17. Assignment of Proceeding
Geoffrey F. Brown is the Assigned Commissioner and Douglas M. Long is the assigned ALJ in this proceeding.
1. In Phase 1 of this proceeding we adopted just and reasonable rates for SoCalGas and SDG&E for TY 2004.
2. In providing adequate service, each utility must be in compliance with laws, regulations, and public policies that govern public utility facilities and operations.
3. In carrying out its statutory obligation, the Commission assesses whether SoCalGas and SDG&E have justified the ratemaking proposals in their applications for post-Test Year 2004 and for earnings Sharing and other incentive mechanisms.
4. The Comparison Exhibit, Ex. 168, served on June 18, 2004, provided a jointly-prepared summary of the parties' litigation positions in Phase 2.
5. On July 21, 2004 SoCalGas and SDG&E filed a motion to adopt a proposed partial settlement jointly with Aglet, NRDC, ORA, SCGC, TURN to settle certain issues in Phase 2. The motion was filed late, as Rule 51.2 requires this filing within 30 days after the last day of hearing. The parties to the proposed settlement also filed a motion for leave to late-file the motion to adopt the settlement. Finally, they also filed a Settlement Agreement Regarding Phase 2 Base Margin Issues.
6. The Base Margin Settlement is not a complete settlement under Rule 51(c), because it fails to reach a "mutually acceptable outcome to the proceedings" which means all litigated issues. It is however a partial settlement. The Commission is not bound to accept the settlement, if it finds the settlement is not "reasonable in light of the whole record, consistent with law, and in the public interest," when compared to a careful consideration of the litigated positions of the parties.
7. The Base Margin Settlement contains an automatic reopening of negotiations if the proposed settlements for SoCalGas and SDG&E in Phase 1 are not adopted. This does not expedite the completion of this proceeding and would contribute to a significant delay to a final decision in Phase 2.
8. PBR is not limited to the program features proposed by SoCalGas and SDG&E; it may also mean a different ratemaking program with a different mix of features as proposed by other parties.
9. The Commission has a clear history of allowing for some form of attrition: adjusting rates in a simplified fashion in between major reviews of rates in a GRC to allow for the detrimental effects of inflation that would otherwise reduce the utility's opportunity to earn a reasonable rate of return.
10. The adopted revenue requirements in Phase 1 for the TY 2004 should be the beginning base for setting rates in 2005 and beyond.
11. For SDG&E's electric operations, indexing should start with the Phase 1 base margin and then exclude generation, transmission, SONGS, CEMA, CARE, DSM and PBOPs costs.
12. For both SoCalGas and SDG&E's gas operations, indexing should start with the Phase 1 Base Margin and exclude CEMA, HSCRA, Self-Generation Program Memo Account (SGPMA), CARE, DAP, DSM, RD&D, Pension, Commission-imposed and PBOPs costs.
13. The otherwise uncontested adjustments or exclusions to the Base Margin are reasonable consistent with previously adopted attrition adjustments for SoCalGas and SDG&E.
14. A MPC method previously adopted in D.97-07-054 converts the revenue requirements for the whole company to a dollar-amount per customer: MPCt = MPCt-1 (1 + Inflationt - X-Factort), where "t-1" is the previous year; the "X-Factor" is the productivity offset factor for year-t; and
"Z-Factors" are defined as events unanticipated when the base rates were adopted but recoverable from customers. Total Base Margint = (MPCt * Customer Forecastt) ± any Z-factor Adjustments.
15. A revenue adjustment method would annually adjust the Base Margin by some factor without a separate direct consideration of customer growth. Any change in customers would be subsumed in the total revenue change so that revenues could rise (due to the index employed) even if there was a quantifiable loss of customers.
16. The most important issue for the indexing method is to correctly identify the most appropriate index to reasonably adjust the post-test year revenue requirements.
17. It is reasonable to base the final weighting on the Phase 1 decision's adopted labor, non-labor and capital expenditures. This will escalate the cost of the three components at an appropriate rate.
18. SDG&E has a separate series of indices for SONGS costs separate from electric distribution.
19. SoCalGas and SDG&E showed that these indices are constructed using costs that are appropriate to consider when adjusting rates for gas and electric utility operations.
