8. Discussion

Before addressing the specific issues in this proceeding, we must commend all those who have worked so diligently, and under very challenging time constraints, to develop the portfolio plans for our consideration today. In particular, the utility program administrators, advisory group and PRG members, our Joint Staff99 and their consultant TecMarket Works, all burned the midnight oil for many weeks to develop and analyze portfolio plans that were responsive to the new energy efficiency rules adopted in April, 2005. By all accounts, the advisory group process established by D.05-01-055 was constructive and collaborative, and based on the filings in this proceeding, has served this Commission well.

Our primary task today is to determine whether or not it is reasonable to move forward with the portfolio plans and funding levels proposed by the utilities, including those modifications agreed to by the utilities in response to further dialog with PRG members and interested parties since the June 1 filings. In doing so, we recognize that the very nature of portfolio management will require that the energy efficiency program activities initiated by today's decision will-and should-evolve over the program cycle to accommodate changes in the market, real-time feedback about program design in the field, the results of EM&V studies completed during program implementation, and other factors. The administrative structure for energy efficiency adopted in D.01-05-055 anticipates that ongoing interaction among program administrators, implementers, advisory group members, customers and other members of the public will serve to identify these changes and develop program modifications to effectively to respond to them. Therefore, we are looking to assess the portfolios in terms of overall consistency with our policy rules, rather than "fix" the portfolio composition at this time.

8.1. Threshold Issue of Portfolio Cost-Effectiveness

As discussed above, our policy rules establish a threshold requirement that the utility portfolios are cost-effective, on a prospective basis, in order to be eligible for ratepayer funding. Based on the record in this proceeding, we find that the utilities' proposed portfolios meet this requirement. Even with the concerns expressed over certain key input assumptions, such as net-to-gross ratios, the analysis of cost-effectiveness presented in this proceeding is quite robust. In particular, Energy Division's consultant TecMarket Works performed sensitivity analysis in its final report that indicates that each of the utilities' portfolios will be cost-effective even if they only achieve 60% of the projected savings. For PG&E and SoCalGas, the portfolios would still be cost-effective at 40% of projected savings. TecMarket Works concludes, as do we, that "from a cost-effectiveness consideration, the current portfolios are a relatively safe risk as submitted."100

8.2. Achievement of GWh and Therm Savings Goals

We are less certain, however, that the proposed portfolios will meet or exceed the Commission's energy savings goals for 2006-2008. With respect to the energy (GWh and therm) savings associated with the portfolios, the risk that the portfolios will not meet these goals revolve around uncertainties in key input assumptions. These include, in particular, estimates of the number of program participants, the fraction of those likely to be free riders (reflected in NTGs) and the estimated useful lives associated with certain lighting measures. Parties have proposed different ways for the Commission to address these uncertainties. (See Section 6.2 above.)

NRDC suggests that some of the disagreement over how best to address uncertainties with respect to NTG assumptions reflects differences in opinion over what D.05-04-051 had to say (or not) about "truing up" those values, and requests Commission clarification on this issue.101 Our decision today on how best to bound the uncertainty associated with this key savings parameter for planning purposes is predicated on the expectation that NTGs will in fact be adjusted (trued-up) on an ex post basis when we evaluate actual portfolio performance. We believe that this is entirely consistent with the resolution of threshold EM&V issues in D.05-04-051.

In that decision, we determined that ex ante savings estimates should be trued up based on the results of ex post load impact studies. As NRDC observes, we did not explicitly state whether or not that would include a true up of net-to-gross ratios to reflect free ridership. However, since many load impact studies evaluate the free ridership parameter as an integral component of their evaluation methodology (e.g., through the use of a non-participant control group in billing analyses), we did not consider it necessary to specify that the NTG assumptions would be trued up as part of that process. So that there is no further confusion on this issue, we clarify today that NTG assumptions should be trued-up in evaluating the performance basis of resource programs. The types of studies to perform, frequency of true-up and specific methodologies are to be developed as part of the EM&V protocols. In fact, it is our understanding that Joint Staff has already circulated among interested parties a proposal on those issues.102

In considering the concerns about the planning assumptions in this proceeding, we agree in principle with TecMarket Works, TURN, ORA and others that NTG ratios must be refined to reflect the findings from recent evaluation studies and appropriately mapped to the new generation of programs in 2006 and beyond. Clearly, there are other refinements to input assumptions that need to be made as we continue to update and improve upon our estimating methodologies. We have already directed that the EM&V protocol development currently underway address the frequency and process for updating key input assumptions, such as EULs and NTG assumptions. Joint Staff has been conducting workshops on these and other EM&V-related issues during the concurrent EM&V phase of this proceeding. Refinements of these estimates over time, using a consistent set of EM&V protocols, will enable us to improve our ability to estimate the impacts of energy efficiency programs for both program planning and resource planning purposes.

However, postponing the implementation of the cost-effective portfolio plans in order to first review and debate each specific ex ante input assumption places unwarranted emphasis on these issues for the purpose of evaluating the uncertainties associated with the portfolio plans. In addition, the amount of effort that would be put into such an approach (by Joint Staff or its consultant, the utilities, interested parties and PAG/PRG members) would be redundant to (and possibly prejudge) the efforts already underway in our EM&V phase to develop protocols for all key parameters related to the estimation and evaluation of energy efficiency savings and net resource benefits. Moreover, we simply do not agree with TURN that the extensive work that it recommends for an additional "Post Phase 1/Pre-Compliance" filing is even feasible to accomplish in the coming weeks, let alone desirable for the reasons stated above.

While moving to the standard NTG values as ORA recommends may make it easier for planning and analysis, we concur with TecMarket Works' observation that this approach usually also increases the risk of overstating savings forecasts within the portfolio.103 In sum, the proposals of TURN, ORA and the authors of the TecMarket Works for addressing the uncertainty associated with the utilities' forecasts of savings have significant shortcomings that we cannot overlook.

However, the CMS document does present an additional option for our consideration. In particular, the CMS describes an alternative that PG&E has proposed in response to PAG recommendations: PG&E plans to recalculate its portfolio cost-effectiveness after the competitive bid solicitation is completed, and it has finalized its proposed program plans (including partnership programs) during the compliance phase. In doing so, PG&E will also conduct sensitivity analysis to assess whether the portfolio will still be cost-effective and meet the Commission's energy goals if key parameters (e.g., NTG ratios and input assumptions for key measures such as lighting) are lower than expected after evaluation.104

We believe that this approach provides us with both a practical and effective way to assess the robustness of energy savings estimates before we authorize the final program plans. We will adopt this approach for all four utilities. In presenting this analysis for our consideration, the utilities should jointly develop a consistent set of sensitivity scenarios, with input from their PRGs. The use of sensitivity analyses to bound the uncertainties over key input assumptions, coupled with other steps we take today to address issues related to peak load reductions, will provide us with sufficient information to assess whether the portfolio plans are likely to meet our goals and remain cost-effective when the compliance plans are submitted for review.

Nonetheless, we are not satisfied for purposes of evaluating portfolio performance with the EUL assumptions contained in the utilities' June 1 filings--particularly for lighting measures, which comprise a significant portion of their proposed portfolios. Since this performance parameter will not be further adjusted on an ex post basis when we evaluate 2006-2008 program achievements, per D.05-04-051, it is particularly important that we make sure that the ex ante EULs that we use to calculate performance basis are consistent with the evaluation studies currently at hand. The TecMarket Works report indicates that this is not the case.105

EUL values that reflect recent evaluation studies, including updated operating hour assumptions for CFLs, were posted to the Commission's DEER website on July 15, 2005, and further updates to EULs are scheduled to be posted on the site in August, 2005.106 The utilities are required to utilize these ex ante EUL values when reporting actual installations during program implementation and when submitting calculations of savings, portfolio cost-effectiveness and performance basis during the 2006-2008 program cycle. Joint Staff is directed to ensure that inputs to the E3 calculator are appropriately adjusted, so that these calculations will reflect the ex ante EUL values referenced above.

For this purpose, Joint Staff may hire a consultant, and/or direct the utilities to submit updated EUL values consistent with today's direction, subject to Joint Staff review, or take other steps as necessary to ensure that these updated DEER EUL values will be used consistently in reporting portfolio performance and in calculating the performance basis for the 2006-2008 program cycle. We expect Joint Staff to complete this work as soon as practicable in 2006. In consultation with Joint Staff, the assigned ALJ shall establish a schedule for completion of these activities.

8.3. Peak Demand Reductions and Related Issues

With regard to the estimates of demand (kW) reductions presented in this proceeding, there are additional issues to address before we can fully assess whether the portfolios will meet or exceed our demand reduction goals. First and foremost, these projections need to be developed using a consistent definition of "peak demand." While coincident peak may be the most appropriate measure of peak demand for use in reliability planning, CMS participants point out that it is the most difficult to estimate with accuracy for each program (let alone each measure). This is because it is hard to accurately forecast the occurrence of the peak day and what fraction of equipment will be on at that exact point of time. Non-coincident demand, on the other hand, is probably the easiest definition to measure and report. However, because it does not consider the issue of coincidence, it will also yield the very highest estimate of demand reductions of all three definitions.107

The clear advantage of using a "daily average"definition of peak demand savings for cost-effectiveness purposes, as discussed in the CMS document, is that it is "the most valid for reflecting the procurement costs of reducing energy usage during the peak period, not just the highest value observed on the hottest day."108 Put another way, dispatchers generally purchase power in a similar manner (e.g., "I need 100 MWs of power from 4 to 6 pm ") and pay an average contract value for that block of power. While this definition may not be as useful to system planners because of their focus on meeting reliability requirements, in our view it represents a reasonably conservative (and broader) estimate of demand reductions appropriate to the tasks of (1) establishing peak reduction goals for energy efficiency and (2) calculating peak demand reductions associated with energy efficiency programs to assess the achievement of those goals and portfolio cost-effectiveness. Moreover, as TURN points out in its comments, this definition would be analytically compatible with the possible inclusion of a "super peak" demand period to improve the valuation of critical peak period savings, should that approach be taken when we update avoided costs per today's decision.109

For the above reasons, we adopt the "daily average" peak savings as the common definition for projecting the demand reductions associated with the utilities' portfolio plans. In particular, the utilities should not use the load factor used to translate our GWh goals into MW goals. Instead, they are required to report their forecasted and achieved demand savings using a daily average peak demand value based on actual peak savings by measure.110

However, we note that the time period for the definition of daily peak proposed by the CMS participants differs slightly from the one we referred to in D.04-09-060. In particular, we included one more hour per weekday resulting in a total of 560 hours during the summer peak period.111 In order to be consistent with our previous definition of the summer peak period, we will use the following time period to calculate the daily average peak: 12 noon to 7:00 p.m., each weekday, from June through September. This translates to 560 hours per year (20 hours per weekday x 7 hours/day x 4 months.) Based on the common definition of peak savings that we adopt today, we direct the utilities and their PRGs to complete the following tasks and report back at the end of the process, as follows:112

1. The utilities shall re-estimate the peak savings from their 2006-2008 portfolio plans using the common definition within 15 days from the effective date of this decision and distribute the results to their PRGs and the service list in this proceeding.

