6. Case Management Statement and Positions of the Parties

The July 15 Case Management Statement (or "CMS") describes the current status of resolved and unresolved issues, based on continued communication among the utilities, PRG members and those parties filing opening comments. We describe that status, by issue, in the following sections. Our description is intended to highlight the range of positions on a particular issue, rather than describe each party's position in detail. Additional descriptive material is presented in attachments.

At the PHC, the assigned ALJ delineated three categories of issues in Phase 1 of this proceeding. "Category 1" issues relate to the those that the Commission needs to address by Commission decision, in order to determine if the proposed portfolios are consistent with the policy rules and if the associated funding levels are reasonable to include in rates. They encompass the Phase 1 issues listed in Section 3 above.

In contrast, Category 2 issues relate to areas of specific program design or implementation that should be the subject of ongoing discussions among the utility program administrators and their advisory groups (including Energy Division) and the public as the portfolio plans and program details are being refined between now and the compliance filing, as well as during their implementation over the three-year program cycle. These are issues that are considered "below the radar" for this decision, and do not require formal Commission action.

The ALJ also identified a potential third "in-between" category of issues (Category 3) that the Commission would not address formally, but could instruct the utilities and PRGs to report back to the ALJ and Assigned Commissioner how they have worked through or addressed these issues.⁴⁰

The body of the CMS focuses on the "Category 1" issues, and provides attachments that describe Category 2 and 3 issues raised by the PRGs or interested parties, the utilities' responses and proposed actions, as appropriate. In the following sections, we follow the general organizational format of the CMS in summarizing the positions of the parties, focusing on Category 1 issues.

All references to the Commission's policy rules for post-2005 energy efficiency programs ("Rules") refer to the Rules presented in Attachment 3 of D.05-04-051.

6.1. Portfolio Cost-Effectiveness

As stated in the Rules, the Commission's overriding goal guiding its energy efficiency efforts is to "pursue all cost-effective energy efficiency opportunities over both the short- and long-term."⁴¹ Therefore, the Rules establish a threshold cost-effectiveness condition for the utilities' energy efficiency portfolios. Cost-effectiveness is measured using two different tests, referred to as the Total Resource Cost (or "TRC") and Program Administrator Cost (or "PAC") tests of cost-effectiveness.⁴² In order to be eligible for ratepayer funding, each utility portfolio and the entire statewide portfolio must pass both tests on a prospective basis, considering all costs of the programs. These include costs not assignable to individual programs, such as overhead, planning, and EM&V.

The CMS indicates consensus on this issue, stating that the proposed program portfolios "are cost-effective on a prospective basis, taking a reasonable account of uncertainty with respect to key cost-effectiveness input parameters." However, as discussed further below, some parties express concerns that certain key program input parameters, such as net-to-gross ("NTG") ratios, need to be updated to provide a more accurate assessment of cost-effectiveness. NTG ratios are used to estimate and describe the "free ridership" that may be occurring within energy efficiency programs, that is, the degree to which customers would have installed the program measure or equipment even without the financial incentive (e.g., rebate) provided by the program. Only energy savings net of free riders are to be counted towards the energy savings goals or in the calculation of resource benefits (savings times avoided costs).

In its reply comments, WEM takes exception to the CMS characterization of consensus over this issue, arguing that it overlooks unresolved issues in TecMarket Work's report as well as WEM's opening comments. We disagree. WEM refers selectively to statements that the author of the report made during the PHC before TecMarket Works finalized its report and conducted sensitivity analysis to consider the impact of lower savings assumptions on the cost-effectiveness results. Moreover, the CMS report discusses the issues that TecMarket Works raises with respect to planning assumptions throughout the document.⁴³

6.2. Achievement of Energy Savings Goals

Per Rule II.5, the utilities are expected to manage their portfolios of programs to meet or exceed the short- and long-term savings goals established by the Commission "by pursuing the most cost-effective energy efficiency resource programs first, while minimizing lost opportunities."

The CMS Participants did not reach consensus on whether the utility portfolios are likely to meet or exceed these goals. Although the utilities believe that their respective portfolios are designed to meet both annual and cumulative energy savings (kWh, therm) and demand (kW) reduction goals, some PRG members and interested parties could not agree with this conclusion because of uncertainties in the underlying forecasts of net savings produced from each administrator's programs. In particular, the NTG values were criticized as too high in the TecMarket Works report and by TURN, ORA and other interested parties.

The NTG ratios used by the utilities were those listed in a table included in a previous version of the Energy Efficiency Policy Manual (version 2), and subsequently posted to the Database for Energy Efficiency Resources (DEER) website when version 3 of the Energy Efficiency Policy Manual was issued by D.05-04-051. The instructions to this table require that a default NTG of .80 be used for any existing programs not listed (or if a proposed program design deviated substantially from past design of related programs). The utilities implemented Rule IV.11 ("use DEER assumptions, when available") with respect to NTG assumptions by utilizing the NTG table values and the table's .80 default values. The PRG assessments, the TecMarket Works Report, TURN and ORA express concern that in some cases the table NTG values (and default value) are outdated and may be too high.⁴⁴

Additional concerns expressed in the TecMarket Works report and by interested parties include the following:

· The program delivery ramp up for such a substantial increase in program funding levels may be slower than expected, causing 2006 savings to be difficult to deliver.