20. The index method must be relevant and appropriate; the components in the CPI include a number of elements that are not inputs into the costs of service for SoCalGas and SDG&E. Food and housing costs are just two components of the CPI that are not typical utility costs, but they compose 48% of the CPI. The CPI does not include costs that we expect the utilities to consume as part of providing service.
21. The Commission has previously adopted versions of the Indices proposed by SoCalGas and SDG&E. There is no evidence in this proceeding showing that the actual historical adjustments implemented as a result of these Indices were either excessive or inadequate.
22. It is irrelevant that ORA and PG&E proposed a settlement in A.02-11-017 that included the use of a CPI adjustment.
23. The Base Margin Settlement would unreasonably introduce a limitation not otherwise in the record to impose a floor and ceiling to the index by setting maximum and minimum adjustments that change annually, that differ between SoCalGas and SDG&E. The SoCalGas gas department and the SDG&E gas department are treated differently.
24. The settlement is silent on why the limits were added, how they were derived, why they change annually and how the change was derived, why they differ between companies, and why the gas departments are treated differently. The limits on the adjustment are not reasonable or in the best interests of the ratepayers. The settlement limits on post-test year ratemaking offer no tangible benefit to ratepayers and obscure SoCalGas and SDG&E's obligations.
25. The Commission must adopt fair and reasonable rates and that may mean employing methods not readily understood by a typical consumer. Nevertheless, consumers can understand that the specific Indices are appropriate and relevant inflation indicators for gas and electric utilities.
26. SoCalGas and SDG&E must ensure that all parties have access to all of the underlying information necessary to review and verify the Indices. Adopting this approach means the necessary data will be just as accessible as the CPI data.
27. If the base year is not adjusted to the actual indices' values before calculating the next period's rates, the ratepayers and the utilities would both be subject to a compounding of any forecast error for the base year. Fairness dictates that the actual inflation rate should be applied to recalculate the correct 2005 Base Margin before forecasting 2006 Base Margin. Over time we drive retail rates away from the reality of SoCalGas and SDG&E's actual costs unless we correct the index to actual values before forecasting the next year's base margin.
28. If costs within the industry are volatile, but the CPI is less variable, the CPI is not accurately reflecting the changes in costs that matter to utility service but those costs are correctly measured by the industry-specific indices.
29. Long term similarity in CPI and industry indices does not offset the short-term impact if next year the economy generally is flat but the utility's costs are dramatically rising (or falling).
30. The CPI is not the most appropriate indicator of inflation for SoCalGas and SDG&E when compared to the Indices. The record does not show that the Gas and Electric industries are constructed incorrectly. To the extent possible, indices similar to those used in Phase 1 to calculate a TY 2004 revenue requirement should be used for post-test year escalation of the same costs.
31. Based on the litigated record, there are several significant flaws in the Base Margin settlement: the imposition of inconsistent floors and ceilings, the use of an inappropriate index, the CPI, and the failure to readjust the base, MPCt-1 when setting MPCt.
32. As set forth in the findings above, the Indices are the more reasonable indicators and it is reasonable to adjust the calculation base (but not reset the base margin collected in rates) to accurately reflect inflation in the prior year.
33. The parties propose minimum floors and maximum ceilings to the base margin adjustment, and while we could reject them as a part of their use of the CPI, we will also reject them because the use of maximums and minimums displace the use of a productivity factor and a stretch factor. A productivity factor and a stretch factor are reasonable to set rates with appropriate incentives to improve performance and are consistent with the adoption of an earnings sharing mechanism.
34. An X-factor reduction to the post-test year rate adjustment has been included in the past ratemaking for SoCalGas and SDG&E as an incentive for management to improve corporate performance over time. SoCalGas and SDG&E propose productivity factors of 1.16% for gas and 0.47% for electric operations for this proceeding based on a national trend found in studies prepared by a consultant economist.
35. An additional "stretch" factor in prior ratesetting proceedings has provided a boost to the incentive by pushing SoCalGas and SDG&E to outperform the industry's X-factor by some increment.
36. The Total Factor Productivity index for the gas and electric distribution companies studied, and the 1992-2002 average annual growth rates, are 1.16% for gas and 0.47% for electric distribution operations. ORA replicated the survey results. There is no reason to limit the inclusion of an X-factor to the MPC; the concept of an incentive to spur improved performance is equally applicable to a revenue adjustment, a rate adjustment, or the MPC.
