11. Assignment of Proceeding
Michael R. Peevey is the Assigned Commissioner and Michelle Cooke is the assigned ALJ in this proceeding.
1. The reasonably foreseeable 2005 demand reduction from implementing the proposed critical peak pricing rates for all bundled customers 200 kW and larger is 36 MW statewide.
2. Limiting applicability of the proposed critical peak pricing rates to bundled customers 200 - 500 kW reduces the expected load reduction for Summer 2005 to 13.2 MW statewide.
3. The BIP reservation payment ($7/kW/month) was adopted in D.01-04-006 and was designed to provide the same bill impact to customers as the non-firm/interruptible rates.
4. Excluding DRP loads from default CPP would further reduce the amount of potential summer peak reductions by 0.1 - 3.2 MW.
5. Excluding agricultural customers from the tariff would further reduce the amount of potential summer peak load reduction by 0.6 - 3.4 MW.
6. Electric generators requiring start-up power, oil pumping customers, schools, and hospitals with loads between 200 and 500 kW cannot be easily excluded by simply excluding a tariff schedule from applicability.
7. PG&E and SCE proposals do not include the rate schedules that serve most oil pumping and generation customers in their eligible customer groups.
8. Defining the amount of start-up load of generators to exempt from critical peak pricing rates presents practical problems.
9. Many large customers make energy related capital investments as part of their ongoing business capital planning process and investment plans for Summer 2005 are already established.
10. The general rate design approach, event definition, and event triggers, should be as consistent at possible between service territories although the actual rate of each utility may vary based on its different cost structure.
11. Predictability and regularity of pricing that is set in advance is most likely to permit customers to adapt their operations to new price signals.
12. TOU period rate differentials lead to sustained reduction in use from increased investment in efficiency improvements.
13. Price signals sent by TOU rates result in an overall lowering of peak demand on all days, not just the most critical days, because the prices reflect average costs to provide energy during each time-of-use period, rather than actual market prices.
14. The narrower peak period of 2:00 p.m. to 6:00 p.m. will generally capture the peak system loads without significant risk of peak shifting.
15. The load level relied on to perform revenue allocation should have a relationship to the demand level for which the utility must procure reserves for as part of the Commission's resource adequacy requirements.
16. A four hour CPP event duration will adequately cover the critical peak.
17. PG&E and SCE did not forecast significant enrollment increases from reopening non-firm rates.
18. The BIP program remains open to customer sign-ups.
19. SDG&E's proposed emergency rate requires participants to reduce load on 30 minutes' notice in exchange for discounted rates during non-critical peak periods.
1. The motions to intervene by SVMG and CHA/CSHE are granted.
2. Admission of SVMG's late-served testimony by ALJ Cooke is affirmed.
3. Any other outstanding motions are denied.
4. Transferring existing non-firm/interruptible rate customers to the BIP reservation payment program now could compromise an important short-term reliability resource for Summer 2005.
5. Non-firm/interruptible load should be excluded from the default CPP for Summer 2005.
6. All customers should receive price signals, regardless of their load shape or size, that indicate when power is more expensive to procure.
7. For Summer 2005, we agree that customers with flat load profiles are generally not well positioned to reduce load on-peak without significant impacts to their core business and therefore customers with 500 kW of load or greater should be excluded if the Commission implements new default rates for Summer 2005.
8. The Executive Director should alert the proper decisionmakers at the Department of Water Resources and U.S. Bureau of Reclamation about the impact water release decisions have on energy consumption and peak demand issues so that we can better coordinate response to expected high demand days throughout the state.
9. Agricultural customers over 200 kW should be excluded from any revisions to the default tariff for Summer 2005.
10. We should not establish an exemption for electric generators requiring start-up power, oil pumping customers, schools, and hospitals with loads between 200 and 500 kW for Summer 2005.
11. Given the exclusions we have identified for Summer 2005, using the aggressive assumptions of load reduction described herein, the resulting upper bound load reduction potential would be 22.3 MW for PG&E, 32.3 MW for SCE, and 8.0 MW for SDG&E.
12. Using our more conservative assumptions, it would be 4.5 MW for PG&E, 6.4 MW for SCE, and 1.6 MW for SDG&E.
13. Most customers will not be well positioned to respond to new default rates this summer, even if the bill impacts justified their response.
14. Implementation of the proposed critical peak pricing rates would not accomplish sufficient demand reduction this summer to justify the expected implementation costs of $10.45 million or the disruption to customers.
15. To achieve significant demand response during the critical peak, we will need to place special emphasis on reaching air conditioning load, which drives 29% of the peak load, whether through pricing or other types of programs.
16. A default critical peak pricing rate for Summer 2005 should not be implemented.
17. Statewide consistency in design will facilitate customer ability to provide demand response.
18. Upon completion of rate design proceedings for each utility, customers should be placed on a critical peak pricing tariff as a default, with the ability to convert to the TOU rates adopted for each utility. This should occur in 2006 for PG&E and SDG&E and in 2007 for SCE.
