5. Rate Design - All Classes
5.1. Rate Levels for PDP Rates
PG&E's original PDP rate proposal contained a $1.80 per kWh PDP period charge, with adjustments for residential, agricultural and small commercial customers. That PDP rate represented PG&E's initial interpretation of the Commission's Rate Guidance (Attachment A to D.08-07-045), which among other things states that TOU demand charges should be eliminated from the generation component of those tariffs that include generation demand charges. However, after reviewing other parties' testimony on this issue, PG&E revised its recommendation to give greater weight to another aspect of the Rate Guidance, which indicates that the PDP adder should be based more strictly on the marginal cost of generation capacity. PG&E also applied two standard adjustment factors identified by DRA to arrive at a PDP adder of $1.20 per kWh in rebuttal testimony. By further applying its initial proposed adjustments to the $1.20 PDP charge, PG&E indicates that the agricultural and standard residential PDP adders would be reduced to $1.00 per kWh (to reflect rate design considerations unique to these two rate classes), and the small Commercial PDP adder would become $0.60 per kWh (based on the same bill impact mitigation considerations first described in its original testimony). Also, under its new alternative for residential customers discussed later in this decision, the residential PDP adder would become $0.50 per kWh.
As discussed later in this decision, adjustments are made to reduce the PDP charge proposed by PG&E for customers on Schedule A-10. For schedules other than A-10, there is no opposition to PG&E's revised PDP rate levels.9 They are reasonable and are adopted.
5.2. TOU Rates
Except for two specific exceptions, PG&E has not proposed to change its TOU rates in this proceeding. The two exceptions are the TOU rates that would be combined with PDP for small and medium C&I customers and for residential customers. First, for customers on Schedule A-1, the new TOU version of Schedule A-1 would become the "backstop" TOU rate for those A-1 customers who do not accept default to the PDP rate. Similarly, the PDP version of Schedule A-6 TOU would become the default rate for customers taking optional TOU service on this schedule.
Second, in response to DRA's recommendation that residential PDP be offered in combination with the standard non-TOU Schedule E-1 residential tariff, PG&E's rebuttal testimony presented a residential PDP rate with TOU prices that are less steeply time-differentiated than those offered under the residential Schedule E-6 tariff. This rate would only be offered in conjunction with residential PDP.
With the changes contained in PG&E's rebuttal testimony, no party opposes PG&E's TOU rate proposals in this case, although DRA has expressed strong interest in development of more greatly time-differentiated TOU rates, especially for medium C&I customers in future cases. The TOU rates for PDP, as now proposed by PG&E,10 are reasonable and are adopted. The need for, and structure of, more greatly time-differentiated TOU rates for medium C&I customers can be raised as issues in future cases.
5.3. Number of PDP Events
All parties that have addressed the number of PDP events support an annual minimum of 9 and a maximum of 15 PDP calls.11 There is general agreement that adoption of these minimum and maximum numbers mitigates the problem associated with over- and under-collections. Although PG&E presented testimony that the fixed temperature thresholds in its proposal would likely be met between 6 and 18 times in most years, PG&E states that the high degree of variability around the design basis of 12 years justifies adopting a somewhat narrower band on the number of annual PDP calls.
The Commission will adopt this consensus position on the minimum and maximum number of annual PDP calls, as well as PG&E's proposal for enforcing the bounds by raising or lowering the temperature thresholds. PG&E states that it should be possible to enforce the narrower bounds on the number of calls each summer simply by raising or lowering the 98-degree weekday temperature threshold in 2-degree increments at monthly intervals over the course of the summer. According to PG&E, in most years, the threshold should not need to be adjusted more than one increment up or down over the course of the summer. The weekend and holiday threshold would be left fixed at 105 degrees.12
5.4. First Year Bill Stabilization/Protection
PG&E proposes to provide all non-residential customers with bill stabilization for the first year they are on the new PDP rates, whether they have been defaulted or opted in. The bill stabilization would protect the customer from a PDP bill for up to 12 cumulative months that exceeds the bill for the period under the customer's otherwise applicable tariff, such as TOU. For residential customers, PG&E proposes bill protection for the first year the customer is on PDP by not allowing the bill to exceed the annual bill under the tariff the customer was on previously, such as non-TOU Schedule E-1, as long as the tariff is available.