37. No party opposed the econometric derivation of the 1.16% and 0.47% gas and electric X-factors.
38. The studies were not based on samples; the data was the entire population of available data for large gas and electric utilities, excluding only the smallest companies. Nor was there any consideration or differentiation of companies that have any incentive ratemaking that might affect the data. They are the best available data as a base for a productivity factor. The X-factor is a positive step towards ensuring efficient operations.
39. From 1998 through 2002 SoCalGas had stretch factors of 0.6% increasing to 1.0% in 2002 and 2003 and SDG&E had stretch factors of 0.55% adopted in
D.99-05-030.
40. Merger savings are avoided costs captured in the development of the test year and are not relevant to the improvement of efficiency of the ongoing operations of the companies.
41. Inherent in the use of any index is the collective effect of the differences in the population of the index and the targets, SoCalGas and SDG&E. A stretch factor removes some element of the worse-performers' impact on the index; otherwise we target average performance rather than best performance.
42. If the productivity study had removed the worse performers, or weighted the better performers, or could more specifically identify the companies most like SoCalGas and SDG&E, then the study results alone could be a reasonable target. It was clear on the record that the studies did not exclude the worst or find the best matches; they relied on the largest population with sufficient data.
43. The applicants' proposal with a study average basis and no stretch factor ignores the actual performance of SoCalGas and SDG&E.
44. TURN proposes stretch factors of 0.5% to 1.0% per year, which are in the range of past stretch factors, but TURN provided no analytical support for the factor to use now. An academic measurement of productivity ignores the efficiency of a specific entity instead of assuming efficient operation of the entity. SoCalGas and SDG&E ask for X-factors of 1.16% for gas and 0.47%. The effect of a stretch factor would change the index formula by including a factor to increase the X-factor (or as a further offset to the inflation factor) to MPCt = MPCt-1
(1 + Inflationt - X-Factort - Stretch).
45. It is clear on the record that without a stretch factor the proposed X-factor includes the offsetting effects of the worst performers in the sample. TURN's 0.5% low-end recommendation would double the impact of the electric X-factor of 0.47, but 0.25%, which is about half the size of the 0.47% electric X-factor, would be consistent with using TURN's 0.5% stretch factor for gas because it is approximately half the size of the gas X-factor of 1.16%.
46. SoCalGas and SDG&E propose a symmetrical sharing mechanism whereby the companies and the customers would share either the excess earnings or losses on an annual basis. This is a change to the mechanism last adopted for SoCalGas in D.97-07-054 and SDG&E requests the identical mechanism.
47. Sharing of excess earnings or recouping shortfalls is a significant departure from the cost-of-service ratemaking convention of granting only an opportunity to earn a reasonable return. SoCalGas and SDG&E have been authorized such a departure in the past for excess earnings. There was no ratepayer sharing of a shortfall.
48. No party challenges the concept of a sharing mechanism; ORA and TURN proposed different mechanisms. ORA proposes the retention of an expanded asymmetrical system. TURN proposes a different sharing rate and to use the last adopted mechanism for SDG&E for both companies.
49. An asymmetrical mechanism can only be reasonable if there is a comparable asymmetry in the degree of control or influence among the parties.
50. The asymmetrical sharing adopted by D.97-07-054 only shared earnings that were 25 basis points above the authorized rate of return. This approach created an incentive for the utilities to avoid expenses if the result would be to drive earnings below authorized levels.
51. SoCalGas showed that in 1998 it absorbed a shortfall $12.2 million but between 1999 and 2002 "shared" excess earnings with ratepayers and returned to ratepayers $54.4 million.
52. Sharing was requested by SoCalGas and SDG&E only as a part of the adoption of a proposed PBR package.
53. The proposed Base Margin Settlement unreasonably allows SoCalGas and SDG&E an option to suspend the mechanism if it earns 175 basis points below the authorized return but ratepayers do not have a similar option at 175 points above authorized. It is not fair to ratepayers to have such an imbalance.
54. Because of the nature of the settlement it is not known why the number of bands was shortened or why the one-sided escape clause was added.
55. Sharing losses would relieve SoCalGas of such risk as it absorbed in 1998 with a $12.2 million loss. For SDG&E the impact is greater: it had losses of $262,000 in 2000, $25,392,000 in 2001, and $51,753,000 in 2002.
