14. Assignment of Proceeding

Michael R. Peevey is the Assigned Commissioner and Meg Gottstein is the assigned ALJ to this phase of the proceeding.

1. The workshop consensus for the definition of energy efficiency peak kW reductions is a pragmatic approach to addressing load impact data limitations at this time. In addition, it takes advantage of a database that the Commission has determined should be the source of all assumptions for estimating load impacts, to the extent possible.

2. As discussed in this decision, PG&E alleges inconsistencies with respect to DEER that do not appear to be based upon relevant analysis or documentation.

3. PG&E proposes an expanded peak period without documentation of the additional research to which it refers, and without the opportunity for interested parties to review the underlying data or to address the potential ramifications of its proposal.

4. If PG&E believes that the issues it raised in written comments concerning the definition of peak kW warrant further evaluation, it may present them in the context of future DEER updates.

5. An appropriate long-term definition for energy efficiency peak kW impacts needs to be considered in the context of available load shape data for individual energy efficiency measures, to be further explored as discussed in this decision.

6. The consensus recommendations concerning the estimates of peak kW the utilities should use for rebalancing their portfolios and reporting program accomplishments during the program cycle are consistent with Rule IV.11 of the Commission's adopted energy efficiency policy rules. However, further clarification is warranted with respect to customized rebate programs, as discussed in this decision.

7. Ongoing exchange of information is needed concerning the peak kW load reduction factors (ratio of kW to kWh savings) that utilities use for portfolio rebalancing and reporting.

8. The record in this proceeding supports the workshop consensus that TOU averaging significantly undervalues measures that produce relatively more load reduction during the highest cost hours, such as residential and to a lesser extent, small commercial a/c equipment upgrades.

9. The Final Report and Supplement provides a reasonable basis for adopting correction factors to adjust the avoided cost valuation of these particular measures, when TOU averaging is utilized to calculate their avoided costs.

10. Adopting correction factors based on DEER hourly load shape data is consistent with Rule IV.11 and preferable to using PG&E's hourly load shape data for several reasons discussed in this decision, including:

a. PG&E itself has elected not to use its own hourly load shapes at any point heretofore in the 2006-2008 energy efficiency planning and design process in any significant manner.

b. Instead, PG&E has utilized TOU blocks or shapes in its application for approval of its 2006-2008 energy efficiency programs and budgets that are in closer agreement with DEER hourly shapes converted to TOU shapes than the TOU shapes created from PG&E's own hourly load shapes.

c. PG&E's hourly load shapes are building end use shapes rather than measure impact shapes, and many of them are from relatively old data collection exercises using relatively small sample sizes.

d. The documentation of DEER indicates that the DEER simulations utilize field data that are more recent, more extensive and more representative of climate and vintage variations than the PG&E hourly load shapes.

e. An examination of PG&E's average hourly load shapes for certain applications (e.g., office and retail indoor lighting, office and retail cooling) indicate patterns that do not appear representative of the load impacts associated with energy efficiency measures.

11. Residential a/c unit energy efficiency savings are likely to be higher in the hotter climate zones, where efficiency improvements result in higher energy savings because of a/c usage patterns. Therefore, TOU-averaging correction factors for these measures should be based on a climate-zone specific weighting of projected measure installations, as opposed to a weighting that assumes an equal distribution of measures across climate zones.

12. The additional precision gained from individual climate-zone correction factors does not justify the complexity and possible confusion resulting from having eight or nine different climate-zone correction factors for the measure.

13. The DEER data for small office and retail building types within the commercial sector presents a reasonable range of the potential undervaluation associated with TOU-averaging for small commercial a/c (packaged and split-system direct-expansion cooling) units across all building types.

14. The weighting options (equal weighting or based on an estimate of installations across climate zones) result in very little difference to the conversion factors for commercial a/c measures. The only exception is in the case of SDG&E's weighting for office installations, which assumes that all installations of small a/c commercial units will occur in the retail sector (and none in commercial offices).

