4. Standby Rates Today

In order to determine whether the existing standby rate design policies fit current market conditions, it is appropriate to review the current standby rate design. Current standby rate design differs significantly among utilities and is quite complex. The timing of the Commission's review of rate design and cost allocation for each utility also differs. In this decision we limit our discussion here to the existing standby rate design previously approved by this Commission.2

Generally, a customer who has installed generation (either a QF or a distributed generation customer) is required to take service on one of the utility's standby tariffs, in combination with their otherwise applicable tariff. The only exceptions to this requirement exist in the residential and small commercial sectors, where net energy metering allows certain wind and solar facilities to avoid standby rates.

SDG&E's current standby service is provided on Schedule AV-1 for customers with distributed generation facilities, and Schedules S and S-I in combination with AL-TOU or other tariffs for QFs. SDG&E has historically had several tariff options that are designed to provide service to customers with non-QF installed generation sources. These include Schedules AV-1, AV-2, AV-3, and RTP-2. Schedule AV-1 is the most commonly utilized of these options. As of January 31, 2000, SDG&E had 41 customers taking service on AV-1, and this represented approximately 80% of all customers using these types of rate options. AV-1 remains open, all others were closed in the rate design window proceeding.

Schedule A-V1 contains a Signaling Equipment Charge, Basic Service Fee, Non-Coincident Demand Charge, Contract Minimum Demand Charge, Signaled Period 1G Energy Charge, Semi-Peak Energy Charge, and Off-Peak Energy Charge. All of these charges vary based on the customer's service level and defined season of the year. The Signaling Equipment Charge is a one-time charge for new customers of $4,580, and covers SDG&E's costs of installing necessary signaling equipment at the customer's site. Under the terms of AV-1, a signaled period, termed 1G, is called when SDG&E's system load approaches peak levels or when either the utility or the ISO called a stage 2 or stage 3 emergency. Customers are notified via electronic signal when a signaled period 1G will commence, and energy prices during this period are much higher than during other periods. Customers with generation facilities usually will operate these facilities during the high-priced signaled period 1G. AV-1 customers pay lower prices to the utility in all periods other than the signaled period, and there is no on-peak demand charge on AV-1. Customers on AV-1 also have the option of signing up for a specified Contract Minimum Demand level, if they are not able to shed their entire load during the signaled periods.

A customer taking service under Schedules S or S-I pays a $/kW standby demand charge based on its contract demand, and receives a waiver of the non-coincident demand charges normally paid on the otherwise applicable tariff through a credit to its bill when its distributed generation unit operates. This credit is not restricted to distributed generation with physical assurance3 or distributed generation operating under a Form Contract.4 If an SDG&E customer's generating facility does not operate, due to a forced or scheduled outage, the customer continues to pay the Schedule S standby demand charge, but the level of the outage, on a $/kW basis, is subtracted from its recorded maximum demand to reduce the non-coincident demand charge on the otherwise applicable tariff. If the outage has been scheduled with SDG&E's concurrence, the on-peak demand charges on the otherwise applicable tariff are waived up to the contract standby level. SDG&E's standby rate design is structured such that Schedule S and S-1 are used to bill standby accounts only for their contracted standby load, but not for actual usage. All energy usage is billed under the otherwise applicable tariff.

SCE's tariffs function in a similar manner. SCE's schedule S is applicable to customers taking service under a regular SCE rate schedule who have an alternate power source. Schedule S operates as a rider to the customer's otherwise applicable tariff. Under these schedules, the customer's contracted standby demand, also referred to as standby reservation capacity, is established at the lower of the nameplate capacity of the generator and the customer's maximum expected demand. The standby demand charge on SCE's current Schedule S is the same as the facilities-related demand charge on the customer's otherwise applicable tariff and is calculated on a $/kW basis. These charges are designed to recover the costs of transmission and distribution facilities dedicated to the customer's use that do not vary with usage and exclude coincident capacity costs that can be avoided by a standby customer, or group of standby customers, by reducing their demand at system peak. Because standby customers' demand charges reflect facilities-related costs assigned to customer based on their non-coincident maximum demands at their sites, SCE argues that its rates already reflect diversity, but no specific diversity factor is applied to the standby demand charge. A monthly reservation charge ($/kW) also applies to all kW of standby demand.

The distributed generation customer pays all of the applicable charges under the otherwise applicable tariff in addition to the standby and generation reservation charges. However, when the otherwise applicable tariff contains a facilities-related demand charge, prior to applying the facilities-related demand charge, the standby demand is subtracted from the facilities-related billing demand5 to avoid duplicate demand charges.

None of the other SCE demand charges are reduced for standby demand. The customer's total demand charge is the sum of the adjusted facilities-related demand component and the time-related demand component from the otherwise applicable tariff. 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 will pay the standby demand charge. In addition to the demand charges, when the customer takes energy from SCE, the customer will be charged based on the energy charges of its otherwise applicable tariff.

PG&E's standby tariff, Schedule S, is structured to function as a stand-alone tariff for customers whose distributed generation unit normally meets their load and who only require backup or maintenance standby service. In this situation, only PG&E's Schedule S would apply. PG&E's Schedule S includes: 1) a monthly reservation charge equal to 85 percent of the customer's contract reservation load6; 2) time-differentiated, seasonal energy charges ($/KWh) for distribution based on the actual backup power purchased; 3) customer charges; and 4) reactive demand charges. No charges are applied from other rate schedules.

For PG&E customers whose load normally exceeds their generation capacity, the customer's otherwise applicable tariff is used in combination with Schedule S. The reservation charge from Schedule S is applied based on the contract capacity. The otherwise applicable tariff is used to calculate customer charges and usage charges. Currently, if a supplemental service7 customer imposes a demand due to an outage of its generator, and the otherwise applicable tariff is the E-19 or E-20 interruptible tariff, the customer's charges on E-19 or E-20 are reduced by the standby reservation charge from Schedule S in order to avoid double payment for reservation charges. For supplemental standby customers, the otherwise applicable rate would apply to service beyond the level served by the generator, together with the standby charge.

PG&E's current rates reflect a diversity discount developed based on experience with generators serving onsite load connected at the transmission level. Currently, distribution level distributed generation customers receive the same discount off the actual cost of standby service based on assumed lower costs to the utility resulting from generation diversity.

For all three utilities, the demand and energy charges also vary according to interconnection voltage level (secondary, primary, and transmission).

2 PG&E, SDG&E, and SCE all have pending rate design applications before the Commission. We describe some of the utility proposals in those applications in the Positions of Parties Section as they relate to standby rates. 3 For purposes of this decision, physical assurance is defined as the application of devices and equipment that interrupt a DG customer's normal load when DG does not operate. (Derived from SDG&E Opening Brief-Phase 1, p. 31.) 4 SDG&E proposes to enter into Form Contracts of one-year duration with DG customers for the provision of electric distribution service. DG customers will provide physically assured load reduction based on either the availability of installed DG capacity, or by load reduction if the full capacity is unavailable. The Form Contract specifies the amount of available DG capacity, and provides for either a bill credit or monthly payment based on reduced on-peak demand charges. 5 The level of recorded demand in a given month or billing period is the billing demand. 6 PG&E's contract capacity is subject to a three-year ratchet provision to allow for increases and decreases over time based on DG performance. 7 PG&E refers to this service as mixed-use. For consistency, we refer to this type of service as supplemental service throughout this decision.

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