VII. Assignment of Proceeding
Michael R. Peevey is the assigned Commissioner and Lynn T. Carew is the assigned Administrative Law Judge in this proceeding.
1. The strategic development of demand response capability in the California energy market requires coordination among this Commission, the CEC, and the CPA; to meet this responsibility, these state agencies have used an interagency working model and three working groups to develop the record in Phase 1 of this rulemaking.
2. Throughout Phase 1, decisionmakers from the CPUC, CEC and CPA (the "Working Group (WG) 1 principals") provided policy guidance to a group of active parties interested in large customer demand response issues ("Working Group 2 or WG2"), encouraging WG2 to develop a tariff or set of tariffs for use by large customers with average monthly demands of 200 kW and above, and to strive for "quick wins" that would take advantage of two key factors: the fact that 1) many large customers have interval meters in place due to AB29X, and 2) Summer 2003 presents conditions ideal to test how large customers who have such meters will respond to time-sensitive rates.
3. WG2 held thirteen noticed workshops, open to all active parties and facilitated by staff supporting the Working Group 1 principals, and during the period November 15, 2003 through March 11, 2003, WG2 produced four written reports. The participants attempted to develop consensus around a set of dynamic pricing proposals, but the diversity of opinion on key issues ultimately worked against the development of consensus on a "quick win" for Summer 2003.
4. The WG1 principals have developed a long-term vision and set of goals for demand response to help guide the efforts of participants in this proceeding. The vision statement provides a definition and simple goal statement, followed by objectives (reliability, lower power costs, and environmental protection), goals and principles (customer service, optionality, technology issues, IOU issues, and coordination), and a timeframe (phases for proof-of-concept, phased implementation for large customers, and residential implementation). This is an evolving document and work-in-progress, although several aspects of the vision require explicit Commission endorsement.
5. The vision statement sets a goal of meeting IOU capacity needs of 5% of system peak demand by 2007 through demand response, thereby requiring the Commission to set interim MW targets. An explicit linkage between these targets and the IOUs' procurement-related obligations included in the procurement plans filed in R.01-10-024 is required.
6. There is agreement that achievable goals are as follows: for calendar year 2003: 150 MW for PG&E, 150 MW for Edison, and 30 MW for SDG&E; for calendar year 2004: 400 MW for PG&E, 400 MW for Edison, and 80 MW for SDG&E; for calendar year 2005: for all IOUs, 3% of annual peak demand for bundled service load; for calendar year 2006: for all IOUs, 4% of annual peak demand for bundled service load; for calendar year 2007: for all IOUs, 5% of annual peak demand for bundled service load.
7. The WG2 participants have been unable to develop one consensus tariff proposal given the diversity of views among large customer interests, respondents, and other parties.
8. Since no single demand response program or tariff satisfies all large customers, a portfolio or "mix" of demand response programs will appeal to the greatest number of customers.
9. While recognizing that mandatory tariffs/programs for large customers would produce the greatest demand response, it is reasonable to authorize voluntary program participation for large customers in the near term. Not all large customers are capable of immediately altering their manufacturing or production processes in order to respond to dynamic pricing tariffs and forcing their participation at this point will have serious unintended repercussions for the California economy.
10. The Association of California Water Agencies (ACWA) presented a Critical Peak Pricing (CPP) proposal widely regarded as a "no-lose" proposition as customers who do not respond pay no more than their current demand charges. Given our goal to develop programs providing meaningful demand response, and the fact that ACWA's proposal provides generous bill savings to participants who provide little or no demand response in return, there is legitimate concern that ACWA's proposal does not provide a meaningful demand response resource.
11. The IOUs present a joint CPP proposal designed to appeal to commercial office buildings and other similarly-situated customers with large air conditioning loads, to be offered to large customers (>200 kW per month), most of whom are already equipped with interval meters due to Assembly Bill 29 of the first extraordinary session of 2000-2001 (AB29X).
12. The City and County of San Francisco (CCSF) seeks to intervene in this proceeding out of concern that the statewide joint proposal does not adequately capture San Francisco's peak load profile.
13. It appears that the load, demand, and capacity characteristics of the San Francisco peninsula are unique in the PG&E territory and merit special consideration, although CCSF's broader concerns about transmission constraints and local generation issues are beyond the scope of this proceeding.
14. While the joint CPP proposal does not enjoy universal support, it is apparent that no single program appeals to all large users. The joint CPP proposal involves a relatively modest expenditure through 2004, provides customer choice, and also allows us to take advantage of the AB29X infrastructure already in place. Modifications to the Joint CPP Proposal allowing agricultural customer participation, certain multiple meter situations, multiple program participation, and the use of incentives, are designed to promote greater participation in this program.
15. There is no record for adopting SDG&E's proposal to expand the Joint CPP proposal to an additional 6700 customers whose usage spans 20 kW to 200 kW. Instead it is reasonable to confine the CPP program to SDG&E customers whose usage exceeds 100 kW, consistent with D. 01-05-032, wherein we authorized SDG&E to procure, install and operate real time meters for each of its customers (except exempted agricultural customers) with peak demand of 100 kW or more.
16. SDG&E's proposal to convert its existing pilot program, the Hourly Pricing Option (HPO), into a full-scale program has merit because the HPO, as modified, breaks new ground by expanding the hourly prices to semi-peak periods and expanding the number of hours for which hourly rates are revealed to the participant.
17. In order to add another type of demand response offering to the portfolio of offerings available to large customers, the IOUs propose to continue the existing Commission-authorized reliability-based demand bidding program, and also expand available demand bidding options, allowing participants to reduce demand voluntarily when requested by the IOUs in one of two ways: via 1) a price trigger, and 2) a system emergency trigger.
18. A customer-specific 10-day rolling average energy usage baseline, calculated "using the average of energy usage for the three highest days for the same hour during the past ten similar days prior to a DBP event" will be used to determine performance, as a means to address concerns that a simple 10-day rolling average may negatively bias temperature-sensitive customer loads. This determination should be made using a consistent methodology using the average of the highest kWh usage consumed over a specific period. For the CPP, the determination of a "high" day shall be based on the total kWh usage consumed over the peak period. For the DBP, the determination of a "high" day shall be based on the average per-kWh consumption over the bid duration period.
19. The DRP offered under the aegis of the CPA assists in meeting our stated demand goals because it is available to a much broader array of participants than the IOUs' DBP, which is limited to bundled customers. DRP is the one offering that is available to direct access customers, a group whose participation in demand response programs is key to meeting statewide goals.
20. The Transmission and Distribution (T&D) Peak Capacity Proposal is presented as a pilot program for implementation in Summer 2003. It is designed to allow both direct access and bundled customers above and below 200 kW in T&D constrained areas to receive financial benefits in the form of reduced T&D charges when they take actions that provide benefits on constrained T&D systems. However the pilot description is very general, as are the specific concepts to be tested, and there is insufficient time to develop hourly prices for T&D constraint costs as inputs to this Summer 2003 demand response program.
21. Time did not permit the full exploration of the Infotility real time pricing (RTP) proposal, designed to test or identify 1) customer interest and response to a real time price signal across multiple building types; 2) customer preferences for baseline methodologies; 3) specific customer education requirements prior to participation in a two-part RTP tariff; 4) technical and administrative barriers to a full roll out; 5) customer satisfaction; and 6) "lessons learned." However there is keen interest among the active parties in developing a two-part RTP pilot or pilots or alternatives, which may use the Infotility proposal as a starting point.
