5. Positions of the Parties

Phase 2 testimony was submitted on July 3, 2000. Circumstances then were quite different from those we face today. Many parties reference the Power Exchange and other entities that may no longer function in the same capacity, or indeed, may no longer exist. We present the positions of parties within the context to which testimony was originally served in order to retain the relevant value of the concepts and proposals, recognizing that certain specific references may no longer apply. Not every party that served testimony addressed standby rate design; we limit our summary of the positions to the standby rate design issue.

5.1 Pacific Gas and Electric Company

PG&E summarizes its position in this proceeding by stating that standby rates for distributed generation customers should reflect the full cost of service, just as charges for all other customers must reflect the full cost of service. PG&E states that standby rates should continue to contain: 1) a contract reservation charge; 2) a kWh based distribution charge for backup service8; 3) an energy (i.e. commodity) charge; 4) a customer charge; and 5) a reactive demand charge. PG&E's current Schedule S combines the kWh-based distribution charge, the energy charges, and the nonbypassable customer charges in the "energy charges" portion of its tariff.9 PG&E's kWh-based distribution charge is intended to ensure that standby charges are based, in part, on frequency of use in order to provide assurance that customers with non-operating generating plants do not sign standby contracts simply to get the lower reservation charges, rather than the full requirements demand charges.

PG&E's customer charge would recover distribution-related costs including metering, service connection, and customer service costs that are not avoided by a customer's election to meet some or its entire load with distributed generation. The customer charges would be the same as those on the otherwise applicable rate schedule, based on the reservation capacity. PG&E would maintain the current standby service reactive demand charge as an incentive for customers to fully provide reactive current requirements associated with the load being served by distributed generation.

PG&E maintains that today's distribution level standby charges are too low for three reasons. First, because there are relatively few distributed generation units connected at distribution voltage, there is virtually no diversity on individual distribution circuits. PG&E states that while such diversity exists at the transmission level, it does not currently exist at the distribution level. PG&E argues that while the 38% diversity factor embedded in PG&E's current standby charges accurately reflects the cost to serve standby customers served at transmission voltage, this diversity factor significantly overstates the level of generation diversity for customers connected at distribution voltage. Second, distribution planners cannot presume that a given unit will operate at the times needed for system reliability. Third, because of lack of diversity, PG&E must plan to serve all standby load on a circuit in the event of a circuit outage and therefore it incurs distribution infrastructure costs to serve that load, even if distributed generation is installed.10

PG&E does not object to using a distribution level diversity factor to set standby rates, so long as the factor employed matches the extent to which generation diversity actually permits the utility to avoid building distribution upgrades. PG&E recommends that standby rates for distribution level customers be revised to reflect the actual costs caused by such customers.

PG&E also opposes proposals that would offer lower rates for infrequent use associated with more reliable distributed generation units. PG&E believes that the primary problem with these proposals is that they propose to collect less revenue than current rates without reducing the cost of providing the service. If the utility is standing by with distribution facilities that must be available to provide service at all times, then the amount of wires reserved for such service is the same whether the customer calls on those lines 10 hours per year or 1000 hours per year. PG&E currently offers separate, lower-cost options for maintenance power since maintenance power can be scheduled over weekends and during the winter season when the volumetric components of the rate are significantly lower. PG&E does not believe any further incentive for scheduled maintenance is necessary or required.

Finally, PG&E believes that standby customers should also continue to pay nonbypassable charges for public purpose programs, nuclear decommissioning, and transition costs, unless an exception applies.

5.2 Southern California Edison Company

SCE opposes any efforts to depart from efficient, cost-based rates to "facilitate" distributed generation deployment. Reflection of truly fixed costs to serve standby customers in variable energy charges is inefficient because it allows these customers to avoid paying their fair share of fixed costs. The Commission's rate design policies should follow sound economic principles rather than be predicated on providing subsidies to customers to promote the installation of distributed generation. SCE argues that there is no cost-based justification for reducing standby distribution rates to reflect alleged system-wide capacity benefits. SCE asserts that standby rates do not, and should not, relate to commodity energy. Furthermore, SCE argues, even if one could establish that generation capacity benefits are derived from distributed generation, there is still no justification for reflecting such benefits in distribution charges.

