6.1 Nature of Costs to Serve Standby Customers
As a matter of policy, most parties agree that standby rates should be cost-based. PG&E, SCE, and SDG&E believe that most of the costs associated with providing T&D services are fixed and recommend that these costs be recovered through fixed charges. SCE testimony notes that "in designing rates for distributed generation customers, similar to other customers, it should be recognized that there are some distribution costs that do not vary with the volume of customer usage delivered through the utility's T&D system and these costs cannot be avoided when customers install distributed generation. Standby rates should ensure that distributed generation customers pay these unavoidable costs, but are given appropriate credits in their standby demand charges in recognition of their reduced demands on the distribution circuits resulting from their deployment of distributed generation." (SCE: Ex. 71, p. 6.)
SCE also states that "it is beyond dispute that a portion of distribution costs is fixed in nature", and that the costs of certain distribution assets do not vary depending on usage. (SCE Opening Brief-Phase 2, p. 22.) For example, SCE states that the cost of maintaining a meter or pole does not vary depending on how much energy a particular customer uses. It is these types of costs that SCE argues should be recovered according to cost causation principles whereby each customer pays a fixed charge to recover the costs incurred on its behalf. Other costs, such as for transformers, do vary depending on usage and their recovery through variable, usage-based charges would be appropriate. (SCE Opening Brief-Phase 2, p. 22.)
TURN disagrees, and points out that there are some costs associated with providing T&D service that are not fixed and that do vary with usage. TURN points to the testimony of SCE witness Jazayeri where he states that costs that are kilowatt-demand related vary with customer usage as support for its position. (TURN Opening Brief-Phase 2, p. 24, citing RT 1290.) TURN takes the position that fixed charges are not consistent with cost causation on the distribution system over the long term. Capstone, et al. maintains that distribution costs vary with customer usage. (Capstone, et al. Opening Brief-Phase 2, p. 10.)
6.2 Types of Standby Service
When a customer installs an onsite generator, the customer may chose to interconnect that generator to the grid. Today, all interconnected generators that do not qualify for net metering or other exemptions, whether serving as a primary or backup power source, must pay standby charges as a function of interconnecting with the grid. However, customers frequently use their onsite generators for different purposes and desire different levels of service. Today, utilities offer three general types of standby service: supplemental, backup, and maintenance.
CAC/EPUC request that the distributed generation customer be able to elect and adjust its reservation capacity for various standby services. CAC/EPUC recommend that the tariff include a reasonable, but not excessively punitive, monetary penalty for exceeding the elected reservation capacity. CAC/EPUC is opposed to contract capacity ratchets such as those in PG&E's Schedule S.
PG&E's Schedule S allows new distributed generation customers to elect their reservation capacity. However, if the customer's demand exceeds the contracted capacity in any billing month, that demand level becomes the new reservation capacity for 36 months. PG&E states that the 36-month ratchet provision is necessary to allow the utility to make necessary planning adjustments to meet the increased standby demand level. Under SDG&E's Schedule S, the contract demand level is determined by customer's Generation agreement. If the customer takes service in excess of its contract demand in any billing month, the increased demand shall become the new contract demand for a 12-month period. Under SCE's Schedule S, the level of standby demand is the lower of the nameplate capacity of the customer's alternate power source, or SCE's estimate of the customer's peak demand.
Supplemental power is supplied by the utility to a customer whose onsite source of generation does not regularly supply all the power necessary at their premises. Currently, supplemental power is priced according to the customer's otherwise applicable tariff, but under a separate tariff. Customers take supplemental power when the installed capacity of their onsite generator does not supply their full load. For example, a customer whose demand is 4 MW who installs a 3 MW generator would have a supplemental power load of 1 MW.15 Likewise a customer whose generator serves as a backup power source and thus the customer normally relies on the utility for power is a supplemental power customer. By its nature, the utility must plan to serve supplemental power loads. The utilities recommend that supplemental power be priced according to the customer's otherwise applicable tariff rate. CAC/EPUC concur with this recommendation.