22. Balancing our goal of maximizing participation in demand response programs against cost concerns, we will allow certain agricultural customers whose usage exceeds 200 kW to participate in the offerings authorized, if they currently have interval meters in place.
23. In furtherance of our desire to ensure the participation of agricultural customers in demand response programs, it is appropriate to require the respondents to provide accurate cost data relative to such participation by those agricultural customers who currently do not have interval meters in place.
24. A liberal meter aggregation policy will encourage participation, but that goal must be balanced against the unknown metering costs and our present lack of knowledge about small commercial customer demand response. Thus, we are not adopting an aggregation policy in this decision, but will explore the issue in Phase 2 of this proceeding. Instead, at this time, it is appropriate to limit participation by customers with multiple accounts to those situations where at least one meter of a multi-meter facility is already >200 kW and where an individual site is defined as in the applicable utility tariff rules.
25. Multiple program participation raises several concerns including two key ones: the possibility that customers will be compensated multiple times for the same load response and the possibility that potential load relief associated with a particular program will be double-counted.
26. There is significant customer inexperience with price-triggered demand response programs and a reluctance to spend the time and effort necessary to participate in these programs, as well as perceived risks about participation. Transitional incentives are one method to increase customer participation levels by overcoming these concerns.
27. The bill protection incentive available to those participating in the CPP and HPO programs will provide 100% bill protection, meaning that the participant pays no more than they would have had they remained on their original rate schedule, for the first fourteen months they are on the CPP or HPO tariff, but no later than December 31, 2005.
28. Under the bill protection incentive, the customer must actually reduce peak demand by a minimum of 3% per CPP event, averaged over the course of their fourteen-month participation. If they do not do so, they will not receive credit at the end of fourteen months. For customers on the HPO tariff, the 3% reduction could be averaged over the entire time period of the customer's participation.
29. The bill protection option involves nearly no cost, as long as existing revenue requirements are established and shortfalls are collected through appropriate balancing mechanisms.
30. WG2 also proposed a technology incentive for participants in the CPP and HPO tariffs, as well as the IOUs' DBP, which would allow a rebate for installation and use of pre-approved technology that enhances the customer's demand response. This transitional incentive would rebate up to $150/kW of curtailable on-peak load for a combination of costs associated with receiving professional technical advice and installing unspecified qualifying hardware. Payments would not made for technical assistance that does not lead to load reduction as 50% of the potential payment is paid only after the customer achieves certain performance targets. Funding for the CPP/HPO technical incentive is proposed at $11.375 million, with an additional $8.249 million for the IOUs' DBP.
31. While an equipment-based rebate is potentially helpful in augmenting demand response, the proposal lacks key detail, including a method for determining what constitutes "qualifying" technologies.
32. The level of projected costs for the technology incentive exceeds $11 million, a significant amount, with no indication of how much demand response such expenditure may encourage. This fact is not counterbalanced by the requirement that would withhold 50% of the incentive in cases of non-performance.
33. The level of expenditure associated with the technology incentives, coupled with uncertainty over the likely customer response to these incentives, leads us to reduce the funding and nature of this incentive by confining it to a professional technical assistance component, without authorizing the additional hardware component of the proposed technology incentive package.
34. Approval of the professional technical assistance portion of the proposed technical incentive package, allowing a rebate for professional technical advice regarding installation of new equipment or modification of existing equipment or behavior, may spur customer participation at a more acceptable cost than that associated with the entire proposal for technical incentives.
35. In this decision we take several steps designed to augment customer participation in the adopted programs, including opening the tariffs and programs to certain agricultural customers, allowing certain multiple-meter situations, allowing multiple program participation in certain circumstances, as defined, and approving bill protection and professional technical assistance incentives. These actions will augment the expected MW demand response targets for 2003 and 2004 shown in Appendix B.
36. Our decision to reject the technology hardware portion of the transitional incentive proposal may diminish to some degree the expected MW contribution detailed in Appendix B related to the statewide CPP, HPO, and IOUs' DBP.
37. Because it has been the standard for rate design and demand-side management measure evaluation historically, the most relevant standard for determining cost-effectiveness for tariffs and programs designed to be part of a growing reliance upon demand response is the cost of a new peaker power plant.
38. Using several tests from the Standard Practice Manual, all programs authorized in this decision are cost-effective, except SDG&E's HPO, which did not pass one of the tests. However, given the limitations of the tests, all program proposals are attractive compared to investing in a new peaker of comparable MW size.
39. Customer participation in demand response tariffs and programs will cause the IOUs to lose revenue (compared to authorized revenue requirement) because load reduction involves both a reduction in energy usage and a shift from energy use during peak periods in which existing rate designs accentuate revenue recovery. The exact amount of revenue loss depends upon many factors, including the nature and extent of customer participation in demand response programs, and other unknowns, such as offsetting energy purchase cost reductions attributable to effective demand response.
40. The estimated revenue shortfall impacts discussed in this decision are very conservative approximations because they assume no short-term commodity procurement cost savings associated with these reductions, and such savings certainly will exist, although their magnitude cannot be predicted in advance.
41. There are starkly differing recommendations regarding recovery of revenue shortfalls in this proceeding: the IOUs recommend recovery of revenue shortfalls from the entire system, whereas ORA argues that such shortfalls should be recovered from the large customer class(es), not system-wide. Under ORA's proposal, certain revenue shortfalls would be recovered from the non-CPP participants in the same sub-customer class, which will give non-participating (static rate) customers an incentive to switch to CPP or other dynamic tariffs and programs. There is merit in the ORA proposal, because it is designed to encourage program participation by sending appropriate cost signals. However, there are some near-term practical impediments to the adoption of ORA's proposal, as discussed in this decision.
1. Phase 1 of this rulemaking has proceeded via notice and comment rulemaking, without the need for evidentiary hearings. The decisionmaking record consists of respondents' formal demand response programs/pricing options filed in compliance with the OIR; the official transcripts of five formally noticed WG1 meetings; the rulings following those meetings and written comments thereon; and the four WG2 reports and related rulings and written comments.
2. The tariffs and programs being developed in this proceeding should be explicitly linked with procurement planning in R.01-10-024.
3. The ACWA CPP proposal should not be adopted as it would provide generous bill savings to participants providing little or no demand response in return.
4. Since CCSF has demonstrated that it has a direct and substantial interest in the outcome of this proceeding that cannot be represented adequately by any other party, its motion to intervene pursuant to Rule 45 should be granted.
5. The joint CPP proposal should be approved, with certain modifications, because it involves a relatively modest expenditure through 2004, provides customer choice, and also allows us to take advantage of the AB29X infrastructure already in place.
6. SDG&E's proposal to convert its HPO pilot into a full-scale program and modify it by expanding the hourly prices to semi-peak periods, and expanding the number of hours during which hourly rates are revealed to participants, offers additional options to customers, and should be adopted. Consistent with D.02-01-062, SDG&E should be permitted to offer this program to customers with monthly demands >100 kW. This outcome should be confined to SDG&E, as efforts are currently underway to develop a two-part real-time tariff for wider application.
