8. Rate Design

Phase 2 focused on rate design issues and the interrelationship of distributed generation to stranded costs (if any), bypass/exit fess, various types of customer charges, standby rates, performance based ratemaking (PBR) and flexible pricing mechanisms, and distribution wheeling rates. D.01-07-027 established policies for standby rate design for distributed generation. Because of the standby rate design policies adopted, in which distributed generation customers pay their fair allocation of the costs they impose on the system, stranded distribution costs will be minimized. (See D.01-07-027, p. 56.) Therefore, we need not further address whether stranded costs will occur or develop any cost recovery mechanisms at this time. Because we have adopted a standby rate policy which minimizes stranded distribution costs, we also need not consider imposition of any exit or bypass fees associated with distribution costs on customers pursuing distributed generation. Issues surrounding responsibility of departing load customers for going forward electricity procurement costs is being handled in R.02-01-011 and will not be addressed here. These conclusions need not be modified today but should continue to be evaluated over time, perhaps in a successor rulemaking.

8.1 PBR Incentives/Pricing Flexibility

The regulation of utility distribution networks in California currently varies widely. PG&E's distribution system is regulated under cost-of-service rate-of-return regulation. SCE's is subject to "revenue cap" regulation, which sets a revenue requirement based on a formula and makes the utility indifferent to changes in electric consumption. SDG&E remains subject to price cap regulation. Our rulemaking asked whether current PBR mechanisms contain proper incentives for the use of distributed generation and in particular, whether the Commission should create special PBR mechanisms for distributed generation, or modify existing PBR mechanisms because of the introduction of distributed generation.

8.1.1 Position of Parties

PG&E notes that it does "not now have an electric PBR in place, and does not recommend that one be designed specifically for DG."(PG&E, Phase 2 Opening Brief, p. 37.) In this area, PG&E recommends a comprehensive approach, stating:

"The design of a PBR has implications that go far beyond DG. The Commission should evaluate different PBR mechanisms in the context of a PBR that would apply to all customers, not just DG, before making a decision on the appropriate methodology or whether changes in the methodology are needed for existing PBRs." (Ibid., p. 39.)

In this particular proceeding, SCE argues that the Commission should not consider revisions to existing PBR structures except in a proceeding related to PBR's. SCE notes that "no party in this proceeding has submitted a proposal for a DG-related PBR." (SCE, Phase 2 Opening Brief, p. 30.) SDG&E argues against the adoption of a revenue cap PBR in this proceeding. SDG&E states that:

"The facilitation of the deployment of DG would be just one of many factors that the Commission might want to take into consideration in adopting the form of indexing selected for a future PBR mechanism. The Commission should not attempt to prejudge this issue in this proceeding, particularly when DG is being considered in isolation from other potential factors." (SDG&E, Ex. 76, pp. 9-10.)¹⁶

Aglet Consumer Alliance (Aglet) opposes authorization of a separate PBR or incentive mechanism dedicated to distributed generation. Aglet states "The Commission's objective should be a fair market test of DG economics and technology." (Aglet, Phase 2 Opening Brief, p. 10.) FEA states that it "strongly believes that Performance Based Ratemaking (PBR) should not be applied either to encourage the installation of DG or to deal with revenue consequences resulting from alterations in the level of use of the system as a result of the installation of DG resources." (FEA, Phase 2 Opening Brief, p. 12.)

ORA states on brief that it "has not offered any testimony on this subject [PBR], and notes that PBR proceedings themselves will discuss this issue." (ORA, Phase 2 Opening Brief, p. 15.)

TURN, UCAN, and NRDC presented Phase 2 testimony supporting a revenue cap PBR. TURN supports this position in its opening brief, noting "Rate policies that tie a utility distribution company's earnings to kilowatt-hour sales create an incentive to maximize kilowatt-hour sales." (TURN, Phase 2 Opening Brief, p. 35.) TURN also supports the adoption of an "anti-padding mechanism," to prevent the growth of ratebase through investments in either a distribution system upgrade or a distributed generation facility. NRDC supports a revenue cap form of PBR. NRDC claims that such a mechanism "breaks the link between the revenues of a distribution company and kWh sales." (NRDC, Phase 2 Opening Brief, p. 10.) In comments on the proposed decision, NRDC clarifies that it does not per se recommend a PBR mechanism but rather a mechanism that ensures that utility revenue is not tied to throughput.