2. The utilities and PRGs shall jointly propose language that will make it clear to all program implementers that they are required to use the Commission adopted definition of peak savings when estimating program savings ex ante and when reporting program accomplishments ex post. This language may be proposed for inclusion in the policy rules or in the adopted EM&V protocols, as appropriate.

3. The utilities and their PRGs shall jointly develop and recommend a uniform set of assumptions to translate annual energy savings resulting from installations of CFLs in residential and commercial dwellings into peak savings, using common load shapes where possible.

4. The utilities and their PRGs shall jointly consider whether a definition of "winter peak" savings is necessary for use by programs being implemented to address winter peaking areas and, if so, to provide one.

The re-estimation of peak savings should include a correction to the erroneous demand reduction estimate for lighting currently contained in DEER that was identified during the course of this proceeding. In particular, SDG&E acknowledges that it needs to reduce residential CFL impacts by a factor of 2.34 in upstream lighting because DEER erroneously incorporated the wrong demand reduction.113 If this error is applicable to lighting measures in the other utilities' portfolio plans, they are also required to make the appropriate adjustment when they submit their response to item #1 above.

The utilities are directed to file a report presenting the results of these efforts by November 1, 2005. Per D.05-04-051, further modifications to our policy rules (including common terms and definitions) may be accomplished by the assigned ALJ or Assigned Commissioner utilizing both formal and informal procedural vehicles as needed.114 By that decision, we also adopted an expedited review process for EM&V related issues that authorized the assigned ALJ in consultation with the Assigned Commissioner to adopt EM&V protocols by ruling, after considering written comments from interested parties.115 Because the issues described above are likely to require modifications/clarifications to our policy rules, EM&V protocols, or both, we will adopt a similar procedural approach for addressing them. Specifically, the assigned ALJ should solicit written comments on the November 1 report and, after consultation with the Assigned Commissioner, address the issues raised in the report and in comments by ALJ ruling.

With respect to the re-estimation of peak savings, the ALJ may direct that this information be submitted with the utilities' compliance filings for Commission consideration, or take other steps as needed to further inform the Commission of the results. Moreover, nothing in this decision precludes the ALJ soliciting input from Joint Staff and their consultants or taking other necessary steps in order to address these issues as expeditiously as possible. In any event, the schedule established above allows for demand savings to be recalculated using a common definition of peak so that this information is available to the utilities and PRGs before third-party solicitations are evaluated during the Stage 2 review process. This ensures that development of the final program plans will take into consideration the possible need for additional demand savings to meet the Commission's goals.

TURN urges us to also defer interim authorization of the 2006-2008 portfolio plans (or the start of the compliance phase) until, among other things, the utilities have rebalanced their proposed portfolios "to significantly increase the level of verified and retained residential and small commercial space cooling savings." 116 This specific recommendation, as well as the overall thrust of TURN's comments, reflects a fundamental policy perspective that is clearly not shared by all parties to this proceeding, as evidenced by the reply comments of NRDC, NAESCO and the utilities.

The perspective is that energy efficiency should primarily be deployed as a resource that reduces critical peak loads (i.e., the needle peaks in kW demand) because it is those loads that establish the maximum capability requirements for California's energy infrastructure (generation, transmission and distribution). There appears to be no disagreement with respect to the general observation made by TURN, Proctor Engineering and others that the most economical production of electric power would be a constant load, and that moving toward a more constant load requires the reduction of consumption in end uses that create peak loads. Parties also do not appear to disagree that the end uses with the highest ratios of peak load to average load are residential and commercial air conditioning.

However, as NRDC points out, this perspective does not acknowledge that California has a clear need for both baseload and peak savings:


"While TURN, the TecMarket report, and others correctly point to a near-term need for peaking resources, we strongly urge the Commission to maintain its focus on energy efficiency as a long-term resource....Energy efficiency is best suited to meet the state's resource needs ten to twenty years out because energy efficiency savings take time to accumulate to provide sizable savings that can have a substantial impact.


"While the efficiency programs certainly can and should help contribute to meeting near-term needs, it would be unwise to frequently shift the primary focus of the programs to meet short-term resource needs. In the long-run, California needs both baseload and peaking resources. One need only look at the more than two-dozen baseload coal plants proposed throughout the West, many aiming to serve California, to understand the importance of the efficiency programs' baseload savings. [footnote omitted.] And contrary to TURN's assertion that building intermediate and baseload generation is often the most efficient and low polluting way to generate electricity, one cannot make a clear-cut statement about what load is most efficient and least polluting to serve: baseload needs can be met with anything from the cleanest renewable resources to the dirtiest coal-fired plants."117

We agree with NRDC that the Commission should continue to require that efficiency programs target both peak and base load savings. Our intent in adding the language regarding critical peak loads to the draft policy rules was not to send the signal that reducing critical peak loads should be the focus of energy efficiency, at the expense of cost-effective base load reduction measures. Rather, it was intended to address specific concerns raised by TURN and Proctor Engineering that (1) current avoided cost valuation measures might not fully capture the value of critical peak reductions and (2) the relatively high load factor reflected in the adopted savings goals could provide the utilities with an incentive to overemphasize lighting programs relative to others with low load factor/high critical peak savings.118 Until these issues could be fully addressed in our avoided cost proceeding and when we updated our demand reduction goals for the next program cycle, we added language to Rule II.5 that was intended to ensure that the utilities considered a wide range of strategies to increase overall capacity utilization/reduce peak loads within the full context of our adopted Rules.

As NAESCO and others point out, that context is established by our "overriding goal" to "pursue all cost-effective energy efficiency opportunities over both the short- and long-term." (Rule 2.) We believe that TURN's insistence that we hold up approval of the portfolio plans until funds are redirected towards residential space cooling applications ignores that context, and focus too narrowly on the perspective that measures with low load factors (e.g., efficient air conditioners) should take precedence over higher load factor measures (e.g., efficient refrigerators) simply by definition. In fact, TURN criticizes the utilities for even attributing any critical peak savings to measures such as efficient refrigerators because they operate continuously, even though improved efficiencies in refrigeration end use technologies clearly does reduce demand during critical peak demand periods and can do so cost-effectively.

PG&E provides numerical calculations that cause us to further question the validity of TURN's position in this proceeding. In particular, PG&E calculates that if it reduced spending on the top four residential CFL measures by 50% and shifted those rebate dollars to the top four residential HVAC measures, "annual kWh savings for the residential component of the Mass Market program would fall by 28%, a 65 million kWh reduction. Peak demand savings would fall by 10% (5 MW) and TRC net benefits would fall by almost $22 million, a 26% reduction."119 Even with disagreement over input assumptions for this calculation, it raises questions concerning the premise of TURN's recommendations, namely, that ratepayers would be better off if PG&E's portfolio shifted more rebate dollars to energy efficiency efforts targeted at HVAC end-uses at this time.

We also observe that TURN's assessment of the utilities' compliance with Policy Rule II.5, as well as the assessments provided by the PG&E and SCE PRGs, fail to recognize that a very large portion of the potential savings associated with residential air conditioner use (and identified in the Kema-Xenergy potentials analysis referenced in the PRG reports) will be captured by the increased state appliance standards for 2006 and beyond. As discussed in PG&E's comments, these standards increase the minimum efficiency rating required for residential size air conditioners by 30%, which will affect both new installations and retrofit applications. We believe that TURN ignores this context in making its claim that the three electric utilities have placed inadequate emphasis on residential HVAC in their program offerings.

Moreover, a careful review of those offerings reveal that, in addition to increasing the savings from (and funding for) residential HVAC relative to prior years, each of the utilities has proposed substantial increases in statewide efforts to support more aggressive codes and standards in the future. In fact, in direct response to the recommendations of TURN, Proctor Engineering and other members of the statewide PAG group on HVAC end-uses (the "HVAC PAGette"), the utilities propose to implement programs that provide market support for the new 2006 standards that are the first of their kind in scope and scale.120 As NRDC suggests, the utilities should monitor the success of these HVAC programs on an ongoing basis with their advisory groups and ramp up the programs faster than planned and capture more savings if it is feasible and cost-effective to do so.

The bottom line is this: Yes, we are concerned about the reported trends concerning increasing peak demands relative to baseload requirements on the utilities' systems, and we do want the utilities to identify and aggressively pursue the most cost-effective energy efficiency, demand-response and/or distributed generation options that can serve to improve (lower) system load factors, . However, rather than require the utilities to arbitrarily "rebalance" their energy efficiency portfolios based on unresolvable disputes among parties over how much program funding should be focused on HVAC end-uses, we believe that the best way to ensure the optimal result over time is to: (1) clearly establish the parameters by which the utilities' portfolio performance in terms of peak load reductions will be evaluated, (2) properly value demand reductions that occur during critical peak periods for all peak reduction resource options, and (3) update our peak savings goals for 2009 and beyond based on studies of peak savings potential, rather than historical program performance.

