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, and there is no evidence that distributed generation deployment will soon cause significant stranded distribution costs, implementation of these policies will not harm the utilities.¹⁶ 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 appear to be fixed in nature. 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.)

In comments on the proposed decision, SCE distinguishes between different types of distribution infrastructure costs. SCE describes facilities-related costs as poles and wires, which it believes are fixed and independent of usage. SCE then describes peak demand-related (or capacity-related) infrastructure costs such as substation capacity and transformation costs as variable in nature. We agree that such a distinction is useful as we discuss standby rate design. The record in the case is insufficient to determine specifically which costs are fixed and which are variable.

However, if a customer is willing to provide physical assurance, it is clear that both facilities-related and peak demand-related 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 either type of 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 facilities or peak demand-related 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 comments on the proposed decision, SCE argues that physical assurance alone will not allow the utility to avoid facilities-related costs unless the customer commits that load normally served by its own generator will drop if the generator trips. As we described in footnote 2, our definition of physical assurance incorporates just the concept described by SCE as an additional requirement above and beyond physical assurance. Therefore, we see no need to add additional language to this requirement as recommended by SCE.

State Consumers argue in their comments on the proposed decision that we should allow for financial penalties, rather than physical assurance, to ensure that distributed generation is in place during peak periods. State Consumers argue that financial penalties have long been recognized as appropriate to support performance of contract provisions. State Consumers argue that the cost of equipment to accomplish physical assurance could make a distributed generation investment uneconomic. We disagree. As pointed out by both PG&E and SDG&E in reply Comments, recent experience with the utilities' interruptible programs shows that customers may choose to pay a penalty, rather than curtail load, absent physical assurance. Our decision to require physical assurance derives from our balancing of the cost impacts associated with requiring physical assurance, against the possible impacts associated with non-performance under the "no physical assurance" scenario. If a generator without physical assurance does not perform and no facilities are in place to handle that load (as would be appropriate based on the rate design principles we adopt today), the distribution circuit can overload resulting in outages and possible property damage. We are not prepared to take this risk and thus require physical assurance for customers to take advantage of reduced standby rates.

In cases where a customer opts out of standby service or takes only maintenance or non-firm service, 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 As suggested by SCE in comments, the Form Contract should address proper remedies for failure to perform, but we will not specify such provision today. As suggested by PG&E, the Form Contract should establish a minimum notification period before which physical assurance devices could not be removed. The customer should not pay standby charges designed to recover the facilities- or peak demand-related 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 or continue to operate existing facilities 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.

Different Types of Standby Service

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 reductions in the cost of providing services such as backup and maintenance service when these reductions occur. By contrast, there will not be cost reductions related to supplemental service. In order to recognize the cost difference that may sometimes exist between supplemental power and backup power needs, we will require that the utilities reflect any actual 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 either facilities-related or peak demand-related 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. As SCE clarifies in its comments on the proposed decision, a maintenance customer will also avoid peak demand-related costs.

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 immediately 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.

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 its 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.) The utility would no more need to build sufficient facilities to anticipate simultaneous failure of all onsite generators than it would need to anticipate that at one moment, every lamp would be lit, every hairdryer would be running on high, and every iron would be hot.

PG&E and SDG&E raise valid concerns regarding the potential for differences in the diversity on the transmssion system compared to the distribution system. However, as PG&E also points out, because there are relatively few distributed generation units connected at distribution voltage, there is virtually no diversity on individual distribution circuits today. Thus, it is reasonable that, in the near-term, each distribution utility would plan its distribution facilities without taking into account the potential benefits of onsite generation diversity. Standby rates should reflect this reality. To do otherwise would be to adopt a policy of promoting distributed generation at the expense of all utility ratepayers.

Based on the records developed in this proceeding we cannot determine whether any diversity exists for generators connected at distribution voltages. In their applications for new standby rates, the utilities should report on the extent of diversity based on actual deployment of onsite genertion on the distrigbution system and propose a diversity factor, if appropriate.

We note that CAC/EPUC suggests that a failure to adopt a diversity factor would violate federal law. Apparently, CAC/EPUC is referring to 18 CFR 292.305(c)(1), which states that standby rates for qualifying facilities "shall not be based upon an assumption (unless supported by factual data) that forced outages or other reductions in electric output by all qualifying facilities on an electric utility's system will occur simultaneously..." In concluding that diversity factors should not apply to the calculation of standby charges at this time, we make no such assumptions about system-wide generators (i.e. those connected at transmission voltages). Rather, we focus on generators connected at distribution voltages. While many distributed generators might still be operating elsewhere in the utility system, there is still a need to meet load in the absence of generation on a given distribution circuit. Standby charges should reflect the cost of providing this reliability.

Different Types of Standby Rates

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, et al.'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, including peak demand-related costs, 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 proposals 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 facilities-related 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, including peak demand-related costs. 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 but does not include peak demand-related infrastructure costs. A customer's maintenance schedule should be coordinated with the utility to ensure that its use of the system corresponds to the peaking characteristics of its distribution circuit.

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. GI/LIF, TURN, and PG&E all address this aspect of the proposed decision in their comments. These parties recommend that public purpose charges be assessed on distributed generation customers total load, including load served by an onsite generator. Our decision today is not intended to dispose of the issue of how public purpose costs should be collected from distributed generation customers, but simply to recognize that currently, standby customers pay for public purpose costs volumetrically and should continue to do so. There was extensive testimony, cross-examination, and briefing on how to ensure that all energy users pay their fair share of public purpose costs and we will address these issues on their merits in the Phase 2 order.

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 support the concept of 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. However, it is unclear how useful such an option would be to customers. 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. In comments on the proposed decision, SCE raises numerous implementation issues surrounding interruptible standby service. We find these arguments sufficiently persuasive to provide utilities the option, rather than the requirement, to develop a non-firm standby rate. The utilities may propose non-firm standby rate options that recover only variable costs of distribution service from customers who offer physical assurance.

Valuation

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. We further agree with SDG&E that the utility should be authorized to provide credits to customers when distributed generation is installed at the right time, in the right location, of the right size and with physical assurances, such that the utility is able to defer a distribution capacity addition. 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. At the same time, we are not persuaded by TURN's suggestion that a value of distributed generation will be a reduction in wholesale electric prices. There is no evidence that, in the current market structure, lower demand will effectively reduce wholesale prices. 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.

Cost Allocation

We are not convinced that standby customers are allocated the proper share of costs on a cost causation basis. From the evidence, we cannot determine whether 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, which 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 may 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.