Backup service is supplied by the utility in lieu of generation normally provided by the customer's onsite generation facilities during periods of unscheduled outages. Backup service is available instantaneously and effectively requires the utility to reserve capacity to serve the backup load at all times. The utility must plan to serve the load of backup customers. In some respects, backup service is similar to supplemental service.
Currently the energy charges on PG&E's Schedule S are differentiated by peak, partial-peak, and off-peak periods and summer and winter seasons. When a customer's distributed generation unit suffers an unscheduled outage, the customer pays for backup power based on the time and season when the outage occurs. For customers with unscheduled outages, SCE backup charges are based on the otherwise applicable tariff, except that instead of the otherwise applicable tariff's peak demand charge, backup customers under Schedule S pay the standby demand charge. SDG&E's Schedule S is used primarily by QFs in combination with the otherwise applicable tariff, such as Schedule AL-TOU. The tariff combination provides reduced demand charges for backup and maintenance service compared to demand charges the customer would otherwise pay on the otherwise applicable tariff. SDG&E emphasizes that Schedule AV-1, not Schedule S, is the tariff applicable to distributed generation installations.
Maintenance service is scheduled by the customer with the utility to replace onsite generation when the customer's generating facilities are scheduled to be out of service. Unlike backup service, maintenance service is scheduled with the utility at times of low load and thus does not require the utility to build or reserve capacity to serve it.
PG&E does not offer an additional reduction or incentive for customers to schedule maintenance with the utility beyond the time differentiated backup schedule. Customers taking backup service under PG&E's Schedule S can schedule maintenance during the lower cost periods. Once a customer whose otherwise applicable tariff includes a time-related demand charge has been on SCE's Schedule S for six months, the added demand created by scheduled maintenance may be ignored for purposes of determining the standby demand charge. The customer continues to be responsible for the generation reservation charge from Schedule S as well as all applicable charges from the otherwise applicable tariff. This exclusion applies to one outage per year, as long as the outage is scheduled with SCE. All other charges continue to apply. When a customer on SDG&E's Schedule S schedules a maintenance shut down of its generating facility, the on-peak demand charges on its otherwise applicable tariff are waived up to the contracted standby level.
CAC/EPUC request that separate incentives be offered for maintenance service or scheduled outages that would be credited against the standard backup standby rates to lower the customer's total cost. PG&E and SCE state that they already offer 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. They do not believe any further incentive for scheduled maintenance is necessary or required.
6.3 Diversity and Reliability
Transmission and distribution costs associated with standby service are related 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 users. The parties all agree with the basic premise that diversity levels represent a statistical assumption that a certain percentage of standby load will be utilizing transmission and distribution service at a particular time. All but one of the parties taking a position on standby issues either supports or is not opposed to the concept of taking diversity into account when establishing standby rates at transmission and distribution voltages. The only party to dispute the applicability of diversity factors to standby customer load is the CA ISO.
SCE states that its proposed post-transition standby rate structure fairly accounts for diversity. SCE agrees that reliable distributed generation will place less demand on the system, and supports applying a diversity factor adjustment based on system-wide averages. SCE's current diversity factors are estimated using a sample of large standby customers with generation metering taking service on Schedule S. The generators owned by the sample customers are relatively large and are expected to be more reliable than smaller generators, resulting in a more diversified back-up load.
PG&E also states that the diversity of standby load is relevant, but argues that it is relevant only to the extent that it results in real savings to the utility. PG&E recommends that each utility separately calculate a diversity factor for customers taking standby service at transmission and distribution levels. That factor should reflect the extent to which generation diversity permits the utility to avoid building system upgrades. In addition, PG&E requests that the Commission find that its current diversity factor requires adjustment.
