4. Discussion

We first address CEC's May 17 petition. We agree that ABX1 29 does require mandatory TOU or RTP metering for customers whose usage is greater than 200 kW of peak demand and we will modify Section V.A. Moving to Time of Use Meters for Commercial Customers of D.01-05-064 to clarify that meter installation is mandatory under ABX1 29 and reflect CEC's position that it intends to install only RTP meters with the $35 million allocated under ABX1 29. We recognize the concerns of CEC, PG&E, AEI, and ORA that our requirement that customers who receive these meters be shifted to TOU schedules may be viewed as a penalty by customers.

Our intent in requiring mandatory TOU participation for customers receiving upgraded meters under ABX1 29 is to ensure that the state's $35 million investment in the sophisticated metering systems delivers the benefit of reducing California's energy demand, especially at times of supply shortages. Customers can meet this objective by participation in demand reduction programs offered by the Commission, or by being on a TOU rate schedule. CEC's choice of RTP rather than the less expensive TOU metering systems makes it even more beneficial for customers to participate in a demand reduction program, as all of these programs, including RTP, utilize the sophisticated features of RTP metering systems. We include in our discussion of demand reduction programs the new Demand Bidding Program (DBP) adopted by the Commission in D.01-07-025. Attachment A to D.01-04-006, "Changes to Current Interruptible Programs, New Interruptible Programs, and Rotating Outage Programs" will be updated to reflect the new Demand Bidding Program, as it has been updated for other demand reduction programs in D.01-05-090 and D.01-06-087.

We should modify D.01-05-064 to permit customers receiving an RTP metering system who are not already on a TOU schedule to choose to enroll in a demand reduction program included in the revised Attachment A to D.01-04-006, rather than be automatically shifted to a TOU schedule. Customers should make this election within 15 days of installation of the new metering system. Customers failing to choose a demand reduction program or TOU schedule shall be placed on a TOU schedule.

The RTP metering system installation being administered by the CEC pursuant to ABX1 29 covers SDG&E as well as PG&E and Edison. RTP issues involving SDG&E that were to be addressed in A.00-10-045 and A.01-01-044 were transferred to this proceeding by ALJ Wetzell at hearings on June 1, 2001, based on a motion by CEC (Tr. at 352). Therefore, the modified language we adopt here should also apply to SDG&E, who is a party to this proceeding.

To address the issues discussed above, we will modify Section V.A. by deleting the last two paragraphs of the section (mimeo. at 32) and replacing them with the following language:

Pursuant to ABX1 29, the CEC is authorized $35 million for the installation of TOU or Real Time Pricing (RTP) metering systems on all customers with electric loads over 200 kW of demand. Under this mandatory program, the CEC has chosen to install RTP rather than TOU metering systems. RTP metering systems provide the communication capabilities necessary for customers to participate in specific load reduction programs, DRPs, administered by the Commission, the ISO, and CDWR. These programs, including the proposed Demand Bidding Program (DBP), currently pending before the Commission in R.00-10-002, offer customers incentives for reducing energy consumption and demand during high net short periods. In order for California to realize the benefits of ABX1 29 metering expenditures, all customers who receive the meters should be on a demand reduction program as listed in the revised Attachment A to D.01-04-006 or placed on a TOU schedule. Customers should make this election within 15 days of installation of the new metering system. Customers failing to choose a demand reduction program or TOU schedule shall be placed on a TOU schedule.

In modifying D.01-05-064 to provide customers receiving ABX1 29 metering systems the choice of participating in a demand reduction program or switching to a TOU rate schedule, we should also adopt a monitoring plan to ensure PG&E, Edison, and SDG&E timely install the new meters and to track the selection by customers of a demand reduction program or TOU schedules. To accomplish this, the following paragraph should be added to the end of Section VII.B., Expedited Installation of Meters. (mimeo. at 49):

To ensure effective monitoring of timely installation of the meters we should require PG&E, Edison, and SDG&E to provide a bi-weekly report until all ABX1 29 metering systems are installed that lists the number of RTP metering systems installed and the selection made by the customer of a demand reduction program (DRP), as set forth in revisions to Attachment A of D.01-04-006 or enrollment on a TOU schedule. The utilities should prioritize the installation of these meters to first include customers who are enrolled in a demand reduction program and then proceed to customers with the highest kW peak demand level.