15. In view of the implementation complexities and uncertainties over the distribution of measure installations for the commercial sector, there is questionable value to approaching the commercial a/c correction factor on a sector-specific (i.e., by building type) basis. Instead, a simple average of the low (office) and high (retail) end of the range presented in the Final Report presents a reasonable approach to calculating a TOU-correction factor for territory-wide commercial a/c unit installations.

16. The CT-adder recommendations made by some parties to this proceeding represent a fundamentally different approach and theory to avoided costs than the interim methodology adopted in D.05-04-024. As discussed in this decision, modifying current avoided costs using this CT-adder approach requires the resolution of complex theoretical issues, assumptions and methodological issues that are beyond the scope of this 2006 Update.

17. Adopting a simple capacity adder, as some parties recommend as an alternative to the CT-adder approach, relies on the assumption that the current hourly price profile fails to value avoided costs properly for low load-factor energy efficiency measures during peak hours. Until the Commission further examines the theoretical and methodological issues raised with respect to the interim methodology, there is insufficient basis in the record for making this assumption.

18. Contrary to TURN's assertions, the Commission has not adopted specific methodologies that put low-load factor air conditioning measures on a different footing with the valuation approaches being applied to rate design or the evaluation of other resource options. In fact, the Commission's recent decision on a methodology for calculating the 2005 MPR would argue against making adjustments to the PX profile to allow the price shape to return the capital cost of a CT.

19. The ex ante avoided costs used for 2006-2008 portfolio rebalancing, as well as to evaluate 2006-2008 performance, should reflect the significantly changed realities in natural gas supplies and market prices that have emerged since the interim avoided costs were adopted in early 2005.

20. Using one set of avoided costs for program valuation and another set for reward determination under a risk/reward incentive mechanism would not only be unduly complicated, but could create a disincentive for utilities to rebalance their portfolios to reflect the updated avoided costs.

21. Improvements are needed to energy efficiency load/impact shape data in time for the 2009-2011 program cycle.

22. Load/impact shape improvements should be considered in the DEER updating process. However, as discussed in this decision, the 2006 Update is not the appropriate forum for specifying the DEER updating process, such as how final determinations are made on what types of data generated by load shape studies (or other EM&V studies) represent an improvement to existing values in DEER, and therefore should replace those values. Instead, these and other aspects of the DEER updating process will be considered in R.06-04-010 according to the EM&V protocol review procedures established in D.05-04-051.

23. As discussed in this decision, Energy Division is responsible for determining how the load shape studies will be managed (e.g., as part of the DEER updating process or through separate EM&V contracts) and at what level they should be funded out of EM&V authorized budgets.

24. The E3 calculator treatment of load increases as a negative benefit (versus a cost) does not affect the calculation of net benefits under the SPM tests, and would not affect the benefit-cost ratios to any significant degree.

25. As discussed in this decision, the reporting requirements developed by Energy Division could lead to a double counting of overhead costs in the SPM tests because some of those costs may already be included in the labor component of the incremental measure cost.

26. The TRC test of cost-effectiveness includes all costs associated with the energy efficiency activity, whether paid for out-of-pocket by program participants or by non-participants through the authorized revenue requirements to fund the programs.

27. The only costs that should be excluded in the TRC test on both the benefit and cost side of the equation are those incentives that represent transfer payments, as defined in the SPM. The SPM restricts such transfer payments to dollar benefits to the participant, such as rebates or rate incentive (monthly bill credits).

28. Given the definition of the TRC and PAC tests, it should generally be the case that TRC net benefits or benefit-cost ratios should be lower than the PAC cost-effectiveness results because the PAC test does not include the costs incurred by participating customers, while the TRC test does include these costs. The exception to this general rule can happen under the SPM definition of the TRC test when very large "transfer payments" between non-participating and participating ratepayers occur. However, as discussed in this decision, this should not be a frequent occurance if the proper definition of transfer payments is used and installation costs are accounted for properly.

29. The manner in which the energy efficiency program/measure is delivered or the rebate is provided to the participating customer should not alter cost-effectiveness results, all other things being equal, except under the very limited circumstances discussed in this decision.