· The energy savings estimates assume a growth economy consistent with the potentials study. If the economic growth projection is not realized, goal attainment is additionally at risk.

· The majority of the electric and gas per measure savings included in the statewide portfolio are based on calculated estimates of per measure load impacts that are generally uncertain until they can be confirmed via ex post studies.

· The very high percentages of screw-in CFLs (almost all in the residential category) have uncertain levels of retention or sustained savings over time, and

· The manner in which residential lighting demand savings were calculating does not reflect the fact that residential lighting load is only marginally coincident with the summer peak period.

Overall, TecMarket Works estimates that if these and other uncertainties act to lower estimated savings by 20% or more, the goals may not be reached unless energy savings credits from the information, education and marketing programs are applied.⁴⁵ Specific sensitivities around the NTG ratio assumptions contained in the PG&E and SCE PRG reports, as well as in TURN's opening comments, indicate that the proposed portfolios may not meet the cumulative 2006-2008 energy (GWh) savings targets. Moreover, TecMarket Works points out in its report concerns over operating hour assumptions used by PG&E, SCE and SDG&E to estimate the expected useful lives ("also referred to as "EULs") and resulting kWh energy savings associated with certain lighting measures.⁴⁶

To address these uncertainties, the authors of the TecMarket Works Report recommend that the Commission direct Joint Staff or its consultant to recalibrate the E3 calculators to new estimates of key parameters and re-run the estimates for all programs (or at a minimum all those that have lighting measures). Alternatively, they suggest that the Commission could direct the utilities to reexamine their estimates, make the appropriate adjustments, document the basis for their assumptions/adjustments and re-submit their savings estimates.⁴⁷

In its reply comments, TURN supports the first approach suggested in the TecMarket Works report. TURN recommends that the Commission direct an independent agent to revise the NTG ratios used by the utilities in their June 1 filing, based on the best existing evaluation results for sector-level end-use technology. In addition, TURN would require that the utilities re-submit their portfolio plans using these updated values in a separate "post Phase 1" advice letter filing for Commission review and approval before the utilities prepare their compliance filing.⁴⁸

ORA proposes a very different approach to addressing the uncertainty over free-ridership assumptions. ORA observes that the NTG assumptions used by the utilities, which were based on values included in version 2 of the Energy Efficiency Policy Manual, reflect the general make-up of the statewide energy efficiency portfolio as of August 2003. ORA contends that these are not useful for the Commission's purposes during this planning cycle because many of these program categories do not map directly to the 2006-2008 energy efficiency programs proposed by the utilities, and will not easily map to the third-party programs to be solicited under competitive bids.

In addition, ORA argues that recent studies indicate that free-ridership within a program can differ by end use, which renders the use of program-level NTGs much less useful. While ORA supports continuing refinements to NTG ratios in the future, it believes that for purposes of portfolio planning and bid selection, a simple default NTG value should be used. In particular, ORA recommends that the Commission instruct the utility administrators and third-party implementers to adopt a default NTG of 0.8 across all programs and measures for the current planning cycle, with the exception of emerging technologies. Programs addressing those technologies should use the default value of 0.96.⁴⁹

Notwithstanding these concerns, some PRG members and parties believe that there is a reasonable chance that each utility will meet its energy savings goals for 2008 (therms and GWh) and state that they are willing to help the utilities and the Commission achieve these goals. Thus, some PRG members and some parties recommend that the Commission should accept each utility administrator's filing with the knowledge that although it will be difficult to meet the goals, it is certainly possible. In particular, NAESCO and Cal-UCONs argue that the "free rider" issue appears to be consuming an unwarranted amount of time and effort by the parties. In their view, having a number of very talented parties spend their time worrying about whether the NTG for a particular measure is 10% or 15% is "unwittingly contributing to the construction of a major market barrier that will block the realization of state policy."⁵⁰

The question of whether the proposed portfolios will meet the peak demand (kW) savings goals is also controversial, and CMS participants and interested parties respond to this question in the context of whether the proposed portfolio plans adequately address critical peak loads. Part of the controversy stems from differences in opinion over what definition of peak demand should be used when calculating the portfolio demand (kW) savings. CMS participants discussed how the different interpretations of the term "critical peak loads" and different estimation processes used by the utilities to estimate the level of peak savings from the portfolios contributed to the difficulty in resolving this issue. In particular, CMS participants found it important to note the distinctions among the following terms:

· Critical Peak Loads generally refers to the highest 100 hours in a utility's load duration curve. These typically occur for a few hours a day on 8 to 12 days per year.

· Peak Loads (Daily Average) refers to the expected load on each weekday afternoon from 12 noon to 6 pm for the four summer months (20 weekdays/month x 4 months x 6 hours =480 hours per year).

· Peak Loads (Coincident) is measured as the estimated highest demand savings estimated during the five hour peak period (from 2 pm to 7 pm) on the hottest day of the year, after taking into account the probability that all equipment affected by the program will be operating at the time of the peak.