We next turn to CEC's June 12 petition proposing a pro-forma RTP tariff. Based on our review of the petition and filed responses, we have significant concerns regarding key provisions of CEC's proposed RTP tariff and therefore do not grant the CEC's petition at this time.

We appreciate the time and effort the CEC devoted to developing its proposal and recognize the significant constraints it was operating under in quickly putting together its proposal. We plan to follow up on the CEC's initiative by requiring the utilities, as well as other interested parties such as the CEC, to file real-time pricing proposals by August 17, 2001 in this proceeding. To assist all parties, we discuss in detail our concerns with the RTP proposal currently before us and, in the next section, we specify the guidelines parties should follow in submitting RTP proposals on August 17, 2001.

In declining to adopt the CEC's RTP proposal, we must first note that it is not a true real-time pricing program because it does not use a transparent real time price.² Instead, the CEC states it's proposal "masks" the Day Ahead energy procurement prices by attaching an "add factor" that allows additional cost reductions from estimates of avoided ancillary service (A/S) costs that have not yet been priced in the ISO A/S markets and estimates of avoided transmission congestion costs.³ As Edison comments, the CEC contemplates that the methodolgy for calculating the hourly prices will be developed by CDWR, the Electricity Oversight Board, and the CEC and this would require the Commission to delegate to this committee our ratemaking authority under Section 451 et al., of the California Public Utilities Code.⁴

The CEC's proposal also does not bill all usage at a single price, but rather creates a complex Customer Baseline Load (CBL) mechanism⁵ that would pay a customer incentives to reduce load based on how that customer's energy usage varies from an administratively calculated usage pattern. We share the concerns with a CBL mechanism expressed by ORA in its comments.⁶ This administrative calculation is complex, with each customer's reference load capable of being calculated in one of three different ways (depending upon the availability of data) and with customers able to request a "customized" calculation that could take into account other factors such as weather and facility outages. Given that the CEC plans to install over 20,000 meters, each of which would require an individual reference load, this administrative calculation constitutes a significant administrative burden to the utilities.

Another issue the CEC's proposal raises is the appropriate starting point for determining when a load reduction is assumed to occur. As the Commission can attest to from its experience in its rulemaking on interruptible programs (R.00-10-002), the calculation of the reference load is one of the more difficult issues that need to be resolved in any demand responsiveness program. The reference load calculation must reflect, to the extent possible, the actual energy usage that would occur absent any demand responsiveness program. Otherwise, program participants are being paid either for load reductions that would have occurred anyway, or for phantom (or nonexistent) load reductions that result from an incorrect calculation of the reference load. This results in all other ratepayers paying for nonexistent load reductions, significantly affecting the benefits and cost-effectiveness of any program. In some cases, these costs can outweigh even the societal benefits that the programs may offer.⁷

As ORA notes in comments on CEC's proposed RTP tariff, "some conservation credits will be earned for declines in consumption that would have occurred even without the RTP program. This would apply to businesses whose activity is declining for economic reasons..."⁸ Any business whose output is less this year than in previous years due to economic conditions could sign-up for the CEC's program and receive payments for these phantom load reductions. While under a mandatory RTP program there may not be a net cost to ratepayers, as those customers whose energy usage is increasing due to economic conditions would offset those who are decreasing, under a voluntary program only those who would benefit have an incentive to sign-up.

This lack of symmetry also affects the ability of customers to seek a "customized" reference load calculation. While every customer has an incentive to advocate for an increased baseline, thus increasing their potential incentive payments, no customer has a corresponding incentive to advocate for a reduced baseline that would make it more likely for the customer to either not receive an incentive, or perhaps even incur penalties under the program.

In order to address the potential for gaming of the reference load calculations, the CEC proposes that the utilities monitor, if necessary, the output and operation of customers participating in the program to ensure that the customer has not "ceased operations or drastically downscaled customer operations at the facility." (Attachment A, Sec. 3F.) This would involve the utilities in the complex and difficult task of monitoring a customer's operations and output.

Because of the above concerns, it appears that the CEC's proposal would result in a large amount of payments for load reductions that either would have occurred anyway or are phantom reductions resulting from an overly generous reference load calculation. We are concerned that these payments would be greater than any benefits from the program, even taking into account the societal benefits that would occur from any actual load reductions the program achieves.