30. The numerical examples in this decision serve to illustrate what should be obvious: A direct install program where the the utility or its contractor performs the installation of a measure should not be more cost-effective from a TRC perspective than a rebate program that provides a cash rebate to the customer up to the full cost of installation.

31. If the SPM cost components are inputted into the E3 calculator in a manner consistent with the SPM formula and definitions for the TRC test, then the scenario that DRA poses for a direct install program, where all costs associated with equipment/measure installations "disappear" from the TRC cost-side of the equation, should not occur.

32. When the SPM definition of transfer payments is properly implemented in the TRC test, participant costs are expected to be "non-negative." As discussed in this decision, there may be isolated instances where an energy efficiency measure actually costs less than the standard efficiency equipment it is replacing. However, one would not expect to see negative participant costs for the vast majority of measures, in or in the evaluation of program cost-effectiveness calculations where there is a mix of measures, if costs are inputted correctly into the E3 calculator and transfer payments are properly restricted consistent with the SPM definition.

33. The record supports the workshop consensus that, at least for the near term, the benefits of the E3 calculator outweigh the shortcomings of a platform based on Excel spreadsheets.

34. Some of the shortcomings of the current E3 calculator platform can be addressed through a redesign of the calculator, such as separating the E3 calculator inputs and outputs from the calculator engine. This separation would also facilitate the development of standardized default input values, as discussed in this decision.

35. Over the longer term, it may be appropriate to consider alternative platforms to use for the ex ante evaluations and submissions of portfolio and program plans. However, migration to another platform should not be decided until more information is known about the availability of new hourly load shapes, as well as the cost and effort needed for such an undertaking.

36. Further refinements that might be needed to the E3 calculator to create a common planning/forecasting tool for use by utility portfolio managers, third-party implementers, regulatory staff and possibly program advisory/peer review group members is also a longer term effort.

37. The issue of whether the utilities should be required to use the E3 calculator to generate the monthly, quarterly and annual reports requires further consideration among the utilities, E3 and Joint Staff.

38. As discussed in this decision, there may be additional ways to assure greater quality control over data entry into the E3 calculators on an ongoing basis.

39. The comments in this proceeding points to the continued need to coordinate across proceedings where avoided costs are being raised.

1. Until further notice of the Commission, it is reasonable to:

2. The consensus recommendations concerning the estimates of peak kW that the utilities should use for rebalancing their portfolios and reporting program accomplishments during the program cycle are reasonable and should be adopted.

3. The utilities should be required to update their ex ante estimates of kW and kWh savings for customized rebate programs and provide information on the peak kW load reduction factors used for portfolio rebalancing and reporting, as described in this decision.

4. Nothing in today's decision modifies the ex post verification and true-up requirements for energy efficiency load impacts directed in D.05-04-051 and in the adopted EM&V protocols in R.06-04-010 and its predecessor rulemaking, R.01-08-028. Today's decision provides a clarification to the true-up process by defining the peak kW metric that will be verified in ex post studies for the 2006-2008 program cycle, namely the DEER definition of peak demand.

5. It is reasonable to adopt TOU averaging correction factors for residential and small commercial a/c unit installations based on the DEER data presented in this proceeding.

6. Modifications to the interim avoided costs methodology for peak valuation adopted in D.05-04-024 should not be adopted for the reasons discussed in this decision. However, the methodological issues raised in this phase of the proceeding may be appropriate topics to explore during Phase 3.

7. The updated natural gas forecasts and avoided costs presented in Attachment 3 reflect the significantly changed realities in natural gas supplies and market prices that have emerged since the interim avoided costs were adopted in early 2005, and should be adopted.

8. As discussed in this decision, it is reasonable to adopt an action plan for improving load shape data in a practical and timely manner.

9. The minor inconsistency between the E3 calculator and the SPM with respect to the treatment of load increases does not merit changes to the E3 calculator.

