The comments we received on Energy Division's proposals were extensive and generally very constructive. In the following sections, we concentrate on the chief points of contention, and do not try to summarize every nuance in the comments.
Pub. Util. Code § 399.15 specifies that the Commission shall "include the reasonable costs involved...in the distribution revenue requirements of utilities regulated by the commission, as appropriate."
To implement this provision, Energy Division recommends that funding for the proposed programs be collected from ratepayers through a non-bypassable usage-based charge, similar to the public goods charge. Energy Division assigns some of the program costs for self-generation to gas ratepayers; however, the majority of program costs are allocated to electric ratepayers. Energy Division recommends that program expenditures be tracked in a balancing account until ratemaking can be formally addressed in each electric utility's next cost of service/performance-based ratemaking proceeding, and SoCal's next biennial cost adjustment proceeding.
The utilities strongly object to Energy Division's recommendations to track costs until future rate recovery proceedings, arguing that such an approach would further jeopardize their already fragile financial position. SDG&E and SoCal take the positions that the entire public, and not just utility ratepayers, should be responsible for funding these programs.
TURN contends that most of the private benefits of the self-generation program accrue to non-residential program participants, and argues that residential customers should probably not subsidize these program costs at all. TURN requests that we track all program costs and benefits by customer class before adopting a specific cost allocation.
Until we have determined that the electric rate freeze is over for PG&E and SCE,4 or until there is specific Legislative authority to impose an additional charge to recover these costs, we cannot consider granting the rate relief requested by the utilities, particularly not in this rulemaking proceeding. Nor can we ignore the Legislature's clear direction to include the cost of these programs in distribution revenue requirements. We recognize that SDG&E's rate freeze is over, although there is a rate cap on SDG&E's generation-related rate component. However, SDG&E is also subject to PBR for its distribution revenue requirements. It would be inconsistent with the PBR framework to address the level of SDG&E's distribution revenue requirements and rates on a piecemeal basis. Instead, SDG&E should address the costs of these programs within the context of the PBR mechanism in its next PBR and cost-of-service proceeding. For PG&E and SCE, where the rate freeze is still in effect, we direct them to increase their distribution revenue requirements, without modifying current rates, to reflect today's authorized budgets.
Should general fund appropriations be made available for demand-responsiveness and self-generation programs through subsequent Legislative action, we will consider augmenting today's approved programs. As described further below, the Energy Division's proposed programs consist of a focused set of pilots that can be broadened to encompass additional market sectors, technologies and system sizes, if and when appropriate.
Within 15 days, PG&E and SCE shall file Advice Letters increasing their electric distribution revenue requirements, without modifying current rates, for this purpose. SDG&E shall address the funding of these programs in its next PBR and cost-of-service proceeding. On the gas side, PG&E, SDG&E and Southern California Gas Company (SoCal) should include the costs of these programs in their next gas rate recovery proceeding, e.g., the Biennial Cost Adjustment Proceeding. In the interim, all program costs should be tracked in memorandum accounts, and the utilities should establish such accounts for this purpose. We will address specific cost allocation issues, including the one raised by TURN, when we address the rate recovery for these programs. In the meantime, the utilities should track all program costs and benefits by customer class, as TURN recommends.
Several parties request clarification regarding the allocation of costs for the self-generation program between electric and gas customers of the combined utilities. As discussed in the Energy Division report, some of the program costs for self-generation are assigned to gas ratepayers, as well as electric ratepayers, to reflect the public benefits (e.g., environmental) that will accrue to gas ratepayers as well. (Report, p. 7.) To establish the budget for each individual utility, Energy Division allocated the total costs for the self-generation program (developed on a statewide basis) to each service territory based on the relative proportion of costs currently allocated to each utility for energy efficiency programs. In our opinion, this represents a reasonable proxy for the allocation of benefits between gas and electric customers that we can expect from the self-generation program. In the Advice Letter filings described above, PG&E and SDG&E should present the specific factors they use to allocate costs between their electric and gas customers, for the purpose of increasing their electric distribution revenue requirements.
The comments reflect divergent opinions concerning the appropriate size and scope of the AB 970 demand-responsiveness and self-generation initiatives. ORA, for example, recommends a much larger overall program funded at $300 million per year, whereas other parties, such as PG&E, express concerns that the level of ratepayer funding proposed by the Energy Division may be too ambitious at the proposed $138 million annual level.