SCE recommends that the goal when designing standby charges should be "to achieve rates which reflect the costs the customer imposes on the system." (SCE Opening Brief-Phase 2, p. 11, citing D.96-04-050.) SCE asserts that both its current standby rate structure, and its proposals in its Post Transition Rate Design (PTRD) Application (A.00-01-009), are based on an analysis of the long-run marginal costs to serve SCE's various customer groups. SCE's proposal in this proceeding is designed to be consistent with its PTRD proposal.

SCE's proposed post-transition rate design standby rates include: 1) a "grid" charge; 2) a standby demand charge; 3) a customer charge; 4) any applicable non-bypassable charges such as recovery of nuclear decommissioning, public purpose, and transition costs; and 5) any ISO-related charges that must be passed through to retail customers. In addition, when a distributed generation customer requires backup service, the distributed generation customers would pay SCE's purchase energy charge. In its PTRD application, SCE proposes to include all fixed distribution costs in a "grid" charge to be paid by all full service and standby customers based on their size, reflecting the expected maximum demand they can place on the distribution system. The grid charge would pay for the costs of distribution facilities dedicated to the distributed generation customer's use, irrespective of when or if backup load is placed on the system. This charge would include the cost of that portion of the distribution and transmission system that connects the distributed generation customer to the alternate sources of power but does not vary with the level of demand on the system.

In addition to the grid charge, SCE recommends that all standby customers pay a standby demand charge calculated by multiplying the peak demand charge on the otherwise applicable tariff by an Effective Demand Factor. The Effective Demand Factor reflects the diversity of standby customer's demands at the time of distribution circuit peak and is calculated on the backup demand of existing customers. Under SCE's post-transition proposal, the lower standby demand charge would apply during months when the onsite generator operates at a capacity factor above 20%. SCE would apply the peak demand charge of the otherwise applicable tariff to the customer's contracted standby demand in the months when the generator capacity factor drops below 20% or if the customer does not install generation metering. SCE plans to update the diversity factors reflected in current rates in future ratemaking proceedings as more generation metering becomes available and as more small generators are employed in the future.

If a customer has supplemental load, which is the portion of the customer's total load that is regularly delivered by SCE, that load would be billed at the customer's otherwise applicable tariff. All other usage-based charges, except the peak demand charge, for the backup load will be billed based on the customer's otherwise applicable tariff. The standby demand charge will apply to the customer's contracted standby demand only. SCE proposes to require that standby customers have the appropriate generation and load metering needed to separately identify their back-up and supplemental loads.

SCE recommends that standby customers continue to pay non-bypassable charges. Standby customers, except those who use cogeneration, must continue to pay the Competition Transition Charge (CTC) based on their total consumption regardless of whether it is supplied by their self-generation system or through SCE's T&D system.11

SCE believes that there should be consistency among utilities in standby rate design with respect to principles such as cost components, data and probability of distributed generation failure used in determining the rate levels. However, due to the differences in the methodologies for calculating their marginal T&D costs, some differences in the utilities' standby rate structures and levels should be expected, just as there are approved differences with regard to rate structures for other customers.

If distributed generation customers use the T&D system at a lower frequency because their distributed generation units fail infrequently, SCE argues this will be reflected in the design of future standby rates because standby customers' load will demonstrate a lower coincidence with distribution circuits' peaks. Customers requiring a lower level of reliability can take service on interruptible rates that allow the utility to avoid certain capacity costs. SCE's current interruptible rate schedules were closed by the Commission to new customers. Standby customers, like all other customers, can participate in market-driven curtailment programs sponsored by the ISO. SCE also states that there is no justification for a TOU standby schedule, as there are a number of distribution circuits that peak in traditional off-peak hours and some that peak in the winter season.

5.3 San Diego Gas & Electric Company

SDG&E recommends that the Commission: 1) adopt policies that are cost-based and that provide for no artificial barriers to or supports for distributed generation; and 2) authorize SDG&E 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 assurance, such that SDG&E is able to defer a distribution capacity addition.

