ALJ/MEG/tcg Mailed 7/3/2006
Decision 06-06-063 June 29, 2006
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA
Order Instituting Rulemaking to Promote Consistency in Methodology and Input Assumptions in Commission Applications of Short-Run and Long-run Avoided Costs, Including Pricing for Qualifying Facilities. |
Rulemaking 04-04-025 (Filed April 22, 2004) |
INTERIM OPINION:
2006 UPDATE OF AVOIDED COSTS
AND RELATED ISSUES
PERTAINING TO ENERGY EFFICIENCY RESOURCES
TABLE OF CONTENTS
Title Page
INTERIM OPINION: 2006 UPDATE OF AVOIDED COSTS AND RELATED
ISSUES PERTAINING TO ENERGY EFFICIENCY RESOURCES 1
1. Introduction and Summary 2
2. Procedural Background 10
3. Purpose and Scope of the 2006 Update 15
4. Peak Definition 17
4.1. Workshop Consensus and Non-Consensus 21
4.2. Other Comments 23
4.3. Final Report Recommendations 24
4.4. Discussion 24
5. Undervaluation from TOU Averaging 29
5.1. Workshop Consensus and Non-consensus 33
5.2. Other Comments 33
5.3. Final Report Recommendation 36
5.4. Discussion 36
6. Modification of Interim Avoided Cost Methodology 43
6.1. Interim Avoided Cost Methodology 43
6.2. Workshop Consensus and Non-consensus 45
6.3. Positions of the Parties 46
6.4. Final Report Recommendations 49
6.5. Discussion 50
7. Modifying Natural Gas and Electric Generation Avoided Costs to
Reflect Updated Market Prices and Natural Gas Forecasts 55
8. Improving Load Shape Data 58
9. Standard Practice Manual-Related Anomalies 62
9.1. Treatment of Load Increases 63
9.2. Overhead Double Counting 64
9.3. Direct Install Costs in the TRC Test 65
10. Other Issues 75
11. Updating the E3 Calculator in Compliance with Today's Decision 79
12. Coordination of Avoided Cost-Related Issues 80
13. Comments on Draft Decision 83
14. Assignment of Proceeding 84
Findings of Fact 84
Conclusions of Law 92
INTERIM ORDER 94
LIST OF ATTACHMENTS
Attachment 1 - List of Acronyms and Abbreviations
Attachment 2 - Supplement
Attachment 3 - 2006 Update Workshops in the Final Report
INTERIM OPINION:
2006 UPDATE OF AVOIDED COSTS
AND RELATED ISSUES
PERTAINING TO ENERGY EFFICIENCY RESOURCES
1. Introduction and Summary1
By today's decision, we address the "2006 Update" of avoided costs and related issues that were identified in Decision (D.) 05-09-043 and subsequent scoping rulings. Avoided cost refers to the incremental costs avoided by the investor-owned utility when it purchases power from qualifying facilities (QFs), implements demand-side management, such as energy efficiency or demand-response programs, or otherwise defers or avoids generation from existing/new utility supply-side investments or energy purchases in the market. Avoided costs also encompass the deferral or avoidance of transmission and distribution-related costs. In D.05-04-024, we adopted an avoided cost methodology for the purpose of evaluating the 2006-2008 energy efficiency portfolio plans of Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE), San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas), which were filed on June 1, 2006.2
By this decision, we refine the interim avoided costs adopted in D.05-04-024 in two ways. First, we adopt correction factors for residential and small commercial air conditioning (a/c) unit installations,3 to account for the undervaluation of avoided costs when hourly avoided costs are averaged for these measures by time-of-use (TOU) periods. TOU-based averaging of the adopted hourly avoided costs occurs when there is insufficient data to create a corresponding load shape (kilowatt (kW) and kilowatt hour (kWh) impacts in each hour) for a particular measure. For residential a/c units, the correction factors are: PG&E-1.171, SCE-1.202 and SDG&E, 1.276. For commercial sector installations the correction factors are: PG&E-1.085, SCE-1.105 and SDG&E-1.145. These correction factors will be applied to the total avoided cost valuation for the installations, excluding transmission and distribution avoided costs. For example, if the ratio is 1.17, and the TOU avoided cost is $100, we will multiply $100 by 1.17 (or increases $100 by 17%) to correct the TOU-weighted avoided cost to the hourly equivalent ($117).
Second, we update the natural gas and generation avoided costs to reflect more recent market realities for natural gas prices. These updates are based on recent market data and updated gas price forecasts, as discussed in this decision. They result in significant increases to avoided costs through 2014. Attachment 3 presents the updated values for natural gas and electric generation avoided costs.
Several parties also recommend that we modify the interim avoided cost methodology at this time to incorporate an adder during peak hours, based on the costs of a combustion turbine (CT). This adder would be in addition to the TOU-averaging correction factors described above. Parties supporting a CT-based adder contend that the current hourly price profile in the interim avoided costs fails to value avoided costs properly for low load-factor energy efficiency measures during peak hours, and therefore, an adder during these hours is appropriate. There was, however, no consensus on this issue. Moreover, there was no consensus on the methodology or input assumptions for calculating the CT-based adder. The record indicates that the value of a CT-based adder could range from approximately $28 to $44 per kilowatt-year (kW-yr), depending the methodology and input assumptions.