Parties also differ with respect to the scope of technologies and applications that should be eligible under the proposed programs. Whereas the Energy Division recommends that all customer sectors be eligible under the self-generation initiatives, ORA recommends limiting the incentives to non-public sector retrofit applications for residential and small/medium businesses. CEC recommends expanding eligibility to cover installations of DG systems on either side of the customer's meter, rather than only on the customer side, as recommended by Energy Division. Capstone recommends that the eligibility of renewable technologies be expanded by lowering the proposed size minimum of 30kW to 10kW, while PG&E and SDG&E recommend that self-generation units be subject to specific size limits.
With respect to the demand-responsiveness pilots, several parties propose significant expansions in scope to include additional options and technologies. For example, CEC recommends that the demand-responsiveness pilots include load curtailment options that address lighting (e.g., dimmable ballasts), metering technologies and market-based rate designs. CEC also recommends that the internet information test pilot be expanded to encompass full-scale deployment of metering systems that provide real-time usage data feedback through internet-based systems to customers. Cannon Technologies recommends that the pilots be expanded to include additional peak reduction technologies that allow the utilities to interrupt load on a one-way basis. Along these lines, TURN recommends that the Commission authorize expansions in the utilities' existing direct load control air-conditioning cycling programs as part of the AB 970 initiatives.
It is clear from the comments that the AB 970 initiatives could be expanded to greatly exceed the $138 million annual budget developed by Energy Division, by including a wider array of technologies, system sizes and applications. However, we are not persuaded that such expansion is in the public interest at this time. Instead, we concur with Energy Division that the § 399.15(b) initiatives should encompass a specific set of programs that can be tested on a pilot basis, without risking major investment of ratepayer funding on a full-scale statewide rollout. In this way, we will complement, rather than duplicate, initiatives for peak-demand reductions that are being explored in the Commission's rulemaking into the operation of interruptible programs (Rulemaking (R.) 00-10-002), proceeding on real-time pricing (Application (A.) 00-07-055), as well as programs being implemented under the CEC's AB 970 demand-responsiveness grant programs and renewables programs.
We believe that Energy Division's proposal for overall program size and scope best accomplishes this goal. Although several parties critique various aspects of the Energy Division's preliminary cost-benefit analysis, no party presents convincing argument or analysis to indicate that the level of proposed funding represents an unreasonable investment in demand-responsiveness and self-generation, relative to expected benefits.5 We find that Energy Division's proposed annual funding level of $137.8 million for the § 399.15(b) demand-responsiveness and self-generation initiatives to be reasonable. Should additional funding become available via legislative action, we may consider expanding today's adopted demand-responsiveness and self-generation initiatives in a subsequent decision. We may also consider future funding increases for these programs via distribution rates, in this rulemaking, as we gain further experience with the programs adopted today.
SCE requests that we clarify the relationship between the programs adopted in this rulemaking and those being considered in the interruptible rulemaking, R.00-10-002. Nothing in this decision is intended to preclude or prejudge the Commission's consideration of additional initiatives involving interruptible programs (for all customer groups including the residential and small commercial sector) in that proceeding.
Although we generally concur with the Energy Division's proposed size and general scope of program initiatives, we do lower the minimum size requirement for receiving renewables incentives and make specific improvements to design and implementation parameters, in response to parties' comments. These modifications are discussed below, by general category and specific program initiative.
In its report, Energy Division assumes that the utilities will administer these programs "for the purposes of expediency," at least for 2001. (Report, p. 6.) SDG&E, SCE and SoCal concur with this approach, and recommend that the Commission affirmatively state now that the utilities will serve as the administrators through at least 2004. PG&E suggests that the Commission consider alternatives to utility administration, particularly if the expectation is to have utilities gear up for only a one-year assignment of program administration.
Although TURN does not propose a specific alternative to utility administration, it recommends that the Commission "find any other entity, private, non-profit or government, whose interest is more aligned with program success" to administer the self-generation program. In TURN's view, the utilities have presented positions in the distributed generation rulemaking (R.99-10-025) that reflect their perception that self-generation will reduce distribution revenues.
ORA expresses similar concerns, and recommends that SDG&E contract with the San Diego Regional Energy Office to provide administrative services for the self-generation programs in SDG&E's service territory. For the longer-term, ORA urges the Commission to establish a statewide network of Commission- certified regional energy offices to become administrators of both energy efficiency public purpose programs and self-generation programs.
ORA's proposal to designate the San Diego Regional Energy Office as program administrator for self-generation in SDG&E's service territory provides us with an opportunity to explore non-utility administration on a limited basis. We believe that such exploration will be valuable, given the concerns raised by parties regarding utility administration in this proceeding. The independent evaluation of the self-generation program should include an examination of the relative effectiveness of the two administrative approaches we adopt today.