SDG&E's current standby rates provide a credit to distributed generation customers when the distributed generation unit operates. This service is provided on Schedule AV-1 and related tariffs. This credit is not restricted to distributed generation with physical assurance or distributed generation operating under a Form Contract. As a result, SDG&E states that its current rules provide for a credit to distributed generation without a reduction in cost to SDG&E. SDG&E states 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.

In its Form Contract 1, SDG&E proposes to provide credits to customers that install distributed generation at the right time, in the right location, of the right size and with physical assurance such that SDG&E is able to defer a distribution capacity addition for a period of at least a year. For customers receiving standby service under Form Contract 2 (where the distributed generation is installed with physical assurance anywhere on SDG&E's system), SDG&E has proposed that a customer's on-peak demand will be reduced for billing purposes to the load level that would have existed had SDG&E called for the running of the distributed generator for 100% of the on-peak hours.

SDG&E states that when distributed generation relied on for distribution capacity does not operate, it affects more than the service drop at the customer's premise. For example, on a circuit with one or more distributed generation units, the entire circuit will see an increase in load when a distributed generator is not operating. This will occur unless there is physical assurance that a corresponding amount of load will be dropped when the distributed generator is not operating.

SDG&E concurs with PG&E that, when a circuit breaker is opened to clear a fault and then reclosed, distributed generation units on that circuit will separate from the utility system leaving 100% of the load served by those distributed generation units for SDG&E to serve. SDG&E had almost 700 of these momentary outages in 1999. This separation requirement is part of each utility's Rule 21 interconnection requirements.

SDG&E is not opposed to standby rates that reflect diversity and reliability factors, however, due to the radial design of the distribution system, it believes it is impossible for units on one circuit to provide diversity benefits to a different circuit. SDG&E states that diversity exists on a networked system, such as the transmission system, because power can flow in multiple directions, but that is not the case for radial distribution systems. SDG&E contends that until there are multiple distributed generation units on any given distribution circuit, it is inappropriate to assume any diversity value from distributed generation for that distribution circuit. SDG&E recommends that the Commission reject the proposition that distributed generation provides systemwide benefits to all ratepayers.

SDG&E currently offers firm and nonfirm standby service under Schedules S and S-1 (applicable to customers with QFs). SDG&E states that it would be willing to offer other types of standby services if there was a reasonable demand for such services, however, such services should reflect rates and conditions that are cost-based.

5.4 Sierra Pacific Power Company

Sierra argues the standby charge should include all fixed costs associated with the system capacity needed to replace a distributed generation unit's output in the event of a failure or scheduled maintenance. The standby charges should reflect the fact that a portion of the system is being held available to provide this service. Since the purpose of the standby charge is to collect embedded costs from customers, Sierra recommends standby rates reflect embedded, not incremental costs.

Sierra believes the costs for a standby customer should be the same as for any other customer of similar size and with similar load characteristics. However, Sierra states there are system components that can be shared among standby customers. Furthermore, as not all standby customers require backup at the same time, it may be appropriate to apply a diversity factor to lower the costs associated with serving standby customers. However, Sierra recommends that diversity factors should only be applied where there would be cost savings for the utility, such as a reduction in the amount of capacity need to provide backup service.

5.5 Federal Executive Agencies

FEA recommends three principles to guide the Commission in setting both general and specific rate design policies for distributed generation. First, rates should appropriately reflect costs imposed on the utility system by all customers. Second, the Commission should not encourage or discourage installation of distributed generation, and should not provide incentives to the utilities, nor subsidies to distributed generation customers. Third, existing standby rates are not appropriately designed and do not reflect the outage characteristics and range of reliability of generation facilities. FEA believes the Commission should institute a separate proceeding to consider the design of standby rates.

These principles encourage the Commission to design standby rates on a non-discriminatory, cost-causation basis to ensure policies that facilitate, but do not subsidize, the development and installation of distributed generation. FEA contends that subsidization sends the wrong price signals, and could result in deployment of uneconomic resources. Likewise, distributed generation customers should not pay standby rates designed to recover full costs if those costs are equivalent to what a full requirements customer would pay, unless the standby customer has load characteristics the same or similar to a full requirements customer. FEA disagrees with State Consumers that because most distributed generation customer loads are small, they impose no costs on the distribution system.