California Solar Energy Industry Association (CALSEIA) opposes any restructuring of utility rates unless and until market penetration of solar electric generation reaches a significant level. When a significant level is reached, CALSEIA believes that the Commission should "consider adoption of a rate design that makes distribution utilities indifferent to the amount of throughput on their systems." (CALSEIA, Phase 2 Opening Brief, p. 17.) CALSEIA states that such rate designs "may include" PBR "based on revenue caps." (Ibid.)

The Solar Development Cooperative calls for incentives to "incorporate DG renewables" deployment onto the electricity network. (Solar Development Cooperative, Phase 2 Opening Brief, p. 20.)

8.1.2 Discussion - No Actions Needed at this Time

Regulation of utilities is in a state of flux due to instability in wholesale electric markets during 2000 and 2001. In the wake of this crisis, other Commission actions have obviated the need to adopt distributed generation specific PBR mechanisms. For example, D.02-04-055 has replaced SCE's price cap PBR with a revenue cap PBR making SCE indifferent to lost electric sales arising from either customer conservation or through the use of electricity produced by distributed generation. PG&E has never had PBR regulation, thus, while the electricity market was unstable, with the cost of procuring electricity exceeding the prices PG&E could charge for electricity, there was no incentive pushing PG&E to promote the consumption of electricity.

Only SDG&E is currently under price cap regulation. Concerning SDG&E, we agree with SDG&E that the effects of distributed generation are likely small at this time, and there is no need to change its PBR program now. Moreover, since SDG&E's PBR is scheduled to expire at the end of 2002, there is no need to change this program for the few months that remain.

The TURN/ORA/UCAN proposal of establishing "project caps" for each proposed distributed generation project is not needed at this time, because each project undertaken by the utilities will be subject to review in the next GRC. For these reasons, we see no reason to modify existing PBR programs or to implement a program specific to distributed generation investment.

This conclusion does not prejudge how or if distributed generation is incorporated into any renewable incentive mechanism considered in R.01-10-024.

8.2 Public Purpose Program Funding

Public purpose programs are activities not directly required to provide utility service, like funding for renewable power sources, research and development, and low-income assistance, that the Legislature or the Commission have determined to be socially desirable and in the public interest. Funding for these programs is part of the rates charged to all customers.

California law dictates that exiting the public electric network does not end a customer's responsibility to provide financial support for public purpose programs. In particular, Cal. Pub. Util. Code §§ 381-382 makes low-income and certain other public interest programs "nonbypassable." As implemented, customers departing for distributed generation must continue to pay for these programs, thereby avoiding unwarranted cost shifts to other ratepayers.

8.2.1 Positions of Parties

PG&E supports the "nonbypassability" of public purpose program charges and urges the Commission to reconfirm this policy. (PG&E, Phase 2 Opening Brief, p. 40.) SCE similarly states that "it is permissible and appropriate to require DG customers to pay the full amount of non-bypassable charges based on their total energy consumption." (SCE, Phase 2 Opening Brief, p. 30.) SCE points out that it currently collects these charges from standby customers through its tariffs. SDG&E believes that "deployment of DG should have little or no impact on public purpose program funding assuming current laws and Commission-approved tariffs remain in effect." (SDG&E, Phase 2 Opening Brief, p. 35.) SDG&E notes that current tariffs provide for the recovery of public purpose program funds associated with customers choosing to self generate.

ORA's position is that distributed generation might have an impact on public purpose funding, but it should not. ORA supports decoupling public purpose program funding from energy "throughput." (ORA, Phase 2 Opening Brief, p. 15.)

NRDC notes the legislative support for a nonbypassable surcharge for the public purpose programs, and states that it is "appropriate to continue to apply this charge to all new on-site generators (based on output) located on the customer side of the meter that provide power to offset the customer's consumption." (NRDC, Phase 2 Opening Brief, p. 11.) On the other hand, NRDC recommends that an "exception should be made for building-integrated PV systems and projects operating under the net metering tariff." (Ibid.)