Today's decision is not the appropriate forum for addressing the administrative structure of energy efficiency and self-generation programs for the longer-term, as proposed by ORA, and we will not adopt ORA's recommendation to establish regional energy offices for this purpose. However, nothing in today's decision precludes the Commission from considering alternatives to utility administration for future demand-responsiveness or self-generation program initiatives, based on our evaluation of the § 399.15(b) pilot results or other relevant information.
We direct the utilities to administer today's adopted pilot programs through the funding period, i.e., through December 31, 2004, with the exception of the self-generation program in SDG&E's service territory. For this program, SDG&E shall contract with the San Diego Regional Energy Office at the full budget amount specified herein ($15.5 million) to provide administrative services.
Energy Division recommends that the self-generation program be administered through the utility's existing standard performance contract (SPC) program. The SPC programs rely on third parties such as energy service companies to install equipment at customer facilities. Contractors then follow an established program procedure to install the equipment, measure and verify the equipment's impact on on-site consumption, and collect payment from the utility.
SDG&E/SoCal point out in their joint comments that SoCal does not currently administer an SPC program for energy efficiency. Therefore, SoCal requests flexibility to utilize other approaches for implementing the self-generation program. Xenergy also comments that their knowledge from conducting the statewide SPC program evaluations suggests that there may be other equally viable, and potentially less burdensome, program delivery choices. Like SoCal, the San Diego Regional Energy Office also does not have an existing SPC program. Given this, we will grant the program administrators flexibility in program delivery mechanisms, as long as they meet the following basic requirements:
· Available incentive funding (dollars per watt or percentage of system cost) is fixed on a statewide basis at the levels described below. (See table in Section 4.6.1.)
· Inspections are conducted to verify that the funded self-generation systems are actually installed and operating.
· The measurement and verification protocols established by the administrators include some sampling of actual energy production by the funded self-generation unit over a statistically relevant period. (See also Section 4.6.2 below.)
· As discussed below, the target expenditures for program administration be limited to 5% of program funding, with the exception of measurement and verification activities.
Finally, we clarify our expectations regarding outsourcing by program administrators. While we afford administrators the flexibility to select the manner of outsourcing (e.g., competitive bidding, sole source contracting) for these pilot programs, we do require program administrators to outsource to independent consultants or contractors all program evaluation activities. This requirement, coupled with the role of Energy Division in the evaluation process (see Section 4.8 below), will ensure that the programs are independently evaluated. In addition, all installation of technologies (hardware and software) at customer sites shall be performed by independent contractors and not utility personnel (for those utilities that will administer their own programs), or agency personnel (in the case of the San Diego Regional Energy Office). This requirement will ensure that market actors other than the program administrators are involved in program delivery, consistent with the manner in which we implement energy efficiency and low-income assistance programs.
Program administrators should also outsource other aspects of program administration and implementation, to the extent feasible. In particular, the majority of program marketing and outreach activities should be outsourced, to the extent feasible, although the program administrator should actively participate and assist contractor efforts for this purpose. We also encourage the program administrators to coordinate and work closely with local governments, community-based organizations, business associations and other entities to recruit and contact interested customers.
In its January 31, 2001 report, Energy Division recommends that administrative expenses be limited to 5% of total program funding, for each program, and estimates a 3% budget allocation for certain evaluation activities in developing the overall funding levels.6 Based on the comments of Xenergy and others, we believe that the administrators should be afforded some flexibility in allocating the authorized budget for each program (e.g., $3.9 million for the residential demand-responsiveness pilot) among the various cost categories (administration, program evaluation, installation, service and operation costs, customer incentives). We agree with Energy Division that contract administration, marketing and regulatory reporting should be undertaken as cost-efficiently as possible by program administrators, so that proportionately more funds are available for hardware installations and customer incentives. However, we also recognize that it is difficult to estimate at the outset precisely what the appropriate allocation across cost categories should be for these programs. For this reason, we are establishing are target of administering these programs at a cost no greater than 5% of program funds, with the exception of measurement and evaluation activities. In any event, the actual cost of administration must be reasonable.
