41. Assignment of Proceeding

Michael R. Peevey is the assigned Commissioner and David K. Fukutome is the assigned ALJ in this proceeding.

1. In D.08-07-045, the Commission ordered PG&E to propose various default CPP rates. PG&E has complied with that order by filing its PDP proposal that is the subject of this proceeding.

2. It would be inappropriate to extend PDP to customers who do not take bundled service, who are typically unable to control or reduce their load in response to PDP events and may be unmetered, who are on net metering, who typically satisfy their own energy needs, or who are residential master meter customers with limited control over tenants' energy use and/or submeters that do not measure interval usage.

3. There is no opposition to PG&E's revised PDP rate levels.

4. In response to DRA's recommendation that residential PDP be offered in combination with the standard non-TOU Schedule E-1 residential tariff, PG&E's rebuttal testimony presented a residential PDP rate with TOU prices that are less steeply time-differentiated than those offered under the residential Schedule E-6 tariff.

5. With the changes contained in PG&E's rebuttal testimony, no party opposes PG&E's TOU rate proposals in this case.

6. The need for, and structure of, more greatly time-differentiated TOU rates for medium C&I customers can be raised as issues in future cases.

7. All parties that have addressed the number of PDP events support an annual minimum of 9 and a maximum of 15 PDP calls.

8. There is general agreement that adoption of 9 minimum and 15 maximum PDP calls mitigates the problem associated with over- and under-collections.

9. There is no opposition to PG&E's proposal for enforcing the PDP call bounds by raising or lowering the temperature thresholds.

10. No party opposes PG&E's proposal to provide first year bill stabilization or protection.

11. No party disputes that under- and over-collections that are associated with bill stabilization should be allocated to all customers by class.

12. There are potential gaming problems with respect to excluding non-participants from the allocation of under- and over-collections due to the variation in the number of PDP events.

13. There are additional costs and difficulties in implementing BOMA's recommendation to exclude non-participants from the allocation of under- and over-collections due to the variation in the number of PDP events.

14. Volatility effects are largely mitigated by lowering the PDP rate, from that originally proposed by PG&E to what is now proposed by PG&E, and limiting the number of PDP events to between 9 and 15 per year.

15. Whether or not under- and over-collections due to the variation in the number of PDP events are substantial, imposing that risk on only those customers who actually sign up for PDP is likely to create one more disincentive for participation.

16. FEA's recommendation that, within each class, the reconciliation of under-and over-collections should occur by applying a credit or a surcharge as appropriate to on-peak and mid-peak demand charges and energy charges is contrary to the settlement approved by D.07-09-004.

17. With the exception of the EUF/CMTA proposal that would allow customers to change their capacity reservation before 12 months has passed on a one-time basis, there is agreement among the affected parties that PG&E's capacity reservation proposal should be adopted.

18. Reconciliation of under- and over-collections should occur by spreading adjustments on an even percentage basis among all generation demand and energy charges.

19. Under DRA's primary proposal for implementing PDP for small and medium C&I customers, customers would face two changes within one year: mandatory TOU beginning in 2011 and default PDP beginning in 2012, which would require two waves of messaging, the first one about TOU and a second one about PDP a year later. Customers would face evaluating their business process first for TOU and then a year later, a second time for PDP.

20. As PG&E's PDP rates were originally proposed, the 20% of small and medium C&I customers who are most impacted could experience a monthly bill increase of 25% to 42% relative to their previous flat rate during a hot year, based on PG&E's load research data.

21. Economic difficulties facing small businesses in California today include job losses, dropping sales, increasing costs and difficulties in obtaining small business loans.

22. Since this proceeding was submitted for decision, (1) public hearings convened by Senator Dean Florez focused on the price shock PG&E customers of PG&E have experienced with their recent power bills and (2) the Commission has ordered an independent audit of PG&E's SmartMeter installations in Bakersfield and the customer education and outreach PG&E is conducting about those installations

23. Delaying the PDP default date for small and medium C&I customers will provide additional time for customer outreach and education with respect to PDP effects and customers' options.