10. The utilities should work on a joint request to the assigned ALJ in R.06-04-010 and Energy Division to modify the reporting requirements in order to fix the problem identified during workshops with respect to the potential double counting of costs in the SPM tests.

11. As discussed in this decision, the treatment of costs and transfer payments in the TRC test has caused some anomalies and inaccuracies in the E3 model calculations. This treatment should be corrected in future applications of the TRC test and the E3 calculator.

12. Nothing in today's decision speaks to the design of programs, or is intended to cap incentives in any manner. Rather, today's determinations speak to the need to ensure that the program cost components and transfer payments are properly inputted into the E3 calculator (or other platforms for calculating and reporting cost-effectiveness results) consistent with the SPM formulas and definitions, as discussed in this decision.

13. As discussed in this decision, our near term focus should be to improve the E3 calculation platform currently in use. In particular, the E3 calculator should be redesigned to separate the inputs and outputs from the calculator engine.

14. As discussed in this decision, approaches to quality control improvements with respect to E3 calculator data entering should be explored by Joint Staff, interested parties, the utilities and their program advisory/peer review groups in the coming months.

15. The utilities, Joint Staff and E3 should confer on the use of a common approach/tool to produce the required reports for post-2005 energy efficiency activities and report back to the ALJ, as directed in this decision.

INTERIM ORDER

IT IS ORDERED that:

1. Until further notice of this Commission, the definition of peak kilowatt (kW) contained in the 2005 Database for Energy Efficient Resources (DEER) shall be used for the purpose of verifying energy efficiency program and portfolio performance. As discussed in this decision, DEER defines peak demand as the average grid level impact for a measure between 2 p.m. and 5 p.m. during the three consecutive weekday period containing the weekday temperature with the hottest temperature of the year.

2. Until further notice, 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), collectively referred to as "the utilities," shall apply the definition of peak kW adopted herein to energy efficiency uses during the 2006-2008 program cycle, including any necessary portfolio rebalancing.

3. When rebalancing their portfolios and reporting program accomplishments during the program cycle, the utilities shall:

a) Use DEER values for peak kW and kilowatt hour (kWh) savings for those measures that are included in the DEER database;

b) Continue to use their best estimates of those values for measures that are not currently included in DEER, or for programs with measure categories rather than specific measures, such as customized rebate programs.

4. As discussed in this decision, the utilities are required to update their ex ante estimates of kW and kWh savings for customized rebate programs as they proceed with implementation, based on site specific installations for these programs, just as they are required to do for the incremental measure costs. In doing so, they shall utilize DEER savings values for the installed measures, if that data is available in DEER. Until further notice, the utilities shall present these updates of ex ante estimates to Joint Staff and the utilities' program advisory and peer review groups every six months, i.e., by June 15 and by December 15 of each year.

5. The utilities shall provide the information necessary for Joint Staff and other program advisory and peer review group members to review the methodology and/or baseline load shape (measure or end use) estimates they are using to estimate peak kW load reduction factors. In addition, the utilities shall jointly schedule a statewide meeting (or series of meetings) with their program advisory and peer review groups to discuss this information as soon as practicable. This information shall:

a) Indicate clearly where DEER and non-DEER values of kWh and peak kW impacts are used, and for the latter, present other sources of load factor data as a basis for comparison.

b) Include data sources and basis for the non-DEER energy and demand estimates.

c) Be provided within 15 days from the effective data of this decision, and on an ongoing basis thereafter, as requested by Joint Staff or the utilities' program advisory/peer review groups during the program cycle, and

d) Be posted on a website with notification of availability to the service list in Rulemaking (R.) 06-04-040.

6. The utilities shall meet among themselves, Energy and Environmental Economics, Inc. (E3) and Joint Staff on a common approach and tool for reporting that applies the Standard Practice Manual cost-effectiveness tests as described in this decision and can generate the required reporting information. The utilities and Joint Staff shall jointly report back on the common approach and tool that will be used for this purpose by October 15, 2006. The report shall be submitted to the assigned Administrative Law Judge (ALJ) in R.06-04-010. The ALJ shall consider this report in consultation with Joint Staff and may take any additional steps necessary to ensure that a common approach and tool for reporting is implemented by the utilities in a timely manner.

