16. Comments on Proposed Decision
The proposed decision of Assigned Commissioner Grueneich and ALJ Gottstein (Proposed Decision) in this matter was mailed to the parties in accordance with Section 311 of the Public Utilities Code and comments were allowed under Rule 14.3 of the Commission's Rules of Practice and Procedure. Comments were filed on August 29, 2007 by the utilities, TURN, DRA, NRDC, California Center for Sustainable Energy, Pacific Energy Policy Center and CE Council. Reply comments were filed by the utilities, TURN, DRA and NRDC on September 4, 2007.
We have carefully reviewed the comments on the Proposed Decision and make clarifications and corrections in response to many of them. 259 However, we do not alter the substantive determinations made in the Proposed Decision, with two exceptions. For the reasons discussed in Section 6.3, we conclude that the lower end of the range of supply-side comparable earnings calculations should be used as an upper bound to the earnings potential under today's adopted risk/reward incentive mechanism. We therefore lower the cap on both earnings and penalties from the $500 million level recommended in the Proposed Decision (for all utilities combined, over each three-year program cycle), to $450 million. The $450 million combined cap is allocated to each utility as follows: PG&E--$180 million; SCE--$200 million; SDG&E-$50 million and SoCalGas--$20 million.
We also modify the Proposed Decision with respect to the treatment of mid-cycle funding augmentation. As discussed in Section 9.5, parties to the 2009-2011 planning phase of this proceeding have submitted specific recommendations for the treatment of savings and costs for funding augmentation that occurs during the funding cycle as part of our generic review of energy efficiency policy rules. Therefore, we will address this issue in a subsequent Commission decision in that phase, rather than in today's Phase 1 decision.
On all other issues, we affirm the conclusions and determinations contained in the Proposed Decision.
In particular, we affirm the Proposed Decision's clarification of how free riders should be accounted for (i.e., how the NTG ratio should be applied) in the calculation of TRC costs. The utilities argue that if we do not adopt their preferred treatment of free riders with respect to the cost side of the TRC calculation-then we have inappropriately introduced a newly revised TRC computation and contradicted the Commission's findings in D.06-06-063, without an adequate opportunity to develop the record. 260 Moreover, PG&E contends that unless we ignore or significantly limit free rider adjustments to savings benefits in the final true-up claim (or in the alternative lower the Commission's adopted goals and associated MPS levels), the "rules of the game are being changed mid-stream." 261
We disagree. With regard to the treatment of free riders on the cost side of the TRC test, the debate over how to apply NTG ratios to TRC costs has been going on for some time among the interested stakeholders, at least since the 2006-2008 planning process began. As discussed in the Proposed Decision (and reiterated today), neither the SPM, the 1988 SPM Correction Memo nor D.06-06-063 explicitly resolve this debate, which is why it was identified in the scoping ruling for resolution in this phase of the proceeding. 262 Today's decision provides the clarification requested by Energy Division and other stakeholders in order to remove any uncertainty over how these computations should be performed for calculating the PEB. The utilities as well as all other interested parties have been provided the opportunity to express their views and make specific recommendations on this issue.
We have reviewed the parties' comments and recommendations on how to apply the NTG ratio to the cost side of the TRC equation, and have carefully considered them in the context of the purpose of the TRC test. We see no merit to deferring this issue until a later date, as some parties suggest in their comments on the Proposed Decision. The utilities recommendation to exclude rebates paid to free riders from TRC costs would increase the PEB under the adopted incentive mechanism 67 cents for each dollar paid to free riders, with zero dollars of added benefit to ratepayers. Paying utility incentives on the dollars they pay to free riders is unreasonable, and today's decision appropriately rejects that proposal.
It is also unreasonable for the utilities to ask us to broaden the scope of Phase 1 in order to reverse our determinations on how to account for free riders in the calculation of portfolio savings benefits, just because NTG ratios may be higher (and net benefits correspondingly lower) on an ex post basis than they assumed in developing their portfolio plans.263 There are many parameters that go into the calculation of PEB, some of which we have determined should be trued-up (e.g., NTG ratios, portfolio costs and unit energy savings) in calculating the PEB and others that will be updated for prospective use only (i.e., to revise ex ante estimates for the subsequent program cycle). Since early 2005, the utilities have been on notice that the parameters used to evaluate near-term net savings, including NTG ratios, would be subject to true-up in calculating the PEB for each program cycle. The Commission made this very clear in D.05-04-051, issued on April 21, 2005, as did the September 2, 2005 ALJ ruling on related EM&V protocols. 264 Moreover, incorporation of up-to-date NTG values into the current portfolios has been the subject of extensive discussion at Commission workshops, as well as program advisory group and peer review group meetings prior to and during the implementation of the 2006-2008 programs.265
In sum, the utilities cannot in good faith claim that risks associated with EM&V results-particularly NTG ratios-are "unforeseen expected evaluation risk." 266 They have had ample opportunity to adjust their portfolios in response to available data, and should be encouraged by Commission policies to minimize expenditures on free riders by doing so. The Proposed Decision achieves this outcome.
The utilities also contend that adoption of per-unit penalty rates that are higher than any of the specific levels proposed by NRDC, TURN and DRA represent a violation of due process. However, they fail to point out that all parties had the opportunity to develop proposals for a fair balancing of risk/rewards under the incentive mechanism, and that the assigned ALJ specifically requested supplemental comments on the basis for the level of per unit penalty rates. 267 In response, the utilities argued that the levels proposed by TURN, DRA and NRDC were arbitrary, not well reasoned, and failed to adequately balance the risks and rewards under the incentive mechanism.268 However, none of the utilities proposed an alternate basis for per-unit penalty rates for Commission consideration. Instead, they continued to argue that this type of penalty provision should be categorically rejected by the Commission.
It is now self-serving for the utilities to argue that we cannot adopt anything other than the per-unit penalty levels that these parties proposed. Moreover, none of the utilities recommended that the basis for per-unit penalty rates be subject to evidentiary hearings, when the Assigned Commissioner solicited comment on the need for further factual inquiry in this phase of the proceeding.269 In sum, we find no merit to their arguments that our decision violates their due process by not adopting the specific penalty rate levels that were presented in the context of other parties' overall risk/reward incentive design. Today's decision adopts per-unit penalties taking into consideration the per-unit penalty levels we have established for other preferred resources, the resulting balance of potential penalties with incentive rewards under the adopted incentive mechanism, and the full record developed on this issue. The utilities may object to our judgment on the appropriate balancing of these risks and rewards, but that does not constitute legal error.
In its comments on the Proposed Decision, DRA introduces for the first time in Phase 1 a proposal for structuring the earnings side of the incentive mechanism as a relatively continuous curve of graduated earnings rates for each 5% interval of goals achievement at or above the MPS. DRA presents two alternatives for the Commission's consideration in these comments: The first would start the shared-savings rate at 1.5% if the MPS is met (85% of goals), increasing as follows: 2.5% (90% of goals), 3.8% (95% of goals), 5.0% (100% of goals), 6.3% (105% of goals), 7.5% (110% of goals), 8.8% (115% of goals), 10% (120% of goals), 11.5% (125% of goals), 12.0% (130% of goals). The second alternative would have the same graduated rates between the MPS until 100% of goals are reached, but be higher once the goals are reached as follows: 9.0% (at 100% of goals), 9.5% (at 105% of goals), 10% (110% of goals), 10.5% (115% of goals), 11.0% (120% of goals), 11.5% (125% of goals) and 12% (130% of goals). DRA argues that these alternatives are preferable to the two-tiered earnings rate structure in the Proposed Decision because, in DRA's view, they would avoid any sharp discontinuities and the potential for creating "perverse incentives" associated with such discontinuities. 270
DRA's newly proposed alternatives significantly reduce the earnings potential at all levels of performance relative to the Proposed Decision and our final decision today. For example, under both of DRA's alternatives, the resulting earnings curve produces an earnings level of $24 million (for all three utilities combined, over the three-year program cycle) if the MPS is reached, i.e., at 85% of goal achievement. At 100% of goal achievement, Alternative #1 produces combined earnings of $92 million, and Alternative #2 produces combined earnings of $242 million (over the three-year cycle). Hence, DRA's proposal is as much a recommendation to reduce the earnings potential under the entire earnings side of the mechanism as it is to address a discontinuity problem.
We affirm the adoption of a simple tiered earnings rate, as adopted in the Proposed Decision and recommended by all parties to this proceeding during workshops and in their pre- and post-workshop comments, including DRA. A wholesale change to a continuous curve of earnings rates at this juncture could introduce incentives and implementation consequences that have not been adequately explored in this proceeding, due to its untimely introduction. The combination of the more simplified tier structure proposed by all parties (including DRA) throughout the course of this proceeding, coupled with our adopted approach to establishing the "trigger" for the MPS and second earnings tiers, reflects the goal to keep the mechanism relatively simple to understand and
implement, and at the same time addresses the discontinuity concerns associated with that simple structure. As discussed in Section 4.1, we rejected the proposal put forth by some parties (including DRA) to trigger the MPS and eligibility for the second tier earnings rate based on an "all or nothing" reliance on specific numerical values. Instead, we adopt a hybrid approach that motivates superior performance while reducing unnecessary pressure points.
For these reasons, we do not modify the two-tier structure adopted in the Proposed Decision. During our review in 2011 of the incentive design we adopt today, Energy Division should evaluate the advantages and disadvantages of alternatives should our experience with a two-tiered structure reveal that discontinuity problems are not sufficiently mitigated by today's decision, and can be more effectively mitigated in other ways.