With respect to distributed generation, FEA believes standby charges fall into two categories: 1) standby rates applicable to the generation resource itself, and 2) standby rates applicable to the T&D systems. Generation standby costs should reflect the probability that the distributed generation facility will cause costs to be incurred by the backup generation resource provider. Similarly, with respect to T&D facilities, the standby charge should consider the probability that an outage of the distributed generation facility would impose costs on the T&D systems.

FEA believes transmission and distribution costs are attributable to two key factors: the overall level of diversity among individual customer loads on the system, and the reliability of the customer's generating facility. The level of diversity among individual loads defines the total amount of load placed on the system by a combination of resources. The utility must serve the diversified load at any given point on the system. The reliability of the distributed generation unit also dictates the frequency and duration of use of the network facilities by that distributed generation customer.

FEA argues that current standby rates do not adequately reflect the reliability of the distributed generation units being backed up. This hinders distributed generation deployment because of the inherent overcharges to distributed generation customers when these inappropriate rates are applied. FEA asserts that usage-sensitive standby charges would facilitate the development of distributed generation by charging rates more consistent with the cost of providing service. The higher the reliability of the distributed generation, the less likely the need for backup, and thus the lower the standby charge.

As in other tariffs, the standby rate should include appropriate service voltage level distinctions: secondary, primary, subtransmission, or transmission. The higher the voltage level of the system where service is taken, the lower the probability that an outage will occur at coincident peak. At lower voltage levels closer to the customer's meter, there is less diversity. A distributed generation facility on a radial feeder line with only a few customers increases the probability that an outage at the distributed generation facility would coincide with peak system demand.

FEA believes that standby rates should be designed consistent with full requirements service charges. If embedded costs are used to develop full requirements rates, embedded costs should be used to develop standby rates. Similarly, if marginal costs are used for the full requirements rates, marginal costs should be used to develop standby rates.

5.6 Office of Ratepayer Advocates

ORA believes that standby charges, especially reservation charges, can be a barrier to an economically viable distributed generation market if those charges are unreasonable. ORA believes that distribution standby rates should reflect the costs actually imposed on the distribution system by customers who normally utilize distributed generation for their energy needs but rely on the utility for backup service.

ORA contends that, in calculating the marginal costs of distribution service, utilities should not assume that all distributed generation units would shut down simultaneously, thus triggering all standby customers to demand service from the utility. According to ORA, the most important aspect of calculating distribution standby rates is designing sufficient distribution capacity to serve the maximum demand expected within a distribution planning area. ORA testified that, "the UDCs' approach to distribution planning may overstate standby capacity requirements and lead to unnecessary investments in distribution facilities in certain instances because it ignores the low probability of multiple outages of self-generation units." (ORA Ex. 22, Gibson, p. 2-5.)

ORA believes that distributed generation customers must pay some reservation capacity charges at peak times to reflect as accurately as possible the probability they would need standby service during such a period. ORA admits that distribution planning requires the utility to design sufficient capacity to serve the maximum demand expected within a Distribution Planning Area (DPA). But there are differences in diversity between distribution, generation and transmission loads and peaks. A customer's maximum demand is usually less than connected load because a customer does not utilize all its potential electrical equipment at any one time. Thus, utilities do not design distribution circuits to handle the total connected load. ORA recommends that installing standby capacity for each DPA at the size of the largest distributed generation unit in the DPA should be sufficient.

ORA believes distribution standby rates should not be used to reflect any generation-related or system benefits provided by distributed generation. Demand reduction benefits are probably already accounted for in lower rates and lower investment in T&D facilities. Therefore, ORA does not recommend attempting to develop focused incentives to reward distributed generation for system benefits in this proceeding.

