4 Discussion

We are persuaded to adopt SDG&E's proposal, but with modifications designed to ensure that the program is reasonably priced, as well as not conferring an undue advantage upon one group of customers over another. As SDG&E says, this is an opportunity to capitalize on available resources to reduce the impact of rolling blackouts that may occur this summer.

SDG&E estimates that the CAISO will most likely require 1,000 megawatts (MWs) of reductions statewide during Stage 3 firm load reduction events in Summer 2001. SDG&E says its share of the 1,000 MW is 7.4%, or 74 MW. SDG&E expects approximately 75 to 100 MW might be made available through the RBRP, with about 50 MW from existing sources, and 50 MW from new sources. Therefore, SDG&E believes the RBRP can be reasonably expected to reduce the number and duration of rotating outages in San Diego. Whether or not these exact megawatts materialize, we agree that an opportunity is presented here that merits adoption.

We agree with SDG&E's proposal that the program run for one year. We will assess its use for Summer 2002 after we have experience during Summer 2001.

SDG&E proposes that the program be implemented only in the SDG&E service territory at this time. While we approve SDG&E's program based upon the record before us, we understand that the State of California may also be considering various backup generation proposals of its own. Should such proposal be implemented, and be applicable to utilities other than SDG&E, this proceeding will serve as the forum for implementation issues that the Commission may need to address.

We also adopt SDG&E's proposal that participating customers must have an emergency BUG capable of providing at least 15% of the customer's annual maximum demand, but not less than 100 kW. This will focus the program on customers with the most ability to reduce demand on the system, without draining administrative resources on small potential reductions. Moreover, it is consistent with standards already adopted in the Base Interruptible Program (BIP) and the Voluntary Demand Response Program (VDRP).

SDG&E proposes that it notify participating customers to reduce demand through the use of the customer's BUG when SDG&E "receives notification from the ISO that a Stage 3 event and rolling outages have been declared." (Emergency Petition for Modification, page 4.) We concur, and clarify that our approval is based on the CAISO actually ordering the implementation of firm load reductions on the SDG&E system. That is, there may be time between the CAISO first calling a Stage 3 event, and the CAISO later calling for actual firm load reductions. It is the latter event which will trigger the RBRP, and which we endorse, as reflected in proposed Schedule RBRP.⁴

Further, a BUG may need some reasonable amount of time to ramp-up its operation, or to continue operation without jeopardizing critical functions, and thereby improve participation. The San Diego APCD defines an emergency as an unforeseen failure by the serving utility to provide power to the customer. The APCD considers such failure to exist when the statewide electrical reserves fall to 3% or less and the CAISO has officially forecast the clock time (e.g., 4:45 p.m.) when statewide electrical reserves will fall to 2% or less (i.e., a Stage 3 electrical emergency is imminent). The APCD considers the emergency to begin at this CAISO forecast clock time, and states that BUGs may startup at this clock time, and run until no more than 30 minutes after the ISO advises that the Stage 3 is no longer imminent or in effect. We agree to the extent that Schedule RBRP should permit BUG operation from the CAISO forecast clock time for firm load curtailments through 30 minutes after the CAISO advises that firm load curtailments are no longer necessary.

SDG&E conditions Schedule RBRP on the customer being responsible for operating its BUG in compliance with all federal, state and local laws and regulations, including those regarding air quality. Again, we agree.

The proposal raises several concerns, however, including prices, disincentives relative to other programs, air pollution and the attendant health effects, and measurement of firm load reductions. As a result, we adopt the program, but with the following limited modifications, conditions, and clarifications.

4.1 Capacity Payment and Interconnection Allowance

We decline to adopt either the proposed capacity payment, or the interconnection allowance, for several reasons.

First, as PG&E points out, the RBRP provides incentives that exceed the levels available in other programs for largely the same level of load relief. That is, SDG&E proposes to compensate RBRP customers as if they are simultaneously participating in both the BIP (at $7/kW/month) and the VDRP (at $0.35/kWh). This provides generous compensation for last-minute load reductions when those reductions are sought earlier in other programs. This is not the optimal incentive to give customers.