7. The IOUs' DBP, as presented in the March 11, 2003 WG2 Report, should be adopted subject to certain modifications which will improve customer participation, as discussed in the text of this decision relative to multiple participation, multiple-meter situation, and inclusion of certain agricultural customers.
8. The CPA DRP should be adopted because it is available to a much broader array of participants than the IOUs' DBP, and is the one offering that is available to direct access customers, whose participation in demand response programs is key to meeting statewide goals.
9. IOUs should be able to dispatch from either demand bidding program, the IOU DBP or the CPA DRP, as both programs will be available to large customers.
10. Multiple program participation in the adopted programs should be allowed, provided that there are acceptable guidelines designed to avoid both double-compensation and double-counting, to the extent provided in this decision.
11. Because they meet the guidelines for avoiding double-compensation and double-counting of benefits, the following program combinations should be allowed: CPP and CPA DRP (or IOU DBP); OBMC and CPA DRP; CPA DRP and interruptible rates, subject to limitations discussed in this decision; and CPA DRP spot market options and interruptible rates, subject to limitations discussed in this decision.
12. The bill protection incentive, as modified in the preceding discussion to extend from twelve to fourteen months, should be approved for customers participating in the CPP and HPO tariffs.
13. Given its high cost, lack of key detail, and uncertainty regarding how much customer participation, and therefore demand response, it will engender, the technology equipment portion of the technology incentive should not be approved.
14. A modest rebate in the amount of $50/kW of curtailable on-peak load for the costs associated with receiving professional technical assistance (related to the installation of new equipment or the modification of existing equipment or behavior) that leads to actual demand response, should be authorized.
15. In order to achieve demand response program stability, the programs authorized in this decision should be available well beyond calendar year 2004, and have no expiration date, although funding is authorized in this decision through calendar year 2004.
16. Since there are no remaining customers enrolled under PG&E's experimental real-time pricing tariff, Schedule A-RTP, and the joint proposal submitted in Phase 1 is a reasonable successor to that tariff, PG&E's Schedule A-RTP should be eliminated.
17. Since rate Schedule E-PBIP, a pilot authorized in D.02-04-060, has only one participant, and the WG2 participants see little harm in eliminating the pilot, the single participant should be encouraged and assisted to join another program or tariff and this tariff should be eliminated.
18. Notwithstanding the limitations of the tests from the standard practice manual, it is apparent that all of the programs and tariffs authorized in this decision are attractive when compared to investing in a new peaker power plant of comparable MW size; therefore, these specific tariffs and programs are sufficiently cost-effective to be authorized.
19. Given the concerns expressed by WG2 participants about the validity of the standard practice manual (SPM) tests, and importance of the process for developing inputs that accurately reflect the value of displaced supply-side power procurement costs, the parties should develop and advance proposed modifications to the SPM in Phase 2 of this proceeding.
20. Since ORA's conceptual revenue shortfall proposal merits further exploration, we should require the IOUs to make a compliance filing outlining their assessment of the customer impacts of implementing the ORA proposal.
21. The IOUs should be required to implement substantially similar customer education and outreach programs for the CPP/HPO and the DBP. Further, these programs should be compatible with the parallel activities of the CPA for its DRP.
22. In connection with the adopted technical assistance rebate, professional technical assistance, incentive certification, and verification of load reduction, should be handled by firms designated by the CEC. The IOUs should coordinate with the CEC to make every attempt to attract customers to these demand response programs who have already received subsidies from the state for installation of demand response equipment.
23. The comprehensive monitoring and evaluation plan proposed by WG2 in its December 13, 2002 report, as augmented by its March 11, 2003 report, should be adopted, in order to identify the nature of those participating in the adopted programs, assess load shape changes, understand how to accomplish load impacts, estimate system benefits, estimate IOU revenue and cost impacts, and assess whether tariff and program changes are necessary. WG2's proposal to supplement the monitoring and evaluation plan to assess the success of the bill protection and technical assistance incentives under the supervision of the CEC, should also be adopted.
IT IS ORDERED that:
1. We hereby adopt the demand response goals enumerated in Table 1 for each IOU. To ensure that these goals are achieved, we direct the respondent IOUs to do the following:
a. Take all appropriate steps to implement the dynamic pricing tariffs and programs adopted in this proceeding in order to achieve these goals;
b. Recommend, as a result of monitoring and evaluation efforts, changes to the tariffs and programs adopted here, as well as additional tariffs and programs, to improve the cost-effectiveness of demand response activities;
c. Include the MW targets for calendar years 2003 through 2007 in their procurement plans to be filed in R.01-10-024. To the extent that this decision is adopted after those plans are filed, the IOUs shall supplement or augment their filings in R.01-10-024 to reflect this requirement, including, in particular: numeric targets coinciding with the findings in this decision; documentation of the amount of demand response (price-triggered) to be achieved by July 1 of each calendar year (with the exception of 2003, where the goals shall be met by the end of the calendar year); which programs and/or tariffs the IOU will rely upon to achieve the targets; and a contingency plan for covering capacity needs should the utility fall short of meeting the demand response goals;
d. Work with state agencies and the Independent System Operator (CAISO) to ensure that demand response programs and tariffs are appropriately considered in any resource adequacy or reserve requirements and emergency response activities.
2. The motion of the City and County of San Francisco (CCSF) to intervene in this proceeding is hereby granted. PG&E shall work with CCSF to create a localized marketing and recruitment area and triggering conditions for the existing CPP tariff proposal. PG&E and CCSF shall file and serve an advice letter containing the details of this localized plan within 30 days of the date of issuance of this decision.
3. The IOUs' joint Critical Peak Pricing (CPP) proposal is hereby authorized, subject to certain modifications relating to specific agricultural customer participation, multiple meter situations, multiple program participation, and the use of incentives.
4. SDG&E's proposal to convert the Hourly Pricing Option (HPO) approved in Resolution E-3782 into a full-scale tariff, and to modify HPO by expanding the hourly prices to semi-peak periods, is hereby adopted for SDG&E alone.
5. Consistent with D.01-05-032 SDG&E is authorized to offer its authorized CPP and HPO tariffs to customers with peak demands of 100 kW or more, consistent with the text of this decision.
6. The IOUs' Demand Bidding Program (DBP) as presented in the March 11, 2003 WG2 Report, is hereby adopted, subject to the following modifications: First, under circumstances specified elsewhere in this decision, we allow customers to participate in both the CPP and the IOU DBP. Second, we permit some multiple-meter situation, under guidelines detailed subsequently in this decision. Third, for the reasons discussed in this decision, we include in the DBP certain agricultural customers whose usage exceeds 200 kW and who have interval meters in place.
7. The CPA's Demand Reserves Program (DRP) is another type of demand bidding program that is available to large customers, as provided in this decision, which IOUs may use to satisfy their demand response goals established herein.
8. The IOUs shall immediately develop with the CPA and the Department of Water Resources (DWR), as necessary, a mutually acceptable interim mechanism for allocating the CPA DRP resources that they schedule in 2003 with the CAISO. IOUs and CPA shall also develop a permanent proposal, based on the experience in Summer 2003, unless such an alternative mechanism is developed in the procurement proceeding. Within 120 days of the date of issuance of this decision, the IOUs shall file and serve a joint compliance filing containing this information.