We will provide some flexibility, enabling the utilities to shift funds across cost categories within the overall budgeted amounts for each of the four programs (i.e., residential demand-responsiveness, small commercial demand-responsiveness, interactive information for small customers and self-generation programs), with the following exceptions. First, utilities may not shift any funds between the demand-responsiveness and self-generation programs that they administer without first obtaining Commission authorization. Second, one-third of the self-generation incentive funds is initially allocated to each of the self-generation categories. Although the utilities may exercise full discretion in moving funds from non-renewable self-generation categories to the renewable category, a utility must seek approval through advice letter prior to shifting additional funds into either of the non-renewable categories. The utilities shall not unreasonably withhold funds that could be used to deploy a greater amount of renewable self-generation. Finally, with the exception of measurement and evaluation activities, administrators must obtain Commission authorization to allocate more than 5% of program funds to "administrator costs" (i.e., contract administration, marketing, and regulatory reporting) within each program budget, for either demand-responsiveness or self-generation programs. Such authorization may be requested via Advice Letter. The funds authorized today are designated exclusively for approved § 399.15(b) demand-responsiveness and self-generation activities, and shall not be used for other purposes.
As discussed above, Energy Division proposed a specific set of customer incentive levels and selected a particular load control technology to test under the residential and small commercial demand-responsiveness pilot programs. Several parties argue that the effectiveness of these programs, which are intended to induce customer behavioral changes, will best be achieved by allowing some flexibility and experimentation in the design of customer incentives, marketing approaches, technology type and other design parameters.
We agree that the effectiveness of these pilot programs will be enhanced by allowing some flexibility in their implementation. In particular, within the overall program funding levels authorized for each pilot, we will allow the utilities to experiment with alternative incentive designs. This may involve higher annual customer incentives and override penalties, or other signals that will differentiate usage of air conditioning during peak periods, as some parties suggest. Similarly, for the interactive consumption and cost information pilot, PG&E should have the flexibility to select the design and amount of the incentive, as suggested in its comments. (PG&E Comments, p. 4.)
We also will allow some flexibility in the overall number of pilot participants, as recommended by Xenergy and others. The utility administrators should consider the 5,000 participant level (for the residential and small commercial) and 10,000-15,000 participant level (for the small customer information pilot) as general targets, rather than strict requirements. In this way, the utility administers will be able to make reasonable modifications to other program design parameters (e.g., incentive levels) and also accommodate within the authorized program budgets any additional costs (e.g., equipment) that exceed the Energy Division's preliminary estimates.
SDG&E and others comment that the 250 kWh threshold for residential customers, as suggested in the Energy Division report, may not be an appropriate level for targeting higher electric load residences. We will afford SDG&E and SCE flexibility in establishing monthly consumption threshold levels in order to define a target group of participants with high average consumption.
However, we will not retreat from Energy Division's recommendation that the residential pilot also target limited- to moderate-income areas. In its comments, SDG&E argues that these customers are unlikely to use central air conditioning, an assertion that appears nonsensical given the high summer temperature climate zones within SDG&E's service territory. SDG&E and TURN also suggest in their comments that many limited- to moderate-income customers do not use personal computers (with internet access), and therefore cannot effectively participate in the residential pilot program. This reflects a basic misunderstanding of the "internet connectivity" referred to in Energy Division's report. Customers are not required to have internet capability via a personal computer, although this is one technology option. Rather, at a minimum, the thermostat equipment itself needs to be capable of internet interface, an option that does not require the customer to own or operate a personal computer. As discussed below, the utilities may elect to employ more than one technology in implementing the pilots, and we expect them to take into consideration the targeted market in making such choices.
Finally, we clarify our intent to allow some flexibility with respect to the specific technologies employed in the residential and small commercial demand-responsiveness pilot programs, and encourage the utilities to solicit multiple bids for this purpose. However, such flexibility is not intended to alter the focus of the pilot program recommended by Energy Division in its January 31, 2001 report. Consistent with those recommendations, we will not test technologies that simply allow the utility to interrupt load on a one-way basis. More specifically, any technology installed for the demand-responsiveness pilot programs must include the following features:
(1) Allow each customer some level of control over its own HVAC equipment (over-ride, etc.),
(2) Provide interactive information for consumers to make consumption decisions (e.g., via the thermostat or a computer internet connection), and
(3) Allow the administrator to verify actual interruption of the individual device at the customer site, including duration and level of kW demand reduction.
With respect to the interactive consumption and cost information pilot, Xenergy seeks to ensure that PG&E pursues other methods of providing customers with information on their energy usage profile and the benefits of various rate options, including mail out audits, telephone approaches and other alternatives. We do not intend this pilot to replace or diminish other effective methods that PG&E might also employ to provide energy information to smaller customers. However, we are not persuaded that including several, very different information dissemination approaches in a single pilot program, as suggested by Xenergy, would enhance the effort. We therefore retain the focus of the pilot, which is to implement and test the website approach proposed by the Energy Division.
Parties provided extensive comments on the various aspects of this proposed program, including incentive design, warranty requirements and the waiver of interconnection fees and standby charges. We summarize the main areas of contention in the following sections, and describe the modifications we adopt to Energy Division's proposal.