Aglet supports the inclusion of a "fair share of public purpose program funding" in standby rates. (Aglet, Phase 2 Opening Brief, p. 10.) Aglet, however, recommends that the Commission support the recovery of these program costs in the long run through taxes, and notes that Aglet "does not support imposition of public purpose bypass charges on customers solely because they depart the utility service." (Ibid., citing RT 1632:13-22.)

Latino Issues Forum and Greenlining Institute (jointly, LIF) state that the "Commission should seek to codify utility tariffs that authorize the collection of public purpose program funds from departed customers." (LIF, Phase 2 Opening Brief, p. 5.) LIF opposes the use of a tax to finance public purpose programs, and opposes the collection of the costs of public purpose programs through a one time "exit fee." (Ibid., p. 7.)

CALSEIA, in contrast, does not support the use of a nonbypassable surcharge to fund public purpose programs. Instead, CALSEIA supports public purpose program funding through "usage based electricity charges." (CALSEIA, Phase 2 Opening Brief, p. 17.) It notes that solar customers "typically draw a significant percentage of their total demand from the grid." (Ibid.) Thus, it sees no threat to public purpose program funding by any "foreseeable increase in the deployment of distributed solar generation." (Ibid.) In short, CALSEIA sees no problem at this time, and therefore no need to collect public purpose program charges through a nonbypassable surcharge.

Similarly, the United States Department of the Navy and All Other Federal Executive Agencies (FEA) states that "customers should not be required to pay public purpose funding surcharges on services that they do not take from the utility." (FEA, Phase 2 Opening Brief, p. 13.) Instead, FEA recommends "adjusting the rate used to collect these charges" in order to ensure funding. (Ibid., p. 14.)

8.2.2 Discussion

Pub. Util. Code §§ 381-382 make low-income and certain research and development programs "nonbypassable" and consequently shape our policy on this matter. In particular, we agree with the commenters that, pursuant to statute, the public purpose program surcharge should be nonbypassable. As SDG&E notes, current tariffs already provide for the recovery of these surcharges from any customer who self-generates, whether in conjunction with distributed generation or simply for economic purposes.

Beyond affirming our support for the legislatively-mandated nonbypassable public purpose program surcharge, we conclude that there is no need to take further action at this time. In particular, we decline to take a position supporting tax legislation as Aglet requests. Similarly, we also note that we have no intention at this time of converting our ongoing surcharge to a one-time exit fee, but instead plan to continue our current tariff arrangements, a policy supported by LIF.

8.3 Localized/Deaveraged Rates

This rulemaking posed the question of whether distribution rate components should be deaveraged to reflect localized differences in costs. Traditionally, average rates provide all consumers in a rate class with an equal cost structure for distribution services, regardless of the varying costs of serving a specific location.

8.3.1 Positions of Parties

PG&E, SCE, and SDG&E oppose area-specific distribution rates. In particular, PG&E states "a change to area rates for all customers could have extraordinarily far-reaching implications, above and beyond the effects of the limited changes sought by participants in this proceeding." (PG&E, Phase 2 Opening Brief, p. 44.) PG&E believes that following the "TURN/UCAN/NRDC suggestion regarding project-specific solicitations" offers a reasonable approach to solving the problem of geographic divergent costs. (Ibid.)

SCE believes that "implementation of geographically deaveraged distribution rates is fraught with practical problems and implicates many fundamental policy questions." (SCE, Phase 2 Opening Brief, p. 31.) SCE notes that deaveraged rates are generally unstable, can be viewed as discriminatory by customers, and would require significant expenditures to change current billing systems. SCE further notes that the Commission "has previously determined" that "it would be inefficient to offer a geographically deaveraged credit when underlying rates are still averaged." (Ibid., p. 32, citing D.98-09-070 (mimeo.) p. 25.)

SDG&E opposes deaveraging distribution rates, which it states "would accomplish relatively little . . . at a great administrative burden." (SDG&E, Phase 2 Opening Brief, p. 36.) SDG&E, however, views the provision of credits to distributed generation "at the right time, in the right location, of the right size and with physical assurance" in a contract as a valid policy approach for solving the locational problems associated with distributed generation. (Ibid., p. 37.)

