7. Discussion and Summary of Adopted Standby Rate Design Framework

In this decision, we must determine whether we should modify the Commission's existing standby rate design for customers who utilize onsite generation for some or all of their electricity requirements. We briefly review the policy goals we identified in this Rulemaking. An April 14, 2000 Ruling addressed the scope of the Phase 2 portion of the proceeding, and directed that rate design and ratemaking policies submitted in this proceeding should:

1) provide for fair cost allocation among customers;

2) allow the utility adequate cost recovery while minimizing costs to customers;

3) facilitate customer-side distributed generation deployment; and

4) send proper price signals to prospective purchasers of distributed generation.

With these goals in mind, we focus on the major issues in the standby rate design portion of the case: the nature of the costs to serve standby customers; different types of standby service; whether costs of standby service should be recovered through fixed or usage-based rates; how to reflect diversity in rates; interruptible rates; credits for reliability; and other optional rate designs such as area and/or time-specific rates. In doing so, we fulfill our goal, supported by all parties, that there be consistency in the design of standby rates for all California utilities. As we adopt policies to address each of these issues, we keep our original goals in mind, and the understanding that unjustified standby charges for onsite generating facilities will discourage development of new generating capacity. In addition, we hope that the policies we adopt will lead to clear, understandable and administratively feasible standby rates. Because the standby rates design policies we adopt herein are cost-based, implementation of these policies will not result in "stranded costs"¹⁶ and thus we have not addressed the stranded cost proposals addressed in the Phase 2 testimony and briefs.

We find that most of the distribution system costs to serve standby customers are fixed. For example, distribution infrastructure investments are lumpy in nature. Traditional distribution system upgrades and extensions are generally installed in increments that provide system flexibility if growth exceeds projects, but could also risk over-building if load does not materialize. Typical increments of capacity needs are in the 1 MW range. (Distribution System Operations and Planning Workshop Report, p. 41.)

However, if a customer is willing to provide physical assurance, it is clear that infrastructure costs associated with serving that customer will either be very limited or nonexistent. By agreeing to provide a physical control to remove load if its distributed generation unit is not operating, the utility does not need to build distribution infrastructure to serve that customer, thus avoiding fixed costs. When a customer is willing to provide physical assurance to the utility, that customer should not have to pay for any fixed costs associated with distribution service and should have the ability to opt out of standby service entirely or only take maintenance or non-firm service on a volumetric basis.

In those cases, the customer should be able to enter into a contract, similar to SDG&E's Form Contract 2 (see Ex. 72, Attachment 2) to specify the capacity for which it will provide physical assurance.¹⁷ The customer should not pay standby charges designed to recover the fixed costs associated with distribution service for the amount of capacity it provides to the utility with physical assurance. Because a customer does not cause infrastructure costs to be incurred when it provides physical assurance, it is consistent with cost causation principles that it not be charged for infrastructure costs.

If a customer is not willing to offer such physical assurance, the utility must construct infrastructure to ensure that load from a customer taking on-demand backup service can be served. Therefore, it is appropriate for those costs to be recovered from backup customers.

CAC/EPUC contend that different types of service impose a different set of costs on the utility and that these separate costs should be reflected in the standby rate design. Since supplemental power provided to customers with distributed generation is no different than power provided to a customer without distributed generation, we agree that there is no policy reason why supplemental power should be priced differently than full requirements power. We recommend that supplemental power continue to be priced according to the customer's otherwise applicable tariff.

We agree with parties such as CAC/EPUC and FEA, who request that standby rates appropriately reflect the reduced cost of providing services such as backup and maintenance service compared to supplemental service. In order to recognize the cost difference between supplemental power and backup power needs, we will require that the utilities reflect diversity in the standby reservation charges, as discussed below. Unlike supplemental power or full requirements service, service associated with backup and maintenance power is intended to be intermittent in nature. Backup service should be allocated a greater share of costs than maintenance service because it is an on-demand service and has distribution infrastructure requirements associated with it.

Maintenance service is arranged at a time when capacity is already available, so the utility will not need to build infrastructure to meet maintenance power loads assuming the customer provided physical assurance. This characteristic should significantly reduce the amount of fixed costs allocated to support maintenance service, thus reducing the reservation charges. While utilities must plan for and reserve transmission and distribution capacity to meet supplemental load at all times, it is not necessary to reserve the same amount of capacity to meet backup loads.

We share the parties concern regarding the need to be able to identify and elect backup reservation capacity. Distributed generation customers are in the best position to determine how much backup reservation capacity they are likely to need. The parties are concerned that utilities may overestimate the necessary backup reservation capacity for standby customers. If a distributed generation customer has underestimated the necessary backup reservation capacity, and relies on the grid in excess of its reservation capacity in a given billing period, the reservation capacity should be adjusted to reflect this increase. Because of the length of time needed for planning and construction of distribution capacity, the increased backup reservation capacity should remain in effect for at least a year, unless there are further increases.