We also concur with the proposed decision's conclusion that the "debt equivalence" debate over what impact power purchase agreements might have on the utility's capital cost structure and return on equity is more properly addressed in our cost of capital proceedings, and not in this rulemaking. It is therefore reasonable, in our view, to include both "with" and "without" debt equivalence scenarios in developing a range of values for the supply-side comparable earnings calculation. DRA objects to this approach, arguing that because energy efficiency would avoid any risks (if any) associated with power purchase agreements, debt equivalence should not be included in establishing the range of values for supply-side comparable earnings. As PG&E points out, this manner of thinking about debt equivalence in the context of today's decision fails to recognize the question that is being asked by supply-side comparability. To the extent that a utility has fewer actual power purchase agreements due to energy efficiency programs, no party refutes the fact that there will also be less impact (if any) on the utility's capital cost structure and return on equity due to debt equivalence. However, DRA is responding to the wrong question: The one being asked by supply-side comparability is what would be the impact on the return on equity and associated earnings (if any), if those power purchase agreements were not displaced by energy efficiency programs. 271
In addition, DRA asserts that the proposed decision "accelerates earnings returns" relative to the asset life underlying the utilities' cost of capital and relative to the 12-year economic life for energy efficiency used in the in the calculation of supply-side comparable earnings. Therefore, DRA argues that the supply-side comparable earnings calculations should be lowered to "reflect the time value of money." 272 DRA's presentation of this new argument and assertion of facts in its opening comments on the proposed decision is untimely. DRA had amply opportunity to present them in its Phase 1 testimony, so that they could be examined during evidentiary hearings. In particular, DRA's argument rests on the assertion that the cost of equity is dependent upon a 30 year asset life. The record provides no support (or even exploration) of this and other factual assertions underlying DRA's assertion of "accelerated earnings returns." What the record does show, however, is that the time value of money is explicitly accounted for in the utilities' comparable earnings calculations. For those calculations, all earnings paid out for the supply-side resources avoided by energy efficiency are discounted to "time zero." 273 In this context, it is difficult to reconcile DRA's assertion of accelerated earnings return, since the recovery period for energy efficiency earnings extends beyond time zero.
Finally, CE Council argues that the omission of references to Bluefield274 (or other Supreme Court cases on utility rate of return) represents a "major oversight."275 We disagree. The use of utility returns on supply-side investments as one consideration in establishing a shared-savings rate does not provide a basis to connect Bluefield and related cases with the risk/reward incentive mechanism for energy efficiency. Even if such a basis could be established, the Commission is not bound to the use of any single formula or combination of formulae in determining rates. As the Court stated in Bluefield, "What annual rate will constitute just compensation depends upon many circumstances and must be determined by the exercise of a fair and enlightened judgment, having regard to all relevant facts." 276 As discussed in this decision, we have considered several methods, relevant facts and presentations before ultimately reaching today's determinations.
1. Ensuring sustained and successful commitment to energy efficiency is best accomplished by moving away from a cost-of-service compliance regulatory framework, to one that creates a "win-win" alignment of shareholder and ratepayer interests.
2. The Commission has determined in previous decisions, consistent with the recommendations of the Energy Action Plan, that shareholder incentives for energy efficiency should be pursued in conjunction with other procurement policies.
3. The purpose and scope of Phase 1 is to develop a shareholder risk/reward incentive mechanism for energy efficiency consistent with the Commission's determinations in D.05-04-051 on the following threshold incentive design issues:
a) Energy efficiency performance will be evaluated based on overall portfolio achievements, rather than on the performance of each individual program;
b) The metric for establishing a dollar value for energy efficiency performance ("performance earnings basis" or "PEB") will represent the net benefits to ratepayers from their investment in energy efficiency;
c) Shareholder earnings will represent some percentage ("earnings rate" or "shared-savings rate") of the net benefits achieved by the energy efficiency portfolio;
d) Before any of these earnings accrue, the portfolio must achieve a minimum threshold of GWh, MW and MTherm savings tied to the achievement of the Commission's savings goals for energy efficiency; and
e) The level of this minimum threshold ("minimum performance standard" or "MPS") is to be determined in Phase 1 of this proceeding.
4. The MPS approach proposed by DRA, NRDC and TURN sets up an all-or-nothing trigger for allowing any earnings that relies too heavily on specific numeric values.
5. Under the DRA/NRDC/TURN approach, missing just one of the MW, GWh or MTherm goals by a small amount could mean that utilities forfeit the potential for any earnings on the portfolio, even if that portfolio produces sizeable net benefits to ratepayers and achieves or surpasses the savings goals for one or more of the other savings metrics.
6. The possibility of missing the MPS by falling short on one metric by a small margin is likely to motivate utility administrators in ways that do not make sense from the standpoint of optimizing portfolio performance.
7. SCE's proposal to base the MPS on a simple average of achievements (relative to goals) could result in the utility becoming eligible for earnings even if it has unacceptably under-performed in achieving one or more of the individual savings goals.
8. The hybrid approach recommended by PG&E, SDG&E/SoCalGas and CE Council represents an option that both provides the utility with some flexibility in achieving the MPS (through averaging) and ensures that poor performance is not rewarded by establishing individual floors for each savings metric.
9. The alternatives that DRA introduces for the first time in its comments on the Proposed Decision to reduce discontinuity of a 2-tiered earnings tier structure would also significantly reduce the earnings potential at all levels of performance relative to the Proposed Decision and today's final decision.
10. A wholesale change to a "continuous curve" of earnings rates (from a 2-tiered rate), as DRA proposes, could introduce incentives and implementation consequences that have not been adequately explored in this proceeding, due to DRA's untimely introduction of its new proposal.
11. The combination of the more simplified tier structure proposed by all parties (including DRA) throughout the course of this proceeding, coupled with our adopted approach to establishing the "trigger" for the MPS and second earnings tier serves to mitigate the discontinuity problem that DRA proposes to address with a much more complicated (and untested) incentive structure.
12. An MPS of 85% recognizes the challenges that utilities face in achieving the savings goals and, when coupled with individual floors of 80% for each savings metric, also gives appropriate weight to the individual goals themselves.
13. An MPS of 85% also recognizes that the utilities' success in achieving 85% to 100% of the savings goals creates a substantial return on ratepayers' investment, even after shareholder earnings are paid. That return will continue to increase if the utilities reach beyond the MPS to meet and surpass the 2006-2008 savings goals.
14. Because SoCalGas is subject to a single goal (for MTherm savings), it has less flexibility than the other utilities in meeting an average MPS of 85%. Establishing an MPS for SoCalGas at the level of the individual floors adopted for the other three utilities (i.e., at 80%) treats all utilities consistently with respect to a minimum threshold of performance.
15. Protecting ratepayers against the risk of portfolio losses (negative net benefits) is not a sufficient penalty mechanism in the context of the Commission's resource planning and procurement objectives, which focus on both achieving specific savings goals for energy efficiency and doing so cost-effectively.
16. In the context of those objectives, it is reasonable to combine a portfolio cost-effectiveness guarantee with per-unit penalty provisions that start when the utilities miss savings goals at a level of performance below the MPS.
17. Taking this approach is also consistent with the Commission's introduction of per unit penalty provisions in other areas of resource procurement, such as the procurement of renewable resources to meet the requirements of the Renewable Portfolio Standard. It also ensures that each end of the deadband, where penalties and rewards are triggered, is structured to reflect the dual objectives of cost-effectiveness and achieving verified MW, GWh and MTherm savings levels.
18. A penalty trigger of 65% of the savings goals strikes the appropriate balance between imposing financial penalties when savings performance is substandard and recognizing that there are significant net benefits created by the portfolio even when performance falls below that trigger.
19. The utilities have a reasonable opportunity to manage the risk of potential penalties under the penalty provisions adopted herein, given the unprecedented level of resources made available to them, the flexibility to use their authorized funding to "dig deeper" to achieve more savings even if the ratio of costs to savings increases in the process, their access to over ten years of completed EM&V studies and their ability to manage risks through portfolio diversification.
20. The calculation of either positive or negative net benefits produced by the energy efficiency portfolio should be based on the adopted PEB formula.
21. PG&E's proposal for calculating negative net benefits under the cost-effectiveness guarantee is inconsistent with the definition of PEB adopted by the Commission in D.05-04-051.
22. PG&E's proposal also produces a lower rate at which penalties would accrue compared to the PEB metric adopted for positive net benefits.
23. As a starting point, the per unit Tier 2 penalty rates that NRDC proposes will serve to balance overall risks with the reward side of the adopted incentive mechanism. However, the Tier 2 kWh penalty rate is still significantly lower than the 5¢/kWh penalty imposed on utilities if they miss their Renewable Portfolio Standard requirement.
24. It is not reasonable to impose lower per unit kWh penalties for poor performance in energy efficiency relative to renewables, particularly since energy efficiency is "first in the loading order" under California's resource procurement priorities.
25. NRDC's Tier 2 kWh penalty rates should be increased from 4 cents to 5 cents per kWh, and the other per unit penalty rates adjusted upwards to reflect a comparable increase. This level of per unit penalties in conjunction with the cost-effectivenesss guarantee and the "reward" side of the mechanism produce a reasonable balance of potential earnings and penalties on either side of the deadband.
26. All parties have been afforded the opportunity to develop proposals for a fair balancing of risk/rewards under the incentive mechanism in this phase of the proceeding. The utilities' showings on this issue argue that the levels proposed by TURN, DRA and NRDC were arbitrary, not well reasoned, and failed to adequately balance the risks and rewards under the incentive mechanism. Instead of presenting alternative levels for Commission consideration or recommending that the basis for per-unit penalty rates be subject to evidentiary hearing, the utilities chose to argue for the categorical rejection of per-unit penalty provisions by the Commission. It is now self-serving for the utilities to argue that we cannot adopt anything other than the per-unit penalty levels that these parties proposed.
27. The risk/reward mechanism's financial penalties are intended to compensate ratepayers for their reduced benefits or increased costs on a pre-tax basis as a result of the utilities' substandard performance.
28. Making the per unit and cost-effectiveness guarantee penalties additive, as NRDC and DRA recommend, results in penalties that would pay ratepayers back more than their full investment in energy efficiency.