9. Within 30 days of the date of issuance of this decision, the IOUs shall file and serve an advice letter with the Commission's Energy Division containing their DRP implementation plan. The issues of operation and scheduling of CPA's existing programs and new multiple program combinations cannot all be resolved immediately, so we require the plan to describe how these concerns can be addressed and solved in phases. The preparation of the plan shall be coordinated with the CPA. Phase 1 of the plan shall include, at a minimum, how the IOUs will coordinate their procurement scheduling activities with the CPA DRP Call Option subprogram in order to ensure that the DRP resources are used when it is cost effective to do so, as well as other efforts to be implemented in summer 2003. The plan shall also contain a timeline identifying when additional phases are expected to start and describe, in a manner acceptable to CPA, the details of the implementation of those phases.
10. In concert with the WG2 participants, the respondent IOUs shall develop a pilot or pilots or consider alternatives, which may use the Infotility pilot proposal as a starting point, testing two-part RTP tariff design features under a schedule to be determined. The cost of the two part RTP pilot(s) or alternatives authorized in this decision shall not exceed $2.8 million, and the actual costs of the pilots or alternatives shall be recorded and recovered using the cost recovery mechanisms authorized for the Statewide Pricing Pilot authorized by this Commission in D. 03-03-036. Before initiating any two-part RTP pilot(s) or alternatives, the respondent IOUs shall present the details of the proposal in an advice letter filing to the Commission's Energy Division for approval; the advice letter shall include a provision detailing how the IOUs propose to provide informational reports and pilot results to the WG2 participants.
11. Agricultural customers, whose peak demand exceeds 200 kW and who have interval meters in place and who are on PG&E's Schedule AG-4 and AG-5, options C and F, or SDG&E's Schedule PA-T-1, are authorized to participate in the programs and tariffs adopted in this decision. Within 15 days of the effective date of this decision, Edison shall define the agricultural schedules to be eligible in its territory. Within 45 days of the date of issuance of this decision, in preparation for Phase 2 of this proceeding, respondents shall file and serve in this docket a compliance filing detailing the projected cost of allowing agricultural customers whose usage exceeds 200kW and who currently lack interval meters to participate in the specific demand response programs authorized in this decision.
12. Participation by customers with multiple accounts in the tariffs and programs adopted shall be limited to those customer sites where at least one meter of a multi-meter facility, as defined in the applicable utility tariff rules, is already >200 kW.
13. Unless a particular program combination is explicitly permitted by this decision, it is not allowed. The following program combinations shall be permitted: CPP and CPA DRP (or IOU DBP); OBMC and CPA DRP; CPA DRP and interruptible rates, subject to limitations discussed in this decision; and CPA DRP spot market options and interruptible rates, subject to limitations discussed in this decision.
14. The bill protection incentive for customers participating in the CPP and HPO tariffs, as proposed by WG2 to include the performance requirement, the site visit requirement, and including a 14-month participation requirement, is hereby approved; in its tariff filing, SDG&E shall specify the exact nature of the performance requirement for HPO customers.
15. A maximum of $50/ kW for professional technical assistance (related to the installation of new equipment or modification of existing equipment or behavior), that leads to actual demand response by customers participating in the CPP/HPO tariffs or IOU DBP, is hereby authorized. The participating customer shall receive a transitional incentive equal to 50% of the potential payment upon certification of potential on-peak load reductions. The remainder of the incentive (the 50% remainder) shall be paid after the customer has shown a calculated peak demand reduction equal to at least 50% of their estimated load drop per CPP event, as averaged over four consecutive CPP or HPO months, while on the program, and before December 31, 2005. If this minimum level of measured load-shifting does not occur, the customer shall not receive the 50% remainder payment. To determine performance, the kW drop will be determined using the customer baseline proposed in the March 11 WG2 report.
16. In the Fall of 2004, the IOUs shall file evaluations for all tariffs and programs authorized in this decision, as well as those authorized in D.02-04-060 in our interruptibles rulemaking, for the purpose of making any necessary revisions for Summer 2005. Should any tariff or program be proposed for elimination, customers participating in it shall be offered a smooth transition to another program, if at all possible.
17. PG&E's experimental real-time pricing tariff, Schedule A-RTP, is hereby eliminated.
18. The pilot and associated rate Schedule E-PBIP, authorized in D.02-04-060, is hereby eliminated.
19. Within sixty (60) days of this decision, the respondents shall file a proposal to recover net revenue losses from participation in the voluntary CPP tariff from within the class that caused the losses. The proposal shall be reviewed in this proceeding to identify an appropriate forum - Phase 2 or another proceeding -- to address the merits of the proposal. Each proposal shall include:
a. identification of existing or proposed new means of tracking gross revenue losses from CPP participants in each tariff;
b. a description of each element of gross revenue losses, (e.g. structural shortfall from CPP participants who do not respond to CPP signals, revenue shortfall from active CPP participants, etc.);
c. identification of existing or proposed new means of tracking procurement costs avoided by CPP participants in each tariff;
d. identification of methods for periodically estimating the aggregate benefits from market price reductions induced by load reductions of CPP participants and proposed means of allocating these benefits to each tariff;
e. identification of methods for determining net revenue losses allocated to each tariff to be recovered from within that tariff;
f. suggested ratemaking proceedings in which net revenue losses by tariff would be periodically reviewed, approved and used to adjust rates for each tariff with net CPP revenue losses;
g. an estimate of the one-time only and ongoing costs of implementing the proposal.
Prior to these filings, the Energy Division will convene and moderate a workshop to further explore the ORA proposal.
20. Pending a further Commission decision on the ORA revenue shortfall proposal, the revenue shortfalls associated with the adopted programs shall be recovered on a system-wide basis.
21. For the authorized tariffs and programs, aggregate program administrative costs shall be limited to $13.0 million and $7.0 million for calendar years 2003 and 2004, respectively. Aggregate capital costs are limited to $7.9 million and $0 for 2003 and 2004, respectively. Aggregate incentive costs, including "other incentives" not already covered in the DWR revenue requirements, are limited to $2.9 and $2.3 million for 2003 and 2004, respectively.
22. The total cost expenditures authorized as a result of this decision are capped at $33.0 million over the two calendar years, exclusive of revenue shortfalls and costs related to "other incentives" which are part of the DWR revenue requirement. Each IOU shall use the cost recovery mechanisms previously adopted in D.03-03-036 as applicable to all Phase 1 programs.
23. The WG2 customer education/outreach proposals contained in the December 13, 2002 report, as augmented by the March 11, 2003 report, are adopted in principle. The IOUs shall implement substantially similar customer education and outreach programs for the CPP/HPO and the DBP. Further, these programs shall be compatible and coordinated with the parallel activities of the CPA for its DRP. In connection with the adopted technical assistance rebate, professional technical assistance, incentive certification, and verification of load reduction, shall be handled by firms designated by the CEC. The IOUs shall coordinate with the CEC and the Energy Division to make every attempt to attract customers to these demand response programs who already have received subsidies from the state for installation of demand response equipment.