· Peak Loads (Non-Coincident) refers to the estimated highest demand savings on the hottest day of a normal weather year for an average program participant. This definition does not take "coincidence" (likelihood of all equipment being on) into account.

To illustrate these different ways of expressed peak loads, we present a very simplistic example, for illustrative purposes only. Assume that the estimated savings between the hours of 2:00 p.m. and 6:00 p.m. from energy efficiency measures installed in a building are as follows:

2-3 pm 3-4 pm 4-5 pm 5-6 pm

2 kW 4 kW 6 kW 2 kW

If peak demand reductions were calculated using the "daily average" definition, then 3.5 kW in peak demand reductions would be attributed to this program. (14 kW/4 hours.) For coincident peak, one would first need to determine when the specific peak for the entire system fell within this period and then estimate the peak savings at that point in time from the data above. Then, one would need to make an adjustment based on data or assumptions related to what fraction of this equipment is likely to be on at the time of system peak.

In this example, if we assume the peak occurred between 4:00-5:00 p.m., then the coincident peak impacts would be 6 KW multiplied by some adjustment for equipment coincidence (typically .7 for air conditioners) to yield a coincident peak of 4.2 kW. Non-coincident peak does not make this adjustment, so the estimate of demand savings would simply be 6 kW under this very simplistic example. Some, all or none of these savings will be counted as "critical peak" demand reductions, depending on the extent to which these savings coincide with the highest 100 hours in the utility's load duration curve.

An additional method for calculating peak load impacts was discussed in parties' comments, and termed "net CEC peak reductions" by ORA.⁵¹ Under this definition of demand savings, total energy savings (kWh) associated with a measure/program are multiplied by a factor of 0.217, which was the conversion factor used to translate the Commission's GWh savings goals to MW peak load reductions goals. This factor was based on historic relationships between energy and peak savings, since there was no available data on the mix of programs or measures to be used in the future.

Some CMS participants⁵² believe that several key inconsistencies need to be resolved before the Commission can fully assess whether the utility portfolios are likely to meet the Commission's demand reduction goals. First, noting that the utilities use different definitions of peak load reductions in calculating those impacts, they recommend that the Commission adopt a common definition of peak demand savings as part of this decision. They propose that the utilities re-estimate the peak savings from their portfolio using this common definition. In addition, these participants recommend that the Commission consider adopting a definition of "winter peak savings" for use by programs being implemented in winter peaking areas. These participants further recommend that a uniform set of assumptions be developed to translate annual energy savings resulting from installations of CFLs in residential and commercial dwellings into peak savings, ideally using common load shapes.

In addition, the CMS document, as well as TecMarket Works Report, refers to a "counting period" inconsistency with respect to the calculation of peak demand savings that also needs to be addressed.⁵³ Each utility uses its respective "E3 calculator" to calculate the projected savings and overall cost effectiveness of their portfolios utilizing the interim avoided costs adopted by D.05-04-024 in R.04-04-025.⁵⁴ Apparently, the E3 calculator for PG&E only counts kW savings for programs with a useful life five years or greater. For SDG&E and SCE, this counting period is three years and two years, respectively. CMS participants generally recommend that kW savings be counted for all measures with a useful life of two or more, across all utilities.

In sum, some parties conclude that it is difficult to make a definitive determination of whether the utility portfolios are likely to meet the Commission's peak demand goals for 2006-2008 without additional information to resolve the inconsistencies noted above. Other parties argue that the Commission has enough information before it on the record to determine that the proposed portfolios will not likely meet the peak demand goals or, as discussed further below, sufficiently target critical peak load.

6.3. Portfolio Balance Between Short- and
Long-Term Savings

The utilities propose to increase funding for both emerging technologies and codes and standards activities, and include a component of the competitive solicitation that provide innovative program ideas that will assist in meeting long-term savings goals. While acknowledging and commending these plans, the PRGs expressed some concern that PG&E's and SDG&E's budgets for programs that procure long-term savings (new construction, codes and standards support and emerging technologies) fell below 20% of total portfolio funding. During the CMS discussions that followed, PG&E agreed to ensure that, after portfolio integration of the third-party winning bidders and final partnership plans, 20% of the portfolio will be for strategies that produce long-term savings.⁵⁵ SDG&E agreed to report and solicit feedback from its PRG as the current programs in its portfolio designed to secure longer-term savings (Advanced Home, Sustainable Communities, Saving by Design) are implemented to consider increased funding levels during the program cycle.⁵⁶ Each of the utilities have reached other agreements related to the issue of how to balance short-term and long-term program activities with their PRGs, as described in the CMS attachments. Overall, the PRG members and the utilities appear to be satisfied with the resolution of this issue in those documents.

With respect to new construction programs, ConSol recommends that the Commission adopt a minimum of 7% funding for residential new construction. In ConSol's view, the most cost-effective way to reduce residential peak load is to provide energy efficiency programs to the residential new construction market that address cooling loads. ConSol also recommends that the residential new construction programs be statewide and consistent, and that Comfortwise (of which ConSol is the owner) be funded as the contractor for that statewide program.