By adopting the definition of peak demand discussed above, and requiring that utility program administrators (as well as implementers) use this definition in reporting all program and portfolio impacts, we have accomplished the most important step in addressing the first issue. As we consider risk/reward incentive mechanisms in a later phase of R.01-08-028, we will further clarify the parameters of performance with respect to peak load (as well as GWh) reductions. In particular, we need to address the specifics of how best to establish the minimum threshold levels for kW and kWh reductions that are tied to our goals.121 Today's definition of peak demand will equally apply in that context.

We will also take immediate steps today to ensure that avoided costs are updated to properly value critical peak load reductions, whether such reductions are achieved through energy efficiency measures, distributed generation or demand response. However, as we observed in D.05-04-051, it is far from clear how critical peak avoided costs should be used in the context of energy efficiency measures that are not fully dispatchable. This issue will need to be explored during the updating process. We describe that process in Section 8.8 below.

Finally, as the updating process for our energy savings goals for 2009 and beyond gets underway, we direct Joint Staff to take the concerns of Proctor Engineering and others regarding the existing conversion factors into consideration by carefully evaluating the peak load savings potential of energy efficiency programs across all sectors.

8.4. Competitive Bidding

As described in the various filings in this proceeding, and summarized above, the utilities have been very responsive to the suggestions of advisory group members, individual parties and the general public in crafting competitive bid proposals that are consistent with our policy rules. In all but a few instances, each utility has also responded to recommendations of their respective PRG, to their mutual satisfaction. Therefore, there are only a few issues related to the competitive bid solicitations that we believe this decision should resolve and/or clarify, before the utilities proceed in developing their compliance filings.

First, we note that each utility has indicated that their PRG will be involved in the bid evaluation process. However, the language of their response to the related PRG recommendations lacks sufficient specificity (especially in the case of SCE) to convince us that our expectations will be reflected in that process. By D.05-01-055, we directed that PRG members (including the independent consultant(s) that Energy Division may hire to assist it as a PRG member) are to "observe" the utilities' selection process "to ensure that the criteria are applied properly."122 We further directed that the utilities "discuss the proposed results of their bid review process with the PRGs (and Energy Division's independent consultants)" before finalizing their selections:


"For this discussion, the [utilities] will provide the program implementation plans, timelines and goals of the bidders in as much detail as available, along with any other bid evaluation information that the PRGs may request. This group will have an opportunity to ask questions about how the criteria were applied and provide feedback on the selection process, and otherwise help to ensure that the bid process is fair. It is the [utilities] responsibility to describe in their compliance filing...how they have responded to criticisms presented by the PRG (and Energy Division consultants) during this process."123

In our view, this will require the utilities to establish a process that allows the PRG members (including Energy Division's consultant, if applicable) to monitor both Stage 1 and Stage 2 selections. Whether that involves physically being "in the same room" or setting up a process whereby the utilities present all the abstracts to PRG members and discuss the proposed selection of those that will go on to Stage 2 (for example), will be left up to the utilities and PRGs to work out to their mutual satisfaction. The sheer volume of Stage 1 abstracts that PG&E receives relative to SoCalGas, for example, may warrant different procedures to accomplish the same goal, namely, to allow the PRG to effectively monitor the bid selection process. However, we do clarify today that each utility should expect and facilitate the active involvement of PRG members in this monitoring process, per the direction in D.05-01-055.

In terms of the bid evaluation criteria themselves, we agree with NRDC that they do not have to be identical across the state. As NRDC points out, each of the utilities has developed its criteria through a transparent and cooperative process with its PAG and PRG members, and the result reflects a great deal of consensus around the evaluation criteria proposed for the specific solicitations being undertaken within each service territory. We also note that PG&E's "targeted" solicitation is much broader than those of the other utilities and, as a result, the factors that PG&E will need to consider to evaluate and integrate third-party programs into the overall portfolio will be more involved than those required for the other utilities.

Although not identical across utilities, we find that the evaluation criteria for each proposed solicitation have achieved overall consistency with the objectives stated in our policy rules, with only a few exceptions noted below. In particular, each resource solicitation will be evaluated during Stage 2 with criteria that place significant weight on performance metrics that directly support our resource planning and cost-effectiveness objectives for energy efficiency. In the case of SCE, SoCalGas and SDG&E, the criteria are specified as "kWh and kW potential" and "cost-effectiveness," whereas for PG&E they are termed "portfolio fit/improved performance" and "levelized costs"-but they address similar priorities.

We also observed in D.05-01-055 that the most important benefit of competitive solicitations is to "help identify innovative approaches or technologies for meeting savings goals with improved program performance that might not otherwise be identified during the program planning process."124 Appropriately, the utilities will value "innovation" when reviewing all the bid solicitations-for resource and non-resource programs alike, with added emphasis on this criteria for those bid solicitations specifically seeking new ideas for tapping energy efficiency potential.125 Moreover, with only one exception, the evaluation criteria reflect our direction that potential lost opportunities be addressed in the portfolio plans by including consideration of the "comprehensiveness" of each bid proposal, and/or how it addresses "lost opportunities."

However, in two instances we find that the bid evaluation criteria require minor modification to be more consistent with our policy direction. First, unlike the other utilities, SDG&E (and its PRG) do not recommend considering "cost efficiencies" in the evaluation of non-resource program bids, either for the targeted or innovative idea solicitations. Instead, they propose to consider "budgets" (administration, direct implementation, marketing and outreach), giving it the same weight (25%) as the other proposals would place on cost-efficiencies. The filings are not very descriptive as to these two terms, but we believe that "cost efficiencies" is a more appropriate aspect to evaluate than the "budget" of a non-resource program. Accordingly, we direct SDG&E to make this change to their Stage 2 evaluation criteria.

In addition, we note that SCE's revised evaluation criteria for non-resource programs under its targeted solicitation have dropped any consideration of "lost opportunities" in order to respond to the recommendations of its PRG. We believe that its original proposal for this solicitation is preferable because it does include "innovation" as an evaluation criterion, and is also more consistent with the review criteria proposed by the other utilities and their PRGs for this type of solicitation. Therefore, we will adopt SCE's original proposal for non-resource programs under its targeted solicitation.

We will also direct SCE to further specify its Stage 1 review criteria and associated weights or scores as the other utilities have done in response to PRG recommendations. In particular, SCE should work with its PRG to further develop the Stage 1 evaluation criteria during the compliance phase, using either of the approaches presented in Attachment 6 as a general model.

We note that there is still a minor difference between SoCalGas and its PRG with respect to the manner in which "skill and experience" should be evaluated under the innovative emerging technologies and innovative resource solicitations. We believe that the utility's preference for combining the consideration of a bidder's skill and experience within the "program implementation and feasibility" criteria is no less reasonable than considering skill and experience as a separate criterion. Moreover, under the proposed weightings, there appears to be very little substantive difference between the two approaches. Finally, we note that the SoCalGas PRG recommends different approaches to this issue, depending on the type of solicitation-without any obvious reason. We will adopt SoCalGas' proposed approach.

With respect to the one remaining area of disagreement on competitive bidding between PG&E and its PRG, we find PG&E's request to defer consideration of a non-resource bid solicitation until after the resource portfolio is complete to be reasonable. PG&E is already undertaking the most extensive solicitation process of the four utilities for 2006. We see no obvious benefit to requiring an additional solicitation at this juncture, as the PRG recommends. Instead, PG&E and its PRG should continue to explore this issue as PG&E prepares for the additional solicitations it plans to conduct during the upcoming program cycle.

Nor do we see any benefit to Consol's proposal for a statewide replacement bid for residential new construction, except perhaps to Consol if we also adopt its proposal to be the statewide contractor for this program. As PG&E points out in its reply comments, the utilities will be offering a statewide consistent California Energy Star New Homes program that has been recognized by the Environmental Protection Agency and won awards for excellence during the past three years. In coordination with the Sacramento Municipal Utilities District, the utilities will continue to offer this performance-based program with a minimum requirement of 15% better than code, as well as offer a variety of prescriptive measures.126 Arbitrarily granting Consol responsibility for the residential new construction program is an unnecessary limitation on a successful program and would be unfair to other potential third-party implementers.

We note that nothing precludes Consol from submitting a proposal in response to the utilities' competitive bid solicitations specifically targeted to residential new construction (e.g., PG&E and SCE), or to their solicitations for innovative proposals in the residential sector (e.g., SDG&E). However, we do not find any support on the record for Consol's assertion that its Comfortwise new homes program should replace the statewide Energy Star New Homes program, which has successfully involved many builders and contractors throughout the state. In fact, as PG&E points out, Consol's claims of high cost-effectiveness is likely a function of the limited market focus and lack of prescriptive measure options under Consol's current program offerings.127

The PRG assessments and CMS also reflect differences of opinion with respect to how the 20% minimum competitive bidding requirement should be calculated. In D.05-01-055, we articulated this requirement in the context of discussing the "portfolio of programs" that the utilities would propose to reflect "continuation of successful [utility] and non-[utility] implemented programs and new program initiatives designed to meet or exceed the Commission's savings goals with cost-effective energy efficiency."128 In that context, we directed the utilities to identify a minimum of 20% of funding for the "entire portfolio" to be put out to competitive bid.129 We believe that SDG&E's and SoCalGas' interpretation that the 20% applies to the non-EM&V portion of portfolio funding levels is fully consistent with this language.

As described in Section 6.8, there are few additional issues between the PRGs and the utilities that remain unresolved. In particular, SCE's PRG recommends a modification to the allocation of funding for SCE's bid solicitation, SDG&E's PRG recommends the expansion of SDG&E's targeted solicitation to include some additional program elements, and SoCalGas' PRG suggests that the utility conduct a series of solicitations throughout the program cycle. We believe that the utilities have taken the PRGs' views under consideration on these issues, and should be allowed to make a final determination on each of them in the context of developing their final program plans during the compliance phase.