No party opposes PG&E's proposal to provide first year bill stabilization or protection. DRA has proposed extended bill stabilization for small C&I customers which is discussed further on in this decision.
PG&E's first year bill stabilization/protection proposal is reasonable and is adopted. As the Commission stated in D.08-07-045, bill protection is valuable to enable customers to become familiar and comfortable with a new rate.13 With bill protection, a customer's first year on a new PDP rate is a no-lose proposition since any annual bill increase relative to the otherwise applicable rate will be refunded. However, a customer will still have an opportunity to experience lower costs if it saves money during the first year. Bill protection can also be viewed as an important consumer protection since customers that are not aware of the new rate for whatever reason will receive a year-end refund for any cumulative bill increase during the first year relative to the otherwise applicable rate. That refund will also serve as an additional reminder about the rate and that the customer as the opportunity to remain on the rate or opt out after the first year.
Any bill protection refund would be provided to a customer at the end of the first year. However, prior to a year-end refund, a customer on PDP would have to pay its actual monthly bills under the new rate. We share DRA's concern that in the current economic climate a small or medium commercial or industrial customer that experiences a high bill during a particularly hot month could have difficulty paying. In extreme circumstances a customer might be faced with a disconnection. To avoid unnecessary disconnections, when applying Electric Rule No. 11, D, 1 (Inability to Pay-Nonresidential), PG&E should endeavor to extend payment arrangements to customers that did not pay their full monthly bill but would be able to pay the bill if it were recalculated under the otherwise applicable rate.
5.5. Allocation of Over- and Under-Collections
The question of how to allocate over- and under-collections due to bill stabilization/protection and the variation in the number of PDP events from the PDP design number of 12 events was initially a contentious issue among a number of the parties. Proposals included: (a) allocation to all customers under certain circumstances; (b) allocation to PDP participants only; (c) allocation by customer class giving rise to the over- or under-collection to all customers in the class; and (d) adoption of different allocation methods for under-collections due to bill protection/stabilization as opposed to over- and under-collections due to variations in the number of PDP events.
PG&E's initial proposal was to make annual adjustments to the generation revenues assigned to each principal customer class for the purpose of approximately adjusting the estimated under- or over-collections following any year in which the number of PDP events significantly differed from the 12 PDP events assumed for rate design purposes. The proposed adjustment would be applied following those years when there have been 9 or fewer PDP events or 15 or more PDP events. However, since a number of parties objected to this deadband recommendation, PG&E now recommends the adjustments should be made every year. PG&E does not expect the adjustments to be so large as to materially affect rates whether they are included or excluded.
With respect to under-collections due to bill stabilization, FEA states that participants alone cannot fund the bill protection because they are the ones who are being provided the protection. Therefore, all customers within each class must participate in funding any bill protection payments.
With respect to under- and over-collections due to the number of PDP events, FEA supports PG&E's revised proposal to allocate on a class basis to all customers so that it can be appropriately accounted for through rate design instead of being spread to all customers in all hours. FEA's associated rate design proposal is based on the fact that the dollars associated with any reconciliation of revenues resulting from more or less than 12 events is generation-related and peak period-specific. Accordingly, it is FEA's recommendation that, for each class, the reconciliation occur by applying a credit or a surcharge as appropriate to on-peak and mid-peak demand charges and energy charges. According to FEA, this approach matches the collections as nearly as practical with the periods in which the revenues were intended to be collected.14
FEA also indicates that purely from an equity standpoint, it would be preferable if the reconciliation occurred only across the participants, but there is a major practical problem with such an approach. The limitation is that with optional tariffs there could be the unintended consequence of either encouraging or discouraging participation because of the anticipated presence of a surcredit or surcharge in any given year.