In response, PG&E argues that ConSol's recommendation for increased funding for residential new construction is unsupported and fails to recognize that this program has been significantly affected by changes in California's Title 20 and Title 24 standards. PG&E also argues that ConSol's concern over the lack of statewide consistency has been made moot by the statewide coordination efforts underway, as described in the CMS. PG&E also disagrees with ConSol's assertion that the residential new construction programs do not focus on peak load savings. In addition, PG&E contends that ConSol's recommendation that the Commission arbitrarily select Comfortwise as the residential new construction program is inappropriate, and suggests instead that ConSol provide a proposal in response to PG&E's competitive bid solicitation.

SDG&E and SoCalGas request that ConSol allow the utilities and their respective PAGs and PRGs review ConSol's program concept and cost-effectiveness assumptions. Otherwise, they recommend that ConSol submit its proposal through the competitive bid solicitations being offered by the utilities.

6.4. Sufficient Strategies to Reduce Critical Peak Loads

Rule II.5 states, in part, that "...the Program Administrators should demonstrate in their program planning applications for PY2006-PY2008 how their proposed portfolio will aggressively increase overall capacity utilization and lower peak loads through the deployment of low load factor/high critical peak saving measures."⁵⁷

By far the most controversial issue in this phase of the proceeding is whether the utilities have included sufficient strategies to reduce critical peak loads consistent with this Rule. In particular, the PRG members of PG&E and SCE as well as individual parties (TURN, WEM, Proctor Engineering) contend that the utility portfolios overemphasize residential lighting at the expense of not achieving impacts from the measures that have the highest kW impacts, such as residential HVAC. For example, PG&E's PRG concludes in its June 8 report that the majority of PG&E's residential program savings (within the Mass Markets program) are not targeted at reducing summer utility peaks:

"Fully 85% of the residential category demand savings and 86% of the residential energy savings are from lighting in PG&E's portfolio filing. Research shows that over 90% of residential lighting does not operate coincident with the utility peak. While achieving these savings may provide cost-effective savings, it is not likely to `aggressively increase capacity utilization' as called for in the Policy Rules.⁵⁸

"Only 5% of forecasted demand and energy savings are projected from residential space cooling-the end use responsible for a large portion of California's utility peaks in the summer.

"PG&E's proposed continued emphasis on residential lighting relative to space cooling is also largely at odds with the Kema-Xenergy potentials analysis. While PG&E's projected HVAC savings from nonresidential category are an improvement over 2004 reported savings, nonresidential HVAC savings are still low relative to the projected peak demand potential identified in the Kema-Xenergy [potentials] analysis. "⁵⁹

SCE's PRG made similar observations in its June 1 assessment, when it concluded that SCE's proposed portfolio did not place sufficient emphasis on reducing critical load, particularly with respect to the potential for achieving reductions in residential space cooling.⁶⁰

Overall, PRG members express concern with the reported trend in system capacity utilization factors, particularly for PG&E and SDG&E. These trends imply that despite the best efforts of energy efficiency programs to target peak demand reductions, aggregate load factors are actually getting worse because peak load use is growing faster than annual sales. They note that there are many factors that may be the cause of this deteriorating load factor (including but not limited to the strong growth in air conditioning demand from new construction in the interior valleys). PRG members, as well as individual interested parties, believe that all ratepayers would be better off if the Commission had a better understanding of the causes of this trend and to what extent demand side efforts can help mitigate the problem.⁶¹

TURN is particularly concerned with this issue. In its June 30 opening comments, TURN argues that despite ongoing dialogue at PAG and PRG meetings the utilities' portfolio plans continue to inadequately target residential HVAC end uses, which "are the epitome of low load factor/high critical peak savings," and instead overemphasize residential lighting measures that are only marginally coincident with the summer peak period.⁶² In TURN's view, this will further hasten the erosion of the utilities' load factors, and thereby forcing ratepayers to foot the enormous bill for generation, transmission and distribution infrastructure investments required by needle peaks. TURN implores the Commission to enforce the requirement in Rule II.5 by directing applicants to revise their portfolios to place significantly greater emphasis on critical peak reduction.

In rebuttal, the utilities contend that their respective portfolio plans, inclusive of third party programs, sufficiently address opportunities to reduce critical peak loads. SDG&E points out that its targeted competitive bid component covers residential HVAC measures, including training, duct sealing and testing and anticipates that the compliance filing will reflect more savings that will be attributed to the HVAC end use based on the results of its bid solicitation. In addition, SDG&E states that more than half of its demand reduction goals will be met by demand reductions in the non-residential sectors, which are a significant portion of SDG&E's load during peak periods.⁶³

Based in large part on the input from its PAG and PRG members, SCE contends that it has presented a portfolio that represents the most aggressive plan targeted towards reducing peak that it has ever proposed, and one that will increase overall capacity utilization through the deployment of low load factor/high critical peak savings measures in both the residential and non-residential sectors. In particular, SCE points to the new comprehensive packaged AC systems program it has created in response to PAG input that is focused on critical peak demand for both sectors. While SCE agrees with TURN and other parties that it is important to aggressively address critical peak loads with energy efficiency, SCE also believes that it needs to appropriately balance peak load reductions with other Commission policy objectives, including the overriding goal guiding its energy efficiency efforts: the pursuit of all cost-effective energy efficiency opportunities. In SCE's view, its proposed portfolio achieves an appropriate balance, accounting for consumer demand, market potential, energy savings and demand reduction goals, and portfolio cost-effectiveness.⁶⁴