Energy Division proposed two categories of self-generation technologies and associated incentives, based on a consideration of various system dimensions, including air emissions characteristics, fuel type, and system cost. After considering parties' comments, we modify certain aspects of Energy Division's proposal, as discussed below.
Several parties argue that incentives are not required or warranted for non-renewable self-generation systems. They argue against funding these systems because they are less efficient and more polluting than combined cycle technologies without waste heat recovery. We find merit in these concerns. Section 399.15(b) requires the Commission to establish both "incentives for... distributed generation to be paid for enhancing reliability" as well as "differential incentives for renewable and super clean distributed generation resources." We agree with PG&E that many fossil fuel applications would fail to satisfy any of these criteria.
As NRDC and TURN have pointed out, some micro-turbines operating on natural gas may be cleaner than large central station fossil generators, but combustion turbines and other small natural gas generators may actually be more polluting than modern central station facilities. While we have not created an exhaustive record in this proceeding from which to reach a firm conclusion, there is nothing to suggest that these technologies offer "super clean" generation, and when run on natural gas, certainly are not renewable.7 Thus, to qualify for incentives, a fossil facility must serve to enhance system reliability.
Since all new generation could arguably add incrementally to the reliability of available generation, the language of § 399.15(b) suggests that the Legislature had in mind some other contribution to system reliability. In order to qualify for incentives, a fossil-fired facility must make a demonstrable contribution to the reliability of the transmission or distribution system. We expect the utilities to work with those customers seeking incentives for fossil-fueled facilities to determine whether a proposed facility will enhance transmission or distribution reliability and document those benefits prior to approving an incentive payment.
We note Capstone's suggestion that micro-turbines be allowed to qualify for renewable incentive levels if they utilize renewable fuels. While it is logical to consider such facilities as providing renewable power, the incentives, that we are offering here, relate to capital cost. Capstone has not suggested that micro-turbines using renewable fuels would be appreciably more expensive to install a unit using renewable fuel than it would to install one using fossil fuels. However, it would be appropriate to enable such a facility to qualify for a normal micro-turbine incentive payment without meeting a "system reliability" test. We will consider expanding the program to include renewable-fuel micro-turbines once we determine what comprises a renewable fuel and are persuaded that a facility that once qualifies for a "renewable fuel" incentive would not later switch to fossil fuel. We seek the Energy Division's assistance in answering these questions and ask the staff to report back to us.
In addition, we will modify Energy Division's proposal, as recommended by TURN and ORA, to require that non-renewable technologies utilize waste heat recovery at the customer site. This further mitigates concerns over providing incentives to nonrenewable technologies. Accordingly, we modify the technology categories to require that fuel cells utilizing non-renewable fuels, microturbines, and internal combustion engines, be installed in combined heat and power applications, in order to be eligible for incentives under the self-generation program.8 However, this requirement only becomes meaningful if the opportunity for heat recovery and reuse is meaningful. We ask the Energy Division to work with interested parties to develop heat recovery standards and to submit those standards to us for subsequent consideration.
Further the CEC recommends creation of an additional category for fuel cells operating on a non-renewable fuel source, stating that these systems do not yield the same benefits as fuel cells operating on renewable fuels. We agree that this distinction is warranted, and establish a $2.50 per watt incentive for this category, up to a maximum of 40% of project cost.
NRDC points out that a small number of very large units could easily use up most or all of the available funding, and suggests that the Commission consider adopting a size limit. PG&E specifically recommends limiting the size of units eligible for funding to 10 MW or less, because PG&E generally does not interconnect any project larger than 10 MW to its distribution system.
We believe that a size limitation is reasonable in order to provide options to assist in the installation of self-generation systems for as many California customers as possible. We prefer adopting a size limit to specifying a maximum percentage of available budget that can be paid to a single customer or system, which is an approach often used in program design. Use of such a mechanism in this case, however, would result in widely varying system size limitations across service territories, because of differing budget allocations for the various administrators.
In our judgment, a system size limit of 1 MW will effectively address the concerns raised by NRDC and others. This size represents a fairly large installation for a single customer site and, at the same time, will not use up an unreasonable amount of program funding. We note that one system of this maximum size would only receive about one-third of the available funding in SDG&E's service territory, which is the smallest budgeted program. Individual customers may apply for incentives for more than one system, as long as the combined size does not exceed 1 MW.
In addition, we will preserve the funds available for use in this program by adjusting incentive payments to complement those offered by the CEC, rather than to compete with them. We discuss this change in Section 4.9, below.