We find that consideration of a CT-adder requires the resolution of complex theoretical issues, assumptions and methodological issues that are beyond the scope of the 2006 Update, and should instead be addressed in Phase 3 of this rulemaking. Some parties recommend that the Commission adopt a simple capacity adder until these complexities can be further examined; namely, a capacity adder of 10 percent for residential a/c and 5 percent for commercial cooling measures. However, this approach still assumes that the current hourly price profile fails to value avoided costs properly during peak hours. We are unwilling to accept this assumption until we can further examine the underlying theoretical and methodological issues discussed in this decision. We will do so in Phase 3.
In sum, the two refinements we make today to the interim avoided costs adopted in D.05-04-024 are to: (1) adopt TOU-averaging correction factors and (2) update natural gas and electric avoided costs based on recent gas price forecasts and market data, as described above. These refinements are specific to energy efficiency resources, and do not address pricing for QFs or other applications of avoided or marginal costs.4 However, in Phase 3 of this proceeding, we will consider the permanent adoption of the interim avoided cost methodology with today's refinements for energy efficiency resource evaluation, as well as consider the potential application of this methodology to other resource options, such as distributed generation and demand response. In the meantime, as discussed in this decision, we will continue to coordinate our consideration of avoided-cost related issues across Commission proceedings to ensure that avoided cost methodology is debated and resolved in this rulemaking, rather than in multiple proceedings where the methods and inputs for specific applications of avoided or marginal costs are applied.
We also address today several additional issues related to the valuation of energy efficiency resources that were identified for this phase of this proceeding. In particular, we adopt a common definition for energy efficiency peak kW reductions based on the Database for Energy Efficient Resources (DEER) definition of peak load reductions, as follows:5
· Peak is defined as the average grid level impact for the measure from 2 p.m. to 5 p.m. during the three consecutive weekday period containing the weekday with the hottest temperature of the year.
· DEER identifies these three contiguous peak kW days for each of the 16 California climate zones, based on the weather data sets developed for the California Title 24 Building Energy Efficiency Standards.
· DEER also defines a secondary peak demand period for educational facilities and other buildings that tend to operate at greatly reduced use during the peak demand period defined above. For this purpose, DEER uses the next highest peak during a period in which the facility is operated in full use mode.
Until further notice, the Commission will use this definition of peak kW for the purpose of verifying energy efficiency program and portfolio performance ex post (i.e., after measure installation/program implementation). In addition, the utilities are required to apply this definition to energy efficiency uses during the 2006-2008 program cycle, including any necessary portfolio rebalancing. An appropriate long-term definition for energy efficiency peak kW impacts will need to be considered in the context of available load shape data for individual energy efficiency measures.
We clarify today what ex ante estimates of peak kW impacts the utilities should use for rebalancing their portfolios and reporting program accomplishments during the 2006-2008 program cycle, and the schedule for updating ex ante estimates of kW and kWh savings for customized rebate programs as they proceed with implementation.6 We also establish the calculator platform to be used for the ex ante evaluations and submissions of portfolio plans in preparation for the 2009-2011 program cycle.
In addition, we take steps to facilitate the ongoing exchange of peak load impact information among the utilities, Joint Staff and members of the utilities' program advisory/peer review groups, as the utilities consider rebalancing their portfolios during the program cycle. To this end, we direct the utilities to provide information to Joint Staff and their program advisory/peer review groups within 15 days of this decision that will enable them to review the estimates they are currently using for peak kW reduction load factors.7
We also adopt an action plan for moving forward with the requisite load shape updating that all parties urge us to undertake in order to improve program evaluation and resource planning efforts in the future. As discussed in Section 8, this "Load Shape Update Initiative" is designed to assist Energy Division in identifying problems in existing load shape data and in establishing priorities and study scopes for load shape improvements by end uses/measures over the next 18 months. It is modeled after the process we have undertaken to obtain public input and technical expertise for this 2006 Update, which we have found to be very effective.
As discussed in Section 8, the Commission will not take formal action on this matter by issuing a decision or ruling on what specific improvements to load shape data should be undertaken or the associated budget level and schedule for these efforts. These specific determinations should be made by Energy Division, per our discussion in D.05-01-055 of Energy Division's functions under the administrative structure for energy efficiency in 2006 and beyond.8
Accordingly, Energy Division will consider the information obtained through the Load Shape Updating Initiative as it proceeds to develop the study scopes, specific work tasks, schedules and budgets for load shape improvements as part of its ongoing evaluation, measurement and verification (EM&V) responsibilities. Funding for the Load Shape Update Initiative and load shape studies to be conducted during 2006-2008 will come out of authorized 2006-2008 EM&V funding levels. Energy Division will determine the specific EM&V budget category for funding these efforts in consultation with the utilities.