We do not want the compensation available in the RBRP to be so attractive that customers elect the RBRP over other programs that are more cost-effective for ratepayers, and, by declining other programs in favor of RBRP, actually precipitate Stage 3 events. Rather, we seek customer participation in necessary load relief and interruptible programs early, with continued participation in those programs through Stage 3. For example, BIP and VDRP programs that begin in Stage 2 do not stop during Stage 3. We do not want to authorize a program that creates unreasonable conflicts between programs.

Second, the total costs are high. Using SDG&E's assumptions, the average payments are $0.56/kWh to existing BUGS, and $0.61/kWh to new BUGs.⁵ The total cost to ratepayers is $0.735/kWh, including costs incurred by SDG&E for metering, monitoring, administration and marketing.⁶ Ratepayers' pockets are not bottomless. Further, the participating customer avoids energy costs that it would otherwise incur were it not to reduce load under the program.

In support of RBRP price levels, SDG&E argues that customer interest in existing programs has been underwhelming. SDG&E asserts that the RBRP would not be necessary if customers were interested in other programs. SDG&E says it has designed the RBRP with incentives to generate sufficient customer interest.

We are not convinced. SDG&E overlooks that, for the other interruptible programs authorized by the Commission, most customers may not provide load reductions to the grid through the use of their backup generation. Except for those customers with permitted equipment, backup generation can only be run when that individual customer is subject to a rotating outage, not when the system as a whole is declaring rotating outages. As the San Diego APCD notes, most backup generation can only be run during an "emergency" defined as when ISO reserves fall below 3%.⁷ Therefore, most backup generation (unless specifically permitted) would be unable to be used as part of other Commission interruptible programs which are triggered when operating reserves are in the 5-7% range (Stage I and II.)

Additionally, tariffs for SDG&E's other programs have been approved only recently, with additional time having been required to bring those tariffs into compliance with D.01-04-006. Customer interest in existing programs can be measured only after reasonable marketing by SDG&E, and a reasonable opportunity for customers to enroll in those programs. We are not convinced that there is a lack of interest in existing programs until there has been both adequate marketing and a reasonable opportunity for enrollment.

Third, the capacity payment necessitates a penalty structure that is needlessly complex. The proposed penalty requires the customer to forfeit increasing amounts of the $7/kW/month capacity payment for one or more failures to comply, and further, in some cases, obligates the customer to pay penalties. Enough failures eventually result in termination from the program. The entire program can be designed more simply, as described below, without capacity payments and a complex penalty structure.

Fourth, paying for capacity would require notification procedures that complicate an already complex system. The program is a demand reduction program, not a program for providing generation capacity to the grid.

Finally, we decline to use the RBRP to pay fixed costs. A capacity payment to an existing BUG compensates the BUG's owner for the fixed cost of the investment. The fixed cost of an existing BUG has already been incurred by the owner, however, and the BUG is in place. Rather, we seek to compensate the owner for the incremental cost of running the BUG, and authorize an energy payment for that purpose.

Further, a capacity payment to a new BUG provides compensation for putting in new investment. Similarly, the interconnection allowance provides an incentive to install a new BUG. In both instances, ratepayers help the BUG owner with the cost of installation. We decline to use this program to facilitate installation of new BUGs. Customers already have adequate incentive to install, own and operate BUGs for many reasons, including the customer's own need or desire for reliability. Moreover, we have existing programs to provide incentives for the installation of distributed generation, including BUGs. We are not convinced that we should disturb existing incentives and programs with yet another program absent more information and further consideration.

Agencies throughout the State have been working diligently to keep existing generating units on-line, and quickly approving permits for new, clean, efficient power plants. The use of existing BUGs may fill an urgent need for Summer 2001, and an energy payment will provide reasonable incentive for their operation. The State is better served overall, however, by new, clean, efficient power plants built to serve ratepayers at reasonable prices based on the cost of service. Our efforts should be directed to that end.