Similarly, TURN, ORA, Aglet, and FEA oppose deaveraging rates. TURN notes that the locational credit proposal submitted by TURN, UCAN and NRDC "is not equivalent to deaveraged ratemaking." (TURN, Phase 2 Opening Brief, p. 47.) On the other hand, TURN supports a "locational credit" that "would provide for a location- and time-specific sharing of cost-savings associated with distributed generation that serves a distribution function and avoids certain distribution costs." (Ibid., p. 44.) TURN believes implementing a credit in an effective way requires "a fair and transparent distribution planning process." (Ibid., p. 41.) ORA states that "[d]istribution rate components should not be deaveraged at this time to reflect localized differences in costs." (ORA, Phase 2 Opening Brief, p. 16.) ORA believes that deaveraged rates are "contrary to long-standing policy." (Ibid.) Like TURN, ORA supports offering credits to specific customers or third parties if the incentives can defer the need for localized distribution expenditures. FEA opposes deaveraging rates, but, states that "to the extent that there are areas of the system where the utility would find it uneconomical, or expensive, to expand the distribution system to accommodate load requirements, these areas could be specifically targeted for incentives to install DG." (FEA, Phase 2 Opening Brief, p. 14.) Aglet opposes localized or deaveraged rates as "contrary to the important societal objective of universal service." (Aglet, Phase 2 Opening Brief, p. 10.)

Those supporting localized deaveraged rates generally argue that they will prove more efficient. The supporters of this position include the City and County of San Francisco (CCSF), State Consumers,¹⁷ New Energy/Capstone,¹⁸ CALSEIA and NRDC. CCSF supports the development of "localized/deaveraged rates and credits to provide for a locational sharing of benefits associated with DG when it helps to avoid or delay distribution costs." (CCSF, Phase 2 Opening Brief, p. 8.) State Consumers state that "standby pricing for distribution should be based on the area-specific marginal costs, capped at existing distribution costs." (State Consumers, Phase 2 Opening Brief, p. 9.) State Consumers believe that such a policy will lead to lower standby rates because "standby customers drive minimal distribution resource additions." (Ibid., p. 10.) Similarly, State Consumers support the use of credits and incentives based on location.

New Energy/Capstone support deaveraged rates, stating that "distribution costs vary significantly by location, and those variation should be clearly signaled to incentivize customers to help minimize UDC costs where they can." (New Energy/Capstone, Phase 2 Opening Brief, p. 21.) However, noting that full geographic deaveraging presents challenges, they support a tariff approach with "rate riders or credits" to "signal the cost of local distribution expansion, and opportunities to reduce them." (Ibid., p. 22.)

CALSEIA "recommends that the Commission consider the adoption of financial incentives in the form of geographically de-averaged buyback rates to reward the installation and operation of on-site solar facilities in designated areas with high distribution costs." (CALSEIA, Phase 2 Opening Brief, p. 17.) NRDC "supports the development of a locational credit mechanism that would provide for a location- and time-specific sharing of benefits. . ." (NRDC, Phase 2 Opening Brief, p. 11.) In addition, NRDC supports the "exploration and identification of distribution development zones." (Ibid., p. 12.) In comments on the proposed decision NRDC clarifies that they do not support deaveraged rates.

8.3.2 Discussion: Contracting for Distributed Generation Obviates Need for Deaveraged Tariffs or Incentive Programs at This Time

Since we are permitting utilities to enter into contracts with customers or third parties that install distributed generation at the right time, in the right location, of the right size and with the physical assurances needed to enable a utility to defer a distribution capacity addition, we see no need for deaveraged tariffs or other incentive programs. We retain most of the efficiencies that deaveraged tariffs promise, yet avoid the complications of reversing the long-standing policy of uniform pricing.

Our administrative experience and the comments of parties makes it clear that geographically-deaveraged distribution rates are fraught with practical implementation problems. Similarly, administering a localized incentive or credit program while maintaining geographically averaged rates offers a piecemeal approach that invites tariff arbitrage and other regulatory problems. Finally, we note the Commission has long used average rates as an equitable means of providing universal and non-discriminatory service. We see no reason to change our current policy.