29. Presenting parties' proposals for shared-savings rates as a ratio of earnings to portfolio costs fails to recognize that the sharing rate and associated earnings are not tied to those costs, but rather to the much larger dollar value of avoided supply-side costs. Comparing those dollar earnings instead to the net benefits created by the energy efficiency portfolio is consistent with the yardstick established in D.03-10-057.
30. Under any of the parties' proposals for earnings levels in this proceeding, achievement of the 2006-2008 savings goals is expected to produce an extraordinary monetary return to ratepayers-on the order of a 107% to 132% return on their investment. This level of achievement is also expected to create an unprecedented level of net resource benefits to all Californians-on the order of $2.7 billion.
31. Utility investors are attracted by opportunities to earn returns, and absent energy efficiency incentives, utilities only earn on supply-side investments. Recognition of this fundamental disincentive to energy efficiency has been expressed in prior Commission energy efficiency decisions, the federal Energy Policy Act of 1992, California's 2003 Energy Action Plan, the National Action Plan for Energy Efficiency and in the Commission's 2006 Procurement Incentive Framework decision, D.06-02-063.
32. No party to this proceeding presented convincing evidence to dispute that this fundamental disincentive exists in today's regulatory environment, now that investor-owned utilities have been returned to the role of managing both supply-and demand-side resource procurement on behalf of their ratepayers.
33. Funding of energy efficiency through a non-bypassable charge on distribution rates does not change the fact that California investor-owned utilities face a risk of bypass today, that expenditures on cost-effective energy efficiency results in initial rate increases, and that higher rates increase the risk of bypass.
34. No party to this proceeding presented convincing evidence to overturn the finding made by this Commission in 1993 concerning the short-term rate impacts associated with energy efficiency, which also serve to bias utilities towards supply-side options.
35. The purpose of a comparable earnings analysis is to provide a numerical benchmark for addressing these biases that favor supply-side resources, and not to prove or disprove the tautology of zero foregone shareholder earnings posed by DRA and TURN in this proceeding.
36. A comparable earnings benchmark recognizes that utilities as decision makers make day-to-day decisions on how to direct their resources and personnel that regulators cannot directly control or mandate.
37. Without an energy efficiency incentive, given the focus of investors and utility management on increasing shareholder value, utilities will on balance be more inclined to devote scarce resources to procurements on which they will earn a return, and not on meeting or exceeding the Commission's energy efficiency goals, or maximizing ratepayer net benefits in the process.
38. Knowing how much investors would have earned on supply-side procurements, if not for energy efficiency, is useful information: It helps the Commission to consider, among other factors, what level of earnings potential will be sufficient to overcome the biases in favor of supply-side resource procurement and achieve the policy objectives for energy efficiency.
39. The Commission has previously rejected recommendations to establish the earnings potential under a shared-savings incentive mechanism by relying on historical evidence of utility management interest, by reducing earnings to reflect claims of utility bias towards energy efficiency (relative to supply-side resources), or by reducing earnings to a minimal management fee.
40. As recognized in D.94-10-059, comparisons of the risk/reward profile for demand-side and supply-side resources are difficult to make, given the differing performance, earnings and investment characteristics of these resources. In addition to who funds the initial investment, there are multiple dimensions to the relative risk between supply- and demand-side resources (and that are changing over time), including (1) how shareholder earnings vary with project performance and (2) who bears the risk of non-cost effective investments.
41. The argument that supply-side comparable earnings are not relevant because ratepayers (not shareholders) put up the initial capital for energy efficiency ignores these multiple dimensions to risk. This same argument was rejected by the Commission in the proceedings leading up to D.94-10-059 as a rationale for either discontinuing shareholder incentives altogether or for reducing the earnings potential to minimal levels.
42. Ratepayers "invest" in both supply-side and energy efficiency resources, irrespective of who puts up the initial capital. The only difference is that for steel-in-the-ground investments (generation, transmission, distribution), ratepayers have to pay not only the cost of the facilities, but also the financing costs (debt service and return-on-equity and associated taxes) to compensate those that put up the initial capital.
43. In contrast, since energy efficiency expenditures are expensed and reflected in rates immediately, energy efficiency saves ratepayers substantial financing costs. Those cost savings are magnified by the fact that a dollar of energy efficiency can displace far more than a dollar of supply-side investment to meet the same GWh, MW and MTherm energy needs.
44. The critical question in establishing the earnings potential under a shared-savings incentive mechanism is not "who puts up the capital" for energy efficiency, but rather, "how can we ensure that the potential return on ratepayers' investment in energy efficiency is actually realized."
45. Decoupling addresses a financial "lost revenues" penalty for pursing energy efficiency-it does not make energy efficiency the preferred resource from a shareholder, investment community or utility management perspective.
46. Decoupling was in place in California and several other states prior to electric industry restructuring, and then resurrected in 2001 in California during the electric crisis.
47. The Commission's reinstatement of a decoupling mechanism in 2001 is not a reason to ignore earlier Commission findings on the existence of significant disincentives to energy efficiency or policy determinations since the energy crisis to address those disincentives.
48. TURN's and DRA's conclusion that changes in the way energy efficiency programs are funded since the mid-1990s have removed a critical disincentive to energy efficiency is not logical or supported by the record. Ensuring that customers leaving the utility system cannot avoid paying their fair share of energy efficiency funding does not change the fact that expenditures on cost-effective energy efficiency can increase the risk of bypass (e.g., through community choice aggregation) by initially increasing rates.
49. No party has refuted the finding the Commission made in 1993 that, "[e]ven though energy efficiency may have a higher ratepayer and societal value, other options (e.g., inter-utility power purchases) may have a higher private value to utilities because they generally do not initially increase rates."
50. Two recent national studies (the July 2006 National Action Plan for Energy Efficiency and the US DOE March 2007 Report to the United States Congress) corroborate that fundamental disincentives to utility pursuit of energy efficiency persist today.
51. DRA's justification for a 3% sharing rate based on the management fees earned by mutual fund portfolio managers suffers from two major shortcomings. First, DRA provides no references or evidence to support its assertion that mutual fund manager fees range from $0.75 to $4.50 per $100 dollars. Second, DRA makes an "apples-to-oranges" comparison by comparing its proposed sharing rate (% of net benefits) to a fee calculation based on total portfolio value.
52. Comparing the earnings rate under a risk/reward incentive mechanism with fees earned by mutual fund managers fails to acknowledge that mutual fund managers would probably demand considerably more than the single-digit fees DRA calculates if they (1) earned only in proportion to portfolio gains, as measured over a multi-year period, and (2) were also required to pay penalties for missing targets and for losses on their clients' investment.
53. DRA's claim that a 3% shared-savings rate is sufficient to motivate utility behavior is premised on a Management Bonus Model that calculates a very high employee bonus "equivalent" associated with $81 million in earnings over three years. This calculation substantially overstates the level of equivalent bonus by basing the calculation on a limited subset of utility employees and on "base" salary that does not include other salary and non-salary benefits.
54. DRA's Management Bonus Model is premised on the assumption that the utilities' short-term bonus compensation plans are sufficient to motivate California investor-owned utilities to aggressively pursue energy efficiency. This premise is unsupported in theory and unproven in practice.
55. When corrected for the limited scope of employees considered in the Management Bonus Model, DRA's proposed 3% shared-savings rate ($81 million at 100% of savings goals) would result in an organization-wide employee "bonus" that would be virtually imperceptible.
56. DRA and CE Council's comparisons to energy efficiency incentive levels offered in other states fail to address the characteristics of individual states that may make them have greater or lesser relevance for California policy makers.
57. In assessing the nine other states' energy efficiency incentives presented in its testimony, DRA does not evaluate numerous important factors that are essential to a valid comparison to California. These factors include: (1) the level of savings goals (if any) established for the utilities in other states and what entities established them, (2) differences in retail sales, energy efficiency budgets and expenditure levels, or whether the investor-owned utilities in the other states had the option of investing in supply-side resources rather than energy efficiency programs, (3) whether verification efforts, if they were in place, were conducted ex post (post installation) and independently of the utility in question, or (4) whether other states' incentive mechanisms included financial penalties, as did all the proposals in this proceeding.
58. The nine states listed in DRA's testimony represent vastly different utilities, in different service areas, with different economic determinants of the power marketplace and the energy efficiency market there, as well as critical institutional differences.
59. DRA's analysis of other states' incentive rates ignores the relevance of electric industry restructuring on the ACEEE survey results. It reflects where most of those states have ended up after the decline in energy efficiency and associated incentives that accompanied restructuring in the mid-1990s.
60. A survey of other state's energy efficiency incentive rates would have looked much different if DRA had considered the incentive rates in place prior to electric restructuring, when investor-owned utilities across the country managed resource portfolios as the California investor-owned utilities do again today.
61. DRA's analysis also ignores the higher end of the range of incentive levels that can be observed from the ACEEE survey for Nevada and Arizona-even though several key variables (e.g., expected rate of population growth) make Nevada and Arizona potentially the most comparable to California.
62. DRA's assertion that less financial incentive is needed to improve performance in California relative to other states because California's programs are more mature than in those states is not founded in basic economic theory or logic.
63. TURN's proposal to benchmark the earnings potential under a shared-savings energy efficiency incentive mechanism to the dollar incentive rewards received by utilities under various non-DSM PBR mechanisms suffers from the following flaws:
a) TURN's analysis is restricted to the absolute dollar amount earned under non-DSM mechanisms, and does not discuss what each mechanism is designed to achieve or the value of success to ratepayers.
b) TURN's comparison looks at the achieved results under the various non-DSM PBR mechanisms, whereas it is the potential results for energy efficiency that is established by the shared-savings rates and reflected in parties' proposals.
c) TURN's analysis does not discuss the maximum penalty provisions under those mechanisms, or the thresholds of performance established before either penalties or rewards can be earned.
d) TURN's analysis lacks reasonable criteria for deciding what PBR mechanisms to include in the benchmark and appears to exclude some that could be relevant.