For all these reasons, we decline to authorize either the $7/kW/month capacity payment, or the $10/kW interconnection allowance.

4.2 Energy Payments

We adopt an energy payment to provide the necessary incentive for BUG operation during periods of firm load curtailment. We decline, however, to adopt SDG&E's proposed rate of $0.35/kWh.

As already noted, customers have either already incurred the fixed costs of their BUG, or have chosen for their own economic reasons to acquire new BUGS. Therefore, the RBRP energy price needed to encourage participation should only be sufficient to pay for the incremental operating costs of running the BUG, plus an incentive.

BUG operators will avoid high on-peak rates by BUG operation, and need little additional incentive. Also, we primarily want customers to participate in existing programs, including BIP, VDRP and OBMC. The RBRP is a last resort, and the incentives should direct customers to existing programs first. Further, the operating cost of BUGs, particularly diesel BUGs, is moderate. Finally, ratepayers must not be burdened with excessively high prices.

The payment level we adopt also needs to take into account the difference between this program and other interruptible programs. Most customers participating in our existing interruptible programs must either reduce output or shift production to off-peak periods in order to reduce their electric load. Therefore, in many cases these customers must factor in the costs of reduced production in their decision to participate in an interruptible program. Under SDG&E's BUG program, by contrast, customers are using their BUGs to displace energy that they otherwise would be taking from the electric grid. Accordingly, these customers do not suffer the financial consequences of lost production revenue that they would incur by participating in other interruptible programs.

Finally, we must also take into account the interaction of this program with other incentives adopted by the Commission to reduce load. Load reductions achieved in this program, as with other interruptible programs, count towards a customer's qualification towards meeting his or her "20/20" goal of reducing load by 20%.

We conclude that a significantly lower payment is appropriate for this program because customers participating in SDG&E's RBRP have already incurred the fixed costs of their backup generation, and they are in many cases able to participate in the program without reducing their production. Further, they improve their eligibility to achieve compensation under the 20/20 energy savings program, and they avoid high on-peak energy charges they otherwise would incur.

As a result, we adopt a rate of $0.20/kWh. To provide for rapid adjustment of the price, if needed, we adopt the same mechanism as used to adjust VDRP prices. (D.01-04-006, mimeo. pages 30-33.)

4.3 Rotating Outage Exemption

In addition to financial benefits, SDG&E proposes that RBRP customers receive exemption from rotating outages if load reductions are 15% or greater on the customer's circuit compared to the previous year's usage. This is similar to the exemption provided customers in the OBMC program. OBMC participants, however, receive only an exemption from outages.

We modified the OBMC program in April 2001 based on comments in Phase I. We reduced the required maximum curtailment for OBMC participation from 20% to 15%. (D.01-04-006, mimeo. page 38.) In doing so, we considered the increased benefit to potential new OBMC participants (i.e., exemption from outages for those who could participate at 15% but not at 20%), and the potential for increased OBMC participation with concurrent benefit to the entire system and State. We balanced this against the potential of reduced benefit to the public and the State by lowering the required curtailment percentage.

We are not persuaded to further modify that balance by granting an exemption to RBRP participants. We think this unreasonably conflicts with the adopted OBMC program, and sends the wrong signals to potential OBMC participants. As a result, we decline to authorize exemption from rotating outages as a provision of Schedule RBRP.

4.4 Environmental Dispatch

We are also concerned with environmental consequences. Firm load curtailments are probable on the hottest days, when air conditioning load is highest. Hot days tend to have poor air quality. This program will result in an incremental increase in BUG operation. The benefits of avoiding outages must be balanced against the harm from increased air pollution.