24. PG&E's alternating day and six-hour window options to mitigate bill volatility provide customers with an incentive to choose or stay on PDP rates, by offering an option to reduce their exposure to potential increases related to those rates.

25. DRA's "soft cap" proposal and the current BPP are mechanisms that spread the effect of monthly rate increases over a longer timeframe.

26. A-10 customers are the only ones that have a PDP default where 100% of peak time usage would be set at the $1.20/kWh charge.

27. The first year of bill stabilization/protection will protect customers who are on PDP rates by allowing them to experience the actual effects of such rates in situations where between 9 and 15 PDP events are called, without facing financial harm over that period, if the PDP is disadvantageous when compared to the otherwise applicable TOU rate.

28. In the current economic climate a small or medium commercial or industrial customer that experiences a high bill during a particularly hot month could have difficulty paying. In extreme circumstances a customer might be faced with a disconnection.

29. Through customer outreach and education, it is extremely important that, as their first year on PDP progresses, customers (especially defaulted customers) become well aware of the PDP program, the details as they affect their rates, their options to opt out or remain in the program and the requirements for switching rates in the future.

30. With respect to DRA's up-front lump sum credit proposal for notification information, by taking the energy usage credit up front, customers will only see the high PDP charges in the monthly bill amounts due, without the offsetting effect of the credits for the month. Artificially high monthly bills may be confusing to customers who are trying to determine whether to remain on PDP or to opt out of the program as they experience the effects of the program.

31. The potential benefit of additional customer contact information by implementing DRA's up-front lump sum credit proposal is outweighed by the downside of potential inaccurate perceptions of the effects of PDP.

32. With respect to DRA's multi-year amortization proposal, PG&E has provided evidence that it is unlikely that the 1% threshold will be triggered.

33. The Commission already has the latitude to impose multi-year amortizations when it feels it is necessary to do so, when looking at all rate changes that are happening concurrently, as well as considering what has happened in the near past and what may happen in the near future.

34. Under PG&E's proposal that certain customers should be subject to default PDP 12 months after their interval meter is installed, it appears that most affected customers would have to make a choice with respect to opting out of the PDP program while having only 10 or 11 full months of interval data.

35. Without 12 months of interval data, the effect of PDP rates and the need to change usage patterns may not be fully understood.

36. There is no convincing evidence to support the proposition that agricultural customers require an additional four months to make their decisions regarding PDP/TOU defaults and options.

37. There is no convincing evidence to support the proposition that farmers cannot make decisions regarding PDP/TOU defaults and options during planting, growing, and harvesting seasons.

38. Enhanced CSOL functionality will address AECA's concerns regarding the availability of information in one downloadable aggregated format for multiple meters.

39. Enhanced CSOL functionality will address CFBF's "shadow bill" proposal by allowing customers to calculate bills under varying scenarios.

40. The enhanced CSOL functionality that will allow customers to calculate bills under varying scenarios is very important and necessary for all customers, including agricultural customers, to evaluate the effects of PDP and make appropriate choices.

41. AECA has withdrawn its recommendations regarding an alternative dynamic pricing scheme and the development of programs that enable growers to virtually aggregate multiple meters.

42. In response to DRA and TURN concerns, PG&E presented an Alternative 1 residential PDP proposal that includes TOU rates that are less steeply time-differentiated than those offered under the Schedule E-6 tariff and extends the existing residential SmartRate tariff for one additional year for both existing and new enrollees, and then implements the revised residential PDP rate design for all residential dynamic pricing participants beginning in 2011.

43. DRA, TURN, and PG&E agree that the Alternative 1 residential PDP proposal should be adopted.

44. The imposition of PDP is significant and there is no good reason to require customers to remain on PDP for a full year because they either failed to make a decision or made the wrong decision.

45. One year on PDP rates is sufficient time for customers to make an informed decision regarding their desire to opt out of the PDP program.

46. While PG&E agrees in principle with EnerNOC's proposal that PG&E's PDP tariff should be modified to allow PG&E customers to opt out of PDP at any time if they opt out to enroll in another DR program, the required functionality in PG&E's PDP implementation processes will not be available until 2011 at the earliest.