CLECA also supports PG&E's revised approach, both for its simplicity and because the concept of visiting potentially large upward or downward adjustments on individual customers who actually sign up for this program is likely to create one more disincentive for participation. CLECA states that the Commission needs to encourage customers to participate by making the program understandable, relatively straightforward and by minimizing the perceived risks of participation. CLECA also notes that exclusion of non-participants would necessitate tracking individual customers, but leaves it up to PG&E to determine whether that is operationally feasible.
DRA concurs with the view of the majority of the parties, that revenue reconciliation take place at the class level, both for revenue deviations due to annual bill stabilization/protection and, conditionally, for those due to variation in number of PDP events.
DRA's initial testimony advocated participant level reconciliation of PDP-related revenue deviations. DRA states that it changed its recommendation, based on the reduced revenue swings associated with the consensus recommendation of 9-15 PDP events and a maximum $1.20 per kWh PDP charge. Given this scenario, DRA no longer believes that the benefits of participant-level reconciliation outweigh the costs of its implementation.
Similarly, CFBF expressed its belief that it would be most appropriate to allocate the PDP over-/under-collection according to the class-specific enrolled load, but if the number of PDP events were restricted to between 9 and 15, the issue would be less important due to the reduced volatility.
Allocation to all customers by class is also supported by EPUC who, similar to FEA, noted that a participant only reconciliation in conjunction with an opt-out provision could lead to annual gaming of PDP rates.
TURN also indicates its support for allocation to all customers by class.
BOMA opposes the allocation to non-participants, stating that such a proposal contravenes the requirements of D.08-07-045 and is inconsistent with the settlement found reasonable in D.07-09-004.
BOMA refers to D.08-07-045 where the Commission stated that "Customers should have the opportunity to opt out of a dynamic pricing rate to another time-variant rate." According to BOMA, PG&E's proposal does not meet that standard. Under it, customers who opt out of the PDP Program to an applicable time variant rate, in order to avoid the financial risks of the PDP rate, will not actually escape those risks because PG&E will transfer PDP risks to the existing time variant rates.
BOMA also asserts that, in effect, through implementation of its E-20 Secondary PDP rate, PG&E will actually change the revenue allocation and rate design of the existing E-20 Secondary rate (which violates the terms of the Settlement Agreement, to which PG&E, FEA, and BOMA were Parties, adopted in D.07-09-004). BOMA adds the FEA Proposal will further change the rate design of the Settlement by forcing all of the under-collection adjustments into peak period demand and energy charges, thus directly shifting revenue responsibilities from flat load customers to customers who use relatively higher proportions of the load during peak period hours.
According to BOMA, the potential magnitude of the E-20 Secondary summer rate increases that could be expected from under-collections could exceed 9% for 75% participation and three calls, and 1% with participation as low as 25% and nine calls. In BOMA's view, both figures represent cost shifts to customers that have "opted out" that are very significant. BOMA concludes that the potential risks that such transfers could occur under PG&E's PDP Plan are unacceptable, inconsistent with Commission precedent, and can be avoided by adopting BOMA's recommended alternative.
BOMA's alternative is derived from D.09-08-028 for the recent Southern California Edison Company (SCE) GRC Phase 2 filing (A.08-03-002), which states:
... that the undercollection or overcollection resulting from the difference between actual called events and twelve events as designed shall be assigned to the summer on-peak and mid-peak periods as a flat cent per kWh surcharge in the subsequent annual period for the CPP participants within each rate group that is responsible for the revenue imbalance.
BOMA states that by retaining revenue responsibility/credits within the subclass of E-20 PDP Secondary, as specified in D.09-08-028, customers will be able to opt out to an E-20 Secondary rate that is independent of the under- and over-collections of the PDP Program and avoid the financial risks and cost shifts associated with the PDP rates. Noting PG&E's arguments against this approach (in addition to their position that cost transfers will be small) which are that they do not know how to program the implementation of the approach, that it would be excessively costly to implement, and that they could not implement it by the May 2010 deadline, BOMA indicates that these arguments are unconvincing especially in light of the fact that SCE has committed to implement D.09-08-028. BOMA states that it does not accept PG&E's apparent premise that programming inconvenience should trump the basic principle of equity in rate setting.