64. A statistical analysis to correlate historical energy efficiency incentive levels with performance would be extremely difficult (if not impossible) to perform due to the numerous variables that have affected portfolio performance as well as differences in how energy efficiency performance has been defined-since the early 1990s.
65. TURN presents figures in its opening brief to support its argument that utility spending and utility savings do not correlate to the higher incentive levels provided by D.94-10-059. TURN's figures are problematic in many ways, including their failure to reflect many other variables that affect performance.
66. As discussed in this decision and D.03-10-057, the Commission has established funding levels for energy efficiency over the years taking a variety of factors into consideration. Therefore, it is not reasonable to conclude that because budgets and spending levels do not appear to be correlated with incentive levels, higher incentive levels are no more effective than lower incentive levels.
67. As the Commission noted in D.03-10-057, the lack of correlation between incentives and spending levels, for whatever reason, does not mean that the incentive mechanism has not produced sizable net benefits to ratepayers.
68. SDG&E presented a figure on the record that suggests a positive correlation between incentive levels and the production of savings at the highest efficiencies (or lowest total costs). Unlike the figures that appear in TURN's brief, this figure was produced in sworn testimony (by SDG&E) and subject to cross-examination.
69. Due to the fundamental differences in reporting and measurement practices, as well as very different purposes and incentive structures over the last 15 years, it would be difficult to draw definitive conclusions from graphing historical data on incentives and savings or net benefits, even if a more comprehensive graphing of data was available.
70. These differences include the fact that "commitments" were counted in reporting savings achievements during some of the last 15 years, while in others they were not. In addition, in most of the years between 1990 and 2005 savings were not subject to ex post verification. Because of these and other differences, the MWh achievements (and other metrics based on those achievements) depicted in TURN's graphs are not directly comparable.
71. The inferences made by DRA and TURN from historical data when incentive levels were capped at 7% of efficiency program budgets ignore the fundamental differences in the role of utilities in energy efficiency and resource procurement, as well as the changes in Commission policy on energy efficiency over the last 15 years.
72. Given the history of energy efficiency described in this and prior Commission decisions, it is unreasonable to infer that the incentive levels adopted during restructuring or during the peak of the energy crisis in 2001 are appropriate for the risk/reward incentive mechanism adopted today.
73. No party presented alternate base case assumptions for the average energy efficiency measure lives and the split between "utility build-utility buy" scenarios used by the utilities in this proceeding. Based on the record and review of utility procurement plans, these assumptions are reasonable for the purpose today of estimating a comparable supply-side earnings benchmark.
74. DRA's proposal to update specific base case assumptions for supply-side comparability calculations at each earnings claim is based on an incorrect premise that these calculations serve as a "model" that directly produces earnings rates. Moreover, under this approach the applicable earnings rates could change at each earnings claim, introducing an unreasonable amount of uncertainty over the design parameters of the mechanism, litigation and associated delays in the earnings recovery process.
75. TURN's alternative-use-of-funds analysis assumes that the utility would make it a practice to raise money in the capital markets to cover supply-side investments that it does not need to make, in order retain those funds so that they could be used for alternative investments.
76. This assumption is not supported by either common sense or by the factual record in this proceeding: Utilities do not plan to have more cash than is needed for the plant and equipment that they will be building (or for working cash requirements), and carefully manage their cash reserves accordingly. They also do not sell shares or issue debt to raise cash for a capital investment they do not need to make, such as the supply-side resources that energy efficiency is planned to defer or displace. Therefore, it does not follow that the utility has "alternate uses" for equity on a dollar-for-dollar basis that was not needed for supply-side resources due to energy efficiency, as TURN's analysis assumes.
77. Utilities use profits from the capital investments and utility operations that they do undertake for a variety of purposes, including the pay-out of dividends to investors or stock repurchases via their holding companies. It does not follow that these profits and uses originate from cash available to the utility because energy efficiency has displaced the need to make supply-side investments.
78. TURN's assertion that a utility's net income will increase as a result of lower capital expenditures defies a basic tenet of cost of service ratemaking: When capital expenditures are lower, by definition rate base is lower and so too is net income, all else remaining equal.
79. TURN's alternative-use-of-funds analysis presents a fundamental contradiction to another position TURN advocates in this proceeding, namely, that the "right" answer to a calculation of foregone shareholder earnings is likely to be zero. If shareholders are no worse off when energy efficiency displaces supply-side resources because they take their investment funds elsewhere to earn a comparable return, it does not follow that the utility can use those funds for the alternative investments that TURN describes in its testimony.
80. TURN's assertion made in comments on the Proposed Decision that the alternative-use-of-funds analysis somehow changes when one looks at overall cash management techniques is not supported by the record.
81. The theory of utility behavior that TURN proposes in this proceeding lacks the support of a factual record and a persuasive conceptual rationale, as did TURN's predecessor economic and financial theories on the same issues in prior energy efficiency proceedings.
82. Calculating comparable supply-side earnings based on "comparable performance", as the utilities propose, is consistent with the purpose and prior application of this benchmark in California. In contrast, NRDC's proposal to base these calculations on "comparable costs" lacks both precedent and a persuasive conceptual rationale.
83. There are persuasive arguments on both sides of two methodological disputes concerning the calculation of supply-side comparable earnings. These are: (1) whether debt equivalence should be imputed for power purchases in the utilities' comparable earnings calculations, and (2) whether some portion of avoided CCGT capacity should be displaced with lower-cost CTs.
84. These disputed issues are more appropriately addressed in cost-of-capital proceedings (for debt equivalence policies and calculations) or resource planning/avoided cost proceedings (for the CCGT versus CT avoided cost question). Rather than attempt to resolve these issues in today's decision, it is reasonable to acknowledge that they create a range of possible outcomes around the base case assumptions for the purpose of calculating comparable earnings.
85. Imputing debt equivalence to power purchases and assuming avoided generation capacity based exclusively on CCGT costs produces the upper range of supply-side comparable earnings estimates, which is approximately $700 million for all utilities combined over the 2006-2008 program cycle.
86. Removing debt equivalence and substituting 24% of avoided CCGT costs with CT capacity costs as TURN recommends produces the lower range of the calculations, which is approximately $450 million for all four utilities combined over the 2006-2008 program cycle.
87. DRA's objection to including debt equivalence in establishing the upper range of values for supply-side comparable earnings fails to recognize the question that is being asked by supply-side comparability: What would be the impact on the return on equity and associated earnings (if any) if those power purchase agreements were not displaced by energy efficiency programs.
88. DRA's comments on the Proposed Decision concerning how the time value of money should be reflected in considering supply-side comparability are untimely. The argument that supply-side earnings should be lowered to reflect "accelerated earnings returns" afforded to energy efficiency rests on factual assertions that are unexamined (and therefore unsupported) by the record, including the assertion that the cost of equity is dependent upon a 30 year asset life.
89. The record shows that the time value of money is explicitly accounted for in the utilities' comparable earnings calculations. For those calculations, all earnings paid out for the supply-side resources avoided by energy efficiency are discounted to "time zero." In this context, it is difficult to reconcile DRA's assertion of accelerated return, since the recovery period for energy efficiency earnings extends beyond time zero.
90. The supply-side comparability benchmark should not be separated by fuel or type of program activity, but rather should serve as a general numerical guide for setting the appropriate share of the combined net benefits from electric and natural gas efficiency programs.
91. Including only the earnings from the electric supply-side resources foregone, and none from any gas supply-side resources foregone, avoids the need to debate the size of gas supply-side resource investments, about which there is no record.
92. Establishing the level of earnings for a shareholder risk/reward incentive mechanism is ultimately a judgment call that the Commission must make, and not a precise science. In making this judgment, consideration should be given to the following:
(a) What level of earnings will balance the level of potential penalties under the mechanism and offset existing financial and regulatory biases in favor of supply-side procurement.
(b) What level of earnings potential will provide a clear signal to utility investors and shareholders that achieving and exceeding the Commission's savings goals (and maximizing ratepayer net benefits in the process) will create meaningful and sustainable shareholder value.
(c) Differences in the risk/reward profiles of utility resource choices in applying the comparable earnings benchmark to the incentive mechanism.
(d) The level of performance expected in return for higher and higher earnings potential.
(e) What is "fair" to ratepayers in terms of the return on their investment in energy efficiency.
93. Although it is challenging to compare the different (and changing) risk/reward profiles among utility resource choices, we can observe the following:
(a) Since the energy crisis, utilities must now manage supply-side resources to meet resource adequacy requirements subject to the risk of significant financial penalties. With the passage of Senate Bill 1368, utilities also now face the risk of non-compliance for any long-term supply-side procurement that does not meet the GHG performance standard required by that statute.
(b) Although its implementation is several years out into the future, the statewide GHG emissions cap pursuant to Assembly Bill 32 will further increase the financial risks associated with any supply-side resource procurement that increases GHG emissions.
(c) These developments serve to increase the risks associated with procuring at least certain types of supply-side resources and, in turn, reduce the relative risks of energy efficiency in the context of utility resource portfolio management, even if the impact of these changes cannot be quantified.
(d) Working in the other direction is the fundamental disincentive to energy efficiency relative to "steel-in-the-ground" supply-side investments of any type (renewables or non-renewable generation, transmission and distribution) due to the fact that utilities only earn on supply-side investments under current regulatory practices.
(e) In addition, unlike supply-side procurements (including purchased power) cost-effective energy efficiency investments will increase rates in the short-term, even though it will minimize revenue requirements and customer bills overtime. This is because energy efficiency, by definition, reduces the sales volume over which fixed costs can be recovered.