47. The Commission addressed the general issue of dual participation in DR programs in D.09-08-027. That decision allows customers to participate concurrently in one program that provides an energy payment and one that provides a capacity payment and states that it is reasonable to consider Critical Peak Pricing to be an energy payment program.

48. PG&E's PDP proposal needs to be revised to address the double payment problem associated with dual participation in PDP and demand response programs.

49. With respect to Auto-DR for smaller customers, there is insufficient evidence to implement any such program at this time.

50. PG&E retained an independent external consultant, PwC, to perform an analysis of PG&E's cost estimates to assess the incremental nature of the requested costs in this proceeding.

51. By imputing DRA's adjustment whereby $32.4 million in PDP costs for customer education and outreach for non-residential customers would be taken from the approximate $42.9 million remaining in the AMI authorization for customer acquisition, the DRA proposal would leave only $10.4 million (24%) for AMI-related residential customer acquisition activities.

52. It has not been alleged or determined that customer acquisition costs previously authorized by PG&E's AMI decision for residential related activities should be significantly reduced.

53. PG&E has presented convincing evidence that the actual spending of customer acquisition costs authorized by its AMI decision has been delayed due to delays in the deployment of SmartMeters.

54. Assuming that it is true that customer acquisition costs authorized by PG&E's AMI decision were not eliminated but delayed, there is likely to be more money, not less, available in 2010 for small and medium C&I customer acquisition activities than the $2.49 million originally forecasted by PG&E.

55. PG&E's revised SmartMeter deployment forecast indicates that 1,662,000 meters will be deployed in 2010, as opposed to 1,037,000 meters indicated in the original meter deployment forecast, resulting in an approximate 60% increase in the number of meters that would be deployed in 2010.

56. PG&E's proposal for foundational customer outreach and education activities and the estimate of the associated incremental costs, which amounts to $5.90 million (excluding contingencies), are unopposed.

57. PG&E's proposal for large customer outreach and education activities and the estimate of the associated incremental costs, which amounts to $5.92 million (excluding contingencies), are unopposed.

58. PG&E's proposal for small and medium customer outreach and education activities and the estimate of the associated total costs, which amounts to $22.20 million (excluding contingencies), are unopposed.

59. Incremental costs for small and medium customer outreach and education, which are calculated by deducting the $3.98 million adjustment determined in Section 11.4 from the total costs of $22.20 million, amount to $18.22 million (excluding contingencies).

60. Outreach and education costs for the residential optional PDP rate program will be covered by customer acquisition cost recovery authorized in the AMI decision.

61. All costs associated with customer outreach and education/acquisition for the voluntary SmartRate program, either in its current form or after the date the underlying rate changes to PDP, were authorized in the AMI Decision through the period of meter deployment and therefore are not requested by PG&E in this proceeding.

62. It is not clear what aspects of customer outreach and education, if anything, would be improved by segregating small commercial customer's costs as recommended by DRA.

63. Since the beginning of 2009, PG&E has been providing DRA with the DPMA reports in the previously agreed-to format, which does not segregate small commercial costs.

64. With respect to DRA's proposed outreach advisory panel, PG&E's concern that pre-approval of outreach and educational materials might result in delay is valid.

65. Certain aspects of PG&E's planned efforts, such as customer workshops and partnering with industry and community groups, would duplicate what an outreach advisory panel might accomplish.

66. The Business & Community Outreach group can be a resource in raising PDP awareness and also ensuring the Commission policy is being implemented effectively.

67. Quarterly meetings will provide opportunities for parties to provide ongoing input into PG&E's outreach plans.

68. DRA recommends that the Commission order PG&E to retain a reputable, independent impact assessment firm to measure and evaluate PG&E's outreach efforts.

69. It is important that PG&E is able, in a transparent way, to demonstrate that it will evaluate its outreach and education efforts and, if necessary, that it will modify its efforts appropriately. PG&E has not provided sufficient details on how this would be done.