EUF/CMTA also proposes that if the Commission adopts a PDP rate, it should limit distribution of the revenue deviation, whether positive or negative, to the PDP participants, to avoid the financial repercussions on those not on the PDP rate schedule. EUF/CMTA asserts that it would not be equitable to pass a rate impact on to a customer that did not participate in that program nor would it be equitable to the PDP participant group, and notes that distributing some of the revenue deviation to non-participants causes the PDP tariff not to be truly optional.
With respect to BOMA's argument that PG&E's proposed class level adjustments and rate design for under- or over-collections violate the settlement on revenue allocation and rate design approved by the Commission in D.07-09-004 for rate changes between GRCs,15 PG&E acknowledges that Section 3 of Appendix B to D.07-09-004 establishes the revenue allocation and rate design guidelines for PG&E between GRCs and recognizes the potential deviation from those guidelines inherent in its recommendation, to the extent that the adjustments might increase (or decrease) the amount of revenue to be assigned to peak period demand and energy charges in some years. However, PG&E claims that these deviations would be small and are likely to be symmetric with respect to increases or decreases. Moreover, adjustments that increase the amount of revenue assigned to peak period charges in one year will be adjustments that make up for an under-collection of peak period revenue in the preceding year (and vice versa). According to PG&E, this means there would be no deviation from Section 3 of the D.07-09-004 Settlement Agreement if a multiple-year perspective is used. Lastly, PG&E asserts that BOMA's recommendation of participant-only adjustments could result in greater deviations from the Settlement Agreement than would PG&E's recommendations, because customers who opt out after enjoying the benefits of a year with a lower than expected number of PDP events would not have any allocation of under- and over-collections due to variation in PDP operations, while ongoing PDP participants would bear all the revenue requirement changes.
No party disputes that under- and over-collections that are associated with bill stabilization should be allocated to all customers by class, and that principle will be adopted.
We will also adopt the principle of allocating under- and over-collections due to the number of PDP events by customer class to both participants and non-participants. While all parties appear to agree that such allocation should be by customer class, there is a difference in opinion, as described above, with respect to whether the allocation should be imposed on non-participants. A number of parties indicate that excluding non-participants would be preferable, but for a number of other reasons feel that inclusion of such customers in the allocation is either preferable or does not matter.
While BOMA's position is bolstered by Commission actions in D.09-08-028 in the SCE proceeding, settlements are not precedential. Also the record with respect to what was considered in the referenced settlement is not clear here in PG&E's proceeding. Here, with respect to excluding non-participants from the allocation, we agree there are potential gaming problems. At this point, there are also additional costs and difficulties in implementing such a proposal. While BOMA is concerned that the effects of allocating to all customers imposes a potentially large burden on non-participants, other parties explicitly state that such volatility effects would be largely mitigated by lowering the PDP rate, from that originally proposed by PG&E to what is now proposed by PG&E, and limiting the number of PDP events to between 9 and 15 per year, both of which are adopted in our decision today. We also note CLECA's point that whether or not under- and over-collections are substantial, imposing that risk on only those customers who actually sign up for PDP is likely to create one more disincentive for participation. Based on the weight of the evidence in this proceeding, we feel it is appropriate to allocate under- and over-collections due to the number of PDP events to both participants and non-participants.
Our decision on this issue reflects the position of a significant majority of the parties. The fact that such a majority of parties, representing the interests of a variety of different customer classes and groups, can agree on the issue is important. This is not to imply that a position should be disregarded or demeaned in any way simply because its support is in the minority. However, to the extent that parties are satisfied with an outcome, it is more likely that potential problems that may concern the customers they represent will be minimized. The more that happens and the more that perceived problems are minimized, the more likely it is that a program such as PDP will be successful.