Attachment 6 presents the adopted evaluation criteria for each utility, by type of solicitation and evaluation stage. This includes a brief description of each utility's proposed approach to portfolio integration after the Stage 2 evaluation stage is complete, based on agreements reached during the CMS process. We will approve these approaches, noting that each of the utilities is expected to continue to work with and involve their PRGs in this final integration phase. The PRG assessments of each utility's competitive bid process should address all stages of bid evaluation, including how the bid results are considered in the context of portfolio plan integration.

8.5. Codes and Standards Savings

Before addressing the specific savings issues related to codes and standard work, we emphasize that these activities have been an essential and valuable component of the energy efficiency program portfolio in the past, and continue to be recognized as such in our updated policy rules. In fact, using ratepayer dollars to work towards adoption of higher appliance and building standards may be one of the most cost-effective ways to tap the savings potential for energy efficiency and procure least-cost energy resources on behalf of all ratepayers. Therefore, as we recognized in D.05-04-051, we need to develop updated EM&V protocols to quantify the resource savings attributable to the Codes and Standards Advocacy Program, and to verify those savings. That process is currently underway in the EM&V phase of this proceeding, and we expect to have protocols established for this purpose and associated EM&V plans for the 2006-2008 cycle by the end of the year.

In the meantime, we agree with the Assigned Commissioner that we should reconsider the exclusion of savings associated with pre-2006 codes and standards advocacy work in this proceeding.130 As we noted in D.05-04-051, counting the savings from this work towards our 2006-2008 goals does not raise the same transition issues as counting pre-2006 commitments from new construction and standard performance contracting programs. This is because energy savings have never been explicitly attributed to this work in previous program years or linked to performance goals for those years. Therefore, there would be no double counting in this respect if we chose to count them in the years when the savings are actually realized, i.e., during the 2006-2008 program cycle.

Our decision in D.05-04-051 to defer the issue of quantifying energy savings from these programs for the purpose of counting them towards our energy efficiency goals was prompted by other concerns. These included concerns over the expediency with which reasonable attribution estimates could be developed for prior year program efforts, as well as over potential inconsistencies between the years in which program investments are made and considered in calculating performance basis. We were also not persuaded that counting some portion of savings attributed to pre-2006 codes and standards advocacy work was a reasonable response to the accounting transition from "commitments and actuals" to "actuals only" in evaluating achievements towards our goals.131 The record developed in response to the Assigned Commissioner's ruling convinces us that this is indeed a reasonable response, for the following reasons.

In particular, the record confirms that the 2005/2006 code and standards revisions were not accounted for in the studies of economic potential that led to the establishment of our savings goals for 2006 and beyond.132 Now that the new standards are in place, this means that those standards may actually work against the utilities with respect to their ability to tap that economic potential with other types of energy efficiency activities. While Joint Staff points out that this alone may not have greatly overestimated the savings potential, because of other technical aspects of those potential studies,133 it is also the case that changing the accounting to "actuals only" works in the same direction.

This is because the analysis conducted by Joint Staff to develop its recommendations for the 2006-2008 savings goals was based on a "commitments and actuals" accounting basis. More specifically, Joint Staff's analysis of the amount of "achievable" economic potential that could be tapped with energy efficiency programs was based on past program effectiveness (kWh/dollar) factors that included commitments from both new construction and retrofit applications. As the Assigned Commissioner points out, this is a short-term transitional issue, and not a long-term problem, because commitments made in 2006 and 2007 for both retrofits and new construction programs will become "actuals" in the program years that follow, thereby assisting in the achievements of the adopted cumulative goals for later years. Moreover, the savings goals updating process that will occur in time for the 2009-2011 program cycle will reflect the "actuals only" accounting practice adopted in D.04-09-060.134

Nonetheless, the method of accounting for program accomplishments towards our goals ordered in D.04-09-060 and clarified in D.05-04-051, in combination with the method by which Joint Staff developed estimates of achievable potential, does create a short-term transitional inconsistency between the two that should be addressed. One option for addressing this inconsistency would be to re-open the goals decision and make some sort of adjustment to the short-term goals in that context. However, we agree with the utilities that this is not the preferred approach. As they point out, if the goal decision is to be revisited, every stakeholder will have multiple reasons for changing the goals-is simply is not feasible to expect that only one reason for change will be considered, in isolation from all other reasons. Furthermore, a great amount of resources and time have been devoted to planning and decision-making based on these 2006-2008 cumulative goals. Several months of reconsideration and redoing would be required to meet different goals. As a result, the whole timetable for launching the 2006-2008 programs in time to achieve the desired savings would be threatened.

Instead, we believe it is reasonable to allow the utilities to credit some portion of the savings attributable to pre-2006 codes and standards advocacy work towards our savings goals during this transition (i.e., for program cycle 2006-2008), as Joint Staff recommends. However, we must further consider whether to count these savings towards the savings goals in subsequent years, in the context of how we update the savings potential and associated goals for those years. As illustrated in Attachment 10 our resolution of this issue will depend a great deal upon the manner in which we establish the baseline for the next round of potentials studies. Therefore, we defer consideration of whether the savings attributed to pre-2006 codes and standards work should also be credited towards our savings goals for 2009 and beyond, pending further discussion of these issues.

In fact, we believe that the record in this proceeding has raised a fundamental issue that we must consider with respect to that baseline, namely: Should our future energy efficiency savings goals be established based on the economic potential associated with the combination of codes and standards update work and other energy efficiency programs that can defer or replace the need for supply-side resources? If this approach is taken, the baseline for our potentials studies might not need to be modified with each update to reflect the latest revisions in state codes and standards. In addition, this approach would provide strong incentives for state staff and the utilities to work together to achieve the mutual savings goals. Alternatively, should we remove the impact of recently adopted higher codes and standards (and the associated economic potential) when we develop the savings goals for utility energy efficiency portfolios? Under this approach, the baseline for our potentials studies would be adjusted to reflect the impact of ever higher codes and standards. (See Attachment 10)

We believe that the concept of estimating the potential for the combination of all program efforts (including codes and standards advocacy work) and establishing energy efficiency portfolio goals on that basis has considerable appeal. Doing so could better enable us to assess the economic potential of improved codes and standards along side direct installation and other resource programs, as well as their associated savings achievements. It would also remove conflicting signals to the utilities that arise if the savings potential of energy efficiency is ratcheted downwards to reflect the higher codes and standards that their advocacy work in previous years has produced. Accordingly, we direct Joint Staff to consider this issue and present recommendations during the goals updating process, which will be underway during the 2006-2008 program cycle.

In terms of the level of savings to credit towards the 2006-2008 goals from these pre-2006 program activities, we agree with Joint Staff that the HMG methodology has a logical coherence and covers the developmental steps that most outside observers agree are important in estimating the savings impacts of codes and standards advocacy work. Nonetheless, as Joint Staff also points out, there are inherent and potentially significant uncertainties associated with the approach taken to attribute savings to this pre-2006 work.135 Moreover, specific input assumptions used by HMG to develop the ex ante savings estimates would benefit from further evaluation and verification before we can rely on them with confidence.136 Given the uncertainty involved in measuring the realized savings associated with this pre-2006 program, we find that Joint Staff's recommendation provides a rationale bound for the attribution of savings to pre-2006 codes and standards advocacy work. In addition, it strikes a reasonable balance among the various concerns with respect to the motivation and perceptions of the various stakeholders surrounding the value of codes and standards advocacy work.

With respect to the potential undesirable outcomes that ORA, TURN and NRDC identify in their comments, we believe that the conditions Joint Staff placed on its recommendation, and the utilities' response to them, have laid these concerns to rest. In particular, the utilities point out that they have not relied on these codes and standards savings attributed to pre-2006 advocacy work in their June 1, 2005 applications, and have agreed that they will not proposed to reduce the activities and efforts in those applications in response to our determination on this issue.137 Joint Staff's conditions on its recommendation to count these savings towards the 2006-2008 goals is predicated on conditions that further ensure that the utilities may not cut back on their funding levels or program efforts in response to today's decision.

Moreover, it is our intent to put in place a financial risk/reward incentive mechanism that directly speaks to ORA's second concern, namely, that the utility would remain indifferent to program changes that lower the projected savings as long as the portfolio stays ahead of the goals. With the adoption of a performance basis for resource programs based on net resource benefits (resource savings minus costs) we have actually taken a major step towards removing this potential indifference and, more importantly, in motivating the utility program administrators to maximize actual program savings as cost effectively as possible. The next step in this process, as discussed in Section 9 below, is to fully develop the risk/reward incentive mechanism associated with this performance basis, as well as further define the minimum performance threshold we adopted in D.05-01-055.

With respect to the performance basis issues that ORA and NRDC raise in their comments, we do not believe that it is necessary to either reject Joint Staff's recommendations or completely defer addressing them until these performance basis issues are resolved. Specifically, ORA asks how the savings attributable to pre-2006 codes and standards work would be treated in the calculation of performance basis, if they are considered as "bonus savings" with respect to the 2006-2008 savings goals, as Joint Staff recommends.

As discussed in Attachment 10, the general concept would be to fully count the stream of savings attributable to each round of codes and standards work that leads to increased efficiency codes and standards in the calculation of the "net resource benefits" performance basis.138 However, this approach would not be appropriate for the resource benefits attributed to pre-2006 codes and standards advocacy work. This is because counting the savings associated with this work towards performance basis, upon which a risk/reward performance mechanism would be based, creates a fundamental policy inconsistency with respect to the cessation of shareholder earnings during the program years when these pre-2006 investments were made. This same policy issue would also arise if we counted towards performance basis the actual installations for 2006 and beyond that were the result of commitments made prior to 2006. In D.05-04-051, we explicitly excluded such savings from the calculation of performance basis.139

In Attachment 10, we also discuss the issue of how savings attributable to codes and standards advocacy work performed during a prior program cycle might be considered when estimating the cost-effectiveness of proposed program plans in a subsequent cycle, after the resulting new standards take effect. According to the policy rules we adopted for 2006 and beyond, the costs of this work would be counted during the program cycle in which they occur. The actual savings would be counted in the calculation of portfolio cost-effectiveness when the standards are put into effect, similar to the manner in which the savings from actual installations associated with commitments made in 2006 and beyond will be counted.