19. By narrowing the peak period, the price differential between the peak and partial-peak TOU rates will increase, sending a stronger investment signal than adding a fourth TOU period.
20. As long as the revenue requirement used to establish TOU rates includes the costs to meet load during critical peak periods, no additional hedging premium should be required if a customer chooses not to participate on the critical peak pricing tariff.
21. In order to send the correct pricing signal to customers under a critical peak pricing rate, the critical peak period costs need to be unbundled from the revenue requirement and recovered from customers only when a critical peak event is called.
22. The utilities should establish a revenue requirement for non-critical peak hours assuming no critical peak events and rates to collect that revenue requirement.
23. The utilities should separately identify the costs to meet the critical peak, and charge those costs to usage only during the critical peak.
24. By calculating rates in this manner, we do not need to establish any particular crediting mechanism for when an event is called, since the revenue requirement being collected from customers on the critical peak pricing rates during non-event hours has already excluded the costs associated with meeting the utility's critical peak needs.
25. The event trigger should bear a relationship to the load levels assumed in rate design and for resource adequacy.
26. The MW trigger level could be set as a specific MW amount or as the difference between the long term and day-ahead forecast load.
27. Notification of a CPP event should be effected by 3:00 p.m. the day ahead.
28. SDG&E's request to expand the eligible participation in its voluntary CPP program is reasonable.
29. The notification time for a CPP event under the voluntary rate should be adjusted from 5:00 p.m. to 3:00 p.m. the day ahead for all three utilities.
30. Continuing a limited term period of bill protection is warranted to provide that additional level of comfort as customers explore their demand responsive capabilities.
31. PG&E and SCE did not forecast significant enrollment increases from reopening non-firm rates.
32. The BIP program remains open to customer sign-ups.
33. Customers who have the ability to shed load under emergency conditions already have an option to be compensated for making that load available to PG&E and SCE.
34. SDG&E's proposed emergency rate requires participants to reduce load on 30 minutes notice in exchange for discounted rates during non-critical peak periods.
35. SCE should pursue a targeted advertising program targeting air conditioning load.
IT IS ORDERED that:
1. The Executive Director should alert the proper decisionmakers at the Department of Water Resources and U.S. Bureau of Reclamation about the impact water release decisions have on energy consumption and peak demand issues so that we can better coordinate response to expected high demand days throughout the state.
2. The Administrative Law Judges in Application (A.) 04-06-024 and A.05-02-019, shall suspend the current schedule (if needed) and require revised rate designs by the subject utilities to accomplish the objectives set forth in this decision.
3. Southern California Edison Company (SCE) shall prepare its next rate design application consistent with these policies.
4. In their rate design applications the utilities shall narrow the current peak period to cover the hours of 2:00 p.m. to 6:00 p.m.
5. In their rate design applications, the utilities shall calculate rates for the non-critical peak hours based on an adopted revenue requirement for all hours that reflects costs in a year with no critical peak events and separately establish the rate for the critical peak period to reflect the utility's anticipated marginal cost to procure power during critical peak periods.
6. Each utility in its rate design proceeding shall designate the specific system conditions that will trigger a CPP event call, consistent with the system conditions used in its rate design and resource adequacy requirements.
7. In each rate design proceeding, the number of events shall be determined based on the forecasts and system conditions used to allocate revenue to the critical peak.
8. In each utility's rate design proceeding, the Commission will review whether the reservation payment Base Interruptible Program (BIP) provides a consistent bill impact to the current non-firm rate discount.
9. Over the three year general rate case cycle the rate discount in non-firm rates shall be converted to a reservation payment under BIP.
10. Pacific Gas and Electric Company, SCE, and San Diego Gas & Electric Company (SDG&E) shall provide all data and background information needed to implement the Working Group 2 monitoring and evaluation plan, under appropriate confidentiality protections, as needed, to those involved in the evaluation process. The utilities shall also make this data available to the CEC and academic researchers, also under suitable confidentiality protection, to facilitate understanding of demand response. The California Energy Commission in coordination with the Energy Division shall supervise this work.
11. All of SDG&E's proposed changes to its voluntary critical peak price (CPP) rates are approved.
12. PG&E's proposed changes to its temperature trigger and algorithm for its voluntary CPP rates are approved.
13. Four test events for evaluation purposes are approved for all three utilities for voluntary CPP rates.
14. Twelve-month bill protection for new voluntary CPP rate customers should be approved.
15. The maximum demand of customer on the voluntary CPP rate on CPP days shall be disregarded for purposes of determining the customer's monthly demand charge, as long as the customer's maximum demand occurs during non-event hours.
16. The 2005 Summary Tables in Section 9.4 are adopted.
17. SDG&E's CPP-E as set forth in Exhibit 7, Chapter 2, Attachment D is approved, effective immediately.
18. A.05-01-016, A.05-01-017 and A.05-01-018 are closed.
This order is effective today.
Dated ____________, 2005, at San Francisco, California.
Evelyn Kahl |
Ed Yates |
|
David L. Huard |
Keith Mccrea |
Marcel Hawiger |
(END OF APPENDIX A)