(f) Energy efficiency is also not as readily "deployed" as supply-side resources, since it involves customer-side appliance changes, arrangements with manufacturers and distributors, etc. Hence, even when the portfolio funding is authorized, there is more uncertainty as to the actual deployment results of energy efficiency than for supply-side resources. In addition, energy efficiency requires independent verification of load impacts that extends beyond program implementation. These attributes introduce uncertainty and performance risks to shareholders that are not shared by supply-side choices.
(g) Although ratepayers put up 100% of the investment capital for energy efficiency programs, shareholders are at risk under the adopted incentive mechanism for losses to that capital and face sizable per-unit penalties for substandard performance of the portfolio. Unlike a rate-based plant, shareholder earnings will vary in direct proportion to performance (i.e., realized net benefits), even when factors entirely beyond the utility's management control affect that performance.
(h) At the same time, the utilities now have over 15 years of experience in implementing energy efficiency and over 10 years of EM&V study results available to them. They also have the authorization and funding to conduct meaningful process and market penetration studies to assist them in managing these uncertainties during the program cycle. In addition, applying the risk/return incentive mechanism to the entire portfolio of programs, rather than on a program-specific approach, will serve to decrease the absolute level of potential penalties as well as the probability of falling into the penalty range.
94. Using supply-side comparable earnings as a benchmark creates the sustainable "clear signal" we are looking for on the earnings side of the incentive mechanism. However, based on observations of the relative risk/reward profiles that energy efficiency earnings and other considerations, it is reasonable to apply the supply-side earnings comparability calculations very conservatively to the adopted incentive mechanism, i.e., by establishing the lower end of the range of values as an upper bound for energy efficiency earnings potential.
95. Establishing supply-side comparable earnings as an upper bound means that earnings on energy efficiency will approach supply-side earnings at a level of superior performance, that is, performance that is significantly greater than the forecasted level of savings or net benefits expected from the authorized energy efficiency portfolio. Using the supply-side comparability benchmark in conjunction with achievement of superior performance is consistent with the Commission's discussion of the role of financial incentives in D.06-02-032.
96. The tiered earnings rates adopted in today's decision strikes a reasonable balance among the following considerations: (1) Creating meaningful and sustainable shareholder value for superior achievement in achieving cost-effectiveness and verified GWh, MW and MTherm savings levels, (2) recognizing that the Commission-adopted savings goals are aggressive (yet achievable), (3) recognizing the different risk/reward profiles of energy efficiency and supply-side resource options, (4) adopting a percentage of sharing that is fair to ratepayers and (5) reasonably balancing the penalty side of the risk/reward incentive curve.
97. Today's adopted shared-savings mechanism is consistent with Section 111(a)(8) of the federal Energy Policy Act of 1992, but based on a broader set of factors than the profitability guideline articulated in that section.
98. It is appropriate to consider a broader set of factors in establishing the earnings potential for a shared-savings incentive mechanism, given (1) the complexity and diversity in our ratemaking treatment of both supply-side and demand-side resources and (2) the context for energy efficiency today under the Commission's procurement incentive framework and related climate change policies.
99. TURN's proposal for a higher kW incentive rate is premised on the assumption that kW savings are not properly valued in avoided cost calculations, a premise that is not reasonable based on the avoided costs adopted after careful deliberations in R.04-04-025.
100. The approach adopted today for the recovery of earnings should send a message to the utility to continue to pursue cost-effective energy savings as quickly and aggressively as possible throughout the program cycle. It should also provide the utility with an opportunity to learn from market and EM&V feedback so that it can make up during the program cycle for lower accomplishments in a single program year.
101. The Single-Year approach to evaluating interim earnings claims does not accomplish either of these objectives and, in fact, could encourage a utility to slow down or shut down programs because either the annual goals have been met before the end of the calendar or there is no possibility to achieve the annual goals.
102. The Cumulative-Program-Cycle approach introduces significant forecasting error into calculations of savings achievements and PEB because those calculations include forecasts of future program participation that were made at the start of the program cycle.
103. By considering the achievements of the previous year as well as the current year, the Cumulative-To-Date approach will encourage continuous effort and improvements in response to feedback throughout the program cycle. Moreover, this approach does not introduce the forecasting error associated with the Cumulative-Program-Cycle method.
104. The Cumulative-to-Date basis is the most reasonable approach for evaluating interim earnings claims and should be adopted.
105. Unlike the shared-saving mechanisms adopted prior to the energy crisis, today's adopted mechanism defines successful performance in terms of dual objectives: The achievement of a specific levels of GWh, MW or MTherm savings while maximizing ratepayer net benefits in the process.
106. Key design parameters, such as the MPS and deadband range, reflect the need for energy efficiency to produce more than positive net benefits. Energy efficiency also needs to produce sizable GWh, MW and MTherm savings that resource planners can depend upon now and in the future.
107. If the true-up adjustment in the final claim does not fully reflect the final EM&V results, then these key design parameters lose their meaning. Under the true-up approach proposed by the utilities the MPS or deadband range could end up being anywhere. This is because utilities could end up keeping the earnings they received in the interim claims even if they only actually achieved energy savings within the deadband or in the penalty range, based on the final EM&V results.
108. The true-up approach proposed by SCE and SDG&E/SoCalGas would result in a skewed treatment of load impact forecasting errors: If those errors work to the benefit of shareholders, the earnings are adjusted so that the actual earnings rate is never lower than the adopted rate. However, if forecasting errors work to the detriment of shareholders, they would be ignored, and shareholders would actually earn at a shared-savings rate that is higher than the one adopted.
109. An approach that fails to true-up savings and net benefit accomplishments based on the results of final load impact studies creates a perverse incentive for utility mangers to promote exaggerated savings assumptions during the planning process.
110. The possibility of refunding earnings already claimed may present certain problems for the utilities with respect to financial reporting. However, these problems are effectively addressed in today's decision by 1) limiting payout of initial claim(s) and 2) deducting any over-collections from future earnings claims, as suggested by PG&E and others in this proceeding.
111. An unrestricted true-up process provides the proper incentive for utility managers and staff to support the most accurate estimates of energy savings as possible and serves to ensure that ratepayers share the net benefits from their investment with shareholders only when the MPS is actually achieved and at precisely the adopted shared-savings rates-no more, no less.
112. To reduce the effect of load-impact forecasting errors on the final true-up claim, it is reasonable to hold back 30% of the earnings progress payments calculated in each interim claim.
113. The adopted schedule for earnings recovery paces the earnings claims so that there is only one claim per calendar year, and ties the claims to only those reports that were intended to be a basis for incentive payments.
114. Moving the first interim claim to the second year of the program cycle makes moot any need for the lower first-year MPS or threshold savings requirement proposed by PG&E and SCE.
115. PG&E's proposal to base the MPS for the interim claims on its ramp-up compliance filing targets, rather than Commission-adopted annual savings goals, could introduce significant gaming of ramp-up targets in future compliance filings.
116. PG&E's concerns that it will forego earnings because of a "slower start" at the beginning of a program cycle only occurs under the single-year basis approach that PG&E has proposed in this proceeding. Under the Cumulative-to-Date approach adopted in this decision, those efforts will be fully reflected over the program cycle in subsequent claims.
117. The MPS should not change from one interim claim to another and should be based on the Commission-adopted annual and cumulative savings goals.
118. There is no guarantee that Energy Division's schedule for completing EM&V reports will never be delayed, based on unforeseen circumstances. However, ratepayer interests are best served if the payout of earnings (or imposition of penalties) occurs only after the installations, program costs and (for the final claim) load impacts have been verified by Commission staff and its contractors.
119. Under the earnings recovery schedule adopted for the pre-1998 shared-savings mechanism, earnings recovery was extended to up to 10 years after program implementation, pending completion of persistence and retention studies. In addition, the EM&V reports managed by the utilities at that time, and resulting earnings claims, were subject to litigation that could cause substantial delays in earnings recovery. In that context, the Commission allowed for the calculation of interest (using the 90-day commercial paper rate) on delayed earnings recovery. EM&V responsibilities for post-2005 programs and the claim review and approval process adopted today do not share these characteristics.
120. The procedures for the review and approval of interim and final earnings claims, set forth in the April 4, 2007 ACR, have had the benefit of stakeholder input.
121. With the clarification adopted in this decision and reflected in Attachment 7, the procedures set forth in the ACR address parties' concerns while achieving both efficiency and accuracy.
122. The steps outlined in the ACR and set forth in Attachment 7 provide parties the ability to participate in the review of evaluation studies, both procedurally and substantively, by setting forth a specific and adequate process by which parties can submit questions, concerns and comments to both Energy Division and evaluation contractors.
123. The multi-party give and take available under the procedures established by the ACR and set forth in Attachment 7 is better suited than cross-examination for the kinds of disputes likely to arise with regard to evaluation study results.
124. The procedures set forth in Attachment 7 provide for a neutral and unbiased party (Energy Division) to facilitate parties' participation. They allow for broad public participation through various conferences. The requirement that all written comments to the various reports be addressed in the final versions of each report also provides for a transparent process.
125. The procedures set forth in the ACR will be equally accurate and more efficient than any of the more formal processes suggested by the parties.
126. Once Energy Division has issued a Final Verification Report or the Final Performance Basis Report, determining the level of earnings or penalties is strictly a matter of applying the formulas in this decision to the results outlined in those final reports. Accordingly, it will be a ministerial task for Energy Division to determine whether the utilities' advice letters filed in response to these reports contain the correct calculation of earnings or penalties.
127. The advice letter procedures under General Order 96-B allow for Commission resolution under appropriate circumstances where Energy Division disposition would require more than ministerial action.
128. Establishing where performance falls along the adopted penalty/earnings curve involves estimating load impacts, load shapes and (for calculating PEB) measure and program costs for an extensive number of programs and measures.
129. The adopted EM&V protocols provide staff the flexibility to establish priorities for the EM&V efforts throughout the program cycle, in recognition that the Commission may not have the resources to verify each parameter on an ex post basis for every program.