In response to TURN's comments, PG&E argues that the majority of its portfolio will capture critical peak energy savings, contrary to TURN's assertions. In particular, PG&E contends that virtually all of the measures installed under the targeted markets programs, which focus primarily upon nonresidential customers, will impact usage during critical peak hours. PG&E also points out that the residential new construction targeted marketing effort has always focused on reducing HVAC loads, and will continue to do so. In addition, PG&E asserts that more than 62% of mass market program rebate dollars are targeted directly at critical peak measures, not counting any of the critical peak reduction achieved from residential lighting, refrigeration, and appliance measures.

PG&E also argues that TURN's comments fail to acknowledge the fact that PG&E has recrafted and expanded its residential air conditioning initiatives in response to TURN's concerns during the months of working with TURN and other PRG and PAG members. Through its work with the statewide PAG subgroup on HVAC (referred to as the "HVAC PAGette"), PG&E points out that it is initiating several new approaches capitalizing on recently increased appliance and building standards that will increase its commitment to on-peak loads five-fold in the residential sector. Primarily at TURN's urging, PG&E states that it increased the budget of the activities focused on residential air conditioning from about $4 million in 2005 to $14.8 million in 2006. In the case of the one component to those efforts, the "Quality Installation" intervention, PG&E reports that budgets were raised approximately ten-fold from 2005 to 2006.

In addition, PG&E argues that TURN completely ignores the fact that a very large portion of the potential savings associated with residential air conditioner use will be captured by the recently updated state appliance standards, which increase the minimum seasonal energy efficiency rating (SEER) for residential size systems from 10 SEER to 13 SEER. Finally, PG&E argues that TURN is focused on the wrong metric and consequently arrives at an incorrect policy recommendation, namely, to spend more on residential critical peak impact end uses, such as HVAC, in lieu of residential lighting measures.⁶⁵

While NRDC agrees with other parties that peak demand savings are very important, NRDC argues that the state has a clear need for both baseload and peak savings, since both energy consumption and demand are growing in California. Moreover, NRDC contends that the residential lighting savings included in the utilities' portfolios are cost-effective and achievable, and therefore should not fall by the wayside in the effort to capture additional savings from HVAC. Instead, NRDC recommends that the Commission require the utilities to monitor the success of the HVAC programs on an ongoing basis with their PAGs/PRGs and ramp up the programs faster than planned and capture more savings if it is feasible and cost-effective.⁶⁶

NAESCO and Cal-UCONs similarly argue that the Commission should reject the "either/or" formulation that TURN has put forth in its comments with respect to lighting measures and HVAC measures. Instead, NAESCO believes that the program portfolios should include aggressive lighting measures and aggressive HVAC retrofit measures, and all available gas and water measures, so that "we wring all available savings out of each customer premise."⁶⁷ Cal-UCONs suggest that it might be more prudent to first fully explore customer metering and tariff options before focusing more energy efficiency resources on critical peak demand reductions.

NAESCO also argues that TURN's concerns over the lower contribution of CFLs to peak demand savings are exaggerated, pointing to the experience of its members in delivering HVAC programs to residential customer facilities where lighting is used 24/7 and where HVAC loads are reduced by the use of lower wattage lighting. In sum, NAESCO and Cal-UCONs urge the Commission to exercise great care before accepting the conclusion that proven effective CFL measures should be discarded.

6.5. Allocation Among Market Sectors With Respect to Savings Potential

There appear to be no outstanding concerns with respect to this issue that are not raised in other sections of the CMS document, such as under the issue of critical peak load reductions.

6.6. Strategies to Minimize Lost Opportunities

As defined in our Rules, "lost opportunities" are energy savings options that:

"...offer long-lived, cost-effective savings and which, if not exploited promptly or simultaneously with other low cost energy efficiency measures or in tandem with other load-reduction technologies or distributed generation technologies being installed at the site (e.g., solar hearing or photovoltaics), are lost irretrievably or rendered much more costly to achieve."⁶⁸

Rule II.5 directs the utilities to manage their portfolio of programs to meet or exceed our adopted short- and long-term savings goals "by pursuing the most cost-effective energy efficiency resource programs first, while minimizing lost opportunities." The utilities are required to describe their strategies to minimize lost opportunities in their program plan applications.

The TecMarket Report reviewed the utilities' June 1 filings with respect to potential areas of lost opportunities that might not be addressed in the proposed programs. Overall, they found that the portfolio plans were comprehensive and diverse, noting only a few areas of potential lost opportunities. In particular, the authors observe that there is a large efficiency opportunity to replace high intensity discharge (HID) lighting with high performance T-8s and T-5s in grocery, warehouse, large retail and other places where a wattage reduction can be almost half of the installed wattage. They also note that some utilities pay more attention to the agricultural sector than others, which they believe may warrant a stand-alone or statewide focus in the future.