Finally, CEC and NRDC express concern over potential overlap between Energy Division's proposed self-generation program and CEC's renewables buy-down program, even with the 30 kW minimum size requirement. We note that only seven systems above 30 kW have been installed under CEC's renewables buy-down program (from a total of 332 systems installed, or 2%) since its inception. Out of 176 additional systems that CEC has approved, but are not yet installed, only nine (5%) represent systems greater than 30 kW.9 With the higher incentive level offered under today's adopted program, we believe that this market can be effectively reached, and will allow customers to participate in both programs, subject to the requirements set forth below.
With the modifications described above, we adopt the following incentive structure for the self-generation program:
Maximum percentage of project cost
Minimum system size
Maximum system size
Fuel cells operating on renewable fuel
_ Fuel cells operating on non-renewable fuel and utilizing waste heat recovery
_ Microturbines utilizing waste heat recovery and meeting reliability criteria
_ Internal combustion engines and small gas turbines, both utilizing waste heat recovery and meeting reliability criteria
Based on California Retailers Association's comments, we clarify that hybrid DG systems that incorporate technologies from different incentive categories will receive payments based on the appropriate category. For example, a 100 kW system that utilizes 60 kW of microturbines and 40 kW of photovoltaics may receive $1.00/W for the 60 kW microturbine system and $4.50/W for the photovoltaic system. The program administrators shall provide for multiple technologies to be included in the customer's program application.
We require that program administrators keep the incentive levels fixed on a statewide basis throughout the program period. This requirement differs from the flexibility afforded to the administrators in the demand responsiveness programs for several reasons. First, the self-generation program is not designed to induce or monitor changes in consumer behavior, but rather to encourage the purchase of equipment. We believe that considerable flexibility in designing incentive levels is warranted in the former instance, but not necessarily in the latter. Moreover, a program design that varies the incentive payment levels may confuse consumers, or cause them to wait for the possibility of higher incentives before installing self-generation systems. In addition, we believe that the incentive payment for this program should be uniform statewide, as the market for self-generation technologies is not limited to or differentiated by a particular region or utility territory.
Energy Division's proposal for the self-generation program does not impose operating requirements or establish differential incentives related to on-peak operation. As a result, SDG&E/SoCal argue that the proposed program design does not ensure that generation units will contribute to peak demand reduction. PG&E also requests that we clarify whether units are required to operate during peak.
We are not persuaded that it is necessary or reasonable to impose operating requirements or incentives related to on-peak operation for this program. We believe that customers willing to invest in self-generation already have sufficient economic incentive from energy prices to employ time-of-use meters to measure their usage and to operate their self-generation systems during peak periods. Moreover, the system output for solar technologies is generally coincident with afternoon system peak without any operating requirements. In addition, a per-watt or percentage of system cost up-front payment is already employed through the CEC's Emerging Renewables Buy-Down Program ("renewables buy-down program"). Maintaining that approach should help minimize market confusion and disruption.
However, for program evaluation purposes, we will require program administrators to monitor the extent to which self-generation units installed under this program operate during peak periods. Program administrators should direct their independent evaluation consultants or contractors to develop a process for monitoring and collecting this data from program participants. At the end of the first program year, administrators should report to the Commission on peak operation from the program, and continue this reporting in subsequent years. By the end of the second program year, the consultants or contractors should present recommendations on incentive or program designs that could improve on-peak load reduction from self-generation.
It is not the intent of this evaluation process to penalize customers for not running their self-generation during peak periods. Nor may the program administrators use the collected information in any way to penalize or restrict the ability of customers to run their self-generation systems. Rather, the purpose of this information is to assist us in identifying potential improvements in program design and incentive mechanisms for self-generation programs in the future.
We offer an example of how this operational data might be obtained for evaluation and ongoing program design purposes. If the self-generation unit does not already have built-in logging capability for this purpose, then the unit could be outfitted with a low-cost single-channel datalogger and sensor (such as a relay switch) which would at least enable the utility to determine when the unit is operating and producing electrical output. Program administrators should develop and disseminate the specific requirements for system installations and monitoring capabilities required for program evaluation. The costs of the required monitoring equipment should be paid from program funds.
Under Energy Division's proposal, self-generation systems must be covered by a warranty of not less than three years. CEC recommends a warranty period of five years for eligible systems, consistent with the requirements under CEC's renewables buy-down program and industry practices. We concur with the CEC's recommendation, and adopt a five-year warranty requirement for technologies in Levels 1 and 2 above.