56. One-way balancing accounts are strictly limited by circumstances and by the expectation that all of the revenues included in rates will not be spent for the intended purpose. Sharing was treated as a one-way mechanism with ratepayers having only the up-side opportunity to share in savings.
57. SoCalGas and SDG&E have shown that sharing may benefit ratepayers or shareholders, and that it provides a positive incentive for the company to manage its costs efficiently.
58. It is necessary to use the adopted revenue requirements to calculate the Base Margin from Phase 1 for the earnings sharing start-point with a further adjustment of excluding the major balancing accounts adopted in Phase 1.
59. Enlarging the inner band with zero-sharing will ensure that the mechanism is only a safety net for significant over or underperformance. If the SDG&E below-authorized losses in 2000 through 2002 had been subject to sharing, they would have been 1 point below with no sharing, 131 points and 253 basis points below the authorized returns, respectively. SDG&E would have only absorbed 65% and 85% of the losses and ratepayers would have paid $8.887 million in 2001 and $7.763 million in 2002.
60. Symmetrical sharing will allow the companies to recover necessary costs they might otherwise try to avoid.
61. The Phase 1 revenue requirement was made subject to refund in
D.03-12-057 because the TY 2004 revenue requirement was adopted after the start of the test year. SoCalGas and SDG&E originally made the request in their rate applications that Sharing would apply to 2004. In the proposed Settlement parties agreed that, subject to its adoption, there would be no sharing for 2004.
62. It would be a poor policy decision to apply Sharing to 2004 because of the uncertainty that was inherent in a Phase 1 decision by adopting a final revenue requirement significantly after the start of the test year. Sharing in 2004 may not exactly offset the actual differences between 2004 expenditures and the adopted revenue requirement; nor would it be reasonable to share a chance gain or loss by SoCalGas and SDG&E when they were not in a position to exercise management discretion that would affect whether 2004 earnings were above or below the authorized rate of return.
63. In this case the final decision on 2004 revenue requirements was adopted extremely late in the year. The practical fact is that SoCalGas and SDG&E could not react and manage to a final revenue requirement.
64. The MICAM is a process to adjust rates in a predetermined fashion if or when certain conditions are met. The mechanism does not reflect the actual cost of capital for SoCalGas and SDG&E.
65. In a traditional ratesetting environment, the cost of capital would be determined by the actual reasonable costs of existing long-term debt and preferred stock, the forecast cost of new securities expected to be issued in the forecast period, and a reasonable return on the forecast equity (common stock and retained earnings).
66. Regardless of how current capital market prices vary, the debt and preferred cost components change in the traditional mechanism only because of new issues or retirements. The traditional cost of capital mechanism recalibrates annually to reflect actual reasonable costs plus any forecast changes, and the Commission authorizes a reasonable return on equity. It protects both ratepayers and utilities from long-term harm if actual costs are out of line with the forecast by annually adjusting the rate of return.
67. The MICAM is a mechanism that, subject to triggering events, adjusts the cost of capital in post-test year rates and it is essentially the same mechanism as last adopted for SDG&E. None of the trigger features are directly attributable to specific changes in the operating conditions, financial condition or operating risks of SoCalGas and SDG&E.
68. The cost of outstanding debt issued by SoCalGas and SDG&E does not change regardless of how the market rates change for new debt.
69. The MICAM relies on the published Moody's Aa Utility Bond rates that may not reflect the risks actually experienced by SoCalGas and SDG&E. SoCalGas had previously used 30-year U.S. Treasury bonds in its MICAM that were traditionally viewed as a long-term risk-free benchmark. The Treasury no longer issues 30-year bonds but does issue 10-year treasury notes, which are viewed as the financial market standard benchmark for risk-free investments.
70. There is no valid reason to link the return of SoCalGas and SDG&E to the investor perceptions of risks indicated by the Aa bonds.
71. The adoption of post-test year rate adjustments should not become mechanically arbitrary and unrelated to the operational risks and service obligations faced by SoCalGas and SDG&E.
72. It is reasonable to reject the proposed MICAM for SoCalGas and SDG&E and require both companies to file annual cost of capital applications because the MICAM fails to correctly and fairly adjust the cost of capital for SoCalGas and SDG&E.
73. In post-test year ratemaking the Commission has recognized the need to protect both the utility and the customers and allow a way to adjust for unexpected and uncontrollable events. SoCalGas and SDG&E have a previously adopted Z-factor mechanism.