PG&E's experience at the transmission level demonstrates that the diversity of generation supply at transmission level and the networked nature of the transmission system can permit the utility to avoid building some capacity that would otherwise be needed. However, radial distribution lines operate quite differently than networked transmission lines, and, in PG&E's opinion, the small quantity of distributed generation on the distribution lines does not support a distribution level diversity discount at this time. PG&E agrees that at some point, after enough distributed generation units are installed and operating on a radial distribution line, distributed generation units could provide a level of reliability sufficient to allow the utility to avoid building new distribution capacity.
SDG&E is not opposed to standby rates that reflect diversity and reliability factors. SDG&E agrees that diversity exists on a networked system, such as the transmission system, because power can flow in multiple directions. However, due to the radial design of the distribution system, SDG&E argues it is impossible for units on one circuit to provide diversity to a different circuit. 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 provided the following example. Assume there are two distributed generation units on a utility's distribution system and each distributed generation unit is located on a different distribution circuit. If one unit is never off and the other is never on, it makes no sense to average the two outage rates and assume there is a 50% likelihood that both units would be online. SDG&E argues that, in this example, the outage rate of one unit is irrelevant to the outage rate of the other unit. (SDG&E Reply Brief-Phase 2, p. 14.)
Sierra agrees that it may be appropriate to apply a diversity factor to lower the costs associated with serving standby customers, since not all standby customers will require backup at the same time. However, Sierra emphasizes that diversity factors should only be applied where there will be cost savings for the utility, such as a reduction in the amount of capacity need to provide backup service.
ORA, TURN, CAC/EPUC, Capstone, et al., Enron, FEA, State Consumers, and Aglet all maintain that reliability and diversity are important characteristics of distributed generation that should be reflected in standby rates. As additional distributed generation units are located on the transmission or distribution system, the diversity of these units will lead to a lower amount of additional standby capacity needed to serve standby loads. These parties suggest that greater diversity of the load of the individual distributed generation facilities should be reflected in lower standby rates.
FEA argues that existing standby rates do not adequately reflect the outage characteristics and range of reliability of generation facilities. FEA suggests that one method to reflect varying degrees of diversity and reliability is to apply an on-going standby reservation charge that reflects costs at a level similar to costs imposed on the system by distributed generation with a high degree of reliability. FEA observes that this methodology has been considered primarily in the context of transmission and generation requirements, but could also be applied to standby distribution service. To reflect lower levels of reliability, higher amounts would be charged for actual standby usage when outages occur. For example, a standby reservation charge might reflect costs associated with a 5% outage rate, provide an ongoing revenue contribution, and provide standby at a minimum level. If a distributed generation facility has an outage rate greater than 5%, increasing amounts of standby usage charges would be levied based on actual use on a per kWh basis. FEA does not propose a specific method to have these characteristics reflected in rates; instead, FEA requests that the Commission institute a separate proceeding to consider the design of standby rates.
ORA takes the position that the utilities should base standby charges on the full cost of serving firm loads, but should not assume that they must be able to serve 100% of standby loads at any particular time. ORA states that, currently, for purposes of evaluating distribution system requirements, the utilities assume that distributed generation or self-generation units are not operating during the peak hour. ORA believes that the utilities' 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 contends that while the utility may be justified in assuming that a single distributed generation unit will be out of service during the peak hour and installing standby capacity to serve that unit, there is only a small probability that multiple distributed generation unit outages will occur simultaneously. ORA suggests that the utility need only build to cover the capacity of the largest distributed generation unit in each Distribution Planning Area (DPA).
PG&E criticizes ORA's proposal as having the potential to substantially impair distribution reliability. PG&E states that its distribution system is operated through approximately 200 DPAs containing over 3,000 circuits. Each circuit contains many individual distribution lines. Unlike the transmission system, which is networked, most of the distribution system is radial in nature. According to PG&E, if there are 20 distributed generation units in a DPA, each on a separate radial circuit, the utility will need to build enough distribution capacity to meet the load of every one of the generators taking standby service, not just the largest one. Capacity on the radial line serving the largest unit in the DPA will not help meet load on other radial lines in the DPA.