7. Until further notice, the following utility territory-wide correction factors shall be applied to the avoided cost valuation using time-of-use (TOU) shapes for residential air conditioning (a/c) unit energy savings:

These correction factors shall be applied to the total avoided cost valuation for all residential a/c unit installations, excluding transmission and distribution avoided costs.

8. Until further notice, the following utility territory-wide correction factors shall be applied to the avoided cost valuation using TOU shapes for small commercial a/c (packaged and split-system direct-expansion cooling) unit energy savings:

These correction factors shall be applied to the total avoided cost valuation for small commercial a/c unit installations in the commercial sector, excluding transmission and distribution avoided costs.

9. If the utilities do not currently identify the a/c unit installations and the associated peak savings referred to in Ordering Paragraphs 7 and 8 above in the E3 calculator (or in other formats where projected savings are presented), they shall develop a consistent and joint approach for doing so. This may entail estimating the fraction/percentage of installations for cooling end-use measures that represent the a/c unit hardware upgrades, and applying the correction factor to that fraction, or some other approach that is reasonable, consistent across utilities and practicable. The proposed approach shall be submitted with the E3 calculator updates directed in Ordering Paragraph 17.

10. The ex ante natural gas and electric generation avoided costs presented in Attachment 3 shall be used for 2006-2008 portfolio rebalancing as well as to evaluate 2006-2008 performance for energy efficiency activities.

11. As discussed in this decision, the utilities shall jointly contract with appropriate expertise to develop a Load Shape Update Initiative in R.06-04-010. The Load Shape Update Initiative shall include public workshops with technical experts to help scope the effort as well as review the draft report. Energy Division may schedule and lead these workshops, or delegate this function to the contractor(s). The contractor(s) shall be tasked with developing draft and final reports addressing the following issues, as well as others that emerge from the scoping workshops, as appropriate:

(a) What load shapes/blocks exist in the E3 calculators, California Energy Commission and utility load forecasts, and the data source quality;

(b) The magnitude of the problem(s) with existing load shape data, utility vs. statewide;

(c) The costs and benefits associated with potential improvements to existing load shape data;

(d) Based on (a) through (c), what should be:

12. The utilities shall ensure that the contractor(s) retained for the Load Shape Update Initiative develops a draft report by October 1, 2006 that includes preliminary recommendations on the issues listed under (d) above. Energy Division (or the contractor(s)) shall hold public workshops on the draft report as soon as practicable thereafter, so that the contractor(s) can respond to feedback and questions. The contractor(s) shall be tasked with developing a final report by November 15, 2006 that, among other things, summarizes the areas of consensus and non-consensus among workshop participants by issue area and presents final recommendations.

13. Energy Division, the assigned ALJ or Assigned Commissioner in R.06-04-010 may solicit post-workshop written comments on the final Load Shape Update Initiative report from interested parties, as they deem appropriate. As discussed in this decision, after considering the final report recommendations, Energy Division shall proceed 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. As soon as practicable after the final report is submitted, Energy Division shall update the EM&V roadmap in consultation with the assigned ALJ in R.06-04-010 to reflect a schedule that targets the completion and incorporation of the highest priority load shape improvements into the E3 calculator by the end of December, 2007.

14. Nothing in this decision is intended to preclude the Assigned Commissioner or ALJ in R.06-04-010 from directing the utilities to broaden the scope of the contractor(s) work, or take any other steps that may be necessary to address the Load Shape Update Initiative. The Load Shape Initiative and load shape studies to be conducted during 2006-2008 shall be funded out of authorized 20062-2008 EM&V funding levels. Energy Division shall determine the specific EM&V budget category (or categories) for funding these efforts in consultation with the utilities.