In its reply, SDG&E states that it will commit to employ environmental dispatch of BUGs, to the extent feasible. SDG&E's plan is to segregate the units into blocks, and dispatch the blocks with the cleanest burning engines first. According to the San Diego APCD, this means engines fired by natural gas, liquid petroleum gas (LPG) or gasoline before those fired by diesel fuel.

We adopt SDG&E's commitment. We condition approval of Schedule RBRP on environmental dispatch, wherein SDG&E will call upon the cleanest BUGs first.

4.5 Interaction with Other Programs

We have eliminated most potential conflicts with other programs in the modifications adopted above. As a result, RBRP customers may simultaneously enroll in any other program offered by SDG&E, including BIP, VDRP, and OBMC (absent any restrictions stated in the other program).

To further ensure programs do not conflict, however, we also require that any payments under the RBRP be only for generation that is not on line when the RBRP is called. That is, a customer may not use its BUG to perform under the VDRP, and be paid a second time under the RBRP. If, however, the customer is performing under the VDRP without use of its BUG, and elects to operate its BUG during an RBRP event, the customer is eligible for payment under the RBRP for operation of its BUG.

4.6 Measurement

SDG&E proposes that the amount of BUG generation brought on line be used to offset the amount specified by the CAISO for SDG&E's share of total Stage 3 firm load curtailment. The CAISO expresses concern.

The CAISO says in principle it is accurate that generation on the customer's side of the meter can help relieve demand on the grid. The CAISO, however, does not endorse counting the energy produced by BUGs located in the SDG&E area towards SDG&E's share of firm load curtailment required by the CAISO. According to the CAISO, BUGs may be in operation prior to the CAISO's declaration of Stage 3. In cases where the BUG is operational before Stage 3, its contribution would become part of the system resources prior to implementation of firm load curtailment. According to the CAISO, SDG&E seeks to count on capacity that could have been made available to avoid or reduce firm load curtailments in the first place. CAISO concludes that for this reason it does not support SDG&E's program as proposed. Further, to the extent other utilities seek similar treatment, the CAISO says its ability to maintain system reliability would be undermined. We disagree.

The San Diego APCD policy prohibits customers from operating BUGs before Stage 3 unless they are doing so to avoid their own facility's curtailment. Thus, a customer's BUG will come on prior to Stage 3 only if its circuit is in the next block at risk of an outage. SDG&E's experience with rolling outages to date is that less than 5% of BUGs would likely be operational prior to Stage 3. Moreover, some BUGs will be on exempt circuits, further reducing the actual operational number. Thus, as SDG&E points out in its reply comments, the CAISO's concern that any significant number of BUGs will be running prior to Stage 3 is not compelling.

Further, the CAISO's concern does not recognize that a generator running before a Stage 3 event will stop running, even during Stage 3, once the customer's circuit has passed through its allotted one hour blackout. Additionally, the customer will not run its generator at all if the customer believes a blackout is unlikely, even during a Stage 2 or 3, absent compensation. Thus, there is very little or no overlap between BUGs used to meet the customer's own emergency needs and those that will be used in the RBRP to maintain system reliability.

As SDG&E points out, statewide concerns, even if meritorious, need not be determinative since this program is only in the SDG&E area at this time. More importantly, however, the program will enhance, not undermine, system reliability. Any additional generation used to either reduce a customer's demand, or make a contribution to the grid, can only assist with overall system reliability.

As a result, we adopt SDG&E's proposed measurement of BUG operation used during the RBRP.

4.7 Cost Recovery

SDG&E asks for current recovery of RBRP costs (e.g., a rate surcharge). Alternatively, SDG&E seeks permission to track program costs in the memorandum account authorized in D.01-04-006.

We continue to decline current recovery for these costs, just as we did in D.01-04-006. Rather, we authorize accounting of RBRP costs in the memorandum account established by D.01-04-006.⁸ The accounting must separately identify costs attributable to the RBRP. The limits adopted in D.01-04-006 continue to apply (e.g., $25 million per year for SDG&E), subject to SDG&E applying for modification of those limits, as described in D.01-04-006.