Indeed, PG&E argues that even when there are two distributed generation units on the same circuit, the utility will need to build enough capacity to meet the load of each. PG&E uses the following example. Assume the utility has a radial line with 4 MW of load not served by distributed generation, and two 1 MW load customers, each served by a 1 MW distributed generation unit. Absent clear proof that both plants will never be out at the same time, PG&E argues the utility will need to build enough capacity to serve the entire 6 MW.
CAC/EPUC remind us that the statistical probability that different individual customers in the standby class will require standby service at the same time (the coincident peak) may be estimated. Using this estimate, the utility needs only to plan for that level of coincident peak demand. CAC/EPUC request that the Commission reaffirm in this decision the principle of assessing charges to standby customers on the basis of the coincident peak of the class.
PG&E believes that CAC/EPUC's basic premise is flawed because there is not one "coincident peak" associated with the distribution system. PG&E contends that the "distribution system" is not one system, but the sum of over 200 different distribution planning areas, comprised of over 3000 circuits. Many of these areas do not have coincident peaks that coincide with each other, or with the system peak. However, even if they did, PG&E argues that it would be irrelevant, since the existence of a generator on a north coast circuit would have no impact on distribution costs in the central valley, even if the two happened to peak at precisely the same time.
Like ORA, CAC/EPUC, Enron, and FEA, TURN disagrees with the utilities' claim that they 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 suggests that utilities' concerns regarding the need 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 also suggests that customers taking standby service have their distribution tariffs adjusted based on the reliability of the distributed generation unit. TURN suggests that such reliability adjustments could be done on a technology-specific or project specific basis.
CCSF suggests that PG&E's analogy of a fire department's need to have equipment beyond that needed to fight just one fire at a time is an accurate comparison to the situation of standby service. (CCSF Reply Brief-Phase 2, p. 2.) CCSF states that it is true that a fire department must plan for the possibility that two or more fires will occur simultaneously, but the fire department does not need a fire truck to standby for every building that might catch fire. Just as the fire department must plan for, PG&E must undertake similar planning activities and plan for the probability that a distributed generation outage will contribute to the occurrence of costs on the distribution system.
CAC/EPUC points out that historically, standby rates in California have accounted for the diversity of the standby class. CAC/EPUC state that the utilities do not dispute the need to account for diversity in the standby rate, the only disagreement is quantitative, i.e., the level of diversity for each individual utility at the transmission and distribution level.
6.4 Should Distribution Costs be Recovered through Fixed or Variable Charges?
The parties have diametrically opposite views as to whether distribution costs to serve standby customers should be recovered through fixed or usage-based rates. The utilities contend that a reservation charge is necessary to compensate the utility for the fixed, ongoing cost of reserving capacity on the T&D system whether or not this service is used. The utilities argue that reservation charges should reflect the fact that a portion of the system is being held available to provide this service.
TURN, ORA, FEA, Capstone, et al., State Consumers, and Enron all propose that the Commission adopt usage-based charges. TURN states that fixed reservation charges to recover distribution costs will discourage the use of distributed generation, stating that the presence of large fixed costs will deter acquisition of distributed generation even when such use would be economically efficient. TURN recommend usage-based, volumetric charges to provide an incentive to reduce usage. ORA also disagrees with the utilities' position, and argues that reservation charges can be a barrier to an economically viable distributed generation market if those charges are unreasonably high. Capstone, et al. is concerned that tariffs insensitive to changes in customer usage will foreclose customer opportunities to reduce their bills by changing their behavior or usage patterns. Capstone, et al. maintains 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 expansion.