ORA suggests that standby rate design ought to be as consistent as possible among the utilities. Since general rate design can legitimately differ among utilities though, ORA recommends this proceeding not mandate that utility standby rates utilize the exact same methodologies. ORA does recommend that certain precepts be applied to all utilities, such as ordering all utilities to consider diversity values in calculating load requirements, but that the Commission should not require utilities to utilize the exact same methodologies.

ORA's proposed guidelines for standby charges are conceptually similar to how standby charges are currently structured, except that current utility presumptions that distributed generation will not operate when needed are too extreme, therefore ORA is not requesting a full-scale revamping of how standby rates are calculated. ORA also supports time-of-use demand charges that reflect the cost of providing service during various times of day or seasons.

5.7 The Utility Reform Network et al.

In their joint testimony, TURN, NRDC, and UCAN (together TURN) state that equity among customers must be considered when establishing standby charges. Ratemaking and rate design should not result in cost shifting between customers who install distributed generation and those who do not. Although the benefits of distributed generation need not be allocated equally across ratepayers, all customers should ultimately realize some benefits. Customers relying on distribution service should pay costs consistent with their reliance on the distribution system. Customers should be allowed flexibility to choose differing amounts of standby services, including variations on timing with appropriate provisions for physical assurance. TURN recommends usage-based, volumetric average distribution rates, and opposes the fixed customer charge proposed by SCE. TURN believes fixed charges are not likely to be consistent with cost causation on the distribution system over the long term.

TURN believes that standby rates should reflect actual costs and benefits to the distribution system. Standby rate design should reflect diversity factors, the availability of differentiated service levels, unit reliability and use of various forms of physical assurance. Standby rate design should also reflect system benefits provided by distributed generation units such as deferral of distribution upgrades, extension of equipment life, and energy supply costs reductions that benefit all ratepayers. TURN believes that these system benefits should be incorporated into the distributed generation rate structure in order to send proper price signals to potential customers.

Like ORA and FEA, TURN disagrees with the claim that utilities must plan and reserve capacity to serve 100 percent of the standby load. TURN believes that the diversity of standby load must be incorporated into the design of standby rates. TURN contends that utility concerns regarding the inability to know with certainty that a distributed generation unit will be operating at times of peak demand can be remedied if customers provide physical assurance.

TURN asserts that the energy and supply benefits of distributed generation may be significant. TURN maintains that it is undisputed that wholesale energy prices in California will be influenced by the addition of new generation capacity and by efforts to achieve peak demand reductions. Therefore TURN suggests deployment of customer-side distributed generation, which performs both supply and demand-reduction functions, can contribute to lowering overall market prices for electricity. Non-participants can benefit from the deployment of distributed generation units only if there are opportunities for all classes to share the cost savings and improved reliability associated with its use. These benefits can be shared if rates are structured to promote the deployment of distributed generation in areas of the distribution system that may otherwise require utility investment to meet existing or projected future load.

Given the clear benefits to non-participants, TURN believes that standby rates should be designed to recognize the value of distributed generation in reducing wholesale energy prices. TURN recommends that the Commission adopt standby rates that reflect, to some extent, the fact that operation of the units during peak periods will provide defined economic savings for all consumers. TURN does not propose the exact quantification of the benefits it identifies, but suggests that it is difficult to conceive that a quantification of these benefits equals zero. TURN contends that failing to consider these benefits will result in excessive standby charges that fail to properly value the costs and benefits of customer-owned distributed generation to the utility. TURN recommends that the Commission direct the utilities to design standby rates for distributed generation that recognize the benefits in order to encourage deployment of distributed generation that will produce cost savings for the utility and its customers.

TURN also suggests that customers taking standby service have their distribution tariffs adjusted based on the reliability of the distributed generation unit. Such reliability adjustments could be done on a technology-specific or project specific basis. TURN argues that even SCE agrees, stating that this approach is warranted because "if a customer generation unit fails more often, it is more likely that the peak demand of that customer would be more coincident with distribution circuit peak than a customer whose generation fails less often." (TURN Opening Brief-Phase 2, p. 21, citing SCE Witness Jazayeri, RT 1292.) TURN believes that this type of rate structure would properly identify and reward the ability of distributed generation units to provide consistent system support during periods of peak distribution usage.