The TecMarket Works report also points to successful efforts in the Pacific Northwest to improve manufactured home new construction, and suggests that the utilities initiate a new program in this sector. Finally, the authors observe that while each utility includes a retrofit program for manufactured housing in their portfolio, the different treatment of this sector (as part of the residential rebate program for SDG&E, the competitive bid component for SoCalGas, the multi-family program for SCE and the mass market program for PG&E.) made it difficult for them to evaluate the potential for lost opportunities in this sector.⁶⁹

In the CMS, the utilities respond that they agree with the report's assessment that there are opportunities in the agricultural sector and HID replacements. SCE and PG&E, which have large agricultural regions, point out that they have proposed targeted, enhanced initiatives in their agricultural offerings that they believe will address that savings potential and minimize lost opportunities. HID replacements are included as a measure, and the utilities will be working on more detailed strategies to capture that opportunity as they develop their final program plans. The utilities also believe that the concept of a new program targeted to improvements at the manufacturer level for manufactured homes is an interesting idea that they would like to analyze beginning with a market assessment of the industry. In its reply comments, SDG&E and SoCalGas also point to the Advanced Home Program as an example of a comprehensive strategy to minimizing lost opportunities in new construction.

The attachments to the CMS documents include utility-specific PRG recommendations with regard to program comprehensiveness/lost opportunities, and the utilities' responses.

6.7. Statewide Programs and Coordination

The CMS indicates that the coordination of statewide activities in codes and standards, upstream marketing, outreach, and emerging technologies is not yet complete. However, the CMS participants have agreed to a statewide planning schedule that will address several coordination issues, as outlined in Attachment 8. Under the proposed schedule, the utilities will present proposed coordination plans to advisory group members and implementers at public statewide meetings, respond to recommendations and feedback, and incorporate the results of this process into additional program detail in their compliance filings.

More specifically, the utilities and Efficiency Partnership will submit of a joint plan on statewide marketing and outreach to facilitate the integration of local marketing and outreach efforts. The utilities will also continue to confer on a coordinated basis with their advisory groups to determine whether increasing the production and distribution of the mass market measures should be done at the manufacturer level, distribution level, or both. The development of consistent statewide rebate levels and participant rules, consistent with the goals described below, is also underway.

In addition, the utilities will jointly develop a statewide strategy for the integration of demand-side programs (energy efficiency, demand-response, renewable technologies and self generation/distributed generation) to end users in a manner that is cost-effective and avoids confusion to customers. They will also develop a detailed statewide 2006-2008 plan for emerging technologies, including a target list of technologies/software and services, estimated commercialization time and estimates of energy savings.⁷⁰

To coordinate their support of future codes and standards revisions, the utilities will develop a statewide plan that includes a target list of CASE studies and a projected timeline for adoption of new standards by the CEC. The utilities will also work together to develop and submit a set of program participation agreements for use across service territories, such as license agreements, site access agreements, and contractor participation agreements. Finally, they plan to coordinate to provide consistency in their RFP template documents, wherever possible.⁷¹

Though the details of the statewide coordination effort have yet to be determined, the parties agree that overarching guidelines and policy goals should be adopted. Disagreements remain regarding the appropriate depth and scope for Commission policies adopted to provide guidance in this coordination process. The PRG members have recommended that the Commission adopt the following five policy goals with regard to statewide coordination:

1) Ensure that all firms with a footprint or facilities in multiple service areas should have easy and consistent access to all statewide programs;

2) Develop consistent rebate levels and participant rules for products promoted in statewide programs for use in negotiating with manufacturers and suppliers;

3) Leverage private advertising dollars for more savings impact;

4) Reinforce energy efficiency investments with positive statewide message; and

5) Protect the utilities' abilities to reduce the competition among utility service territories or among programs within the same service territory.⁷²

The last policy goal is intended to avoid situations among utility service territories where, for example, if one utility is offering better rebates (e.g., for lighting measures) or providing contractor incentives that the other utilities are not offering, then contractors will "migrate" to work in the service territories where the rebates/incentives are more advantageous to them. For markets where there are not enough contractors or service providers, this potentially leaves the other utilities without enough market participants to install measures in customer premises. With respect to programs within the same service territory, the same type of problem with contractor migration can occur when non-utility implemented programs (e.g., through local partnerships) offer rebates for the same measures as the statewide programs, but at different rebate levels.

6.8. Competitive Bid Components and Evaluation Criteria

There remain some disputed issues regarding the competitive bid components and evaluation criteria. As discussed in Section 6.3 above, ConSol urges the Commission to require the utilities to solicit a replacement bid for residential new construction on a statewide basis. In ConSol's view a statewide approach is needed to ensure consistency in this market sector. Some parties have also proposed that the bid criteria be consistent across the state. Others argue that some differences are appropriate, especially given the different scope and timing of PG&E's solicitation compared to the other utilities.⁷³

Based on the information available to PRG members in mid-May, the PRG assessments identified several areas of concern with respect to the bid solicitation criteria and evaluation process, and made specific recommendations to address them. In several instances, the utilities already incorporated the recommendations into their June 1 filings, based on discussions with their respective PRG prior to filing. Overall, the CMS documents indicate that each of the utilities and their respective PRGs have worked towards near consensus on all of the competitive bid issues in the weeks that followed.