We agree with ORA, TURN, FEA and other parties, that it is possible to estimate the probability of multiple distributed generation units being out of service simultaneously and that this estimate should be reflected in standby rate design. This is called the diversity factor. While it is clear that the utility must supply all of a full requirements customer's expected demand at all times, it is also clear that the utility must only supply a standby customer with backup and maintenance power occasionally, since the standby customer supplies his own requirements most of the time. PG&E's witness agrees that the diversity on a distribution circuit can affect its distribution costs (PG&E: Pease, RT 1081) and that it is not always necessary to provide standby power 100% of the time. (Id. At 1080.)

We find that there are well-supported arguments that diversity reduces transmission and distribution infrastructure requirements. The utilities arguments fail to demonstrate that the utility must, in all cases, reserve capacity equivalent to 100 percent of the potential load associated with customers possessing distributed generation units if there is some diversity on the transmission or distribution system. Therefore, we find that the utility should continue to take diversity into account when calculating standby charges for backup service. Diversity reduces necessary distribution investment, but does not affect variable costs, which are incurred only when load is imposed on the system. Therefore, diversity factors need only be applied to charges that recover fixed costs.

PG&E and SDG&E have raised valid concerns regarding the potential for differences in the diversity on the transmission system compared to the distribution system. We expect that parties in the rate design applications filed pursuant to this decision will provide further support for their positions on this issues. The exact determination of a numerical value for diversity for each utility is not at issue here. Pursuant to the scoping decisions in this rulemaking, the calculation of the utility-specific diversity factors will not be determined in this decision, but in each utility's individual ratemaking proceeding. We do not require the utilities to separately calculate diversity factors for the transmission and distribution level interconnected generation in this decision, but will consider such proposals if supported by studies of diversity at various voltage levels.

We reject PG&E's request to make a finding that its current diversity factor is inappropriate for distributed generation connected at distribution voltage. This request is beyond the scope of this proceeding. The record in this proceeding does not include the evidence necessary to determine whether or not a utility's diversity factors should be increased or decreased relative to its current level. However, we do provide guidance about developing diversity factors. The utilities should propose diversity factors assuming various levels of penetration of distributed generation. In order to ensure that standby rates do not inhibit deployment of distributed generation, we intend to adopt a diversity factor assuming a distributed generation deployment level that is higher than exists today. It is through adoption of this diversity factor that backup customer will realize a lower rate than full requirements customers.

Certain parties have linked diversity and physical assurance. In particular, SDG&E argues that unless distributed generation is installed under one of its two proposed Form Contracts, or is installed with physical assurance, standby rates for distributed generation should recover the same amount of revenues for distribution from the customer with or without the operation of the distributed generation unit. We reject this argument. Parties have demonstrated that diversity exists on the distribution system without physical assurance. We will not require physical assurance for purposes of calculating diversity factors.

There is no persuasive reason to require customers to pay for charges that are not incurred, just as there is no persuasive reason to excuse customers from paying for charges incurred on their behalf. We agree that if costs associated with maintaining distribution and transmission facilities to serve diversified standby load are fixed, those costs are appropriately reflected in fixed reservation or demand charges. We reject Capstone's argument that fixed charges create an inefficient price signal because no action by the customer can avoid or reduce these charges. We find that if costs are fixed and unavoidable by the utility, a fixed charged is an efficient price signal. To the extent that there are costs that do vary with usage, those costs should be reflected in a usage-based charge.

As we analyze proposed rate design options, it is helpful to keep in mind that all parties recommend that standby rate design be cost-based. Assuming that a usage-only standby rate is intended to recover the total cost associated with providing standby service, the usage-only rate would necessarily need to recover more costs over fewer increments of usage and must therefore be set higher. Moreover, in any given month, with a usage-only fee, a customer with a distributed generation unit who required no standby service during that month would potentially pay no standby charges at all. In that month, assuming that the total fixed cost of providing distribution service does not change, the cost associated with providing standby service to that customer would be shifted to other customers. Conversely, a distributed generation customer that requires frequent standby service will contribute a significantly higher amount. Under this type of rate design, both units would pay the same rate, but distributed generation units that are more reliable would pay less than the cost to serve them. Similarly, less reliable distributed generation units would pay more for the same amount of reserved capacity. This type of rate design would result in inequitable cost allocation within the customer class.

A reservation fee only proposal would also allow customers a choice in payment terms. The reservation fee only proposals would allow customers to levelize their standby charges over an extended period of time, paying a fixed amount each month for a certain level of service. The reservation fee only proposal have appeal if one could be designed and presented in a manner that is consistent with our goal of cost-based rates. Unfortunately, none of the proposals presented in this rulemaking contained sufficient detail for us to evaluate it on this record. Therefore, we decline to consider a reservation fee only proposal at this time.