Finally, TURN supports the concept of time of use standby rates that provide incentives for distributed generation customers to operate their generation in a manner consistent with demand peaks in the local distribution system.

5.8 State Consumers

State Consumers encourage the Commission to adopt "forward looking" rate design policies, particularly with respect to standby charges. Such policies should recognize that customers integrate energy procurement, conservation, energy efficiency and other strategies to manage their energy needs. State Consumers testify that the components of standby rates should be unbundled, usage-based, and priced individually to reflect actual cost-causation. State Consumers did not present a definitive evaluation of current standby rate structures, but rather present recommendations on standby rate policies to reflect a competitive market structure for energy procurement. This approach could also consider location-specific standby rates. In no case do State Consumers recommend increasing standby rates beyond existing levels.

State Consumers recommend the Commission adopt incremental marginal cost pricing and cost causation allocation methods for each component of standby charges. State Consumers support market-based pricing for the energy component of standby rates, whether that energy is obtained from the Power Exchange, through bilateral contracts, or demand bidding systems. State Consumers assert that there is no reason why the utilities must be the sole providers of the generation portion of standby service. State Consumers believe standby customers should have the ability to purchase power when they need it at a competitive price. There should be no special standby rate for energy, as there is no generation capacity dedicated solely to provide standby energy. Customers should be able to access other entities for the energy portion of standby service.

State Consumers take the position that standby customers are significantly over-allocated responsibility for distribution revenue recovery, while imposing essentially no incremental distribution costs. State Consumers state that standby customers cause minimal distribution resource additions, citing the relatively small number of standby customers currently taking standby service. According to State Consumers, PG&E serves approximately 300 customers on its standby tariff. State Consumers further state that PG&E's 1999 coincident system demand served under its standby tariff accounts for approximately 0.25 percent of total system energy volumes. As a rate class, PG&E's standby customers pay 38 percent of total costs. (State Consumers Opening Brief-Phase 2, p. 10. See also Exhibit 34.)

State Consumers recommend that the Commission require the utilities to submit calculations of distributed generation impacts on system planning forecasts to support any future standby rate applications.

5.9 California Independent System Operator

According to CA ISO, standby charges should take into account the methodology for setting charges and allocating costs at the wholesale level and the impact of different approaches at the retail level. CA ISO indicates that FERC has jurisdiction over the methodology for the allocation of wholesale and transmission costs, but this Commission has jurisdiction over the design of distribution and retail rates, except for the unbundled transmission component of retail rates. Entities providing transmission and other wholesale services subject to the jurisdiction of FERC should be allowed to collect the costs of providing those services but should not over-collect those costs from customers.

The CA ISO transmission access charge is assessed to and collected from customers by the utilities for all end use customers within their service territories. The grid management and ancillary service charges are assessed to scheduling coordinators. In individual proceedings at Federal Energy Regulatory Commission (FERC)12, the CA ISO proposes to assess different types of CA ISO-administered charges based on gross load13 within the ISO control area, including load served by self-generation. These charges include the transmission access charge, the control area services component of the grid management charge, and charges for (or responsibility to self-provide) ancillary services. CA ISO claims that this Commission must consider the structure and allocation of CA ISO administered charges in determining retail standby rates.

The CA ISO does not claim that this allocation must predetermine the allocation of charges at the retail level. Moreover, the ISO recommends that CPUC and FERC jurisdictional components of rates be harmonized so that wholesale costs are collected accurately. Thus costs collected in FERC jurisdictional components should not be included in CPUC jurisdictional components and vice versa, and all legitimate costs should be accounted for in either FERC or CPUC jurisdictional components.

The CA ISO does not take a position on the appropriate billing determinant(s) for purely CPUC jurisdictional components of retail standby rates. Thus, for example, if some portion of the cost recovery component of standby rates is currently determined based on usage volume for net load14, the CA ISO is not proposing that billing determinant for this component should now be based on gross load.

The CA ISO's comments as to the appropriate billing determinants apply to the allocation of CA ISO-administered charges, and to consideration of this allocation, for purposes of designing the components of retail standby rates that correlate to CA ISO services. The CA ISO urges this Commission to be clear as to the billing determinant to be used for each standby rate component so that CPUC and FERC jurisdictional requirements can be implemented without anomalous or unintended results.