70. With respect to DRA's recommendation that the Commission order PG&E to retain a reputable, independent impact assessment firm to measure and evaluate PG&E's outreach efforts, hiring an independent evaluator will likely necessitate a formal evaluation, in which the evaluator would look at a snapshot of PG&E's efforts and then provide feedback based on that moment in time, rather than facilitating a process of providing ongoing feedback on, and proposed modifications of, PG&E's outreach and education activities.

71. None of the parties oppose the customer inquiry activities proposed by PG&E.

72. SmartRate conversion inquiries are new types of calls that were not anticipated when the Commission adopted the $2.7 million savings amount for customer contact associated with the implementation of SmartMeter.

73. PG&E's customer inquiry cost estimate for 2010 is premised on customer inquiries associated with a May 1, 2010 date for transitioning residential, as well as small and medium C&I, SmartRate customers to the applicable PDP tariff.

74. Based on the residential PDP rate design adopted by this decision, the existing residential SmartRate tariff will be extended by a year for both existing and new enrollees, and then the residential PDP for all residential dynamic pricing participants will begin in 2011.

75. It is not clear what incremental inquiry costs related to conversions might be incurred in 2010 with respect to small and medium C&I customers who are not subject to the one year delay.

76. No party has opposed event notification activities or the associated cost estimate of $1.173 million, as originally presented by PG&E.

77. With respect to PG&E's requests for an additional $1.170 million in incremental notification costs due to the effect of D.09-08-027, $0.106 million relates to contingencies; $0.407 million relates to 2010 PDP costs that were included in the detailed description of the estimated cost components, and specifically excluded from the total customer notification costs requested in this application; and $0.607 million relates to work that PG&E asserts continues to be needed to support customer notification when the voluntary CPP program is replaced with PDP the costs of which were not included in the detailed description of the estimated cost components, and were not specifically excluded from the total customer notification costs requested in this application.

78. The record on what the optimal cut-off time for PDP event cancellation should be is limited by the timing of TURN's modified proposal and the fact that PG&E did not provide evidence regarding how much time it needs.

79. While there are other means for notifying customers of PDP events, use of the AMI/HAN capabilities for this purpose can significantly enhance the notification process. There is additional value in having devices that have "plug and play" capability as well as the ability to provide notification information consistent with the parameters of PG&E's adopted PDP program.

80. There is sufficient time for market development of notification devices for small and medium customers in time for the 2012 PDP peak season.

81. With respect to CSOL, updating rate comparisons tools to include the PDP rates, as well as updating the rate comparison and load analysis tools to support the new rate structures, is necessary.

82. There is a need, especially as it relates to agricultural accounts, for CSOL to be able to group and analyze multiple accounts.

83. It is in the public interest to take the opportunity of this proceeding to implement certain CSOL and customer notification requirements that will provide benefits for residential customers who have SmartMeters and choose to not leave the existing Schedule E-1 tiered rate structure.

84. PG&E utilized its formalized PDM process to assess and develop the IT functionality needed to meet its business stakeholders' requirements. Through this PDM planning process, PG&E identified three areas of work that needed to be completed as part of Dynamic Pricing Phase 1: billing system changes, CSOL changes, and the CC&B version upgrade to Version 2.2.

85. No party opposes PG&E's proposed billing system modification activities or the associated cost estimates of $25,939,290 (excluding contingencies) in capital for 2009-2010 and $1,515,023 (excluding contingencies) in expense for 2008-2009.

86. Included in PG&E's proposed IT costs related to CSOL are re-platforming costs of $10.7 million that reflect a foundation re-platform estimated at $7.4 million and a Middleware re-platform to BEA estimated at $3.3 million.

87. Re-platforming should be done at some point and improvements can accrue from the change.

88. Certain CSOL functionality, such as the ability to navigate the PG&E website with a single login to access multiple meter data, can only be accommodated on the re-platformed system.

89. PG&E analysis indicates that it would be cost neutral, if not less expensive, to re-platform CSOL at the same time it upgraded the tools.

90. While DRA argues that PG&E's analysis of cost-neutrality may be flawed and overstated, DRA has not provided an independent analysis of how much more, or less, it would cost to implement the same functionality on the current system rather than on the re-platformed system.