74. There are nine identified criteria for a Z-factor's occurrence: the event must be exogenous to the utility; the event must occur after implementation of rates; the costs are beyond the control of the utility management; the costs are a normal part of doing business; the costs must have a disproportionate impact on the utility; the costs and event are not reflected in the rate update mechanism; the costs must have a major impact on overall costs; the cost impact must be measurable; the utility must incur the cost reasonably. No party opposed the continued use of a Z-factor.
75. The Commission has previously adopted a $5 million "deductible" for all events before applying a Z-factor. SoCalGas and SDG&E are as randomly likely to have government mandates change in their favor, as they are to incur unexpected increases. We should apply the deductible to all Z-factors.
76. The sole burden of proof is on SoCalGas and SDG&E to show that they competently responded to the Z-factor event in a reasonable and efficient manner before they can recover any costs in a Z-factor Memorandum Account. There is no reasonable presumption of recovery of an identified event.
77. The decision in Phase 1 required SoCalGas and SDG&E to file a Notice of Intent for an application with a TY 2008. Nothing in Phase 2 has assuaged the concerns that the underlying base margin in Phase 1 for TY 2004 is not sufficiently robust to be an appropriate base for five years' of rates (2004 through 2008). Nothing in the post-test year ratemaking process can improve on the 2004 foundation to make it a reasonable component of rates for five years.
78. Decision 04-01-007 extended the performance indicators for 2004 but deferred consideration of incentives, rewards and penalties to this proceeding.
79. The only reason to adopt the incentives would be to achieve better service over time than would occur without the incentives.
80. The capital expenditures for cable maintenance and replacement, and other reliability-related expenditures adopted in Phase 1, have a direct bearing on identifying the appropriate Electric Reliability Incentive targets. No party proposes to separate the underground cable performance from overhead system performance.
81. The parties propose an array of SAIDI, SAFI and MAIFI goals and Aglet opposes the adoption of any incentive mechanism.
82. A deadband is a range around the target where no incentive penalty or reward is assessed. ORA's proposed deadband narrows the effective range of penalties or rewards because it did not widen the liveband. One benefit of a deadband is that minor random variances in performance do not trigger an undeserved penalty or reward. ORA's deadbands are too large; there is no evidence that supports the proposed range as likely to encompass only the random influences that affect the final result.
83. A liveband puts an outer limit on both a penalty or a reward in the event of extraordinary results because SDG&E has little direct control over specific outages.
84. The purpose of an incentive is to ensure proper attention, including expenditures on maintenance and capital improvements, is paid to electric reliability.
85. SDG&E proposes to use the 10 most recent years' annual average of 71 minutes, rounded from 71.19. The problem with a 10-year average, especially when there have been incentives in place, is that any progress achieved over that time is diluted by earlier years' results. The only justification for providing incentives is to improve service.
86. ORA proposes the most recent five-year average and a "rolling" average adjusted each year, but the next rate case for both SoCalGas and SDG&E will have a TY 2007. It is reasonable to use the most current five-year average as a part of the correct base for setting the targets.
87. An incentive mechanism, based only on a penalty, is not an incentive. Based on a "value of service" measurement, commercial customers face significant financial hardships from any outage and therefore place a high value on avoiding outages. A reward/penalty cannot compensate/penalize SDG&E for the full cost expended or avoided for achieving the goals. The payments are rewards or penalties for a level of special performance, not the sole reimbursement for improving service reliability. The Commission can pursue other sanctions for any failure by SDG&E to meet its obligation to serve customers safely and reliably.
88. ORA's analysis suggests that commercial and industrial customers receive 97% of the benefit of a reduction in service interruptions, but only 46% of the costs. The Commission can consider a reallocation of the costs in the appropriate rate design proceeding rather than reduce the penalty or eliminate the reward. If we eliminate the reward then there is no cost of a reward to allocate to any customer class.
89. The adopted Base Margin in Phase 1 would allow SDG&E to maintain current levels of reliability.
90. The 10-year status quo proposed is not an appropriate target for reliability incentives.
91. ORA's proposed five-year average, without the burden of annual adjustments, is the most reasonable base to set the Electric Reliability Incentives, but the use of averages does not sufficiently drive SDG&E to improve performance. Thus a small stretch factor, similar to the stretch factor in the base margin escalation process, would be beneficial.