24. The comprehensive monitoring and evaluation plan proposed by WG2 in its December 13, 2002 report, as augmented by its March 11, 2003 report, shall be adopted. WG2's proposal to supplement the monitoring and evaluation plan to assess the success of the bill protection and technical assistance incentives shall also be adopted. IOUs shall provide all data and background information needed to complete this plan, under appropriate confidentiality protections, as needed, to those involved in the evaluation process. The IOUs shall also make this data available to academic researchers, also under suitable confidentiality protection, to facilitate understanding of demand response. The CEC in coordination with the Energy Division shall supervise this work.
25. The WG2 facilitator is designated to work with the IOUs and parties who wish to be included in the coordination effort that is necessary to ensure that the appropriate monitoring and evaluation data is collected and made available for analysis. These efforts include, among other things, review of implementation plans, fine tuning of program implementation mechanics, and review of compliance filings or tariffs that may be required. In the event of disagreement that cannot be resolved within the WG2 process, the facilitator will bring the matter to the attention of the assigned ALJ, who will resolve the matter in consultation with the assigned Commissioner.
26. The IOUs, in coordination with the CEC and the Energy Division, shall conduct evaluation activities to be completed by the Fall of 2004, as input to a systematic review of demand response policy, tariff development, and program design to be conducted in the Winter of 2004/2005.
27. Any necessary modifications or refinements to tariff or program designs beyond those authorized in this decision that arise during the implementation phase, to the extent they cannot be resolved within the WG2 process, shall be requested by formal motion, filed and served on all parties of record. The assigned ALJ, in consultation with the WG2 facilitator and the Assigned Commissioner, is authorized to make any necessary modifications by ruling.
28. Within ten days of the issuance of this decision, the IOUs shall file advice letters containing the tariffs required to implement the adopted offerings. The filed tariffs shall become effective 20 days after their filed date, unless otherwise suspended by Energy Division. To the extent the attachments to this decision are more definitive than the decision text, the attachments govern. The following are the offerings, as modified in this decision:
· The Joint IOU CPP proposal, following the parameters specified in Attachment C. SDG&E's tariffs shall reflect the authority granted to it to offer the CPP to its customers with monthly peak demands of 100 kW or more.
· For SDG&E, a tariff implementing the authority granted to it to modify the HPO pilot program approved in resolution E-3782 and convert it into a full-scale tariff, and to offer HPO to its customers with monthly peak demands of 100 kW or more as specified in Attachment D.
· The IOU DBP, as modified in this order and detailed in Attachment E.
29. The protest period applicable to the advice letter required in Ordering Paragraph 28 shall be shortened to 10 days.
30. Echelon's Petition to Intervene is hereby granted.
31. The Joint Commenters' Motion for Acceptance of Late Filed Comments is hereby granted.
This order is effective today.
Dated June 5 , 2003, at San Francisco, California.
MICHAEL R. PEEVEY
President
GEOFFREY F. BROWN
SUSAN P. KENNEDY
Commissioners
I will file a dissent.
/s/ LORETTA M. LYNCH
Commissioner
I will file a dissent.
/s/ CARL W. WOOD
Commissioner
ATTACHMENT A
California Demand Response: A Vision for the Future
(2002-2007)
Joint statement for consideration by the California Energy Commission, Public Utilities Commission, and Consumer Power and Conservation Financing Authority
This vision is intended as a broad statement for encouraging demand responsiveness in California. It should be read in the context of maximizing the efficient use of resources, while maintaining the economic vitality of businesses in the state, as well as the health, welfare, and comfort of residential electricity users.
We acknowledge that demand response is one resource among many that may be procured by utilities on behalf of their electricity customers. We also seek to make the most cost-effective investments in demand response from an overall societal perspective.
Finally, this vision is intended as a starting point, and should not be interpreted as prejudging the outcome of analysis and recommendations delivered by the working groups to the policymakers in this proceeding.78 Further, we intend to use this vision as a guide to our efforts, will continue to reevaluate its validity and assumptions as we progress, and will make any modifications, as necessary and appropriate, when new information becomes available.
Definition
DEMAND RESPONSE gives an individual electric customer the ability to reduce or adjust their electricity usage in a given time period, or shift that usage to another time period, in response to a price signal, a financial incentive, or an emergency signal.
Vision
All California electric consumers should have the ability to increase the value derived from their electricity expenditures by choosing to adjust usage in response to price signals, by no later than 2007.
Objectives
Reliability
· Timely demand response (within minutes or hours) from customers can offset the need for investment in generation, transmission, and/or distribution
· Demand response activities should be designed to achieve a target of 5% reduction in peak demand by 2007
· Cost-effective demand response should be used to meet a portion of reserve requirements
· Numerous and diverse customers voluntarily reducing or shifting their demand in response to economic signals is preferable to controlled outages during power system emergency situations
Lower power costs
· During high-cost periods, demand response can assist in bringing supply and demand into balance by signaling to the consumer the actual costs of buying power at the margin and/or investing in new power resources, thereby lowering overall wholesale electricity costs for all customers
· Timely demand response can, along with other wholesale market measures, help mitigate wholesale market power and ensure reasonable prices
· To encourage demand response, a long-term objective is designing retail rates that dynamically incorporate the marginal cost of providing electricity service
· Demand response activities and infrastructure should be designed to be cost-effective from a societal perspective
Environmental protection
· Reducing consumer electricity usage during peak periods can help reduce fuel use and therefore overall air emissions by reducing output from marginal generation units
· The agencies' definition of demand response does not include or encourage switching to use of fossil-fueled emergency backup generation, but high-efficiency, clean distributed generation may be used to supply on-site loads
Goals and Principles
Customer Service
· Electric consumers in California should be made aware of the time-variable nature of electricity costs and of general steps they can take to help lower those costs
· All customers that desire it should have greater access to information about their own electricity use, at least weekly or daily, with the option for hourly or more frequent data
· Technologies to enable demand response may also provide other customer service benefits including outage detection and management, power quality management, and other information capabilities
· Demand response programs and tariffs should be designed to be customer-friendly, simple, and easy to understand, as well as to minimize customer confusion and allow for continuity among options
Optionality
· Customers should have the ability to choose voluntarily among various tariff options, including:
_ Very large customers (over 1 MW): Hourly real-time pricing (RTP), critical peak pricing (CPP), or Time-of-Use (TOU) Pricing
_ Large customers (200 kW to 1 MW): CPP, TOU or RTP
_ Residential and small commercial customers (under 200 kW): CPP, TOU or flat rate (the latter with an appropriate hedge for risk protection)
· Customers should also have the option to participate voluntarily in programs where they are paid to provide demand reduction as a dispatchable resource, including:
· In ISO markets: real-time, hour ahead, day ahead, ancillary services, planning reserves