While this would be the general approach for activities undertaken in 2006 and beyond, we conclude that this should not be the approach for savings attributed to pre-2006 codes and standards advocacy work. This is because cost-effectiveness calculations need to be developed on a consistent basis with performance basis. It simply makes no sense, and would also create undue confusion, to calculate the TRC and PAC tests of cost-effectiveness for the utilities portfolio plans including those savings, when the resource savings used to calculate the net benefits performance basis will excludes those savings for the reasons discussed above. Moreover, we note that the cost-effectiveness calculations (and performance basis) for the 2006-2008 program cycle and beyond will similarly exclude resource benefits associated with program investments made prior to 2006 from standard performance contracting and new construction activities, per our direction in D.05-04-051.

In sum, the cost-effectiveness calculations and net resource benefit calculations for 2006 and beyond (for the calculation of performance basis or other purposes) should be calculated on a consistent basis, i.e., by excluding the savings associated with pre-2006 codes and standards advocacy work. However, the savings attributable to codes and standards work undertaken during 2006 and beyond should be counted in both cost-effectiveness and performance basis calculations on a going forward basis. As we discuss in Attachment 10, there are timing issues related to the calculation of the performance basis for codes and standards work that need to be further explored during the EM&V phase.

NRDC's comments raise an additional issue with respect to how savings from pre-2006 activities should be credited, in particular, whether they should count towards the minimum threshold for performance that will be tied to our adopted kW and kWh goals, per D.05-04-051. We will be addressing the specifics of how to tie the minimum threshold requirement to our goals when we have an opportunity to evaluate all aspects of a risk/reward mechanism.140 At that time, we will address this issue, which may also depend upon the baseline considerations we discuss in Attachment 10.

So that there is no confusion over how and when the savings attributed to pre-2006 codes and standards advocacy work will be considered we clarify that:

In terms of the methodology for developing estimates of resource savings for codes and standards advocacy work on a forward looking basis, the specific methods for verifying those savings and other associated evaluation activities, we do not adopt Joint Staff's specific recommendations at this time. Rather, we believe that these recommendations and associated EM&V plans should be considered as part of the EM&V phase of this proceeding, per the review process we established in D.05-01-055. With regard to Joint Staff's specific recommendation regarding portfolio rebalancing, we observe that such rebalancing could occur in any direction among various program activities (e.g., direct installation, codes and standards and other statewide programs) throughout the program cycle. That process should be informed by ongoing EM&V work as well as continued communication among utility program administrators, their advisory groups (including Joint Staff) and the interested public. We therefore decline to direct the timing and specifics of such rebalancing efforts in today's decision.

In principle, we agree with CCSF and NRDC that there is value in establishing EM&V protocols to count savings from both local and statewide codes and standards efforts. These efforts are already underway: For example, PG&E currently provides code compliance training for local government and third-party programs through current courses that are open to all.141 However, the timing and priority for EM&V studies specifically addressing local efforts must be considered in the context of the overall EM&V priorities and associated budgets being developed during the EM&V phase. Therefore, we encourage CCSF and other interested program implementers to continue to actively participate in EM&V phase on these and related EM&V issues.

8.6. Funding Levels and Ratemaking Treatment

We find that the level of program funding proposed by the utilities over the three-year program cycle is reasonable and supported by the record. As discussed above, their portfolio plans to engage market participants in all aspects of energy efficiency improvements to homes, commercial buildings, and industrial/commercial processes are projected to be highly cost effective, taking reasonable account of uncertainty with respect to key cost-effectiveness input parameters. The competitive bid results and final program selections should enhance this expected portfolio performance, both in the short- and longer-term.

While we have directed further work to more accurately project the contribution of these program plans to our savings goals, particularly in terms of peak demand reductions, we disagree with WEM that this calls into question the overall level of portfolio budgets. The utilities, with input from their advisory groups and the public, will continue to rebalance and modify the specific program plans to enhance portfolio performance throughout the three-year program cycle. If greater savings per dollar can be achieved than currently projected, today's authorized funding levels will be used in the pursuit of "all cost-effective energy efficiency opportunities over both the short- and long-term," consistent with our Rules.142

We have also reviewed the utilities' proposed cost allocation and ratemaking treatment for the incremental revenue/funding requirements required to fund 2006-2008 energy efficiency activities at today's authorized levels. We find that the utilities have allocated the costs of these programs to customer classes in a manner that appropriately assigns costs relative to the expected share of program benefits, and that the resulting rate and bill impacts are reasonable. Accordingly, we authorize the utilities to recover the incremental revenue/funding requirements costs (not including EM&V) via their proposed ratemaking treatment once we have approved the final compliance plans. By separate decision later this year we will address the EM&V portion of portfolio plans and associated funding for the 2006-2008 program cycle.

With our approval of the compliance plans, the 2006-2008 program budgets proposed by the utilities and associated incremental revenue/funding requirements, will serve to fund their energy efficiency activities during the three year program cycle, including those activities implemented under the interim authorization we grant today. (See Section 9)

8.7. EM&V-Related Issues

Several EM&V-related issues were raised in TecMarket Works report, the CMS documents and in parties' comments, some of which have already been mentioned in other sections of this decision. In general, the EM&V phase is the appropriate forum for fully considering the EM&V related recommendations contained in those submittals. However there is one EM&V issue raised by CMS participants in conjunction with the Governor's GBI that warrants clarification today.

In particular, the utilities seek guidance on whether their portfolio plans to increase efficiencies in commercial buildings during 2006-2008 will be discounted by "free ridership" in light of the GBI. In considering this issue, we note that the aggressive energy efficiency savings goals we established by D.04-09-060 on September 23, 2004 clearly speak to the Governor's July 2004 directive to apply our "energy efficiency authority" to "improve commercial building efficiency programs to help achieve the 20% goal" articulated in the GBI.143

In this context, it is reasonable to consider the GBI's 20% goal for improved efficiencies in the commercial building sector as a subset of the overall savings goals we have established for the utility service territories, rather than as a state code or standard used to establish project-specific baselines. In other words, utility efforts that support the GBI goal for the commercial building sector will work towards achieving the statewide goals we adopted for the portfolio plans, and vice versa. Accordingly, for the purpose of our EM&V protocols, and the energy savings and demand baselines established under them, we clarify that utility programs that assist with the design of, or provide incentives for, the energy efficiency measures on a project that achieve a 20% improvement over Title 24 should not be disallowed the claimed savings on the basis of GBI free ridership.

8.8. Avoided Costs/E3 Calculator Related Issues

During the course of this proceeding, the following issues and proposed solutions were raised with respect to current avoided costs and the E3 calculator model used to calculate cost-effectiveness:144

We agree with CMS Participants that each of these issues needs to be addressed and corrected in order to improve the ability of program administrators, implementers, advisory groups, the public and this Commission to assess the resource benefits from various energy efficiency activities during the 2006-2008 program cycle, and evaluate portfolio and program performance. Moreover, we agree with ORA that a common E3 calculator should be developed for use by all implementers, in order to facilitate an apples-to-apples comparison of projected savings and cost-effectiveness calculations. A common calculator ensures consistency in assumptions (e.g., end-use load shapes, expected useful lives, net to gross values) while alleviating program implementers from the burden of carrying out data-intensive calculations involving hourly avoided costs and end-use load shapes.

In their reply comments, SDG&E and SoCalGas contend that the current avoided costs value critical peak appropriately, and no further consideration of this issue is warranted. However, we are not persuaded that this is the case, based on the record in this proceeding. As we noted in D.05-04-024, the E3 methodology adopted in that decision represent a vast improvement over the use of statewide average values that do not reflect on-peak vs. off-peak reductions, as well as utility-specific cost differences. At the same time, we fully anticipated that we would "continue to refine the E3 methodology and forecast" in Phase 3 of that proceeding:149


"As discussed in this decision, we intend to consider the permanent adoption of the E3 methodology for generating avoided cost energy forecasts for use in [Standard Practice Manual] cost-effectiveness tests used to evaluate energy efficiency programs. We will also consider any potential revisions to the E3 methodology in Phase 3 of this rulemaking.150

We believe that further consideration of the E3 methodology with respect to critical peak values, as well as the E3 calculator model issues outlined above, should be undertaken without delay, i.e., in advance of Phase 3 of that rulemaking. We recognize that of the tasks outlined above, refining avoided costs to properly reflect the value of savings during critical peak hours on the utility system is likely to be the most difficult. However, this clearly needs to be undertaken in order to more accurately evaluate the relative cost-effectiveness of various energy efficiency measures, as well as demand-response and distributed generation options in the future. How critical peak avoided costs will be used in the context of energy efficiency measures that are not fully dispatchable should also be addressed in the process.

Commissioner Kennedy is assigned to both our generic energy efficiency rulemaking (R.01-08-028) and our avoided cost rulemaking (R.04-04-025). Therefore, she is in the best position to coordinate the development of these avoided cost/E3 calculator refinements in consultation with the assigned ALJs. For this purpose, we believe that the most cost-effective and expeditious approach is to build upon the E3 work conducted in the avoided cost rulemaking. Consistent with the approach we have taken in that proceeding, we direct the utilities to contract with the appropriate expertise in consultation with Energy Division staff. The costs of the contract will be paid for out of the utilities' portion of EM&V budgets for the 2006-2008 program cycle.

The contractor(s) will be tasked with developing a draft report with specific recommendations on the refinements to be made to the avoided costs/E3 calculator. This draft report will be due by February 1, 2005. Energy Division will hold public workshops on the draft report. The contractor(s) will be present to respond to feedback and questions concerning the proposed refinements. Based on that feedback, the contractor will develop a final report on avoided cost/E3 calculator refinements addressing the issues discussed above.