130. Excluding all non-resource program costs from the PEB, as some parties recommend, would be inconsistent with the manner in which we evaluate portfolio performance for the purpose of committing ratepayer dollars.
131. This approach would also create a perverse incentive for the utility to game the classification of programs or the allocation of costs across programs in order to maximize the net benefits of those programs subject to the incentive mechanism (resource programs) relative to those that are not (non-resource programs). Moreover, utility program administrators would be less motivated to make the non-resource programs as cost-efficient as possible if costs were excluded from the PEB, since those improvements would not impact the calculations of shareholder earnings.
132. Since the impacts of statewide marketing and outreach programs, upstream market transformation programs, information and education programs and other non-resource program activities will promote the achievement of program savings over the near- and long-term, and their impacts will be reflected in the success of the resource programs, their costs should be included in the PEB as well.
133. Including non-resource program costs in the PEB should not result in the short-changing of these programs by utility program managers, as some parties suggest, for the following reasons:
a) Since energy efficiency funding is now authorized over 3-year program cycles and subject to a 10-year trajectory of increasingly aggressive savings goals, it is not in the interest of the utility to shortchange non-resource programs that can enhance portfolio savings performance over both the short- and long-term.
b) The ability of utility program managers to unilaterally implement shifts in portfolio funding away from non-resource programs is restricted under the Commission's adopted fund-shifting rules.
134. EM&V is an integral cost of delivering reliable and verifiable energy efficiency savings, irrespective of who manages those efforts. Although the utilities may not manage most of those funds, it does not follow that shareholders should be paid a larger share of portfolio net benefits by excluding EM&V costs.
135. Including in the calculation of PEB all resource and non-resource program costs and all associated EM&V, with the exception of the Emerging Technologies Program is fully consistent with the Commission's energy efficiency policy rules on how to evaluate portfolio cost-effectiveness on a prospective basis.
136. Counting 50% of the savings attributed to pre-2006 C&S advocacy work towards establishing whether the MPS has been met for the 2006-2008 cycle, and excluding those savings from the PEB, is fully consistent with the Commission's determinations in D.05-09-043.
137. Although there may be a significant lag between when the costs for C&S advocacy programs are incurred and when the savings are actually realized, over time these streams of costs and benefits should tend to even out as they do for commitments to long-lead time projects such as new construction.
138. SDG&E and SoCalGas propose to exclude C&S costs from PEB at the time they occur, but do not indicate when those costs will ever be counted. Moreover, they do not provide a compelling reason to depart from the adopted practice of including program costs and savings on an actual basis in determining portfolio performance for post-2005 energy efficiency.
139. The baseline issues that may affect whether C&S advocacy work will count towards savings goals for the 2009-2011 cycle (and beyond) cannot be addressed until after the Commission has had an opportunity to consider comments in response to the Assigned Commissioner's June 1, 2007 ruling.
140. The potential studies underlying the Commission's savings goals did not distinguish between measures installed under low-income energy efficiency (LIEE) versus non-LIEE programs.
141. Consistent with the Commission direction in D.04-09-060, verified savings from LIEE programs should count towards the MPS under the risk/reward incentive mechanism, but not towards the PEB.
142. The Commission establishes funding levels for each three-year program cycle after an extensive program planning and compliance process, in which portfolio cost-effectiveness and the ability to achieve the three-year savings goals with the funds authorized are evaluated on a prospective basis with the input of all interested stakeholders and program advisory group members, including Commission staff.
143. Utility requests for funding augmentation once the Commission has approved funding levels and the utility program portfolios for a particular program cycle should be limited to extraordinary circumstances.
144. Specific proposals for the treatment of savings and costs associated with mid-cycle funding augmentations are being addressed in the 2009-2011 Portfolio Planning Phase of this proceeding .
145. There are implications associated with classifying a program as LIEE and augmenting its funding that carry over to the risk/reward incentive mechanism adopted today. If programs are misclassified as LIEE, the utilities could end up earning more than their authorized share of net benefits.
146. Shareholder incentives represent a true economic cost in the production of utility programs.
147. The costs of shareholder incentives should be included in calculations when evaluating the cost-effectiveness of program plans submitted during the program planning cycle, or when conducting a cost-effectiveness review of portfolio performance in hindsight.
148. TURN's proposal to subtract forecasted incentives out before applying the sharing rate is a circular proposition. It is akin to saying that we will share a quarter of a pie with you, but before we slice it into 4 pieces, we will first remove a quarter.
149. Because the simplified numerical examples presented in D.06-06-063 involved only one participant, the issue of how to fold in free rider considerations on the cost side of the TRC equation was never explicitly addressed.
150. The 1988 SPM Correction Memo formulation prohibits applying the NTG ratio to the administrative cost component of TRC costs, since these are costs unrelated to participant expenditures.
151. Parties to this proceeding disagree on whether the "rebate" incentives term ("INC") paid to free rider program participants should be adjusted by the NTG ratio.
152. As currently formulated in the 1988 SPM Correction Memo, the cost equation would remove from TRC costs all revenue requirements associated with paying free riders a rebate incentive. However, an equivalent financial incentive to the customer offered under a direct install program would not be removed.
153. All other things being equal, this means that the 1988 SPM Correction Memo formulation would assign more costs to a direct install program than to a customer rebate program that is identical except for the delivery approach.
154. Adding a transfer incentive (INC) recapture quantity to the 1988 SPM Correction Memo will ensure that the removal of free rider participant costs does not also remove program costs that become ratepayer revenue requirements.
155. Clarifying the formulation of TRC costs in this way serves to ensure that direct install programs and customer rebate programs are treated consistently when the measure cost, the customer financial incentive, program administrative costs and the NTG ratio are the same under the two delivery approaches.
156. This clarification is consistent with the text description of the TRC test in the SPM, which recognizes that the incentives (INC) term will cancel from the benefit and cost side of the equation "except for the differences in net and gross savings."
157. The utilities' recommendation to exclude rebates paid to free riders from TRC costs would increase the PEB under the adopted incentive mechanism 67 cents for each dollar paid to free riders, with zero dollars of added benefit to ratepayers. It is not reasonable to pay utility incentives on the dollars they pay to free riders.
158. The utilities have been put on notice well before the 2006-2008 program cycle began that PEB parameters associated with load impacts, particularly NTG ratios, would be trued-up based on ex post studies in each program cycle. Assertions that a true-up of these parameters in the final earnings claim represents unforeseen evaluation risk are therefore without merit. The utilities have had ample opportunity to adjust their portfolios in response to available data, and should be encouraged by Commission policies to minimize expenditures on free riders by doing so. Today's decision achieves this outcome
159. Directing Energy Division to work with Energy and Environmental Economics ("E3") and other technical expertise on the E3 calculator or to manage the development of that calculator, as Energy Division deems appropriate, is consistent with the post-2005 administrative structure adopted in D.05-01-055. Under that structure, this Commission is responsible for overall quality assurance and policy oversight responsibilities for energy efficiency.
160. Establishing a separate milestone-based incentive mechanism for certain non-resource programs, as PG&E recommends, runs the risk of double-counting the savings benefits already attributable to resource programs.
161. Our past experience with milestone-based incentive mechanisms corroborates the concerns expressed by SCE over the difficulty in establishing reasonable milestones and determining if performance is achieved.
162. Excluding emerging technologies program costs in the calculation of PEB addresses NRDC's concerns about not having a performance adder mechanism for this program.
163. To the extent that resource savings associated with utility audits are verified through staff EM&V efforts, they should be reported in the Final Performance Earnings Basis Report and included in the true-up calculation of PEB.
164. Changes to Commission rate recovery and cost allocation procedures for shareholder incentives was not a topic identified in any of the scoping rulings for Phase 1, by workshop participants in their pre- and post-workshop filings, or by the Assigned Commissioner in her ruling identifying the issues for Phase 1 testimony and evidentiary hearings. This issue was first raised in TURN's direct testimony.
165. Changes to cost allocation should be addressed only after proper notice is given to all potentially affected customers. In making any such changes, the Commission should consider a variety of possible approaches as well as factual information on the impacts for various customer classes.
166. As discussed in this decision, recovery of shareholder earnings in rates creates short-term rate and bill impacts that do not reflect the overall impact on rates and bills of energy efficiency programs (including shareholder incentives) over time.
167. The overall impact of energy efficiency programs-even with the payout of shareholder earnings-will be to decrease utility revenue requirements, customer rates and bills relative to the levels without energy efficiency programs.
168. The magnitude of these short-term rate and bill impacts depends upon the actual level of portfolio performance, the associated earnings rate and the earnings recovery schedule.
169. Based on the bill and rate impacts prepared using a range of assumptions for these parameters, the payout of shareholder earnings for 2006-2008 energy efficiency activities is estimated to result in:
a) A short-term increase in average annual rates to all customers of no more than 0.41% to 0.69%, depending on the utility.
b) A short-term increase in annual residential rates of no more than 0.44% to 0.66%, which translates to average residential bill increases in the range of 9¢ to 58¢ per month, depending on the utility.
c) Net decreases overall in bills and rates due to the much greater decreases in revenue requirement and customer bills that are resulting from the implementation of 2006-2008 energy efficiency activities
170. Instead of addressing the factual or methodological issues for establishing a relevant benchmark for shared-savings, WEM argues in its opening brief against adopting any amount of shareholder incentives for energy efficiency in this proceeding. WEM also argues for third party administration of energy efficiency programs, a proposal that has been decided in prior decisions and is not the subject of this proceeding.
1. The fundamental regulatory and financial biases against energy efficiency (in favor of supply-side resources) identified in D.93-09-078 also exist under the current regulatory framework, in which utilities have returned to their traditional role as resource portfolio managers.
2. It is unreasonable to base the earnings potential under a shared-savings incentive mechanism on the alternate benchmarks presented by DRA and TURN in this proceeding.