Below, we briefly describe the areas of further discussion and agreement, and note where the utility's CMS response may not have fully resolved the issue. Where the CMS documents indicate that the utility has responded to specific recommendations made by individual parties on competitive bid issues, (e.g., PG&E and CCSF), we also note that response.

6.8.1. PG&E

An overarching criticism from the PRG was that PG&E's competitive bid plan as originally submitted lacked complete information.⁷⁴ In response to this concern, PG&E has agreed to submit a full competitive bid plan for PRG review, including the RFP, bid evaluation scoresheet, instructions to bid evaluators and bid schedule. This submittal will include the plans for widely disseminating the RFP and a process description and flow charts for each evaluation phase and for final portfolio integration.⁷⁵ In response to PRG feedback, PG&E has also agreed to provide several clarifications when issuing bid solicitations, including the priority areas for each solicitation and instructions to bidders that their response to the targeted market RFP can cover multiple sectors.⁷⁶ PG&E and members of the PRG also agreed that the PRG would have input on both the formulation of the competitive bid plan and the actual analysis of bids.⁷⁷

PG&E's PRG also made a number of recommendations for improvement and refinement of PG&E's bid evaluation and integration process. These include: (1) the creation of a set of criteria for the assessment of innovative programs (as there is no explicit definition of success in PG&E's proposal); (2) an improved "mainstreaming" process for the continuation and integration of successful third-party programs; (3) the development of a process to replace existing programs with third-party programs that are more cost effective and/or comprehensive in the program approach; (4) the establishment of measurement approaches that ensure that contributions to critical peak savings are considered as a part of the "portfolio fit" criteria; and (5) the development of a plan for the coordination of PG&E, third party and local government programs. PG&E has agreed to continue working with the PRG to realize these goals.⁷⁸

At the request of the PRG, PG&E has also agreed to delay issuing the integrated demand-side management solicitation until 2006, by which time it should have completed additional work on demand-side management in consultation with its advisory groups.⁷⁹ In addition, in response to CCSF's comments, PG&E has agreed to add "consideration of constrained areas" to the list of factors it will consider during the portfolio integration stage.⁸⁰

The PRG also recommended that PG&E include building operator certification and real estate related time-of-sale program strategies (e.g., inspections and energy efficiency mortgages) in its targeted solicitation. PRG members maintain that these areas hold the potential to provide substantial long-term energy savings.⁸¹ PG&E has agreed to allow time-of-sale programs to submit bids, but only if they are able to document savings. Additionally, PG&E has agreed to seek bids for building operator certification programs, but they note that these activities may be coordinated under a statewide bid.⁸²

There appears to be only one issue related to competitive bidding between PG&E and its PRG that could not be fully resolved during the CMS process. In its June 1 application, PG&E did not propose to solicit bids for programs that do not produce measurable energy savings. The PRG recommended that PG&E modify the Target Markets RFP to accept such bids, for programs such as information and outreach efforts, audits, training, etc., and suggested a set of evaluation criteria and weights that could be used for their evaluation (see Attachment 6). In response, PG&E states that it would be willing to consider a solicitation seeking non-resource program proposals that could enhance the performance of its resource-based programs, but only after the resource-based portfolio is complete and achievement of energy savings goals is assured.⁸³ PG&E also indicates that it is open to the PRG's bid evaluation criteria, but believes that further discussion with the PRG regarding the timing and targets of a non-resource program solicitation would be necessary prior to the finalization of the criteria.

6.8.2. SDG&E

The CMS documents indicate that all of the issues raised by the PRG related to competitive bidding have been resolved by SDG&E's responses.⁸⁴ In particular, SDG&E has agreed with the PRG recommendations to: (1) remove the pre-registration requirement for bidders and work with interested parties to ensure wide distribution of its RFP, (2) further clarify the criteria that SDG&E will use to assemble the final portfolio, including the considerations recommended by the PRG, (3) present and discuss with the PRG the short list of selected proposals prior to making its final selection and (4) place more emphasis on the "innovation" evaluation criteria by increasing the relative weighting of this Stage 2 criteria for it, as proposed by the PRG.⁸⁵

However, there are two areas of possible differences between the PRG recommendations and SDG&E's final proposal for competitive bidding. The first has to do with the interpretation of what constitutes the minimum competitive bid requirement of 20%. Although SDG&E states that it intends to solicit third party bids at a dollar level that is above the 20% minimum, it defines that requirement in terms of the total portfolio minus EM&V budgets. The PRG interprets the requirement to apply to the total portfolio level of funding, including EM&V.

In addition, the PRG recommended that SDG&E's targeted solicitation be expanded to include the following additional elements: building operator certification, retro- or continuous-commissioning, and real estate related time-of-sale (e.g., inspections and mortgages) in order to ensure a better balance between long-term and short-term savings. In the CMS, SDG&E states that building operator certification will be offered as part of the San Diego Energy Resource Center partnership, but is silent on the issue of whether the elements listed above will be included in the targeted bid solicitation.