Energy Division will then develop recommendations on these issues for Commission consideration. For this purpose, Energy Division may solicit pre- and post-workshop written comments from interested parties, obtain input from additional technical experts and/or take other steps as necessary to consider the recommended avoided costs/E3 calculator refinements. In consultation with Energy Division, the Assigned Commissioner or Assigned ALJ will establish the schedule for the submission of Energy Division's recommendations and for comments on those recommendations that will enable us to issue a decision on these issues during the first half of 2006.

All reports, notices of availability, notices of workshops or other filings related to the avoided cost/E3 calculator refinements discussed above should be distributed to the service list in this proceeding, the energy efficiency rulemaking (R.01-08-028), the distributed generation rulemaking (R.04-03-017), the avoided cost rulemaking (R.04-04-025) and the demand response rulemaking (R.02-06-001.) Our draft decision will be issued for comment in our avoided cost proceeding. All those who are not currently parties to R.04-04-025 (i.e., listed as an appearance on the service list) and wish to reserve the right to comment on that draft decision should file a motion to intervene with the assigned ALJ in R.04-04-025 as soon as possible.

Even under an expedited schedule for this effort, we will not be able to consider Energy Division's recommendations and parties' comments in time to make our final determinations on them before we complete the compliance phase and program roll-out for 2006 begins. We note that strict application of our performance basis "true-up" procedures would require that the results of these efforts be used only on a prospective basis, and not to evaluate the performance results of activities undertaken during a prior program cycle. However, as explained below, we believe that the unique circumstances facing us as we embark on the 2006-2008 program cycle warrant a limited exception to this requirement.

The practice of using the same set of avoided cost assumptions for both planning and for performance evaluation makes sense when an established avoided cost methodology is in place, where updates generally reflect new forecasts of what generation resources are on the margin and their associated fuel costs. The risk of these types of forecasting errors is applicable to any resource decision made using the planning assumptions, and these errors generally move in either direction (over-estimation and under-estimation) without systematic bias over time. Therefore, we have ruled in the past that we would not adjust projections of avoided costs on a retrospective basis, to reflect these forecasting errors.

In contrast, the update required to avoided costs at this juncture relates to a fundamental aspect of the interim avoided cost methodology that needs to be addressed, i.e., the need to value savings during critical peak periods differently (higher) than during the summer peak period. It would be unreasonable to ignore this important update to our ex ante estimation of avoided costs just because the timing for completion of this update, relative to the upcoming three-year program cycle, is off by a few months. Moreover, it is important that program administrators know that this improvement to the valuation of avoided costs is in the making, and that it will be incorporated into the evaluation of 2006-2008 portfolio performance as they finalize their program selections during the compliance phase of this proceeding.

Accordingly, we put the utilities and all interested parties on notice that we will use the valuation of avoided costs for critical peak hours that is developed through the process described above to assess the performance basis of the 2006-2008 portfolio and programs.

8.9. Fund Shifting Guidelines

As described in Attachment 9, the four fund shifting proposals before us are similar in some respects, and quite different in others. Rather than adopt one of the four proposals in its entirety, we believe that it is more appropriate to consider each type of fund shifting flexibility, and pick the option for each type that best meets our objectives for portfolio management.

Those objectives are as follows: First, utility program administrators need the flexibility to make decisions, without undue restrictions or delays, so they can effectively manage their portfolios to meet or exceed the Commission's savings goals cost-effectively. Second, portfolio management should involve obtaining feedback from advisory groups on a wide range of implementation issues, including fund shifting and program design changes, so that program administrators can benefit from the broad range of expertise provided by individual advisory group members. We note that all of the utilities have clearly stated that they will continue to involve their advisory groups in these issues throughout program implementation. Third, a review/approval process should be triggered for situations that affect the broad portfolio balance issues discussed in the Rules and in this decision, such as ensuring sufficient funding for programs geared toward longer-term savings and maintaining the minimum competitive bid requirement. Finally, the review/approval process should utilize an efficient administrative approach, so that a timely decision on the fund shifting request can be made.

With respect to "fund shifting among budget categories," we think that the approach that best meets these objectives is the one proposed by PG&E. Under this approach, utilities could shift funds among budget categories within a specific program (e.g., between marketing and training, or audits and rebates) without restriction, with the exception of the EM&V program category. For EM&V, shifts between the utility and Energy Division EM&V budget categories should be subject to review and approval, through the process described below. We do not adopt the approach presented in two of the proposals that would trigger a review process if administrative costs exceed a certain threshold (e.g., 105% of budgeted levels on a portfolio basis). Although we will continue to monitor administrative costs through our reporting requirements, and audit those costs as necessary to verify them, we believe that program administrators should have discretion to move funds between training, marketing, overhead and other budget categories to achieve the Commission's goals. This is consistent with the shift in our oversight paradigm from one that focuses on "cost control" to one that encourages the achievement of a maximum level of net resource benefits to ratepayers and verifies portfolio performance on an ex post basis.

With respect to "fund shifting among program categories," as defined and discussed in Attachment 9, all of the proposals appropriately recognize that fund shifting out of emerging technologies, codes and standards and statewide marketing and outreach should trigger a review process. This is consistent with our goal of maintaining an appropriate balance between short-term and long-term program activities throughout the program cycle. The budget levels approved in today's decision for these three program areas reflect the need to significantly expand efforts in emerging technologies and codes and standards, and maintain our current commitment to statewide marketing and outreach. Accordingly, as proposed by two of the CMS fund shifting options, we will limit fund shifting out of these programs to no more than 1% of budgeted levels, absent prior approval. We also adopt restricts for shifts out of the EM&V budget category in order to ensure that the final EM&V plans we adopt in this proceeding will be sufficiently funded throughout the program cycle.

That leaves us with the issue of fund shifting among the "Resource/Non-Resource" program categories described in Attachment 9. PG&E proposes the greatest degree of fund shifting discretion for these program categories. In particular, under PG&E's approach and definition of "programs" and "program categories" there would be no review or pre-approval requirement for shifts between any of PG&E's targeted program areas, such as between Residential New Construction and Industrial market sectors. The other three proposals provide for considerable flexibility (e.g., up to 25% of budgeted amounts or a fixed dollar level on an annual basis) for shifts between Residential and Non-Residential program categories before a review process is triggered.

In addition, under PG&E's proposal there would be no review triggered if there are major shifts in funding away from the third party programs selected via competitive bidding, whereas the other three proposals would require some form of review if the allocation drops below the 20% minimum threshold.

While we believe that the utilities should have considerable discretion in making portfolio management decisions because they are the entities held accountable for portfolio performance, the degree of flexibility that PG&E requests would provide essentially no opportunity for Commission review during the three-year program cycle for major shifts of focus relative to the portfolio plans submitted for approval today or after the final portfolio plans are approved based on the competitive bid results during the compliance phase. In our view, the other three proposals, with some modifications, provide a more balanced approach to fund-shifting for the Resource/Non-Resource program categories.

In particular, we agree with SCE and the PRGs that a review/approval process should be triggered if funds are shifted away from competitively selected programs which cause a reduction in funding below the 20% minimum requirement. As discussed in Section 8.4, we define the 20% minimum threshold in terms of total portfolio funding levels, excluding EM&V budgets. This fund shifting restriction is consistent with the overall approach to quality control we adopted in D.05-01-055 to safeguard against bias in program selection.151

We also agree with the PRGs that some threshold for review should be established when there are major funding shifts among Residential, Non-Residential and Cross-Cutting programs, since each of these categories represent significantly different market strategies or focus for achieving the energy savings goals. At the same time, we believe that the threshold should be set to trigger review only in the case of major shifts in funding so that the utilities can manage their portfolios without undue restrictions or delays, per our objectives outlined above. We believe that a 25% annual (50% cumulative) threshold for shifts among these major categories of Resource/Non-Resource programs in either direction accomplishes this balance. In our view, a percentage trigger is preferable to a dollar level approach because it provides a degree of flexibility that is directly proportional to the approved budget levels.

This requires redefining PG&E's program categories somewhat, relative to the definition presented in its fund-shifting proposal. For the purpose of fund-shifting rules, we will define the Resource/Non-Resource Program categories for PG&E as (1) the "crosscutting" program of Mass Markets, (2) the residential targeted market sectors within Targeted Markets (e.g., Residential New Construction) and (3) the non-residential targeted market sectors within Targeted Markets (e.g., Industrial, Commercial, Agricultural and Food Processing). This creates a more consistent corollary to the categories defined in the fund shifting proposals for the other utilities.

Within each program category, as defined above, we believe that the utilities should be able to shift funds without triggering a formal Commission review/approval process. In other words, the utilities should be able to modify their allocation of funds among the various non-residential program offerings based on feedback from market assessments, field experience, program advisory group input, and other information that indicates the best way to tap the potential for short- and long-term savings cost-effectively in the non-residential sector. Similarly, the utilities should be able to adjust their strategies within their residential and cross-cutting programs (not including emerging technologies, codes and standards and statewide marketing and outreach) without triggering a formal review.

At the same time, we believe that the utilities should inform and solicit input from their PRGs when major shifts in programs within each Resource/Non-Resource program category (as defined above) are contemplated, as proposed under the SCE/SoCalGas PRG fund shifting proposal. Accordingly, we will require the utilities to notify their PRG fifteen days prior to making shifts in programs within each category that exceeds the 25% annual (50% cumulative) limit and to solicit comment from the PRG members before making a final decision.

This means that if PG&E wants to shift more than 25% of funding in a single year from the Industrial to Agricultural targeted market sectors within the Non-Residential program category defined above, they will need to inform and solicit comment from their PRG members before making their final decision. This also means, for example, that SCE would need to solicit feedback from its PRG if it is contemplating shifting more than 25% of budgeted amounts from the Business Incentive Program to their Retro-Commissioning Program within the Non-Residential category. We do not anticipate frequent instances of shifts of this magnitude, but if they do occur, we believe that the PRG members should provide their input as non-financially interested members of the PAG. This is not intended to preclude the utilities from seeking input from the broader PAG membership when contemplating such changes, in fact such outreach is encouraged. However, we recognize that non-PRG members may have a significant financial interest in the outcome, and therefore will not require the utilities to solicit comment from the broader advisory group before making its final decision on funding shifts of this magnitude.