At page 9 of its petition, CEC states its proposal places CDWR as the entity financially responsible for the payment of incentive costs or receipt of charges from RTP tariff participants and cites Executive Order D-36-01 as authorizing such financial responsibility. We share Edison's concern that the Executive Order does not explicitly designate CDWR as the responsible financial entity and agree that this issue must be resolved before we can adopt a RTP program.⁹

The CEC's proposal goes beyond a real-time pricing program by including a High Reliability Option (HRO) which would offer participants a chance to avoid both blackouts and load reductions. While ORA offers suggestions on adjustments to make this feature workable, such as setting the CBL at zero and the total surcharge at $28/kWh, we agree with PG&E that a program to allow customers to avoid blackouts should not be considered here to avoid unintentional conflict with the Optional Binding Mandatory Curtailment (OBMC) programs which the Commission has already adopted in its interruptible load rulemaking after full litigation.¹⁰

The CEC's proposal also overlaps, and is similar to, our revised Demand Bidding Program. Both programs have as their stated purpose encouraging demand response¹¹; are targeted toward the same customers; pay incentives to customers to reduce load; achieve almost all of their benefits during hours of peak energy usage; and are funded (or proposed for funding) by CDWR.

The major substantive difference is determining the reference load and whether or not CDWR is obligated to purchase the demand reductions. The Demand Bidding Program uses a 10-day baseline to calculate reference load while the CEC's program is proposing a yearly average. While not without its own limitations, and also subject to potential gaming, the use of the average energy usage over the previous ten days better reflects the effects that current energy rates and current economic conditions have on energy usage. It must be remembered that the Commission first approved the use of the 10-day average in PG&E's and Edison's Summer 2000 demand reduction proposals, a proceeding in which the CEC itself advocated for the use of a 15-day (not 10-day) average as being better reflective of actual load reductions.¹²

The second difference between the programs is whether or not CDWR is obligated to purchase demand reductions. Under the Demand Bidding Program, CDWR has the option of either accepting or not accepting bids to reduce load based on conditions in the market. Customers are also allowed to submit bids at four different price points (15, 35, 55, 75 cents/kWh) allowing the CDWR some flexibility to select lower-priced bids while rejecting higher-priced bids. Under the CEC's RTP proposal, by contrast, the CDWR does not have this flexibility.¹³ It would be obligated to both "purchase"¹⁴ all load reductions that are offered and would have to pay for them at its posted real-time price.

Since both programs target the same customer groups, the CEC's proposal both competes with the Demand Bidding Program and limits the flexibility of CDWR to achieve a least-cost procurement strategy. In his letter to the Commission, Governor Davis stated his goal that the Commission "aggressively market" the Demand Bidding Program. Not adopting the CEC's proposal at this time meets the Governor's goal of allowing the Commission, CDWR, and the utilities to focus their efforts on making the Demand Bidding Program successful. Demand Bidding Program is a useful bridge to an RTP program, exposing customers to market-responsive energy planning. Approval of the CEC's program would also run counter to the Governor's stated goal to simplify demand reduction programs and avoid duplication.

Finally, there is a need to fully understand the interactions between the CEC's proposal, the Commission's recently adopted rate structure, and CDWR's revenue requirement. Although incorrectly described by some parties as "revenue neutral,"¹⁵ any shortfalls in revenues will be made up by the CDWR, which in turn will have to collect this shortfall through rates from all other customers. Therefore, it would be useful to have better information about the total cost of the CEC's program, and its potential for intra-class subsidies. Since a portion of the CDWR surcharge will be used to finance bonds that will be used not to pay for current energy usage but to amortize long-term bonds to reimburse the state for the cost of past- and future energy purchases, there is also a need to assess if there are any inter-generational equity issues that should be addressed.

As previously mentioned, the Commission assigned a significant portion of D.01-03-082's rate increase to on-peak energy usage in order to provide a strong incentive for customers to shift energy usage away from these hours. For example, for Edison's industrial customers, almost 15% ($160 million/year) of the rate surcharge is collected in the 4% of the hours in the year corresponding to the summer on-peak.¹⁶ An additional 9% ($96 million) of the surcharge is collected in the 7% of the hours in the year occurring in the summer mid-peak. As these are the same hours being targeted for incentive payments to reduce load under the CEC's proposal, there is a "double whammy" effect on CDWR's revenue stream. It is not only foregoing revenues from on-peak sales but actually paying out additional monies to reduce load.