Both Capstone, et al. and FEA suggest that shifting away from fixed-type charges that are insensitive to usage toward usage-based charges encourages demand-responsive behavior, and need not compromise the objective of cost-based charges. FEA also asserts usage-sensitive standby charges will facilitate the development of distributed generation by charging rates more consistent with the cost of providing service.
State Consumers propose three standard tariff options: usage only, usage and reservation fee, and reservation fee only. State Consumers also propose contracts for tailored standby rates between the utilities and their customers. Enron proposes two options: reservation fee only, and usage only rates. These parties did not provide any additional details regarding how these rates should be structured. Enron and State Consumers also propose options for backup standby service that recovers some distribution revenue from reservation charges and some from usage charges. The utilities oppose the optional rates described because they argue they do not provide accurate price signals to customers.
ORA and FEA support time-of-use demand charges that reflect the cost of providing service during various times of day or seasons. ORA notes that the utilities have designed current TOU definitions to be compatible with daily and seasonal variability of energy and generation costs. ORA suggests that the Commission should consider changing current time of use definitions to be more compatible with distribution systems costs. PG&E, SCE, and SDG&E all oppose TOU on the basis that there is no direct link between TOU usage shifts and distribution facility cost savings, and the system average TOU rates cannot capture the wide variation in peak load times in various distribution planning areas.
Currently, the energy charges associated with the otherwise applicable rate schedules used by the utilities in conjunction with their standby tariffs do not include commodity charges. SCE's and SDG&E's "energy charges" recover transmission, distribution, public purpose and other nonbypassable charges on a per kWh basis, but do not actually include energy commodity charges. PG&E's "energy charges" also recover transmission, distribution, public purpose and other nonbypassable charges, however, PG&E's Schedule S, when used as a stand-alone tariff by those customers whose distributed generation units do not exceed their load, also contains energy commodity charges.
FEA points out that standby service requires the use of generation, transmission and distribution facilities. On an unbundled rate basis, FEA presumes that the generation component will be contracted for in the marketplace, the transmission component will be contained in FERC-approved rates, and that the distribution component will be included in the rates approved by this Commission.
6.5 Should Standby Rates Reflect Embedded or Incremental Costs?
The parties have differing views as to whether distribution costs to serve standby customers should reflect embedded or incremental costs.
SDG&E states that a standby charge that reflects the incremental cost of distribution assets to provide service to distributed generation is inappropriate because it fails to address the full cost of providing service to the whole customer. (SDG&E: Ex. 72, Appendix A, p. 3.) SCE states that "charges for standby service should be based on the marginal cost of serving standby customers scaled to the utility's revenue requirement, consistent with retail rate design for other services provided by the regulated utility. Current standby rates are based on the marginal cost of providing T&D services to retail rate groups, which include both full service and standby customers. (SCE: Ex. 71, p. 19.) PG&E states that to the extent possible, standby charges for distribution should be based on the same marginal cost-based ratemaking consideration used for all other retail rate classes. (PG&E: Ex. 73, p. 14 )
FEA believes that 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. Aglet's position is that standby charges should recover fixed and variable costs of providing standby service. Aglet supports determination of standby charges based on embedded, not incremental costs of service, consistent with the manner in which rates are calculated for other distribution services. State Consumers take a different position and recommend adopting incremental marginal cost pricing and cost causation allocation methods for each component of standby charges.
State Consumers support area-specific marginal cost pricing for standby rates. Capstone and NRDC join State Consumers in recommending that standby prices be linked to the utility's individual distribution system planning areas to reflect area-specific investment rather than system-wide investment. According to these parties, standby customers require minimal distribution system additions and would induce no additional costs in a DPA that is uncongested.
FEA does not support standby rates reflecting geographic distinctions unless the same methodology is used to determine rates for full requirements customers. The utilities do not support area-specific standby rates under any circumstances. PG&E asserts that while localized distribution rates might send more accurate price signals for customers, it cannot rely on price incentives alone to ensure adequate capacity is available to serve load. PG&E and SDG&E prefer individual contracts with physical assurance provisions to localized rates. SCE cautions against a piecemeal introduction of localized rates. All utilities claim that averaging utility rates across a service territory fairly spreads the costs of system improvements to all customers.