Today's decision also addresses several anomalies that were observed during the 2006-2008 planning process for energy efficiency with respect to cost-effectiveness calculations. In particular, we find that anomalies with respect to the treatment of costs in the total resource cost (TRC) test need to be corrected, and provide direction for this purpose. We reiterate that the TRC must capture all participant and non-participant costs of the program. In addition, we direct the utilities to develop a joint request to modify the reporting requirements in order to correct the overhead double-counting problem discussed in this decision.
Finally, we discuss potential improvements to the quality control and oversight of data assumptions and inputs used to perform cost-effectiveness calculations in the future. We direct the utilities to collaboratively explore these and other approaches with Joint Staff, interested parties and the public through workshops noticed to the service list in R.06-04-010 and to the utility program advisory and peer review group members. By December 15, 2006, the utilities are required to report back to the assigned Administrative Law Judge (ALJ) and assigned Commissioner in R.06-04-010 on consensus and non-consensus recommendations presented at the workshops. For this effort, the utilities are directed to jointly hire technical expertise to ensure that options for improvements and implementation requirements associated with them are fully explored and presented in the report.
We direct the assigned Commissioner and ALJ to consider these recommendations in consultation with Joint Staff and take the necessary steps to implement any quality control improvements that they determine are reasonable and practicable. For this purpose, the assigned Commissioner, ALJ and/or Energy Division may hold further workshops, solicit written comments, obtain technical expertise or take other steps that they deem necessary to further consider and implement quality control improvements to the data assumptions and inputs used to perform cost-effectiveness calculations.
Compliance with today's decision will require updates to the model and model inputs used to perform energy efficiency cost-effectiveness calculations. We direct the utilities to jointly contract with the appropriate expertise to perform these tasks. As discussed in Section 9, these model and model input updates will be reviewed by the utilities' program advisory and peer review groups in statewide public meetings prior to submission to the Commission.9 The compliance submission is due by September 8, 2006. The utilities are directed to file a Notice of Availability and serve that notice on the service list in R.06-04-010.
All interested individuals or organizations who are not already parties (appearances) to R.06-04-010, and who wish to have the opportunity to comment on the compliance submittal described above should file a motion to intervene for this purpose in R.06-04-010 without delay. Parties to R.06-04-010 may file opening comments on the compliance submittal by September 22, 2006 and reply comments by September 29, 2006. After considering written comments, and in consultation with Joint Staff, the assigned ALJ in R.06-04-010 will address the compliance submittal by ruling, or take other steps as necessary to ensure compliance with today's decision.
1 Attachment 1 describes the abbreviations and acronyms used in this decision.
2 We refer collectively to PG&E, SCE, SDG&E and SoCalGas throughout this decision as "the utilities."
3 As discussed in this decision, "small commercial" unit installations refers to direct-expansion packaged or split-system a/c units installed in the commercial sector.
4 As we recognized in opening this rulemaking, marginal costs used for revenue allocation and rate design in Commission proceedings are a "close derivative" of avoided cost calculations. Although "marginal costs" and "avoided costs" are not precisely identical in all contexts, for the purpose of today's decision we use these two terms interchangeably.
5 DEER is a database developed jointly by this Commission and the California Energy Commission (CEC), and funded by ratepayers.
6 In this context, "ex ante" refers to estimates of load impacts that are made prior to measure installation/program implementation. As noted above, "ex post" refers to load impacts that are verified after-the-fact, i.e., after measure installation/program implementation. This verification can be based on a combination of site inspections of installed measures, engineering studies using site-specific data, regression analyses of billing data or other approaches. We have established protocols for ex post verification of load impacts in Rulemaking (R.) 06-04-010 and its predecessor proceeding, R.01-08-028.
7 Joint Staff refers to Energy Division and CEC staff assigned to work on energy efficiency issues in the collaborative process set forth in R.01-08-028 and Application (A.) 05-06-004 et al.
8 As we stated in that decision, and reiterate in today's decision: "we anticipate that the CEC staff can be called upon to provide Energy Division with technical input and, if needed, staffing support for these functions." D.05-01-055, mimeo., p. 51.
9 The utility program advisory and peer review groups are part of the administrative structure for post-2005 energy efficiency established in D.05-01-055 (Section 5.2.2). The utilities' program advisory groups draw from the energy efficiency expertise of both market and non-market expertise across the full spectrum of program areas and strategies. The program advisory groups: (1) provide guidance to the utilities regarding region-specific customer and program needs, (2) provide a forum for input and collaboration with the local interests and stakeholders served by the program, and (3) meet on a statewide basis to address statewide design and consistency issues across service territories. The peer review groups are a subgroup of non-financially interested members with extensive energy efficiency expertise that serve as peer reviewers in the competitive solicitation process, implementation and planning process, as described in that decision. Joint Staff are members of both the program advisory and peer review groups, and Energy Division chairs the latter.