15. As discussed in Ordering Paragraph 18 below, Joint Staff, interested parties, the utilities and their program advisory/peer review groups shall collaboratively explore ways in which to ensure that the Total Resource Cost (TRC) cost components are entered into the E3 calculator (or in other platforms for calculating and reporting cost-effectiveness results) in the future in a manner that is consistent with the Standard Practice Manual (SPM) definitions and formula for the TRC test. As discussed in this decision, all participant and non-participant costs shall be fully reflected in the TRC test with the limited exception of dollar benefits such as rebates or rate incentives (monthly bill credits) to the participating customer. Those dollar benefits shall be treated as a transfer payment and excluded on both the benefit and cost side of the TRC equation, as currently directed under the SPM. However, they will be included in the Program Administrator Costs (PAC) test. If the incentive is to offset a specific participant cost, as in a rebate-type incentive, the full customer cost (before the rebate) must be included in the TRC test as a participant cost. In situations where a direct install program does not bill or collect from the customer for any portion of the costs, then all costs should appear as program administrator costs in both the PAC and TRC tests.

16. The utilities shall jointly contract with the appropriate expertise to update each of their E3 calculators in compliance with today's determinations. These updates shall reflect:

The cost of the contract shall be paid for out of the utilities' portion of EM&V budgets for the 2006-2008 program cycle.

17. Prior to submitting the required updates to the E3 calculator described in Ordering Paragraph 16, the utilities and their contractor(s) shall present the revised E3 calculators (including all inputs) to their program advisory and peer review groups for review in joint statewide public meeting(s), with notice to the service list in R.06-04-010. At least two weeks prior to the meeting(s), the utilities and/or contractor(s) shall post to a website all of the revisions responding to today's directives with a written summary of the changes made. At the same time, the utilities shall notify the utility advisory group/peer review group members and the service list in R.06-04-010 of the availability of this information.

In addition to the revised E3 calculator and input files, the website posting shall include a summary of the changes made in response to today's decision. The website posting shall also include a table summarizing the comments made at the review meeting(s) discussed above, the name/organization providing the comment, and the utilities/contractor(s) responses to each comment (e.g., whether the comment resulted in further modifications to the E3 calculator to satisfy the requirements of today's decision, or not-and why not).

After considering the input received at the meeting(s), the utilities shall submit final E3 calculator and input revisions no later than September 8, 2006 in the form of a Notice of Availability (Notice). The Notice shall provide a website address where the revised E3 calculator and associated inputs can be accessed, and include the due date for comments on the E3 calculator revisions and filing/ service requirements, as set forth below:

(a) The Notice and all comments shall be filed in the Commission's Docket Office and served on the service list in R.06-04-010, consistent with the electronic service protocols in that proceeding.

(b) Parties to R.06-04-010 may file opening comments on the compliance submittal no later than 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 shall address the compliance submittal by ruling, or take other steps as necessary to ensure compliance with today's decision.

18. During the third and fourth quarters of 2006 the utilities shall jointly plan and notice workshops for the purpose of exploring with Joint Staff, interested parties and program advisory and peer review group members ways to assure greater quality control over E3 calculator inputs on an ongoing basis. As discussed in this decision, the utilities shall jointly contract with appropriate expertise to assist in this effort. The utilities shall jointly report back to the Assigned Commissioner and ALJ in R.06-04-010 on the consensus and non-consensus recommendations presented at those meetings no later than December 15, 2006. The workshop notice and report shall be served on the service list in R.06-04-010 and on the utility program advisory group and peer review group members. The Assigned Commissioner and ALJ in R.06-04-010 shall consider the report in consultation with Joint Staff, and implement quality control improvements as they determine are appropriate and practicable. Approaches to consider during the workshops shall include:

(a) Programming the E3 calculator to use a common or standardized data base as default values for most or all measures, and include the capability to flag data entries that differ from those values, and

(b) Establishing a review process for selected calculator inputs before they are entered into the calculator, such as measure cost inputs.

(c) Additional refinements to the E3 calculator that can serve to flag or correct input inconsistencies to assist in the quality control of input data.