For Level 3 technologies, however, we adopt a different requirement, based on SDG&E's observation that equipment manufacturers for these technologies typically offer warranties of only three to 12 months. In our opinion, a three-year warranty period is sufficient to ensure the continued operation and reliability of these systems and will encourage manufacturers and vendors to offer high quality products. We will adopt SDG&E's recommendation that the customer installing these self-generation systems purchase a three-year (minimum) maintenance contract from the manufacturer or vendor in order to comply with this requirement, if the system does not already include the required warranty. The customer may include the cost of this warranty in the system cost, for purposes of calculating their program incentive, up to the maximum percentage levels specified.
The utilities strongly object to Energy Division's recommendation that interconnection fees and standby charges be waived for any self-generation units installed through the program. They argue that this recommendation is not justified and would ignore the Commission's recent decision on interconnection standards (Decision (D). 00-12-037) as well as the record developed in R.99-10-025 on standby charges. California Retailers Association, on the other hand, supports this recommendation and urges the Commission to adopt it.
We conclude that the appropriate forum for addressing interconnection fees and standby charges for distributed generation is R.99-10-025. We will not prejudge the issues still being considered in that proceeding, or modify prior Commission decisions regarding interconnection fees in designing the § 399.15(b) programs we adopt today. However, we do clarify that the interconnection fees (as defined in D.00-12-037) should be included in total installation costs for the purpose of determining the maximum size of the self-generation incentive. In this way, program dollars can be used to defray a portion of those costs.
AB 970 directs the Commission to reexamine the methodologies used for cost-effectiveness, and revise them in "in light of increases in wholesale electricity costs and of natural gas costs to explicitly include the system value of reduced load on reducing market clearing prices and volatility." (§ 399.15(b)(8).) In its January 31, 2001 report, Energy Division proposes refinements to existing cost-effectiveness testing for this purpose, on a preliminary basis. Energy Division applied this new methodology to estimate the benefits and costs of the proposed self-generation and demand-responsiveness programs.
In their comments, the utilities and CEC contend that Energy Division's estimates for certain cost-effectiveness parameters (e.g., avoided transmission and distribution costs, reliability benefits) are overstated, and that the analysis does not take into account all of the costs associated with DG. ORA presents its own cost-effectiveness test results that it contends is more consistent with the approach (and inputs) used by the Commission to evaluate demand-side management programs.
Despite criticisms of certain aspects of Energy Division's analysis, none of the parties present convincing argument or facts to indicate that Energy Division's recommended programs will not produce sizeable public benefits.10 They do recommend, however, that we continue to refine our cost-effectiveness methods for the future. We concur with this recommendation, and clarify that the cost-effectiveness inputs and methods applied to the Energy Division proposals are limited only to these pilots.
An appropriate cost-effectiveness method for future, longer-term programs still needs to be developed. Energy Division's proposal to hire an independent consultant to perform such a task, utilizing funds appropriated for implementation of AB 970, is a reasonable approach. The scope of work should encompass the development of methodologies, input assumptions and forecasts for addressing § 399.15(b)(8) and other cost-effectiveness issues. In particular, we seek to develop a cost-effectiveness methodology that can be used on a common basis to evaluate all programs that will remove electric load from the centralized grid, including energy efficiency, load control/demand-responsiveness programs and self-generation.
Energy Division should submit the final consultant report no later than December 31, 2002, and serve a notice of its availability to all appearances and the state service list in this proceeding (or its successor). Energy Division may hold public workshops with the consultant and interested parties during the development of this methodology, as it deems appropriate. The schedule for comments on the final report will be established by Assigned Commissioner or Administrative Law Judge ruling.
The programs adopted today will be evaluated during and after the program period, consistent with Energy Division's recommendations. For the residential and small commercial demand-responsiveness pilot programs, SDG&E and SCE will each conduct a process evaluation during 2001 and an energy savings and peak demand savings impact study at the end of 2002. For the interactive and cost information pilot program, PG&E or its evaluation contractor will contact site users and non-users to discuss their satisfaction with the information on the site and suggest potential improvements. Program administrators for the self-generation program are required to perform program evaluations and load impact studies to verify energy production and system peak demand reductions, as described in greater detail in Section 4.6.2. They are also required to conduct an independent analysis of the relative effectiveness of the utility and non-utility administrative approaches we adopt today. (See Section 4.3.)
As discussed above, program administrators are required to outsource to independent consultants or contractors these evaluation activities. Energy Division shall assist program administrators in the development of the scope of work, selection criteria and the evaluation of submitted proposals to perform these program evaluations. The assigned Administrative Law Judge, in consultation with Energy Division and the program administrators, shall establish a schedule for filing the required evaluation reports. Energy Division should hold a workshop with program administrators as soon as practicable to develop scheduling proposals for this purpose.