6.8.3. SoCalGas

For the most part, SoCalGas' PRG was very supportive of the competitive bid plan, but raised selected concerns with respect to SoCalGas' proposed evaluation process. In response to these concerns, SoCalGas has agreed to (1) clarify that bidders should not limit their program design based on the proposed program description given for each of the targeted areas, (2) inform the PRG of Stage 1 results and discuss with PRG members the short list of selected proposals prior to making its final Stage 2 selections, (3) coordinate with SCE (as well as PG&E and SDG&E) if a vendor submits a solicitation for the same program in more than one utility service territory, (4) clarify the criteria that SoCalGas will use to assemble the final portfolio, including the considerations recommended by the PRG and (5) add more weighting to the innovation criteria under the innovative resource and non-resource solicitations.⁸⁶

SoCalGas' PRG also recommended an increase in funding allocation to comprehensive water heating replacement solicitation (under targeted markets), given the energy savings potential of that market. SoCalGas agrees to consider increased funding to this solicitation by reviewing the final statewide hot water advisory sub-group report, and then reporting back to the PRG with its decision on this issue.⁸⁷

However, SoCalGas' interpretation of the Commission's minimum bidding requirement continues to differ from that of its PRG. Like SDG&E, SoCalGas believes that it is consistent with the policy rules to apply the minimum requirement to portfolio funding levels that do not include EM&V. SoCalGas' PRG disagrees, and expresses concern that the budget that SoCalGas has allocated to competitive bids could drop below the 20% threshold, based on the PRG's interpretation of the minimum requirement (i.e., 20% of the total portfolio funding including EM&V). Moreover, the CMS does not resolve the PRG recommendation that SoCalGas also conduct third-party competitive solicitations in 2006 and 2007, on a staggered solicitation schedule. SoCalGas responds that it will do so if ordered by the Commission.⁸⁸

6.8.4. SCE

In general, the PRG found SCE's plan to be fair to potential bidders and to appropriately allow for both traditional and innovative proposals. Nonetheless, it recommended greater emphasis on innovation criteria in evaluating the IDEEA bids, as well as come minor modifications in the weighting of evaluation criteria under SCE's other solicitations.

In response, SCE has agreed to modify its criteria weights to reflect the PRG's recommendations, with minor exceptions for its IDEEA non-resource solicitation. In addition, SCE has further clarified the portfolio-level factors it will consider as it finalizes the portfolio plans following Stage 2. (See Attachment 6.) SCE has also agreed with other PRG recommendations to work with SoCalGas and other utilities to identify areas where a joint competitive bid makes sense, and work with the PRG during the competitive bid process/selection to discuss the appropriate length of the INDEE programs.

The CMS documents also indicate that SCE and the County of Los Angeles have been working collaboratively to address the concerns that the county raised in its June 30, 2005 comments.⁸⁹

However, there remain several issues between SCE and its PRG that have not been resolved. In particular, the PRG recommends that SCE increase the combined budget allocation to the IDEEA and INDEE programs from approximately 15% to 25% of the budget for competitive solicitations, in order to be more consistent with the Commission's intent to spur innovative ideas through competitive bidding. SCE argues that that degree of reliance on unproven program designs would not be prudent. In addition, while SCE's bid schedule includes PRG participation in reviewing Stage 1 and Stage 2 selections, SCE does not directly respond to the PRG's recommendation that SCE includes a process that allows the PRG to monitor both the Stage 1 and Stage 2 selection process.⁹⁰ In addition, SCE's CMS responses do not address the PRG's recommendations to provide a more explicitly set of criteria for screening Stage 1 submissions.⁹¹

6.8.5. Fund Shifting Guidelines

Fund shifting guidelines or rules establish the level of flexibility that utility program administrators have (without prior authorization) to modify funding levels for specific energy efficiency activities as the portfolio plans are implemented. In particular, the guidelines establish the extent to which the utilities may shift funds among programs within the same program category, across program categories, carry over or carry forward funds from one program year to the next, as well as discontinue programs that are not performing or add new programs during the program cycle.

Throughout the course of this proceeding, several different sets of fund shifting guidelines were proposed for Commission consideration by the utilities and PRGs. At the direction of the ALJ, the CMS participants consolidated and narrowed the options for consideration, but were not able to come to a consensus.⁹² At this time, there are four distinct proposals, described more fully in Attachment 9.

6.8.6. Funding Levels, Rate Recovery and Associated Bill/Rate Impacts

The CMS states that "parties agree that the overall funding levels proposed for the portfolio plans are reasonable."⁹³ However, in its reply comments, WEM contends that parties' comments on peak reduction issues call into question the reasonableness of overall funding levels.⁹⁴ The PRGs and other interested parties did not submit comments on the proposed ratemaking treatment or resulting rate and bill impacts.

⁵⁷ A load factor is the ratio of gigawatt hours (GWhs) of consumption (or savings) divided by megawatts (MWs) of peak consumption (or savings).