· In retail markets: such programs as direct load control, including air-conditioner or water pump cycling, and controllable thermostats
Technologies
· All customers should be provided an advanced metering system capable of supporting a TOU tariff or better, if cost-effective, and with minimal hardware upgrades necessary to choose among various dynamic tariffs
· All customers who choose to should be able to conveniently access their usage information using communications media (e.g., over the internet, via on-site devices, or other means chosen by the customer and respectful of potential privacy concerns)
· The broadest possible range of metering and communications technologies that can enable demand response should be encouraged (i.e., optionality), but all technologies should be compatible with utility billing and other back-office systems
· State building code (Title 24) updates provide a cost-effective opportunity to introduce demand response technologies during the construction of new buildings or renovation of existing buildings
Investor-Owned Utility (IOU) Issues
· IOUs should be reimbursed for all reasonable expenditures on infrastructure and administration to enable demand response
· IOUs should be required to procure demand response resources as a portion of their overall procurement portfolio (target of 5% of peak demand by 2007) and as a portion of their reserve requirements beginning in 2004
· IOUs should also be provided an incentive mechanism to encourage the best choices for ratepayers
· Operation of an IOU's overall demand response portfolio should be designed to collect the approved revenue requirement and be revenue neutral to the IOU (e.g., revenues stay consistent with costs), with periodic true-ups as necessary
· All IOU demand response efforts should be periodically evaluated to determine past performance and improve future effectiveness
Coordination Issues
· Effective demand response efforts will require coordination among the agencies promulgating this vision statement, as well as the California Independent System Operator (ISO) and the California Legislature
· Coordination will also be necessary related to:
· IOU procurement planning
· IOU rate design modifications, either in general rate cases, or separate venues
· Energy efficiency (and other public purpose) programs
· Other peak demand reduction programs
· ISO efforts to develop transparent wholesale market pricing mechanisms
· Legislative reports such as required by SB1976 and Public Utilities Code Section 393
· Necessary legislative change to rationalize rate design structures
Timeframe
2003: Proof-of-concept phase
· Policy decision including vision and implementation plan
· Dynamic pricing as a full program option to customers with advanced meters in place (>200 kW)
· Pilot programs implemented to gather further information on smaller customer demand response and tariff or program preferences
· Business cases for phased implementation of universal demand response capability (potentially with automated meter reading technology) developed and evaluated, including cost-effectiveness analysis
2004: Phased implementation begins
· Full menu of demand response programs and dynamic pricing tariffs implemented for large and very large customers
· Small commercial and residential pilot program information evaluated
· Vision and timeframe reevaluated
· Technological options reevaluated, based on pilot program results
· Small and medium commercial customer infrastructure deployment phase begins
2005 and 2006: Residential implementation
· Major mass-market education effort initiated
· Full menu of tariff and program options rolled out to residential customers by the end of 2006
(End of ATTACHMENT A)
ATTACHMENT B
Attachment B |
|||||||||||
DEMAND RESPONSE TARIFF/PROGRAM COST AND INCREMENTAL REVENUE REQUIREMENTS |
|||||||||||
Program or Tariff Sponsor |
Program Name |
Impacts in 2003 (MW) |
Program Administration Costs (O&M + A&G) for Calendar Year 2003 (4) |
Capital Costs for Calendar Year 2003 (3) |
Transitional Technical Incentive Calendar Year 2003 |
Other Incentives in 2003 |
Total Amounts Proposed for Approval via R.02-06-001 for 2003 |
Incentives Already Approved via DWR Rev. Req. |
Revenue Reductions from Participants | ||
Joint UDC's |
CPP |
131 |
$3,848,000 |
$400,000 |
$1,272,717 |
$0 |
$5,520,717 |
$0 |
$8,267,000 | ||
PG&E |
DBP |
16 |
$310,000 |
$164,000 |
$75,758 |
$239,417 |
$789,175 |
$0 |
$0 | ||
SCE |
DBP |
34 |
$684,000 |
$0 |
$641,026 |
$664,957 |
$1,989,983 |
$0 |
$0 | ||
SDG&E |
DBP |
3 |
$208,000 |
$7,000 |
$8,333 |
$17,652 |
$240,985 |
$0 |
$3,000 | ||
SDG&E |
HPO |
2 |
$150,000 |
$140,000 |
$0 |
$0 |
$290,000 |
$0 |
$426,000 | ||
CPA |
DRP |
225 |
$3,700,000 |
$2,500,000 |
$0 |
$0 |
$6,200,000 |
$12,750,000 |
$2,835,000 | ||
WG2 |
2-part RTP |
0 |
$2,655,000 |
$145,000 |
$0 |
$0 |
$2,800,000 |
$0 |
$0 | ||
WG2 |
Additional meters |
0 |
$0 |
$4,500,000 |
$0 |
$0 |
$4,500,000 |
$0 |
$0 | ||
WG2 |
Comp. M&E Plan |
0 |
$861,000 |
$0 |
$0 |
$0 |
$861,000 |
$0 |
$0 | ||
WG2 |
M&E of Incentives |
0 |
$125,000 |
$0 |
$0 |
$0 |
$125,000 |
$0 |
$0 | ||
WG2 |
M&E Data Collection |
0 |
$460,000 |
$0 |
$0 |
$0 |
$460,000 |
$0 |
$0 | ||
Total Expenditures/Impacts (1) |
411 |
$13,001,000 |
$7,856,000 |
$1,997,833 |
$922,026 |
$23,776,860 |
$12,750,000 |
$11,531,000 | |||
Total Annual Incremental Revenue Req. (2) |
$13,001,000 |
$942,720 |
$1,997,833 |
$922,026 |
$16,863,579 |
||||||
Annualized Benefits (5) |
$36,900,000 |
||||||||||
Notes: |
|||||||||||
(1) Revenue reductions as a result of participant load shifts/reductions cause revenue shortfalls, but these may be partly offset by power procurement cost reductions. |
|||||||||||
(2) Assumes a 10% rate of return, with a net-to-gross multiplier of 2 recovered over ten years. |
|||||||||||
(3) Capital investments for CPA DRP include $2,500,000 to support utility incremental software development for better handling of meter data to support DR customers consistent with ISO practices. |
|||||||||||
(4) For CPA DRP administrative expenses, $1.6 million is for the IOUs, and $2.1 million is for CPA, of which $500,000 is for The Energy Coalition. |
|||||||||||
(5) Utility Avoided Costs (UAC) for CPP, DBP, HPO and DRP. UAC is based on costs avoided from building a new peaker plant (a fixed cost of $85 per kW-yr., and a fuel cost of $3.50 per mmBTU). The size of these benefits reflects the positive cost-effectiveness results reported in the WG 2 report dated 3/11/03. The UACs for CPP, DBP and HPO are found in Appendix E of the 3/11 WG 2 report (Both Incentives scenario), while the UAC for the DRP is in Appendix C of the 1/16 WG 2 report, (divided by two for 2003 to reflect a phased implementation over 2003-2004.) |
|||||||||||
Program or Tariff Sponsor |
Program Name |
Impacts in 2004 (MW) |
Program Administration Costs (O&M + A&G) for Calendar Year 2004 (4) |
Capital Costs for Calendar Year 2004 (3) |
Transitional Technical Incentive Calendar Year 2004 |
Other Incentives in 2004 |
Total Amounts Proposed for Approval via R.02-06-001 for 2004 |
Incentives To Be Approved via DWR Rev. Req. |
Revenue Reductions from Participants |
Joint UDC's |
CPP |
371 |
$2,642,000 |
$0 |
$597,791 |
$0 |
$3,239,791 |
$0 |
$5,670,000 |
PG&E |
DBP |
74 |
$25,000 |
$0 |
$431,818 |
$67,565 |
$524,383 |
$0 |
$0 |
SCE |
DBP |
37 |
$25,000 |
$0 |
$192,308 |
$444,995 |
$662,303 |
$0 |
$0 |
SDG&E |
DBP |
11 |
$25,000 |
$0 |
$50,000 |
$373,043 |
$448,043 |
$0 |
$0 |
SDG&E |
HPO |
11 |
$50,000 |
$0 |
$152,905 |
$0 |
$202,905 |
$0 |
$794,000 |
CPA |
DRP |
450 |
$3,700,000 |
$0 |
$0 |
$0 |
$3,700,000 |
$25,500,000 |
$23,413,000 |
WG2 |
2-part RTP |
0 |
$0 |
$0 |
$0 |
$0 |
$0 |
$0 |
$0 |
WG2 |
Additional meters |
0 |
$0 |
$0 |
$0 |
$0 |
$0 |
$0 |
$0 |
WG2 |
Comp. M&E Plan |
0 |
$275,000 |
$0 |
$0 |
$0 |
$275,000 |
$0 |
$0 |
WG2 |
M&E of Incentives |
0 |
$250,000 |
$0 |
$0 |
$0 |
$250,000 |
$0 |
$0 |
Total Expenditures/Impacts (1) |
954 |
$6,992,000 |
$0 |
$1,424,822 |
$885,603 |
$9,302,425 |
$25,500,000 |
$29,877,000 | |
Total Annual Incremental Revenue Req. (2) |
$6,992,000 |
$942,720 |
$1,424,822 |
$885,603 |
$10,245,145 |
||||
Annualized Benefits (5) |
$85,305,000 |
||||||||
Notes: |
|||||||||
(1) see 2003 table above |
|||||||||
(2) see 2003 table above |
|||||||||
(3) incremental cost is due to levelizing capital expenditures over ten years, see 2003 table. |
|||||||||
(4) see 2003 table above |
|||||||||
(5) see 2003 table above |
|||||||||
(End of ATTACHMENT B)
ATTACHMENT C
ATTACHMENT C
Critical Peak Pricing Tariff
The purpose of the Critical Peak Pricing (CPP) tariff is to achieve demand reductions from customers when electricity supply is low or when spot market power prices are high.