19. Today's refinements to the interim avoided costs adopted in Decision (D.) 05-04-024 are specific to the evaluation of energy efficiency resources, and do not address pricing for Qualifying Facilities or other applications of avoided or marginal costs. However, as discussed in D.05-04-024, and reiterated in this decision, in Phase 3 of this proceeding the Commission shall consider permanent adoption of the interim avoided cost methodology adopted in D.05-04-024 for energy efficiency as refined today, as well as consider the potential application of this methodology to other resource options, such as distributed generation and demand response programs.

20. In the meantime, as discussed in this decision, the Commission shall continue to coordinate its consideration of avoided-cost related issues across Commission proceedings to ensure that the 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.

21. Unless otherwise directed, all reports, notices of availability, notices of workshops or other submittals required by this decision shall be distributed to the service list in the energy efficiency rulemaking, R.06-04-010, consistent with the electronic service rules established for that proceeding. Those rules are contained in Appendix A of the Ordering Instituting Rulemaking in R.06-04-010, issued on April 13, 2006. As indicated in those rules, hard copies of all submittals should also be served on the assigned ALJ and Commissioner in R.06-04-010.

22. The Assigned Commissioner or Administrative Law Judge in R.06-04-010 may, for good cause, modify the due dates established by this decision.

23. All interested individuals or organizations who are not already parties (appearances) to R.06-04-010, and who wish to receive the notices and submittals described in today's decision and have the opportunity to file comments, where solicited, shall file a motion to intervene for this purpose in R.06-04-010 without delay. For instructions on how to file such a motion, contact the Public Advisors Office at (415) 703-2074.

24. All individuals or organizations who do not wish to become parties (appearances) to this proceeding but wish to be served documents electronically may be added under the "state service" or "information only" categories of the service list in R.06-04-010 by submitting a written request to the Commission's Process Office. Such requests should include the full name, address, phone number and email address of the individual/organization and should reference R.06-04-010, and should be mailed to the Process Office at the California Public Utilities Commission, 505 Van Ness Avenue, Room 2000, San Francisco, California 94102.

25. This decision shall be served on the "2006 Update" service list in this proceeding, and the services list in Application 05-06-004 et al. and R.06-04-010.

This order is effective today.

Dated June 29, 2006, at San Francisco, California.

LIST OF ACRONYMS AND ABBREVIATIONS

A.

Application

a/c

air conditioning

ALJ

Administrative Law Judge

AMI

advanced metering infrastructure

CCGT

combined cycle gas turbine

CEC

California Energy Commission

CT

combustion turbine

D.

Decision

DEER

Database for Energy Efficient Resources

DR

demand response

DRA

Division of Ratepayer Advocates

E3

Energy and Environmental Economics, Inc.

EM&V

Evaluation, measurement and verification

Final Report

final report summarizing consensus and non-consensus positions on the 2006 Update issues, including final recommendations for Commission consideration

kW

Kilowatt

kWh

kilowatt hour

kWh-yr

kilowatt-year

LRMC

long-run marginal costs

mimeo.

Mimeograph

MPR

market-price referent

Notice

Notice of Availability

NYMEX

New York Mercantile Exchange

p.

Page

PAC

program administrator cost

PG&E

Pacific Gas and Electric Company

PX

California Power Exchange

QFs

Qualifying Facilities

R.

Rulemaking

RPS

Renewals Portfolio Standard

SCE

Southern California Edison Company

SDG&E

San Diego Gas & Electric Company

SEER

Seasonal Energy Efficiency Ratio

SoCalGas

Southern California Gas Company

SPM

Standard Practice Manual

"the utilities"

Pacific Gas and Electric Company, Southern Califonria Edison Company, San Diego Gas & Electric Company, and Southern California Gas Company, collectively

TOD

time-of-delivery

TOU

time-of-use

TRC

total resource cost

TURN

The Utility Reform Network

"2006 Update Consultants"

Energy and Environmental Economics, Inc. and James J. Hirsch and Associates

UC

utility cost

"workshop participants" or "participants"

Referred to those participating at the workshop collectively

(END OF ATTACHMENT 1)

Gottstein Attachment 2

Gottstein Attachment 3

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