3. In the context of other considerations, supply-side comparability provides a relevant numerical benchmark for conservatively establishing the upper bound of earnings potential under a risk/reward shareholder incentive mechanism for energy efficiency.
4. Today's decision creates incentives of sufficient level to ensure that utility investors and managers view energy efficiency as a core part of the utility's regulated operations that can generate meaningful earnings for its shareholders. At the same time the adopted incentive mechanism protects ratepayers' financial investment and ensures that program savings are real and verified.
5. Today's decision achieves a "win-win" alignment of shareholder and ratepayer interests in the following ways:
a) The level of potential earnings under the adopted incentive mechanism represents a meaningful opportunity to earn for utility shareholders based on consideration of supply-side comparability and other factors.
b) However, earnings to shareholders accrue only when utility portfolio managers produce positive net benefits (savings minus costs) for ratepayers.
c) These earnings begin to accrue only as the utilities reach to meet and surpass the Commission's kWh, kW and therm savings goals.
d) Earnings are greatest when savings performance is superior, not just "expected."
e) All calculations of the net benefits and kW, kWh and therm achievements are independently verified by the Commission's Energy Division and its evaluation, measurement and verification (EM&V) contractors, based on adopted EM&V protocols.
f) Ratepayers receive the vast majority of realized savings, since they pay for all of the energy efficiency portfolio costs.
g) The shareholder "reward" side of the incentive mechanism is balanced by the risk of financial penalties for substandard performance in achieving the Commission's per kW, kWh and therm savings goals.
h) Ratepayers are protected against financial losses on their investment in energy efficiency. If portfolio costs exceed the verified savings from that portfolio, shareholders are obligated to pay ratepayers back dollar-for-dollar for those negative net benefits.
i) The overall level of potential earnings and penalties is capped in a manner that symmetrically limits both ratepayers' and shareholders' exposure to risks, while still encouraging superior performance.
6. The use of utility returns on supply-side investments as one consideration in establishing a shared-savings rate does not provide a basis to connect Bluefield and related cases with the risk/reward incentive mechanism for energy efficiency. Even if such a basis could be established, the Commission is not bound to the use of any single formula or combination of formulae in determining rates. We have considered several methods, relevant facts and presentations before ultimately reaching today's determinations.
7. Today's adopted schedule for earnings claims represents a reasonable balancing of various considerations, namely, the need to ensure that claims and payments are linked directly to EM&V results while providing ongoing incentives to the utilities throughout the program cycle and recognizing the resource limitations and competing priorities for staff time.
8. As circumstances warrant, the assigned ALJ should be permitted to modify the earnings recovery schedule set forth in Attachment 6, in consultation with Energy Division and the assigned Commissioner. For reasons discussed in today's decision, no interest should accrue on delayed payments of either earnings or penalties.
9. The procedures for review and approval of earnings claims set forth in Attachment 7 are reasonable and should be adopted.
10. As it deems appropriate, Commission staff should have the discretion to use any of the approaches discussed in this decision when reporting on estimated PEB for those programs that do not receive an impact evaluation.
11. The clarifications in cost-effectiveness calculations discussed in today's decision ensure consistent application of the SPM and our determinations in D.06-06-063, and should be effective immediately.
12. PG&E's proposal for performance adder incentive mechanisms should not be adopted.
13. It is reasonable to establish per-unit penalty rates that are higher than the per-unit rates proposed in this proceeding based on our consideration of per-unit penalty levels established for other preferred resources, the resulting balance of potential penalties with incentive rewards under the adopted incentive mechanism, and the full record developed on this issue.
14. Until further order by the Commission, shareholder earnings associated with energy efficiency activities should continue to be collected through electric distribution and gas transportation rates, using the cost allocation methods adopted for that purpose.
15. The rate changes required to recover positive earnings under the adopted incentive mechanism should be consolidated with the next scheduled change in the utility's electric distribution and gas transportation rates.
16. Any pay-back obligations that might arise in the final true-up claim should be booked against positive earnings in the next energy efficiency program cycle, and not be consolidated with other electric distribution or gas transportation rate changes for the next scheduled change.
17. The Commission should revisit today's adopted risk/reward incentive mechanism after gaining experience with its implementation.
18. The opening brief of Women Energy Matters (WEM) goes beyond the scope of Phase 1 and the Assigned Commissioner's Ruling dated March 26, 2007, which clearly defined the issues that were to be included in evidentiary hearings and addressed in the briefs.
19. In order to implement the regulatory framework for post-2005 energy efficiency as expeditiously as possible, this decision should be made effective today.
IT IS ORDERED that:
1. The energy efficiency risk/reward incentive mechanism described in this decision is adopted for Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE), San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas), collectively referred to as "the utilities." Today's adopted incentive mechanism applies to the energy efficiency programs funded for the 2006-2008 program cycle and for subsequent program cycles until further Commission notice.
2. The adopted risk/reward shareholder incentive mechanism is structured as follows:
a) To be eligible for earnings, SDG&E, PG&E and SCE shall meet the following minimum performance standard (MPS) for the energy efficiency portfolio as a whole:
(1) Achieve a minimum of 85% of the Commission-adopted savings goals, based on a simple average of the percentage of each individual gigawatt-hour (GWh), megawatt (MW) and, as applicable, million therm (MTherm) goal they achieve, and also
(2) Meet a minimum of 80% of the goal for each individual savings metric.
b) SoCalGas shall meet the MPS and be eligible for earnings if it achieves a minimum of 80% of the MTherm savings goal.
c) Once the utility meets the MPS, earnings shall be calculated as a percentage (sharing rate) of the "performance earnings basis" (PEB) metric defined in Decision (D.) 04-10-059, as follows:
(1) Portfolio net benefits calculated using the Total Resource Cost test of cost-effectiveness are weighted by two-thirds, and
(2) Portfolio net benefits calculated using the Program Administrator Cost test of cost-effectiveness are weighted by one-third.
d) Program savings and costs shall be counted in determining whether the MPS is met and in calculating the PEB, as follows:
(1) Savings from low-income energy efficiency (LIEE) programs shall count towards determining whether the utilities have met their MPS, but neither LIEE program costs nor savings shall be included in the calculation of the PEB under today's adopted incentive mechanism.
(2) With the exception of the Emerging Technologies Program and LIEE, all energy efficiency portfolio costs including associated evaluation, measurement and verification (EM&V) shall be included in the calculation of PEB.
(3) Fifty (50) percent of verified savings from pre-2006 Codes and Standards Advocacy Programs shall count towards the MPS for the 2006-2008 program cycle.
(4) Consideration of whether savings from pre-2006 Codes and Standards Advocacy Programs shall also count towards the goals for 2009 and beyond is deferred until further consideration of the baseline issues discussed in D.05-09-043 and responses to the Assigned Commissioner's June 1, 2007 ruling in this proceeding.
e) If the utility has met the MPS, a first tier sharing rate of 9% shall apply. If the utility has met 100% of the savings goals, a second tier sharing rate of 12% shall apply, up to the earnings cap adopted for each utility.
(1) If the MPS is met, each individual savings metric must be no less than 5% below the second tier threshold to be considered within that tier based on the three-metric average.
f) Penalties shall begin to accrue if portfolio performance for any single savings metric (GWh, MW or MTherm) falls to or below 65% of the savings goal for that metric. If this occurs, the larger of the following penalty provisions apply up to the penalty cap adopted for each utility:
(1) 5¢/kWh, 45¢/therm and $25/kW per unit penalties applied to each unit below the savings goal, or (if larger):
(2) Dollar-for-dollar payback of negative net benefits ("cost-effectiveness guarantee"), where negative net benefits are calculated based on the PEB formula adopted in D.04-10-059.
g) Total earnings and penalties are capped for the four utilities combined at $450 million over each three-year program cycle, beginning with the 2006-2008 program cycle. The $450 million combined cap is allocated to each utility as follows: PG&E--$180 million; SCE--$200 million; SDG&E-$50 million and SoCalGas--$20 million.
3. Utility requests for funding augmentation once the Commission has approved funding levels and the utility program portfolios for a particular program cycle are expected to be limited to extraordinary circumstances. The Commission shall address the treatment of savings and costs associated with mid-cycle funding augmentations on a generic basis in a subsequent decision in this proceeding, after reviewing and considering the proposals submitted in the 2009-2011 Portfolio Planning phase. As discussed in this decision, each request for LIEE program funding shall be carefully examined to ensure that the request is properly classified as LIEE.
4. Earnings (or penalties) under today's adopted incentive mechanism shall be paid as follows:
a) There shall be two "progress payment" interim earnings claims and one final true-up claim for each three-year program cycle. They shall be linked to Energy Division's Verification and Performance Basis Reports as described in this decision and in Attachment 6.
b) Interim claims shall be evaluated on a "Cumulative-to-Date" basis, which counts the verified achievements from program year(s) in determining whether the MPS is met in each subsequent interim claim.
c) Thirty (30) percent of the earnings calculated for each interim claim shall be "held back" until the final true-up claim, in order to minimize the risk of overpaying the utilities in their interim claims.
5. The procedures for submitting, reviewing and approving claims set forth in Attachment 7 are adopted. These procedures augment and substitute for Attachment 4 to Administrative Law Judges' Ruling Adopting Protocols for Process and Review of Post-2005 Evaluation, Measurement and Verification Activities, dated January 11, 2006.
6. D.05-01-055 shall be modified as follows:
a) The text on page 109 of D.05-01-055 (mimeo.) that begins with "The forum for this review may be..." shall be modified as follows (additions are indicated in italics.)
"The forum for review may be this rulemaking, a pending Commission proceeding (e.g., the AEAP) or a future Commission proceeding in which resource planning assumptions are being developed. It may involve conferences with stakeholders, workshops or other review procedures. The appropriate forum and procedures for this review will be established by Assigned Commissioner's ruling or by Commission decision."
b) The paragraph beginning with "If disputes concerning the study filings" on page 111 of D.05-01-055 (mimeo.) is deleted in its entirety, and replaced with the following new paragraph:
"It is premature to adopt an automatic placeholder for alternative dispute resolution in today's decision, and NRDC and other members of the Reaching New Heights Coalition recommend. Instead, we will consider this issue in the broader context of our EM&V procedures in a subsequent decision, after further consultation with Energy Division and after obtaining further input from interested parties."