5.10 Enron Energy Service Inc. and Enron North America Corp.

Enron states that it is widely recognized that standby rates will continue to represent a decisive factor for consumers who are considering distributed generation installations. Enron maintains that standby rates should fairly compensate utilities for the costs associated with facilities needed to provide standby service to distributed generation customers, and at the same time, utilities should not be overcompensated for these services by requiring customers to pay for services that they do not request or use. The challenge is to set rates that equitably assign cost responsibility to distributed generation customers who need these services without creating incentives for customers to "island" load from the grid.

Enron recommends that the utilities offer at least two basic standby rate options. One option would involve only a capacity reservation fee priced comparably with the standard delivery tariff that applies to all customers. Under this approach, the distributed generation customer would pay only the reservation fee, which would entitle the distributed generation customer to unlimited distribution services up to the amount of reserved capacity.

The second option would allow distributed generation customers to pay for standby service under a volumetric rate based on the concept of "proportionate responsibility." Under this approach, rates would reflect a distributed generation customer's anticipated contribution to the capacity requirements of key components of the distribution system and the frequency with which the customer uses the system. This option would require utilities to unbundle the major components of the distribution system and assign cost responsibility based on realistic probabilities that distributed generation customers will require use of the distribution system and taking into account the diversity of loads served by distributed generation units. In particular, standby rates should not be premised on the assumption that all standby customers will require distribution services to serve their entire load at the time of system peak.

5.11 Capstone Turbine Corp., Inc. et al.

Capstone, et al.'s recommendations regarding standby rate design relate primarily to fixed versus usage-based rates. Capstone, et al. advocates that since distribution costs vary with customer usage, usage-based pricing is the fairest and most efficient way for utilities to recover both fixed and variable costs associated with distributed generation and to reflect the costs of system expansion. Capstone, et al. suggests that shifting from high fixed charges and demand charges that are insensitive to usage, toward usage-based charges that encourage demand-responsive behavior, need not compromise the objective of cost-based charges. Such a shift means only that utility costs are recovered differently.

Capstone, et al. also emphasizes that costs imposed on the system can be collected through usage-based charges differentiated as it proposes, and may include per-kWh demand charges for firm reservation of delivery capacity. Capstone, et al. recommends that standby rates considered should include a capacity reservation fee, differentiated by quantity, firmness, time and location of use. Capstone, et al. states that if standby charges are differentiated along the lines it proposes, customers can decide how much standby they need (perhaps less than their maximum demand); when and how firm they need it (perhaps not at certain times of the day, week, or season); and how much it is worth to them.

At a minimum, Capstone, et al. recommends the utilities should offer two levels of service: firm and nonfirm. Standby charges should not be used to recover stranded costs, exit fees, bypass charges, or other special provisions. Capstone, et al. suggests that if a customer with distributed generation can enter into an arrangement specifically relieving the utility of the obligation to provide standby power at certain times, such as during peak load, then that customer should not be charged a standby rate that assumes the customer would require service at system peak.

Capstone, et al. opposes utility arguments that anything short of physical assurance will not provide the certainty the utility needs to build or reserve less distribution infrastructure than the customer's full potential demand. Capstone, et al. maintains there are types and levels of assurance, other than physical assurance, that offer different values to the utility and can provide sufficient certainty.

5.12 Cogeneration Association of California/ Energy Producers and Users Coalition

CAC/EPUC state that in designing standby rates, the Commission should be guided by the principle of cost-causation and require that a customer only be assessed charges for those costs that the customer caused the utility to incur on his behalf. In this context, the cost-causation principle requires that the diversified demand of all standby customers as a class must be taken into account in passing through any transmission and distribution charges to standby customers.