With respect to BOMA's use of D.08-07-045 to support its position, by the PDP program adopted today, customers can opt out of a PDP rate to a time-variant rate (for non-residential customers) as required by D.08-07-045. In D.08-07-045, the Commission does not state that non-participants in dynamic pricing programs are necessarily immune from all costs of the program, such as the allocation of certain under- and over-collections. It is the Commission's prerogative to adopt a program such as PDP and assign associated costs, on a case-by-case basis, in a manner that is consistent with the record and consistent with furthering its goals and policies. With respect to costs here in this section, it is reasonable for non-participants to share in a portion of the risk and costs of the PDP program, since its purpose is to lower rates for all customers in the long term.
With respect to FEA's recommendation that, within each class, the reconciliation should occur by applying a credit or a surcharge as appropriate to on-peak and mid-peak demand charges and energy charges, the only parties that addressed it were PG&E and BOMA. PG&E supports this recommendation, while BOMA opposes it.
With respect to BOMA's claim that the FEA/PG&E proposal violates the Settlement in D.07-09-004, according to PG&E the equal cents-per-kWh surcharge approach suggested by BOMA (and adopted but not yet implemented for SCE) would deviate further from the 2007 GRC settlement than the approach endorsed by FEA and PG&E, because it would assign recovery of all peak-period revenue under- and over-collections to an undifferentiated cents-per-kWh charge.
However, we also note PG&E's statement that:
While PG&E endorses the FEA approach, the company indicates that if the Commission wishes to take an approach to rate design that is fully compliant with the settlement approved by D.07-09-004, it would make no distinction in rate design for these under- and over- collections. In that event, the adjustments would be spread on an even percentage basis among all generation demand and energy charges. Rate design guidelines provided by D.07-09-004 are somewhat different in the residential class to comply with the rate restrictions of AB 1X. (PG&E, Reply Brief at 8, footnote 6.)
We prefer to maintain the settlement approved by D.07-09-004 to the extent reasonably possible, as long as it does not impede our efforts regarding implementation of dynamic pricing. With respect to this particular issue, as indicated by PG&E, maintaining the principles reached in that settlement is a viable alternative to FEA's proposal and to BOMA's proposal. For this reason only, we will require that adjustments, to the extent possible, be consistent with the Settlement in D.07-09-004 and, for non-residential customers, be spread on an even percentage basis among all generation demand and energy charges. The merits of the FEA/PG&E proposal or the BOMA proposal can be addressed in future proceedings, as appropriate.
9 As specified in Exhibit 7, Tables 2-3 through 2-5, and Table 2-6, Alternative 1.
10 As specified in Exhibit 7, Tables 2-3 through 2-5, and Table 2-6, Alternative 1.
11 Parties agreeing on this issue include PG&E, EUF/CMTA, CLECA, EPUC, FEA, CFBF, and DRA.
12 See Exhibit 7 at 2-4.
13 D.08-07-045, Finding of Fact 29.
14 PG&E supports this recommendation. According to PG&E, these rate design adjustments to generation capacity-related rate components are reasonable because these class level adjustments recognize variation in revenue collection of generation capacity-based PDP charges due to variation in the number of PDP operations, and since these charges are generation capacity related, rate design adjustments to generation rate components that collect generation capacity costs are reasonable.
15 PG&E states that BOMA's brief does not explain which provisions of the seven separate settlement agreements attached to D.07-09-004 it believes would be violated by PG&E's proposed class level cost allocation and rate design adjustments. However, rate changes between GRCs are governed by Section 3 of the marginal costs and revenue allocation settlement agreement, which is at pp. 17-19 of Appendix B to D.07-09-004. PG&E indicates that there are two subsections of Section 3 which appear relevant to BOMA's argument. Subsection 3(A) provides in part that, "Each customer group will be held responsible for approximately the same percentage contribution to each component in rates" (emphasis added); and subsection 3(G) holds that, "Non-residential rate changes will be implemented as equal percentage changes to demand and energy charges by component as necessary to collect revenue."