1.1. Applicability
1.1.1. This tariff schedule is applicable to bundled service customers in Southern California Edison (SCE) and Pacific Gas and Electric (PG&E) service territories that have demands greater than 200 kW.
1.1.2. This tariff schedule is applicable to bundled service customers in San Diego Gas and Electric (SDG&E) service territory that have demands greater than 100 kW.
1.1.3. Service under this tariff is voluntary.
1.1.4. Customers shall have an advanced metering system (meter, communication pathway, and internet access to data) as installed pursuant to AB29x or its functional equivalent.
1.1.5. Customers on this tariff must agree to allow the CEC or its contracting agent to conduct a site visit for measurement and evaluation, and agree to complete any surveys needed to enhance the program.
1.2. Critical Peak Events
1.2.1. There will be -a maximum of 12 critical peak days called per summer.
1.2.2. Critical peak days may be triggered using temperature thresholds, special alerts issued by the California Independent System Operator, forecasts of high spot market power prices, or for testing/evaluation purposes.
1.2.3. The IOUs will adjust their CPP temperature thresholds up or down over the course of the summer for the purpose of achieving 12 CPP operations.
1.2.4. The IOUs may designate separate climatic zones within their territories to account for temperature variation.
1.2.5. Critical peak days will only be called Monday through Friday, and not on holidays.
1.2.6. The summer season is defined according to the utilities' definitions as found in their existing tariffs.
1.2.7. The IOUs shall notify customers of the critical peak day the day before.
1.2.8. Critical peak hours shall be aligned with each IOU's respective commercial peak periods.
1.2.9. For the summer of 2003, the maximum number of critical peak days will be prorated to account for the late starting date.
1.3. Critical Peak Rate Effects
1.3.1. This tariff shall be designed with two time periods during critical peak days, a high-price period and a moderate-price period of approximately equal duration.
1.3.2. The high-price period energy charge shall be five times the customer's otherwise applicable on-peak energy charge. SDG&E shall use a multiple factor that will closely align its energy charges with the other IOUs (approximately a factor of 10).
1.3.3. The moderate-price period energy charge shall be three times the customer's otherwise applicable partial-peak energy charge. SDG&E shall use a multiple factor that will closely align its energy charges with the other IOUs (approximately a factor of 5).
1.3.4. On non-critical peak days, the customer's on-peak and partial peak energy charges shall be discounted such that the critical peak rate schedule is revenue neutral in comparison to the otherwise applicable rate schedules.
1.4. Transitional Incentive Options
1.4.1. Customers on the CPP tariff may select from two types of transitional incentive options: bill protection and technical assistance. Customers may elect to receive one of these incentives, both incentives (sequentially or simultaneously), or none.
1.4.2. Both transitional incentive options shall expire on December 31, 2005.
1.4.3.
1.4.4. The bill protection option shall provide 100% protection (the customer pays no higher than what it would pay under its otherwise applicable rate schedule) for the customer for a maximum of 14 months.
1.4.4.1. The bill protection option shall be capped at a participation level of 500 MWs (200 MWs for PG&E and SCE, 100 MWs for SDG&E).
1.4.4.2. If a customer leaves the CPP prior to the end of their 14 month commitment they shall receive no bill protection for any period they were on the tariff.
1.4.4.3. To receive the benefit of a lower CPP bill, customers shall reduce peak demand by a minimum of 3% per CPP event averaged over the course of the CPP months during the customer's 14 months of bill protection.
1.4.4.4. For the purpose of measuring demand reduction, kW drop is to be estimated as the difference between a customer's specific baseline for that hour and the customer's actual energy usage during that hour. The customer-specific baseline is a 10-day rolling average energy usage determined on an hourly basis, using the average of energy usage for the three days with highest total energy usage during the peak period (excluding other CPP days or other days the customer was otherwise paid to reduce power or the customer was subject to a rotating outage) prior to a CPP event.
1.4.4.5. Bill protection benefits are computed on a cumulative basis at the end of the bill protection period and, if warranted, shall be received as a credit on the customer's bill following the end of the bill protection period.
1.4.5. The technical assistance option shall enable customers to earn a rebate for professional technical assistance that enhances a customer's ability to respond to curtailment events.
1.4.5.1. Customers shall receive a rebate (not to exceed actual costs) based on no more than $50 per kW of curtailable on-peak load for technical assistance that modifies existing equipment or behavior.
1.4.5.2. Customers shall receive 50% of the rebate upon certification by a professional engineer of potential on-peak load reductions.
1.4.5.3. Customers shall receive the remainder of the rebate after demonstrating peak demand reduction equal to at least 50% of their estimated (projected by the professional engineer) load drop per CPP event as averaged over four consecutive CPP months. If the minimum level of demand reduction does not occur, the customer shall not be awarded the remainder of the rebate.
1.4.5.4. The method of measuring demand reduction is the same as described in Section 1.4.4.4.
(END OF ATTACHMENT C)
ATTACHMENT D
ATTACHMENT D
Hourly Pricing Option Tariff
The purpose of the Hourly Pricing Option (HPO) tariff is to provide a day-ahead price signal to create an incentive for customers to avoid peak usage and or shift usage to off-peak periods. The HPO tariff was approved as a voluntary pilot program for SDG&E in August 2002. The existing HPO tariff is modified in the following manner:
1.1. Applicability
1.1.1. This tariff schedule is applicable to customers with demands greater than 100 kW in San Diego Gas and Electric (SDG&E) service territory.