7. No additional customer notice need be provided pursuant to General Rule 4.2 of General Order 96-B for the compliance advice letter filings required under the procedures adopted in Attachment 7.
8. The utilities shall submit the compliance advice letters as directed in Attachment 7, the timing of which shall be tied to the issuance dates of Energy Division's Verification and Performance Basis Reports. Should circumstances warrant, the assigned Administrative Law Judge may modify the schedule for Energy Division's reports set forth in Attachment 6, in consultation with Energy Division and the assigned Commissioner.
9. In performing its EM&V duties, Energy Division staff or its evaluation contractors may utilize any or all of the following approaches in order to report an estimated PEB for those programs that do not receive an impact evaluation, as staff deems appropriate:
a) Extrapolate findings from comparable programs to determine net resource benefits for programs that do not receive full impact evaluation; or
b) Accept reported savings values for programs that do not receive impact evaluation; or
c) Extrapolate savings findings from impact evaluations for comparable programs for some net resource benefit parameters and accept reported values for others; or
d) Apply a discount factor to savings or costs from programs that do not receive impact evaluation based upon historic impact evaluation results for comparable programs.
Energy Division shall describe the method(s) it uses to estimate PEB for those programs that do not receive an impact evaluation in its Final Performance Basis Report, which shall be issued to obtain stakeholder input pursuant to the Attachment 7 procedures. As discussed in this decision, Energy Division may need to prioritize resources for verifying measure installations and program costs over the program cycle, and may, as circumstances warrant, report the results of completed verification tasks in the Final Verification and Performance Basis Report. If such circumstances arise, Energy Division shall describe in each Verification Report the additional verification activities that will be performed and reported later in the program cycle.
10. The costs of shareholder incentives shall be included in calculations when (1) evaluating the cost-effectiveness of program plans submitted during the program planning cycle (on a projected basis), or (2) conducting a cost-effectiveness review of portfolio performance in hindsight. These costs shall not be included in the calculation of PEB.
11. The Energy Efficiency Policy Manual, Version 3 presented in Decision 05-04-51, Attachment 3, shall be modified as follows:
a) Add after the first sentence (ending in "eligibility for ratepayer funds") of paragraph IV.6 the following sentence:
"This prospective showing of cost-effectiveness shall include the costs for shareholder incentives that are projected to be paid for portfolio performance under the energy efficiency risk/reward incentive mechanism in effect at that time."
12. Energy Division shall post to the Commission's website The Energy Efficiency Policy Manual, Version 3 with the modification adopted today, as soon as practicable.
13. The clarifications on how to apply net-to-gross adjustments for free riders presented in today's decision and illustrated numerically in Attachment 9 are adopted. In consultation with the assigned Administrative Law Judge, and as soon as practicable, Energy Division shall post the clarification to the Standard Practice Manual described in Section 10.2 as a "2007 Standard Performance Manual Clarification" memo on the Commission's website, together with the latest (2001) version of the Standard Performance Manual.
14. The utilities shall take immediate steps to ensure that all future cost-effectiveness calculations apply the free-rider adjustment ("net-to-gross ratio") as directed by this decision. This shall include accomplishments reported for the 2006-2008 energy efficiency portfolios, effective immediately.
15. Energy Division shall confer with Energy and Environmental Economics (E3) and other technical expertise, as staff deems appropriate, to explore whether the naming of input values in the E3 calculator should be modified to better capture the Standard Practice Manual cost definitions and calculation methods, including the net-to-gross ratio adjustments clarified by today's decision. As discussed in this decision, Energy Division may directly manage the development of the E3 calculator in the future, at its discretion.
16. Until further notice by this Commission, all rate changes required to recover positive earnings under the adopted risk/reward shareholder incentive mechanism shall be consolidated with the next scheduled change in the utility's electric distribution or gas transportation rates. As discussed in Section 8.2.2, any pay-back obligations that might arise in the final true-up claim shall be booked against positive earnings in the next energy efficiency program cycle, and not be consolidated with other electric distribution or gas transportation rate changes for the next scheduled change.
a) Upon review and authorization of earnings for the interim or final earnings claim, SCE shall record the authorized earnings in the distribution sub-account of the Base Revenue Requirement Balancing Account. The year-end balance recorded in this account shall be recovered in SCE's annual Energy Resource Recovery Account forecast proceeding, where we consolidate authorized revenue requirement changes (including balancing account balances) for SCE into one rate change that is implemented on or soon after January 1st of each year.
b) PG&E shall include the electric revenue requirement and gas incentive amounts that are authorized for a particular interim or final earnings claim in the next scheduled Annual Electric True-up and Annual Gas True-up advice letter. These consolidated rate changes are implemented on or soon after January 1st of each year.
c) SDG&E and SoCalGas shall also collect authorized shareholder earnings through the advice letter process they use to consolidate rate changes that become effective on or soon after January 1st of each year. These are the December Consolidated Filing to Implement Electric Rates and December Consolidated Gas Rate Changes advice letter filings.
Energy Division shall prepare an evaluation report on today's adopted risk/reward incentive mechanism by February 1, 2011, so that the Commission may consider any recommended modifications to the mechanism in time for the 2012-2014 program cycle. In its report, Energy Division shall evaluate the advantages and disadvantages of alternative tier structures should the experience with a two-tiered structure indicate that discontinuity problems are significant, even with the hybrid approach we adopt today for the MPS and second tier trigger, and can be mitigated more effectively in other ways. Energy Division shall use 2009-2011 EM&V funds for this evaluation, and may hire evaluation contractors as it deems appropriate. Energy Division shall solicit stakeholder input in the scoping of the evaluation and in the review of the draft evaluation report(s).
17. For good cause, the Assigned Commissioner or Administrative Law Judge may modify the dates for utility submittals or Energy Division reports required by today's decision.
This order is effective today.
Dated September 20, 2007, at San Francisco, California.
MICHAEL R. PEEVEY
President
DIAN M. GRUENEICH
JOHN A. BOHN
RACHELLE B. CHONG
TIMOTHY ALAN SIMON
Commissioners
259 The comments of Pacific Energy Policy Center urging us to adopt policies related to the review and approval of utility applications for new plant construction are beyond the scope of Phase 1, as are the comments of the California Center for Sustainable Energy on policies regarding third party programs and the role of the program advisory groups. We encourage the participation of these and other interested organizations in our proceedings, but they should be mindful of the scope of each proceeding (or Phase of proceeding being addressed in the decision) so that their participation can be meaningful.
260 As discussed in today's decision, the utilities prefer to apply the NTG ratio to program costs, a view that is not shared by any other party.
261 Comments of PG&E on Proposed Decision, August 29, 2007, p. 6. See also Opening Commments of SDG&E/SoCalGas on Proposed Decision, August 29, 2007, pp. 2-5.
262 See Assigned Commissioner's Ruling and Scoping Memo and Notice of Phase 1 Workshops, May 24, 2006, p. 7. See also May 9, 2006 Prehearing Conference RT at p. 56.
263 The scope of Phase 1 does not include revisiting these protocol issues or how the Commission's savings goals should be established, which are issues raised by PG&E's and SDG&E/SoCalGas comments on the Proposed Decision.
264 See D.05-04-051, mimeo., pp. 48-53 and Administrative Law Judge's Ruling on EM&V Protocol Issues, September 2, 2005, Appendix 3. For the reasons discussed in D.05-04-051, the Commission did not require that the results of "persistence studies," which evaluate the extent to which near-term savings from a program persist over time, be used to true-up the PEB for a particular program cycle. Rather, the Commission stated that those results would be used on a perspective basis only, that is, to inform updates to ex ante savings projections for future program cycles. The Commission also indicated its intent to revisit this policy and revise it at a future date, as appropriate, if the evidence indicated that the results of ex post persistence studies were significantly different from the ex ante estimates. (Ibid, pp. 52-53.)
265 TURN Reply Comments on Proposed Decision, September 4, 2007, p. 2. See also DRA's Reply Comments on Proposed Decision, pp. 3-4.
266 Comments of PG&E on Proposed Decision, August 29, 2007, p. 7.
267 See Administrative Law Judge's Ruling Memorializing Electronic Rulings on Phase 1 Requests for Information and Changes to Submittal Dates, March 13, 2007, Attachment 2.
268 See PG&E's Response to Parties' Proposed Incentive Mechanism Penalty Rate Explanation, March 21, 2007; Reply of SDG&E and SoCalGas to Response to ALJ Electronic Ruling, March 21, 2007; Reply Comments of SCE to the TURN/DRA/NRDC Submittal on Proposed Incentive Mechanism Rate Explanation, March 21, 2007.
269 Assigned Commissioner's Ruling Soliciting Comment on the Need for Additional Factural Inquiry and Evidentiary Hearings in Phase 1, February 28, 2007.
270 Comments of the DRA on Proposed Interim Decision, August 29, 2007, pp. 8-9 and Appendix B.
271 See Comments of DRA on Proposed Decision, August 29, 2007, p. 3, footnote 11; Exh. 46, p. 14; DRA Opening Brief , June 18, 2007, p. 30; Reply Brief of PG&E, June 27, 2007, pp. 40-41.
272 Comments of DRA on Proposed Decision, August 29, 2007, pp. 3-4.
273 See, for example, Exh. 34B.
274 Bluefield Water Works and Improvement Co. v. West Virginia Public Service Commission, 262 U.S. 679, 692 (1923).
275 CE Council Comments on Proposed Interim Decision, August 29, 2007, p.4.
276 Bluefield, at 692.