Standby rates should be designed to appropriately reflect costs imposed on the utility system by all customers, including those employing onsite generation. Ideally, a fixed standby reservation charge should be based only on infrastructure costs that do not vary with usage. Standby customers with onsite generation who sign up for backup service should be charged a $/kW reservation charge for their reserved capacity. The reservation charge should reflect the distribution infrastructure costs that do not vary with usage. In addition, backup standby rates should include a volumetric rate, based on actual usage, that collects variable distribution costs. Public purpose costs are collected volumetrically under current rates. We will continue to recover public purpose costs from standby customers through a $/kWh usage charge. Maintenance customers and others whose use of the distribution system is on an as-available basis, should be charged a volumetric rate, based on usage, that recovers variable distribution costs.

We are concerned that some elements of generation capacity and energy charges still remain bundled in the standby tariffs. It is in the interest of all customers, standby and full service alike, to ensure that standby charges collect only the costs associated with providing standby service. Standby rates should remove any charges not associated with providing distribution standby service. That includes any generation capacity or energy charges that may presently be bundled with and collected through standby rates. Instead, the utilities should develop an electricity procurement rate option, which may be a real time price, that will be paid by standby customers when the utility procures electricity on their behalf. If allowed under state law, standby customers should also have the option to procure electricity to serve their backup or maintenance supply from a third party.

We agree that the Commission has a responsibility to enforce § 372(f). The ISO's proposed gross metering policy has implications extending well beyond the immediate rate design of standby charges. To the extent that transmission charges recover fixed costs, they may be recovered through reservation charges. Variable transmission charges should be recovered through variable rate components. To the extent a customer with distributed generation offers physical assurance, no fixed transmission costs should be recovered from that customer. This approach should ensure the CA ISO of recovery of fixed costs without the customer burden of gross metering. Therefore, at this time, we will not support the CA ISO's gross load metering policy.

We agree with parties who support interruptible standby service in order to provide customers with more choices during peak periods. Standby customers willing to forego energy use during peak periods should receive the same options as customers without distributed generation. Parties who support an interruptible standby option concurrently oppose the utilities' desire for physical assurance to ensure that the delivery system will not be called upon. Utility system planners would prefer a policy that guarantees customers will not demand standby during distribution system peaks. Non-firm/interruptible service taken by customers without distributed generation serves as a source of supply during times of peak load. When a customer has a distributed generation facility, it will generally be serving its own load and not relying on the distribution system. If that distributed generation customer provides physical assurance, it will not have to pay reservation charges under today's adopted policies. Non-firm standby service then becomes similar to maintenance service-load can be imposed on the system on an an-available basis at non-peak times. The utilities should propose non-firm standby rate options that recover only variable costs of distribution service from customers who offer physical assurance.

Without prejudging the outcome of our Phase 1 decision, we believe several benefit valuation proposals have merit and contain ideas for future consideration. In particular, we note agreement by several parties that SDG&E's Form Contract proposal could be used as a basis to determine certain incentives or credits for curtailment resulting in deferred utility distribution investment. However, at this time, we believe distributed generation standby service is separable from the question of whether distributed generation provides grid benefits. A distributed generation customer taking standby service may not necessarily provide measurable grid benefits. Likewise, a distributed generation customer providing grid benefits may elect not to take standby service. We believe the diversity factor included in the unbundled standby rates we adopt today appropriately accounts for lowered costs of distribution capacity deferred due to increased distributed generation deployment. Therefore, we will not incorporate a valuation methodology into standby rate design. Consistent with the schedule adopted in the January 19, 2000 Scoping Memo, we will consider the need for a valuation system of distributed generation benefits to the grid in our Phase 1 decision, and consideration of locational credits, time-of-use rates and SDG&E's Form Contracts in the Phase 2 decision.

We are not convinced that standby customers are allocated the proper share of costs on a cost causation basis. State Consumers demonstrated that PG&E's standby customers were allocated responsibility for 38% of total costs in 1999, but accounted for only 0.25% of system peak energy use. From the evidence, we cannot determine whether the costs allocated to standby customers were for fixed costs associated with on-demand backup service or other services. Therefore we cannot conclude decisively whether this cost allocation overcollected revenues from standby customers. Nevertheless, the statistic is shocking and certainly argues for a reexamination of the allocation of costs to standby customers. In the standby rate design applications ordered herein, the utilities should review and revisit, if applicable, the costs allocated to standby customers as they develop rates consistent with this order. We agree with Aglet that standby charges should be based on embedded, not incremental, costs of service, consistent with the manner in which rates are calculated for other distribution services. We will adopt new standby rates consistent with the correct cost allocation, consistent with this order. This may result in some temporal cost recovery concerns since other distribution rates will not be adjusted contemporaneously amongst all customer classes for any new cost allocation. The utilities should propose ratemaking approaches to address any temporal inequities associated with their recommended cost allocation in the applications ordered herein.