6.6 Transmission Charges/Gross Load Metering
ORA recommends that standby customers have the option of taking service at either distribution or transmission voltages, as they do today, with appropriately differentiated cost-based rates for each service.
State Consumers urge the Commission to advocate before FERC for marginal cost pricing for the transmission component of standby rates. Use of marginal cost-based transmission charges would accommodate transmission-related discounts where distributed generation can reduce line losses and help meet local reliability needs through provision of reactive power and voltage support. Discounted standby rates would serve as a proxy until the ISO either implements competitive procurement or pays distributed generation providers on a contractual basis for ancillary services.
State Consumers and CAC/EPUC support further unbundling of the transmission component of standby service. Both oppose the ISO's proposed policy to meter the gross loads of distributed generation customers and charge the ISO Grid Management (GMC) and Transmission Access Charges (TAC) for gross load even if the load is partially or entirely met by on-site distributed generation. State Consumers assert that only costs associated with a distributed generation customer's load taking energy from the grid should be reflected in standby rates. State Consumers assert that the Commission should enforce the mandate of Pub. Util. Code § 372(f) to "undertake all necessary efforts to revise, mitigate, or eliminate the policy or action of the ISO that unreasonably discourages cogeneration or self-generation." State Consumers assert that the ISO's gross load metering policy is exactly the type of "unreasonably discouraging" policy or action that § 372(f) was designed to address. State Consumers urge the Commission to file a position at FERC protesting the ISO's gross metering proposal
6.7 Interruptible or Non-Firm Standby Rates
Non-firm standby service would interrupt distribution service to customers during periods when load on the associated distribution circuit is constrained. Enron, CAC/EPUC, Capstone, et al., ORA, FEA, and TURN all propose that non-firm options be offered for backup standby service. None of these parties evaluated any of the current interruptible standby options offered by the utilities. Nor did any party offer specific recommendations for designing this type of option.
ORA indicates the utilities should have no responsibility to include non-firm standby demands in the forecasted peak loads of their resource plans. ORA states that customers would have to accept energy delivery on an interruptible or as-available basis, and in return, the utilities could eliminate reservation charges for non-firm service.
Both PG&E and SDG&E currently offer varying types of non-firm standby services. SDG&E is willing to continue its interruptible program; PG&E has proposed to eliminate the non-firm option in its pending GRC application, since non-firm programs have typically related to provision of generation service. PG&E indicates that non-firm service options for distribution service would be possible provided the discount accurately reflects cost savings and PG&E could rely on the customer's curtailment.
PG&E's current non-firm standby service is contained within its standby tariff. Customers who choose non-firm standby service under Schedule S must have at least 500kW of average peak-period on-site load, participate in PG&E's emergency curtailment program, maintain a communication channel from the customer's facility to a PG&E control center, and be subject to pre-emergency and emergency curtailments each year. Customers who do not curtail upon request are subject to a penalty over and above the regular charges. PG&E provides bill reduction credits for curtailment during on-peak and partial peak periods, and an additional credit for customers who participate in the Under Frequency Relay program.
SDG&E offers two interruptible standby services. The first service is offered primarily through its Schedule AV-1, a general service, time-of-use tariff most commonly selected as the otherwise applicable tariff by distributed generation customers on Schedule S-Standby tariff. Schedule AV-1 allows customers with or without on-site generation to choose whether or not to shed peak load in response to an electronic signal notification by the utility. The utility typically signals customers when SDG&E's system load reaches peak levels, or when either the utility or the ISO calls a Stage 2 or Stage 3 emergency. The customer may choose to pay higher peak prices or curtail load. SDG&E states that customers achieve bill savings on AV-1 as a result of lower prices in all periods other than the signaled peak, and the fact that there is no on-peak demand charge associated with Schedule A-V1.