8.3 Implementation Costs

Implementation costs are those costs associated with implementing a new program. The question then becomes, what costs are implementation costs associated with distributed generation, and which are costs already covered under current distribution system planning budgets.

8.4.1 Position of Parties

The three utilities express particular concerns with implementation costs. PG&E states that "[a]ny implementation costs incurred to accommodate DG should be tracked in a separate balancing account." (PG&E, Phase 2 Opening Brief, p. 13.) These costs, in PG&E's view, should be recovered "through a general charge assessed on the beneficiaries of the particular programs." (Ibid.) SDG&E argues that "if implementation costs are attributable to individual customers deploying DG, the costs should be recovered from those individual customers. . ." (SDG&E, Phase 2 Opening Brief, p. 10.) On the other hand, "if implementation costs are not directly attributable to any one customer or group of customers, SDG&E would propose to collect such costs from all distribution customers." (Ibid.) SCE proposes that implementation costs "should only refer to those costs that the UDC incurs due to activities mandated by this Commission." (SCE, Phase 2 Opening Brief, p. 10.) SCE cautions the Commission against mandating any particular costs, such as requiring SCE to provide educational or engineering advice to prospective distributed generation customers. Further, SCE argues that implementation costs "should not refer to physical plant additions for a specific customer to utilize DG." (Ibid, p. 10.) SCE believes that these facility costs should continue to be administered through tariffs, but if the costs from mandated changes become large, SCE argues that the Commission should establish a separate recovery mechanism for these costs.

Enron states that "costs incurred to interconnect a specific DG installation should be assigned to that customer." (Enron, Phase 2 Opening Brief, p. 2.) On the other hand, Enron argues that implementation costs "that cannot be ascribed to a specific (or group of) customer(s) should be recovered through general distribution rates." (Ibid., pp. 2-3.) FEA states that "[a]ny implementation costs that are not appropriately chargeable to individual customers should be considered network costs and be recovered in charges for secondary service, primary service, subtransmission service, and/or transmission voltage level service as applicable." (FEA, Phase 2 Opening Brief, p. 5.) FEA, however, considers these costs as "no different than how other general network expansion, upgrade, or replacement costs are handled." (Ibid.)

In contrast to these positions, TURN and Aglet express skepticism that any distributed generation implementation costs warrant recovery. TURN "strongly opposes proposals for establishing a balancing account to track implementation costs as suggested by PG&E and SCE." (TURN, Phase 2 Opening Brief, p. 14.) TURN notes that no utility has identified specific implementation costs that are not already covered in existing charges. It further states that "[i]f costs are associated with particular system investments, then they should be recovered through rates and interconnection charges." (Ibid., p. 13.) Aglet states that the "Commission should reject any special recovery of DG costs." (Aglet, Phase 2 Opening Brief, p. 3.) Aglet argues that costs associated with a program like this are among those that are typically covered under the overall cost umbrella of a GRC. Aglet further notes that the "low level of DG market penetration forecast for the near future also supports denial of utility requests for special implementation funding." (Ibid., p. 4.) In addition, Aglet argues that these costs are related to competition, and that the Commission has frequently rejected utility requests for additional revenues to reflect the effects of competition. In the long term, Aglet concludes that "the Commission should consider DG implementation costs in general rate cases, as it considers other distribution costs." (Ibid., p. 5.)

8.4.2 Discussion

Since the purpose of this rulemaking is "is to develop policies and rules to facilitate deployment of distributed generation in California," (D.02-03-057) we authorize the creation of memorandum accounts to track distributed generation implementation costs that cannot be attributed to a specific distributed generation projects. These could include, for example, the costs of a distributed generation education program, major changes in the utility planning process necessitated by this decision, or some other subsidy to a general distributed generation program.

As TURN, Aglet and FEA have indicated, the costs of implementing the distributed generation policies adopted herein will likely be small. In addition, to ensure the eventual incorporation of distributed generation into routine utility operations, we will set these memorandum accounts to expire unless continued at the next GRC for each company. At that point the Commission can consider whether to incorporate a special revenue requirement into the distribution system to finance distributed generation or continue with a memorandum account system.