92. SDG&E's control over reliability is not perfect and is not total; deadbands are needed to protect against unwarranted rewards or penalties.
93. A further ratepayer protection could be to lengthen the measurement period and any reward/penalty would need to be increased too. Reliability improvement is a long-term exercise, dependent upon consistent maintenance and timely capital expenditures. Annual measurement artificially distorts the long-term commitment necessary for reliability improvements.
94. The parties must consider the effects of adopting a multi-year evaluation in the next performance incentive proceeding.
95. SoCalGas and SDG&E both have a safety incentive mechanism in-place, and no party objects to some form of incentive continuing into the test year and post-test years. All parties agree on the use of reportable or recordable events as defined by the California OSHA. Applicants propose different employee safety penalty/reward performance indicators.
96. Under SoCalGas or SDG&E's proposals, to receive a reward, they must exceed the average performance of the two best years ever, and to receive a penalty their performance would have to decline below the five-year average from 1999 through 2003. ORA's proposal sub-divides the mechanism into four broad categories that face different degrees and types of risks. ORA's proposal would eliminate any reward possibility, creating a penalty-only environment.
97. ORA's penalty structure would have disparate impacts depending on which category of worker is injured.
98. SoCalGas has earned a reward annually but did not consistently improve safety.
99. We do not know whether the same injury affects service reliability or the safety of other workers differently depending on the circumstances of the injury. SoCalGas and SDG&E and CCUE use a moral argument, that there should be no differentiation.
100. SDG&E's safety record between 1988 and 1993, shows that the OSHA rate rose from 5.07 to almost 11 in 1991 and was above 9 in 1993 before the first incentive was adopted in 1994. Over the next four years (1994-98), SDG&E's OSHA rate fell slightly from its 1993 level, to 8.65 in 1998, but after the incentives were matched to OSHA recordable events SDG&E's rates fell significantly and the rate has improved every year since 1998.
101. CCUE's proposed benchmark of SDG&E's 2003 OSHA recordable rate of 5.21 exceeds the projected trend of recorded rates. Some events are unavoidable and not attributable to the action or inaction of SDG&E. A small deadband eliminates unfair rewards or penalties due to random chance, especially in a short one-year measurement cycle.
102. A balance of reward and penalty around a fair target is a reasonable tool to enhance service and provide a safer work environment.
103. There is no evidence that supports the width of the applicant's deadband proposals and large deadbands conflict with CCUE's valid concern about backsliding. However, a narrow deadband is appropriate because every accident is not a failure of the incentive mechanism because chance still plays a role on the outcome.
104. The financial incentives proposed by SoCalGas and SDG&E are too high, especially given recent consistent annual rewards to both companies. CCUE's reward/penalty of $8,000 per 0.1 change in the rates for both companies is not justified because there is no basis to suggest it would be effective. Halving the applicants' rates to $12,500 and $25,000 per 0.1 change in the rates, is a reasonable compromise between the Applicants proposals and CCUE's proposal. This approach is reasonable because it should still provide an adequate incentive to SoCalGas and SDG&E to achieve the targets.
105. SoCalGas and SDG&E should track the reportable incidents in the four categories proposed by ORA: meter reading, customer field service, distribution, transmission and storage, and office. It is not necessary to review this information before the next rate proceeding.
106. Standardizing the service quality indicators and reward mechanisms for the two companies is consistent with many other facets of these applications where past differences are now aligned. Since the adoption of service quality indicators in 1997, SoCalGas has met or exceeded benchmarks for most
incentive-related indicators in each year, though performance did fall below the benchmarks (but within the deadband) for a few indicators in 1997 and 1998. SoCalGas did not incur any penalties.
107. In the period 1999 through 2002, SDG&E earned rewards of $2.960 million and has paid out less than $28,000 to customers for missed appointments.
108. The intervenors argue for a monitor only or penalty only mechanism because they believe there is no definitive indication that rewards have provided any better incentive to maintain appropriate service quality as compared to reasonable Base Margin funding, monitoring requirements, or penalty-only indicators.
109. While the parties disagree whether SDG&E has shown that ratepayer funded financial rewards are warranted to ensure that SDG&E provides safe, reliable and adequate service to its customers, the existing system of incentives was successful in focusing management attention on service quality through monitoring the indicators, avoiding penalties, and earning rewards.