CAC/EPUC urge the Commission to adopt standby rate design policy with five primary characteristics. First, the standby rate should accurately reflect the expected diversified demand of all customers taking standby service. Historically, standby rates in California have accounted for the diversity of the standby customer class. CAC/EPUC asserts that the utilities do not dispute the need to account for class diversity in the standby rate, the only disagreement is quantitative, i.e. the level of diversity for each individual utility at the distribution and transmission level. CAC/EPUC state that if the utilities do not take class diversity into account in this manner, federal law affecting standby rates for qualifying facilities would be violated.

Second, the rate design should allow for separately assessing charges for maintenance and backup power. Supplemental power is no different from the service provided to a full-requirements customer and may be priced at the same rate. In contrast, maintenance power is power supplied by the utility to replace the generation from distributed generation facilities when the facilities are scheduled out of service for maintenance. Maintenance power is provided on a pre-arranged scheduled basis and is only required for short durations. Since the supply of maintenance power can be arranged at a time when the utility has idle capacity available, the utility will not need to plan for or add capacity to meet maintenance power demand. This characteristic should be reflected in the rate paid for this power. Similarly, the payment for backup service should reflect the cost imposed on the system by distributed generation equipment of different characteristics. CAC/EPUC maintains that there should be a separate charge for each of these services due to their unique cost-causative characteristics.

Third, the standby tariff should be a stand-alone tariff in order to ensure that diversity is taken into account, that maintenance and backup service are assessed charges according to the cost-causative characteristics of those services, and to avoid excessive metering costs. For, example, SCE's proposed Schedule S would require dual meters for load and generation in place of the current single meter configuration. This is an unnecessary cost for customers who only purchase standby service.

Fourth, Standby rate design should allow customers to elect a standby reservation capacity. The elected capacity should be the basis for a minimum monthly charge paid to the utility.

Fifth, customers should have the option of firm or interruptible service. Customers who select interruptible service should be assessed a lower rate to compensate them for their willingness to accept standby service at a lower level of reliability.

5.13 City and County of San Francisco

CCSF generally supports the position of the State Consumers and states that the Commission should endeavor to reduce the need for transmission and distribution upgrades by supporting a healthy customer-side distributed generation market. CCSF further states that bundled energy prices for standby service are anti-competitive in a post-transition economy. CCSF asserts that standby costs are "so minimal that they are within the noise level of planning for the UDCs". (CCSF Opening Brief-Phase 2, p. 7.) CCSF also states that diversification of distributed generation resources will counteract the need for 100% standby service. The need for standby service must factor in the probability that a distributed generation unit outage will contribute to the incurrence of costs on the distribution system. The cost to the utility of standby power will be a factor of the overall level of diversity of distributed generation units in the system as well as the reliability of distributed generation units. By reducing barriers to distributed generation deployment such as standby charges, distributed generation investments will grow and help to defer the cost of new distribution capacity. CCSF claims that any method that can defer new distribution capacity, such as distributed generation deployment, will help to decrease costs. CCSF further claims that these decreased costs must be accounted for in the formulation of standby costs.

8 Backup service is service supplied by the utility to replace the generation from non-utility facilities during periods of unscheduled outages. 9 PG&E Opening Brief- Phase 2, p. 13. 10 When a circuit is de-energized, any DG units must remain separated from the distribution circuit to prevent backfeed into the de-energized line. When the circuit is being re-energized, the DG units are still separated from the system; after the circuit is energized, the DG units can be synchronized with distribution system voltage frequency and phasing. In such events, load must be restored and served by PG&E's distribution system prior to the availability of the DG. In other words, after an outage, all load on a distribution circuit, including the load formerly served by the DG, will come on simultaneously and need to be served by the distribution circuit. Therefore, PG&E must plan and reserve distribution capacity to serve 100 percent of the standby load. This phenomena becomes even more significant when blackouts are more frequent. 11 This exemption from CTC for cogeneration customers derives from Pub. Util. Code § 372(a)(1) which exempts customer who install cogeneration systems from payment of CTC after June 30, 2000. 12 Related FERC proceedings include Docket Nos. ER00-2019-000, ER01-313-000, and ER98-997-000. 13 Gross load is the customer's total onsite load, whether served by self-generation or the utility. 14 Net load is the customer's remaining load not served by self-generation. Net load is measured at the point of common coupling.

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