91. CC&B Version 2.3 will be installed in order to support RTP.

92. CC&B Version 2.3 was released in December, 2009, and PG&E updated the record stating that it will upgrade CC&B directly for Version 1.5 to Version 2.3.

93. No party opposes PG&E's proposed incremental M&E activities or the associated cost estimate of $1.321 million (excluding contingencies) in expense for 2009-2010.

94. No party opposes PG&E's proposed project management activities or the associated cost estimates of $2.389 million (excluding contingencies) in capital for 2009-2010 and $2.397 million (excluding contingencies) in expense for 2008-2010.

95. PG&E requested PwC's assessment of the factors creating uncertainty in PG&E's cost estimates and the resulting cost contingencies and risk-based allowance are included in PG&E's PDP cost forecast.

96. In total, PG&E requests approximately $32.6 million for contingencies, or approximately 25.6%.

97. At this point, there is no way to determine what amount of contingencies will actually be expended, and for any amounts expended, what the related activities or materials are, whether the related activities or materials are necessary and optimal, and whether the associated costs are reasonable.

98. Beginning January 2011, PDP cost recovery will be through the 2011 GRC and subsequent GRC authorizations thereafter. Capital IT costs found reasonable in this case, including the approved CC&B Version 2.3 upgrade costs, will be included in the 2011 GRC rate base.

99. Contingencies are not added to GRC forecasted expenses to fund perceived risks and uncertainties.

100. The revenue requirements for this proceeding, as originally calculated by PG&E, will need to be recalculated to conform to the costs adopted by this decision.

101. No party has challenged PG&E's general methodology, results of operations model, or model assumptions for calculation of the revenue requirement.

102. In PG&E's last GRC Phase 2 proceeding, A.06-03-005, the uncontested Settlement Agreement on Marginal Cost and Revenue Allocation Settlement was adopted by the Commission in D.07-09-004. That settlement also addressed rate changes between GRCs.

103. PDP implementation cost recovery for 2011 and beyond will be determined in PG&E's 2011 and subsequent GRCs. Likewise, marginal cost, revenue allocation and rate design for 2011 and beyond will be determined in Phase 2 of PG&E's 2011 and subsequent GRCs.

104. With respect to PDP costs authorized by this decision, the effects of using different allocation factors or exempting certain classes from certain cost responsibilities are small.

105. Allocating 2010 distribution-related capital costs and related O&M costs by distribution level EPMC-related allocators, and applying that allocation to all distribution customers including DA customers, are consistent with (1) how distribution costs are generally allocated, and (2) the marginal cost and revenue allocation settlement agreement adopted in D.07-09-004, with respect to rate changes between GRCs.

106. Parties can recommend different revenue allocation methodologies in PG&E's 2011 GRC Phase 2 proceeding, when the allocation of all costs is considered. It is a more appropriate proceeding for considering new or different revenue allocation methodologies and for evaluating the need to exempt certain customer classes from specific cost responsibilities.

107. Other than the characterization of these incremental PDP costs as part of the distribution function and the methodology for allocating the revenue requirements to customer classes, there is no opposition to PG&E's cost recovery mechanism, as it relates to this decision.

108. PG&E's proposal to coordinate cost recovery where there is overlap between costs approved in earlier proceedings and the incremental costs in this proceeding is unopposed.

109. PG&E may incur additional incremental costs in complying with the reporting, presentation, evaluation and consultation requirements set forth herein that are beyond the scope of its application.

110. AECA proposes that PG&E provide analysis after 1,000 and 10,000 agricultural customers are converted to SmartMeters to ensure that the analysis of the effects of migration from non-TOU rates to TOU rates that was provided by PG&E is accurate enough to continue rate migration.

111. In fall 2010, PG&E expects to have 12 months of available interval load information for at least 10,000 agricultural customers, with data from the AMI system and proposes to develop an analysis of the projected bill impacts under TOU for this 10,000 customer sample of agricultural customers by November 2010.