For adding new programs, except for those chosen during the competitive bid process, we adopt SCE's suggestion that the utilities file an advice letter. With respect to changes in incentive levels or modifications to program design (such as changes to customer eligibility requirements) we do not believe that approval from Energy Division staff or this Commission is required, as some parties recommend. We expect many program design parameters to change and evolve as implementation strategies are tested in the field. As clearly indicated in CMS documents, the utilities will be conferring with their program advisory groups to solicit input on the most effective program design strategies throughout the program cycle, and are actively coordinating those designs and incentive levels for statewide programs.152 In addition, the EM&V plans for market assessments, process evaluations and other studies will provide program administrators with feedback during the program cycle on how to modify program design to increase the effectiveness of their market strategies.

In our view, putting Energy Division staff or this Commission in the role of reviewing and approving what we anticipate to be relatively frequent program design modifications is a retreat to the oversight paradigm of the last few years that we rejected in D.05-01-055. We prefer to let the process described above take its course to reveal the best practices in program design over the program cycle.

For similar reasons, we reject other proposed rules for fund-shifting presented for our consideration. In particular, the SCE and SoCalGas PRGs originally contemplated a trigger for Commission approval with reductions of 10% or more in certain program offerings within the program categories listed above. ORA and TURN jointly propose a very detailed prescriptive set of rules governing customer incentive design that would trigger a Commission review/approval process for any exceptions to those rules. In addition to imposing a level of restrictions to portfolio management that we find questionable, there are other significant drawbacks to these proposals. For example, the SCE and SoCalGas PRG recommendation identifies specific programs that are not included in PG&E's portfolio, so it would be unclear what elements of that portfolio should be subject to the 10% trigger, and therefore how to effectively monitor compliance.

In our view, the ORA/TURN joint proposal imposes a level of prescriptive design requirements that would require extensive (and costly) monitoring for compliance, and it is far from clear that those requirements are appropriate for the next generation of energy efficiency programs. For example, they propose a restriction that only freezer and refrigerator units built before 1990 could qualify for recycling incentives when, in fact, the Commission has recently ruled that such restriction should not apply to SCE's 2005 summer program-a position that we note both ORA and TURN supported in that proceeding.153 It is also not evident that their proposed requirements for early equipment retirement are appropriate to adopt at this time, since such issues are currently being considered by Joint Staff in developing their recommendations in the EM&V phase of this proceeding, per D.05-04-051.154 We will not adopt these proposed rules.

Finally, with respect to carryover/carryback funding flexibility, we adopt the approach recommended under all of the proposals, namely, to allow for such flexibility without triggering a Commission or PRG review/approval process.

For the instances in which Commission review is triggered under the fund-shifting rules we do adopt today, the utility is required to file an advice letter. We note that the current procedures in place for review and approval of fund shifting or program modification proposals vary by utility and type of fund shift. For example, per D.03-12-060, requests for proposed increases to customer incentive levels must be approved by Energy Division staff following 20-day notice to staff and the service list. On the other hand, at least for PG&E, requests for reallocations of funds collected via procurement rates are reviewed by Energy Division staff within 10 days. If staff needs additional information, the approval period is lengthened by 10 days from the date Energy Division receives the additional information.155 Other rules are currently in place for different types of fund shifts, creating a patchwork of procedures that are difficult to understand and follow.

With the exception noted below, we believe that a single and consistent advice letter procedure for the review and approval of fund shifting proposals should be established for 2006 and beyond. We believe that the advice letter procedures adopted in D.05-01-032 are appropriate for this purpose. Those procedures call for a 20-day comment period and 30-day initial review period by Energy Division. In our view, this provides a reasonable timeframe for interested parties and Energy Division staff to review and respond to the large shifts in funding or new program proposals that trigger review under today's adopted fund shifting rules. At the same time, they provide a mechanism for the proposed changes to go into effect relatively quickly if there are no protests. Specifically, unless suspended, advice letters that are not protested or acted upon in some way by the Commission within 30 days are "deemed approved."156 The advice letter filings required by today's decision shall be served on the service list in this proceeding and in R.01-08-028, or its successor rulemaking, unless otherwise directed by the assigned ALJ.

We make one exception to this process for shifts between utility and Energy Division EM&V budget allocations, or shifts out of the EM&V category. Such changes need to be carefully considered in the context of the Commission's EM&V oversight role described in D.01-05-055. The advice letter process does not specifically provide for Joint Staff input or consultation with the Assigned Commissioner or ALJ on these matters. Therefore, for proposals to reallocate funding between utility and Energy Division EM&V budgets, or out of the EM&V category, the utilities will be required to file a motion. The assigned ALJ or Assigned Commissioner will address such motions by ruling, after consultation with Joint Staff.

We reject proposals to have a PRG "vote" to exempt the utility from review by the Commission, where such review would otherwise be appropriate. The PRG is an advisory group only, and its consensus or non-consensus views on an issue should not substitute for the review and approval process adopted by this decision. Nonetheless, consistent with the ongoing role we have established for the advisory groups, including the PRGs, the utilities are expected to seek informal review with advisory group members for all significant shifts in funding or modifications in program design, whether or not an advice letter filing is triggered. For those shifts in which Commission review/approval is required, the utilities should also meet and confer interested stakeholders so that their concerns can be communicated, and possibly addressed, before the advice letter is filed.

As discussed above, our objective is to enable the program administrators to make program funding modifications without undue restriction or delays, but at the same time to require the appropriate level of review for major changes in program allocations. In our opinion, today's adopted fund-shifting rules and associated review/approval processes strike the appropriate balance. Our adopted fund shifting rules are presented in Table 8. This table shall be appended to the Appendix A of version 3 of the Energy Efficiency Policy Manual adopted by D.05-04-051. Energy Division shall post the updated Appendix A to the Commission's website as soon as practicable. As provided for in the Rules adopted by D.05-04-051, the assigned ALJ in consultation with the Assigned Commissioner may provide necessary clarifications to the fund-shifting rules adopted today, or consider modifications to those rules, during the 2006-2008 program cycle.157

8.10. Other Issues

The CMS documents identify a range of issues related to program design that were raised in the PRG assessments, and responded to by the utilities on a point-by-point basis the attachments. As indicated in those documents, many of the issues have been resolved between the utility program administrators and the PRG members to their mutual satisfaction. We also note that the utilities have responded in writing to the specific comments raised during the meetings with PAG members and the general public leading up to the applications, and again, in many instances have directly incorporated these suggestions into their portfolio plans.158 Still, some parties request that we intervene on specific program design issues, clarify partnership arrangements or funding allocations to specific partnerships, address contract terms and other implementation details as part of today's decision. In some instances, these specific requests appear to be motivated by the interest of specific implementers in having their program offering sanctioned by the Commission prior to the final selection of partnership programs or third-party competitive bid proposals during the compliance phase.

As discussed at the PHC and in the Assigned Commissioner's scoping ruling, today's decision is directed towards the policy level "Category 1." As directed by the ALJ, issues related to areas of specific program design or implementation ("Category 2") should be addressed as part of the ongoing collaborative process among the utilities, advisory group members and the public to develop the best portfolio plans that meet the objectives we have set forth in our policy rules, and further clarified today. To the extent that the Assigned Commissioner or ALJ believes it necessary to instruct the utilities and PRGs to report back to them on how they have worked through or addressed specific issues ("Category 3"), they may do so by ruling at any time during the program cycle.

Nonetheless, there are a few comments on other issues that we feel compelled to respond to today.

In particular, CCSF requests that we modify our procedures established in D.05-01-055 concerning the compliance phase filing, at least for PG&E. Under that procedure, we will allow the compliance filing to be submitted as an advice letter if the utility and its PRG are in full agreement on the final program plans and bid selections. If not, the utility will submit a compliance filing in this consolidated application docket requesting Commission approval of the final programs.159

CCSF recommends that those local governments on PG&E's short list must give their consent in order for PG&E to proceed with its filing as an advice letter. As a procedural matter, we observe that this is not a Phase 1 issue, and CCSF should have filed a petition for modification of D.05-01-055 in our rulemaking proceeding if it wanted to suggest such a change to the procedures adopted by that decision. On a substantive basis, we find no merit to this recommendation. By definition, PRG members have no financial interest in the outcome of the final program plans-either the selection of third-party bidders or, in the case of partnerships, the final allocation of budgets to local government entities or other aspects of the partnership arrangements. Therefore, it is appropriate to consider their assessment of whether the utilities have developed those final program plans and partnership arrangements in compliance with our policies, in deciding the procedural vehicle for this compliance filing. In contrast, CCSF is clearly not a disinterested stakeholder in this process, nor are the other short-listed local governments being considered as partners for this program cycle. Their withholding of consent could clearly reflect specific financial interests, rather than an objective assessment of compliance issues. Apparently, CCSF's recommendation stems from a worry that they would not have the opportunity for a "full fledged filing" in response if an advice letter filing is made.160 This is simply not the case. Our Advice Letter rules allow 20 days for written protests, which presents such an opportunity to all interested parties.

In its comments, WEM alleges that the utilities are "double-dipping" and rewarding non-compliance when they provide funds for codes and standards programs and also provide incentives for developers whose offerings are non-compliant with those standards.161 The CMS documents and other parties' comments respond to this allegation, and we believe that these responses should be duly noted.162 They clearly indicate to us that at least over the short-term, code compliance market support has potential to tap energy savings opportunities that would otherwise be irretrievably lost, particularly for HVAC end-uses. We encourage the utilities to continue to work with the HVAC PAGette and other interested stakeholders to refine their program strategies to address these lost opportunities during program implementation.

