-08-027 that dual participation can be accommodated while also ensuring that customers do not receive two energy payments for the same curtailment activity.
EnerNOC asserts that it is inescapable that modification of PG&E's PDP proposal here is now required to ensure consistency with the Commission's directives in D.09-08-027. EnerNOC believes that D.09-08-027 makes clear that, in allowing dual participation, it is not the intent of the Commission to replace existing DR programs with a non-dispatchable TOU program, such as the PDP proposed by PG&E, but rather to ensure that the move to dynamic pricing complements existing programs.
It is EnerNOC's position that the combination in PG&E's PDP proposal of defaulting all commercial and industrial customers to PDP, while not allowing these customers to opt into another DR program or participate concurrently in a dispatchable capacity-based program, defeats and conflicts with the Commission's intent and directions in D.09-08-027. In addition, these provisions will make it impossible for DR providers either to maintain existing contracted DR levels in existing PG&E programs or to reach contracted ramp rates in contracts already approved by this Commission.
Therefore, EnerNOC recommends that, to the extent that PG&E's PDP proposal is approved by the Commission, such approval be conditioned on PG&E amending that proposal consistent with D.09-08-027. Specifically:
PG&E's PDP tariff should be modified to allow PG&E customers to participate in both the PDP and Day-of dispatchable demand response programs at the same time, to conform to the Commission's rules for dual participation established in D.09-08-027.
PG&E acknowledges that should the Commission continue to treat PDP as an energy payment program, PG&E's proposed PDP initiative would need to be revised. PG&E does not believe, however, that these revisions are properly within the scope of this case and states that it plans to address these requirements in compliance with the Ordering Paragraphs of D.09-08-027. Moreover, PG&E asserts that there is no record in this case to base a new PDP rate that complies with D.09-08-027, since that decision only came out a few days before PDP hearings began, which did not allow sufficient time for parties to develop and propose a PDP rate that would comply with the directives in D.09-08-027.
This decision is not the appropriate vehicle for modifying previous Commission determinations in D.09-08-027 with respect to dual participation or the consideration of CPP as an energy payment program. At this point, any desired changes to these determinations should be addressed through modification of D.09-08-027 by suitable means.
Therefore, at this time, we agree with EnerNOC's recommendation that PG&E's PDP tariff should be modified to allow PG&E customers to participate in both the PDP and Day-of dispatchable demand response programs at the same time, to conform to the Commission's rules for dual participation established in D.09-08-027.
Also, unless and until D.09-08-027 is modified as discussed above, we agree with PG&E, CLECA, and EnerNOC that the PDP proposal needs to be revised to address the double payment problem. We also agree with PG&E that the record in this proceeding is inadequate to make the necessary revisions at this time. We will therefore authorize PDP implementation without making such revisions. PG&E states that it plans to address this when complying with the Ordering Paragraphs of D.09-08-027. That is satisfactory, if it is feasible to do so. Alternatively, appropriate revisions can be considered in PG&E's 2011 Phase 2 GRC or a subsequent rate design window. In any event, to the extent that PDP is implemented before the revisions are made, PG&E should collect data to understand and evaluate how the payments overlap and use that information in determining how best to revise the PDP program.
10.3. Automated Demand Response
CLECA stresses the importance of automated demand response (Auto-DR), noting that having access to technology that facilitates response to dynamic pricing may well encourage customers not to opt out of such rates. CLECA states there should be provisions of customer information as to the availability of such technology and incentives for installing it as long as it is cost-effective. CLECA notes that Utility Technology assessment/Technology Incentive programs are one source of funding for larger customers and suggests that funding should be available for smaller customers as well, as long as the programs are cost-effective.
PG&E states that it supports Auto-DR and has an Auto-DR program for large customers in its 2009-2011 Demand Response programs. However, according to PG&E, the technologies that facilitate Auto-DR for large customers are currently too costly for mass market applications, and technology suitable for small and medium customers is not sufficiently developed to implement CLECA's proposal at this time.
According to PG&E, an open Auto-DR standard is in development, with use cases and business requirements expected around October 31, 2009. Subsequent technical requirements for the protocol must be developed. The draft technical requirements document is expected in 2010. The draft technical requirements would then go to the International Electrotechnical Commission, where the standard would be finalized as an international standard for DR. For customers with loads less than 200 kW, PG&E states that it may present an Auto-DR program in the 2012-2014 DR program cycle with the expectation that by that time the standards will be in place and vendors will have developed technologies for smaller customers. However, PG&E adds that the present dynamic pricing case is not the right forum to consider CLECA's proposal.
In general, the Commission supports programs such as Auto-DR that cost-effectively facilitate customer responses to dynamic pricing. With respect to Auto-DR for smaller customers, there is insufficient evidence to implement any such program at this time. We agree with PG&E's position that Auto-DR is being addressed and should continue to be addressed in the demand response proceedings.
20 See D.09-08-027 at 154-155.