110. Monitoring alone will not provide an incentive for improvement or deter a decline in performance by SoCalGas and SDG&E.
111. SoCalGas achieved a 5.4% improvement in on-time arrivals without a service guarantee while SDG&E made relatively few payments under its guarantee program. Service guarantees micromanage one narrow facet of performance and are a disincentive to offering more appointments. A service guarantee for SoCalGas and SDG&E is not a reasonable or necessary mechanism.
112. The generic service quality measures, Phone/Office Contact Satisfaction, Field Visit Satisfaction, Field Service Orders Appointments Provided/Percent Made, and Call Center Responsiveness, ought to be more closely aligned considering the companies have essentially one management structure. They are not operational incentives, such as safety-related measures, that reflect the unique risks for the two companies.
113. There is no clear reason to accept poorer performance for a benchmark going forward simply because of poorer past performance. The Commission already adopts just and reasonable rates that are sufficient to fund safe and reliable service; therefore, any reward or penalty is solely an incentive to improve (or not backslide). There is no convincing argument that the rewards and penalties need be of different sizes for SoCalGas and SDG&E.
114. There is no reason to excuse either SoCalGas or SDG&E from the full set of measure-only service indications except for the unique electric measure; therefore it is reasonable to adopt them for both companies.
115. In the next proceeding applicants and interested parties may draw any appropriate conclusions based on the data. Absent a good reason at that time to continue the tracking, the Commission should consider dropping the reporting requirements as unnecessarily burdensome.
116. The year is so advanced that enforcing the adopted incentives for 2004 would be unfair to applicants and ratepayers. Like the sharing mechanism, the incentives adopted herein should begin in 2005.
117. In D.04-07-022 the Commission adopted a flexible outage schedule ratemaking mechanism for SONGS 2 & 3 and a per-outage O&M estimate. A part of that process is to forecast outage O&M costs in annual post-test year filings based upon the adopted outage cost estimate and a forecast of the number of outages expected to occur in the next year. Those filings must include a proposal for refunding to ratepayers the costs of any outage that is forecast and included in rates but does not occur in that year. It is reasonable to adopt that requirement here.
1. The Commission's legal obligation to the residents of California is to ensure that SoCalGas and SDG&E both provide adequate service at just and reasonable rates.
2. For all uncontested issues not expressly addressed in this decision, SoCalGas and SDG&E made a prima facie showing that the requests were just and reasonable.
3. Only SoCalGas and SDG&E have an obligation to meet the burden of proof that their rate requests are reasonable.
4. We grant the Late-Filed Motion to adopt a proposed partial settlement, but we should not adopt the Base Margin Settlement in this decision.
5. The Base Margin Settlement is not a complete settlement under Rule 51(c), because it fails to reach a mutually acceptable outcome to the proceedings which means resolving all litigated issues.
6. This decision may lawfully find only some of the individual features included in the requests by SoCalGas and SDG&E to be reasonable, and that some of the alternative features proposed by the intervenors, are reasonable in order to adopt a complete ratemaking package. A hybrid outcome can be reasonable in light of the whole record rather than a single parties' specific package of ratemaking program features.
7. It is reasonable to adjust rates in a systematic fashion between GRCs.
8. The Indices as proposed by SoCalGas and SDG&E rather than the CPI as proposed by ORA, TURN and Aglet are reasonable because they are based on utility costs and not a general index of consumer spending.
9. The inclusion of an appropriate stretch factor is necessary and reasonable because it will improve efficiency.
10. Adoption of a sharing mechanism is not retroactive ratemaking.
11. A sharing mechanism should be adopted for post-test year ratemaking because it will provide an incentive to control costs and prevent undue hardship.
12. Sharing is not reasonable for 2004 because the applicants lack notice of the mechanism.
13. SoCalGas and SDG&E both have the burden of proof to justify any future recovery of a Z-factor exogenous event; there is no presumption of recoverability.
14. The three Electric Incentives, SAIDI, SAIFI, and MAIFI for SDG&E should be adopted as modified because they will provide an incentive to improve reliability.
15. A Service Guarantee mechanism should not be adopted for either SoCalGas or SDG&E because there are no demonstrable benefits to ratepayers.
16. The four Customer Service incentives for both SoCalGas and SDG&E should be adopted because they provide an incentive to improve service.
17. The monitor-only service quality indicators should be adopted because they will provide useful information to evaluate service quality.