Several parties commented on coordination and eligibility issues, particularly with respect to the CEC's programs. In particular, CEC and NRDC express concern over potential overlap between Energy Division's proposed self-generation program and CEC's renewables buy-down program. As the CEC points out, the CEC's program currently offers payments to renewable self-generators at a level lower than that approved in this order. The CEC argues that rather than add to the over-all deployment of renewable resources, a parallel program, offering larger incentives, would drive participants away from CEC program altogether. This would not be a sensible result.
We encourage the CEC to consider adopting a rebate level equal to that adopted in this order. However, as long as the CEC does not reduce its "buy-down" levels, it is appropriate for those receiving CEC incentives to also receive incremental payments from the utilities, bringing the total incentive payments up to the level approved in this order. Of course, this process must be carefully monitored to ensure that no customer can play one program off against another, to achieve exorbitant incentive payments.
It is unlikely that these programs can be successfully coordinated unless there is a common application process for involvement in either program. Thus, we direct the utilities and the Energy Commission to work with the CEC to develop a one-step application process, for use by all customers seeking a CEC renewables "buy-down" or utility renewable self-generation incentive payment.
Energy Division's program proposals for both demand-responsiveness and self-generation state that customers receiving incentives from these programs cannot also participate in any other interruptible or curtailable rate programs. Some parties, including TURN, argue that this prohibition should be eliminated. We agree with the Energy Division that participation in multiple programs could potentially allow an individual customer to receive multiple incentive payments for taking a single action. For example, a commercial customer could be receiving an interruptible rate discount, while at the same time utilizing incentives from the self-generation program to assist in the purchase of on-site generation for use during interruption periods. However, we do not find it necessary to prohibit customers from participating in an interruptible program with load that is not displaced by self-generation receiving incentives through this program.
In its comments, the CEC refers to the guidelines already in place for CEC's renewables buy-down program. Although we do not specifically adopt the CEC guidelines today, we do agree with the CEC that the administrators of these new self-generation programs should take advantage of the work already done by the CEC in developing appropriate program details to encourage self-generation. Those program parameters are available at http://www.energy.ca.us/greengrid/. In order to ensure that the new self-generation program is available as consistently as possible on a statewide basis, we direct SoCal to take the lead in convening a working group including PG&E, SCE, SDG&E, and the San Diego Regional Energy Office to select final program details for statewide implementation. These details may include eligibility criteria for heat recovery levels or system efficiency.
We note that SoCal and SCE generally serve the same service territory and customers. Accordingly, SCE and SoCal must coordinate their marketing and tracking of program incentives very carefully in order to ensure that customers do not receive incentives for the same self-generation equipment from both utilities. In the alternative, as ORA proposes, SoCal may administer the self-generation program for the combined geographic region, if SCE and SoCal so agree.
We recognize that additional incentives for self-generation and demand-responsiveness programs may be authorized by the Legislature in the coming months. As several parties point out, additional issues regarding eligibility and coordination may need to be addressed at that time. We delegate to the Assigned Commissioner the task of clarifying these and other implementation issues by ruling, if and when such a need arises.4 We are examining this issue in A.00-11-038 et al. 5 ORA presents an analysis of program cost-effectiveness that produces a benefit cost ratio for self-generation of 2:1, which is significantly less than Energy Division's preliminary analysis, but still comparable to the energy efficiency portfolios of the combined utilities. See ORA's comments, p. 5. 6 See Energy Division Report, p. 6 and program budgets on pp. 15 and 21. 7 We note that neither the Energy Division report nor the applicable statute provide a definition for "super clean" generation and find that the information before us does not provide a basis for declaring that any particular fuel-burning technology fits in such a category. 8 This modification also makes moot Energy Division's proposal to pay additional incentives for energy savings from the installation of combined heat and power systems. 9 Source: From "Appendix C: Emerging Renewable Resources Account" in "Renewable Energy Program: Annual Project Activity Report to the Legislature", CEC publication nos. P500-00-004 (March 2000) and P500-00-021 (December 2000). Available online at http://www.energy.ca.gov/reports/2000-12-04_500-00-004.PDF and http://www.energy.ca.gov/reports/2000-12-04_500-00-021.PDF. 10 ORA presents an analysis of program cost-effectiveness that produces a benefit cost ratio for self-generation of 2:1, which is significantly less than Energy Division's preliminary analysis, but still comparable to the energy efficiency portfolios of the combined utilities. See ORA's comments, p. 5.