At the same time, consistent with TecMarket Works and Joint Staff's recommendations on this issue, the utilities will be required to complete a market survey to estimate the actual level of code compliance. We agree with TecMarket Works recommendation that the issue of code compliance be further investigated as a longer-term program strategy, as enforcement effects begin to take effect. To this end, Energy Division should include an evaluation plan for this issue in its proposed 2006-2008 EM&V budget.

The CMS notes that most parties consider the establishment of both the PRG and to be a success in helping the utility portfolio administrators design strong portfolio plans and improve the competitive bidding proposals.163 However, it also notes that the Commission was silent in its previous decisions about the future role of the non-financially interested PRGs. Most PRG groups have requested that the Commission clarify their future role and some have provided specific language. Some parties have also expressed their views on the future role of the PRG in their comments.

We agree with NRDC that the ongoing involvement of the PRGs for each utility throughout each program cycle is essential to the administration of the energy efficiency portfolios. In particular, such involvement is essential for matters best dealt with by non-financially interested parties, such as fund shifting and ensuring non-bias in the selection and ongoing implementation of utility and non-utility implemented programs. We also note that PG&E and SCE have proposed to have staggered solicitations at different times within the 2006-2008 program cycle for non-utility implemented programs. We believe that the PRG should be involved during each of these solicitations to continue to advise the utilities during the selection process. The continuation of this advisory support to the utilities can help ensure that there is no bias between utility and non-utility programs at any point during program implementation, and that all programs are evaluated and chosen for continuation based on their ability to meet the Commission's objectives for energy efficiency.

Therefore, we clarify today that the PRG's role should not stop with the upcoming selection of the third-party programs. We encourage PRG members to continue their work with each utility program administrator to implement the recommendations provided in the respective PRG assessments and strive to jointly achieve our energy savings and policy goals. In particular, each utility administrator should meet with or confer with their PRG members to decide how frequently the PRG's should meet and for what purpose. In addition, members should discuss to what extent frequent meetings would constitute a financial hardship or time commitment problem. After these meetings, the utilities should inform the assigned ALJ of its proposed schedule for the next 12 months. Per D.05-01-055, the assigned ALJ, in consultation with the Assigned Commissioner, may provide additional clarification and direction with respect to these and other advisory group issues.164

99 "Joint Staff" refers to the following Energy Division and CEC staff members working jointly on energy efficiency matters at the Commission: Zenaida Tapawan-Conway, Tim Drew, Ariana Merlino, Peter Lai (Energy Division) and Mike Messenger (CEC). 100 TecMarket Works Report, pp. 26-27. We disagree with WEM's assertion in its reply comments that a finding concerning overall portfolio cost-effectiveness cannot be made without updating or further evaluating all input assumptions. As discussed above, TecMarket Works' final report presents a reasonable assessment of uncertainty (via sensitivity analysis) to support our conclusion. 101 CMS, p. 1; Reply Comments of NRDC, July 21, 2005, p. 3. 102 Our discussion in D.05-04-051 recognizes, however, that it may not be necessary to true-up the performance basis using ex post studies for some measures and/or programs. See D.05-04-051 p. 52. 103 TecMarket Works Report, Finding 10, p. 9; and p. 22. 104 CMS, Attachment 6, p. 4. 105 TecMarket Works Report, pp. 30-31. "It appears that the non-DEER estimates do not take into account recent EM&V studies results that were used to update DEER...The non-DEER workpapers also use the same assumptions for CFL and non-CFL lighting; this is known to be significantly in error for some occupancy types."

106 Those values can be viewed under "supporting documents" at www.cpuc.ca.gov/deer.

107 In our numerical example, 6 kW of demand reductions would be "non-coincident," 6 kW adjusted downwards by some factor to account for the fact that some of the building would have air conditioners/lighting and other appliances turned off would be counted as "coincident" demand, and 3.5 kW would be counted as the daily average peak demand. 108 CMS, p. 13. 109 See Reply Comments of TURN, p. 12. This and other options to improve the valuation of critical peak period savings should be addressed in Energy Division's recommendations in our avoided cost proceeding, as discussed in Section 8.8 below. 110 Although our peak demand goals were calculated using a load factor multiplier (.217) applied to the electricity GWh goals, this factor should not be used in utility reporting of peak demand achievements (forecasted or actual). See NRDC's June 30, 2005 Opening Comments, pp. 5-6. 111 See D.04-09-060, p. 28. We note that there is a typographical error in the description of how the 560 hours is derived. The text should state that the months of June (not July) through September are included in the summer peak period. 112 The CMS participants delineated a similar set of tasks, including ones related to "fixing" the E3 Calculator. However, we believe that this should be coordinated with our avoided cost proceeding, and direct that work in Section 8.8 below, under a somewhat different timeframe. 113 See Joint Reply Comments of SDG&E and SoCalGas on Parties' Comments, July 21, 2005, pp. 2-3; CMS, p. 11. 114 Rule XI.1. 115 D.05-04-051, pp. 67-68; Ordering Paragraph 12. 116 TURN Reply Comments, p. 15. 117 NRDC Reply Comments, July 21, 2005, p. 4. 118 D.05-04-051, pp. 18-20. 119 Reply Comments of PG&E, pp. 8-9. 120 See CMS, pp. 33-34; Reply Comments of PG&E, pp. 19-21. 121 See D.05-04-051, pp. 42-43. In its June 30, 2005 Opening Comments (footnote 8), TURN urges us to reconsider its earlier objections filed in R.01-08-028 concerning our determination that net resource benefits should be used as the performance metric for energy efficiency resource programs, arguing that this metric is causing HVAC (even with positive benefits) to "lose out" to lighting measures. Underlying this argument is the fundamental perspective described above that low load factor energy efficiency measures should, by definition, win out over high load factor measures. For the reasons discussed in today's decision, we reject this perspective and instead address the issues that we believe will more accurately value and estimate the peak demand reduction savings from all energy efficiency measures. 122 D.05-01-055, p. 103. 123 Ibid. 124 D.05-01-055, p. 86. 125 Here again, there are some differences in the metrics used to evaluate this attribute, that we do not find significant. For example, PG&E does not explicitly list "innovation" as an evaluation criteria under its targeted solicitation for resource programs, but includes "improved performance" as a criteria along with "portfolio fit" instead. 126 Reply Comments of PG&E, pp. 14. 127 Ibid., p. 13. 128 D.05-01-055, p. 88. 129 Id. 130 Assigned Commissioner's Ruling Providing Clarification on Energy Efficiency Savings Issues Associated with the 2006-2008 Program Cycle, May 11, 2005 in R.01-08-028. 131 See D.05-04-051, pp. 56-60. 132 Joint Supplement, Attachment 2, p.7. 133 Attachment 4, pp. 11. 134 Assigned Commissioner's Ruling Providing Clarification on Energy Efficiency Savings Issues, May 11, 2005, pp. 6-7. 135 CMS, Attachment 4, pp. 8-10. 136 In particular, see Joint Staff's recommendation for verifying parameters used by HMG to develop its ex ante savings estimates. Rather than formally direct Joint Staff to set up an evaluation contract to verify these parameters in today's decision, as Joint Staff suggests, the specifics of such EM&V activities should be established via the process we established for the EM&V phase in D.05-04-051. 137 Joint Utilities Response to Joint Staff Comments on Codes and Standards Program Energy Savings Assessment, July 21, 2005, p. 6. 138 More specifically, the performance basis is a calculation of net resource benefits that weights the resource benefits and cost components of the TRC test by 2/3 and the PAC test by 1/3. See D.05-04-051, p. 40. Also, see the discussion in Attachment 10 concerning the various timing issues for calculating the performance basis for codes and standards work conducted during a program cycle, and associated options and considerations. 139 D.05-04-051, p. 56. 140 Ibid., p. 43. 141 PG&E Reply Comments, July 21, 2005, p. 23. 142 See D.05-04-051, Attachment 3, p. 2, Rule II.2. 143 See Executive Order S-20-04, paragraph 4. (Emphasis added.)

144 "Current avoided costs" are those avoided costs calculated using the E3 avoided cost methodology, as specified in D.05-04-024, and as set forth in the associated May 2005 compliance Advice Letter filings by PG&E, SCE, and SDG&E.

145 TecMarket Works Report, p. 9. See also CMS, p. 1. Our policy rules direct the utilities and implementers to perform cost-effectiveness analyses that are consistent with the indicators and methodologies included in the Standard Practice Manual. (See Rule IV.1.) 146 CMS, p. 13. 147 Id. 148 Id. 149 D.05-04-024, p. 37 150 Ibid., p. 3. 151 See D.05-01-055, p. 10, 86. 152 See Attachment 8. 153 See D.05-05-012, pp. 21-23. 154 D.05-04-051, pp. 30-31; Ordering Paragraph 14; See also D.05-05-012, footnote 13 beginning on page 22. 155 Letter dated May 13, 2005 from Sean Gallagher, Director, Energy Division, to Roland Risser, PG&E. 156 D.05-01-032, Appendix, Rule 4.7: "Advice letter that is subject to Public Utilities Code Section 455 or that implements a rate increase previously approved by the Commission is deemed approved if, at the end of the initial review period, the Industry Division has not suspended the advice letter (as provided for in Rule 4.6)." 157 See D.05-04-051, Rule XI. 158 See Attachment 2 to this decision and CMS Attachments 6-9. 159 D.05-01-055, pp. 103-104. 160 Reply Comments of CCSF, p. 4. 161 WEM Reply Comments, pp. 9-10. 162 See CMS, pp. 33-34; Reply Comments of Proctor Engineering, July 20, 2005, p.6; Reply Comments of PG&E, pp. 20-21; Joint Comments of SDG&E and SoCalGas Regarding the California 2006-2008 Energy Efficiency Portfolio Final Report Prepared by TecMarket Works, July 21, 2005, p. 5. 163 CMS, p. 37. 164 D.05-01-055, Ordering Paragraph 3.

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