1.1.2. Customers shall have an advanced metering system (meter, communication pathway, and internet access to the usage data) as installed pursuant to AB29x, or the equivalent.
1.1.3. Customers on this tariff must agree to allow the CEC or its contracting agent to conduct a site visit for measurement and evaluation, and agree to complete any surveys needed to enhance the program.
1.2. Hourly Pricing
1.2.1. The hourly pricing mechanism currently provided during on-peak periods shall also apply to semi-peak periods.
1.3. Transitional Incentive Options
1.3.1. Customers on the HPO tariff may select from two types of transitional incentive options: bill protection and technical assistance. Customers may elect to receive one of these incentives, both incentives (sequentially or simultaneously), or none.
1.3.2. Both transitional incentive options shall expire on December 31, 2005.
1.3.3. The bill protection option shall provide 100% protection (the customer pays no higher than what it would pay under its otherwise applicable rate schedule) for the customer for a maximum of 14 months.
1.3.4.1. The bill protection option shall be capped at 100 MWs.
1.3.4.2. If a customer leaves the HPO prior to the end of their 14-month commitment they shall receive no bill protection for any month.
1.3.4. The technical assistance option shall enable customers to earn a rebate for professional technical assistance that enhances a customer's ability to respond to curtailment events.
1.3.4.1. Customers shall receive a rebate (not to exceed actual costs) based on no more than $50 per kW of curtailable on-peak load for technical assistance that modifies existing equipment or behavior.
1.3.4.2. Customers shall receive 50% of the rebate upon certification by a professional engineer of potential on-peak load reductions.
1.3.4.3. Customers shall receive the remainder of the rebate after demonstrating peak demand reduction equal to at least 50% of their estimated (projected by the professional engineer) load drop as averaged over four consecutive HPO months. If the minimum level of demand reduction does not occur, the customer shall not be awarded the remainder of the rebate.
1.3.4.4. For the purpose of measuring demand reduction, kW drop is to be estimated as the difference between a customer's specific baseline for that hour and the customer's actual energy usage during that hour. The customer-specific baseline is a 10-day rolling average energy usage determined on an hourly basis, using the average of energy usage for the three highest-use days for the same hour during the past 10 similar days.
(END OF ATTACHMENT D)
ATTACHMENT E
ATTACHMENT E
Demand Bidding Program
The DBP is an existing program recently modified by D.02-07-035. The purpose of the modified Demand Bidding Program (DBP) is to provide customers an opportunity to voluntarily bid demand reductions as a means of off-setting the utilities' procurement of energy supply when the cost of that energy exceeds a certain price. The DBP is modified in the following manner:
1.1. Applicability: This program is applicable to customers with demands greater than 200 kW in Pacific Gas & Electric, Southern California Edison and San Diego Gas and Electric (SDG&E) service territories.
1.1.1. Customers shall have an advanced metering system (interval meter, communication pathway, and internet-based access to usage information) as installed by AB29x, or its equivalent.
1.1.2. Customers on this tariff must agree to allow the CEC or its contracting agent to conduct a site visit for measurement and evaluation, and agree to complete any surveys needed to enhance the program.
1.2. Price Trigger
1.2.1. Utility procurement departments shall forecast an hourly price offer on a day-ahead basis. This price offer is to remain confidential, which participating customers will agree to as a condition of the agreement to accept service on this tariff.
1.2.2. The DBP is triggered in those hours where the forecast price offer exceeds $0.15 per kWh for four consecutive hours between noon and 8 pm.
1.2.3. The incentive paid to participants shall be the product of the price offer and the amount of demand load reduction.
1.2.4. The demand load reduction must be greater than or equal to 50% of the bid, up to 150% of the bid.
1.2.5. Participants must commit to a minimum bid of 100 kW per hour.
1.2.6. For the purpose of measuring demand reduction, kW drop is to be estimated as the difference between a customer's specific baseline for that hour and the customer's actual energy usage during that hour. The customer-specific baseline is a 10-day rolling average energy usage determined on an hourly basis, using the average of energy usage for the three highest-use days for the same hour during the past 10 similar days (excluding other DBP days or other days the customer was otherwise paid to reduce power or the customer was subject to a rotating outage) prior to a DBP event. The three highest-use days will be determined on the basis of customer's total energy usage during the scheduled bid period for the DBP.
1.2.7. Participants will have the option to designate a pre-bid amount in which they will only be notified of a DBP event when the price trigger meets or exceeds their specified pre-bid amount.
1.3. Emergency Trigger
1.3.1. The IOUs may activate the DBP Emergency Event option, on a `day-of' basis, when it is deemed necessary to offset outstanding system issues that may affect system reliability.
1.3.2. When a customer signs up for the program, the participant must designate a Committed Load Reduction amount that they agree to reduce their load by in the occurrence of an Emergency Trigger DBP event.
1.3.3. The incentives paid to participants during Emergency Trigger events shall be the product of their energy reduction and $0.50 per kWh.
1.3.4. The demand load reduction must be greater than or equal to 50% of the bid, up to 150% of their Committed Load Reduction.
1.3.5. Emergency Test Trigger
1.5.5.1 The utilities may activate the DBP with a simulated emergency event test trigger twice per year.
1.5.5.2 Emergency test events shall be no longer than 4 hours.
1.5.5.3 The incentive paid to participants shall be the product of their demand reduction and $0.50 per kWh per test event.
1.5.5.4 The demand load reduction must be greater than or equal to 50% of the bid, up to 150% of their Committed Load Reduction bid.
1.5.5.5 The method of measuring the demand reduction shall be the same as described in Section 1.2.6.
1.4. Transitional Incentive Option
1.4.1. Customers on the DBP may select a technical assistance incentive option.
1.4.2. This option shall expire on December 31, 2005.
1.4.3. The technical assistance option shall enable customers to earn a rebate for professional technical assistance that enhances a customer's ability to respond to curtailment events. Customers shall receive a rebate (not to exceed actual costs) based on $50 per kW of curtailable on-peak load for technical assistance that modifies existing equipment or behavior.
1.6.3.1. Customers shall receive 50% of the rebate upon certification by a professional engineer of potential on-peak load reductions.
1.6.3.2. Customers shall receive the remainder of the rebate after demonstrating peak demand reduction of at least 50% of their estimated (projected by the professional engineer) load drop as averaged over all DBP events or tests. If the minimum level of demand reduction does not occur, the customer shall not be awarded the remainder of the rebate. A minimum of two DBP events or tests must be successfully completed.
1.6.3.3. For the purpose of measuring demand reduction, kW drop is to be estimated as the difference between a customer's specific baseline for that hour and the customer's actual energy usage during that hour. The customer-specific baseline is a 10-day rolling average energy usage determined on an hourly basis, using the average of energy usage for the three highest-use days for the same hour during the past 10 similar days (excluding other DBP days or other days the customer was otherwise paid to reduce power or the customer was subject to a rotating outage) prior to a DBP event. The three highest-use days will be determined on the basis of customer's total energy usage during the scheduled bid period for the DBP.
(END OF ATTACHMENT E)
78 CPUC rulemaking R.02-06-001 on policies and practices for advanced metering, demand response, and dynamic pricing.