SDG&E's second interruptible standby option is offered through Schedule S-I Standby Service-Interruptible. This tariff allows customers with total load over 500 kW to avoid the minimum charge provision of their applicable tariff, Schedule AL-TOU, and the costs associated with the peak load being curtailed. Curiously, SDG&E's current Schedule AL-TOU does not have a minimum charge rate component, so it appears the benefit of the waived minimum charge in Schedule S-I is already conferred in Schedule AL-TOU. SDG&E requires a customer on Schedule S-I to install a circuit breaker with remote control capability for the utility to disconnect interruptible load during periods of curtailment. Customers on Schedule S-I receive a thirty-minute notification prior to interruption, and must drop load during interruption periods. There are currently no customers taking service under Schedule S-I.
SCE recommends that the Commission reject proposals for non-firm or interruptible standby rates. SCE states that the majority of distribution costs are fixed and are not avoided when the customer provides the utility with the right to curtail its load at the time of a shortage of distribution capacity. Moreover, SCE states that, due to the limited number of participating customers on each circuit, the utility would need to have physical assurance that these customers will not impose backup load on the distribution circuit at the time it peaks. Traditional penalties such as high "excess energy" charges will not be sufficient to ensure the reliability of the distribution system.
PG&E also opposes any future requirement to provide non-firm standby and states that future non-firm service options for distribution would only be possible provided that the discount accurately reflected the cost savings and that PG&E could rely on the customer's curtailment. PG&E argues that price incentives, by themselves, do not provide the assurances required to ensure sufficient capacity is available to serve the load. In addition, PG&E states that it is unaware of how the physical details of the hypothetical non-firm standby service would work, or what the physical steps would cost. The facilities necessary to make sure that the load never draws on the utility during peak hours have not yet been designed or tested.
R.99-10-025 questioned whether a valuation methodology should be established to assign value for potential distribution benefits of distributed generation. In Phase 1 of this proceeding, parties submitted testimony on the concept of a valuation system, and whether such a system is needed.
Several parties submitted Phase 1 and Phase 2 testimony that supports recognizing certain benefits provided by distributed generation users to the distribution system. Potential benefits listed by parties include extended distribution equipment life, deferral of distribution capacity upgrades, increased supplies of reactive power and lower energy supply costs for non-generating ratepayers. In Phase 2, TURN, ORA, Joint Parties and State Consumers proposed methods to reflect these potential benefits, which included standby rate credit mechanisms and other standby rate designs, such as time-of-use rates and locational or geographic-specific pricing.
TURN did not propose a specific methodology to quantify distributed generation benefits. In general, TURN urges the Commission to direct the utilities to design standby rates that recognize distributed generation's economic benefits to encourage deployment that will produce cost savings for both utilities and customers. TURN supports a standby rate structure where customers with less reliable generators pay a higher amount for more frequent use of the distribution system. TURN further supports the concept of time-of-use standby rates that provide incentives for customers to operate distributed generation in a manner consistent with peak demand in the local distribution system.
ORA supports credits to reflect specific localized benefits of distributed generation. Joint Parties supports locational standby rate riders or credits to reflect distribution cost savings due to distributed generation installed in a given geographic area. Joint Parties indicates that the form contracts proposed by SDG&E could serve as a starting point for this approach.
SDG&E's Form Contract proposal was presented in Phase 2 as a methodology to value distributed generation benefits to the distribution system. SDG&E proposes to provide credits when distributed generation is installed to meet SDG&E's criteria: right location, right time, right size, and with physical assurance such that SDG&E is able to avoid a distribution capacity addition for at least one year. SDG&E states that since its current standby rates apply only to QFs and not distributed generation, the credits would apply to the distributed generation customer's on-peak demand charges from Schedule AV-1.15 The 3 MW load normally served by onsite generation would take backup standby service.