112. PG&E is already under orders to assess the load impacts and financial benefits of its active and anticipated DR programs including D.08-04-050, D.09-03-026, D.08-07-045, D.08-02-009, and D.06-07-027. Also in D.09-03-026, Ordering Paragraph 10, the Commission directed PG&E to report annually the financial benefits of DR programs enabled by its AMI system, and, in D.08-04-050, PG&E was directed to assess the load impacts of each DR resource on an ex post and ex ante basis, annually.

113. A 2012 RDW could review 2010 and 2011 PDP performance and identify any PDP program deficiencies or problems and address them in a timely manner, if necessary.

114. DRA's Request for Official Notice of Documents, dated January 11, 2010, is consistent with the provisions of Rule 13.9 of the Commission's Rules of Practice and Procedure and Section 452 of the Evidence Code.

1. The PDP program should go forward, in furtherance of the Commission's long-term policy to provide dynamic pricing to all customers.

2. PDP rates should not be applicable to the following customer groups: DA, Community Choice Aggregation service, Transitional Bundled Commodity Cost, street light and traffic control, NEM, residential master-metered customers with or without tenant sub-meters, and standby (Schedule S). Partial standby customers will be eligible for PDP for the load PG&E serves on a regular basis.

3. The following customer groups, among others, should be eligible for PDP rates: Non-residential master-metered customers that qualify and elect to install sub-metering under rule 18.C.2 shall be subject to default PDP; nonresidential customers on a discount tariff rider option or stand-alone special tariff associated with an otherwise-applicable rate schedule, e.g., Schedules ED, E-31, will be eligible for default or to elect PDP based on their underlying rate; and nonresidential customers on a stand-alone special tariff, e.g., Schedules AG-ICE, E-37, will be eligible for default or to elect PDP, based on an applicable rate schedule.

4. PG&E's revised PDP rate levels are reasonable.

5. The TOU rates for PDP, as now proposed by PG&E, are reasonable.

6. An annual minimum of 9 and a maximum of 15 PDP calls, as well as PG&E's proposal for enforcing the PDP call bounds by raising or lowering the temperature thresholds, are reasonable.

7. PG&E's first year bill stabilization/protection proposal is reasonable.

8. To avoid unnecessary disconnections, when applying Electric Rule No. 11, D, 1 (Inability to Pay-Nonresidential), PG&E should endeavor to extend payment arrangements to customers that did not pay their full monthly bill but would be able to pay the bill if it were recalculated under the otherwise applicable rate.

9. With respect to under- and over-collections due to first year bill stabilization/protection and the variation in the number of PDP events, it is reasonable for non-participants to share in a portion of the risk and costs of the PDP program, since its purpose is to lower rates for all customers in the long term.

10. It is reasonable that under- and over-collections due to first year bill stabilization/protection and the variation in the number of PDP events should be allocated to all customers by class.

11. The EUF/CMTA proposed change to PG&E's capacity reservation proposal is not necessary, since most customers will have made their initial capacity reservation choice prior to the May 2010 implementation of PDP and would be able to change their capacity reservation prior to the 2011 summer season or any time after that.

12. PG&E's capacity reservation proposal, including the condition that the capacity reservation may not be changed for 12 months, is reasonable.

13. Defaulting small and medium C&I customers first to TOU rates and then one year later defaulting them to CPP rates may lead to customer confusion and frustration, resulting in reduced participation in the PDP program.

14. It is reasonable to defer the effective date for defaulting small and medium C&I customers to PDP from February 1, 2011 to November 1, 2011.

15. PG&E's alternating day and six-hour window options to mitigate bill volatility are preferable to DRA's "soft cap" proposal or PG&E's current BPP.

16. To provide bill volatility protection for PDP default A-10 customers, it is reasonable to set the PDP charge at $0.90 per kWh.

17. One year of bill stabilization/protection should be sufficient for all PDP customers to get the point that, when there are PDP events, any usage during the peak period will be significantly more expensive than before.

18. The proposal to extend bill stabilization/protection for two additional years for small commercial customers should not be adopted.

19. The proposal to provide an up-front lump sum credit for notification information for small and medium C&I customers should not be adopted.

20. The proposal that revenue shortfalls resulting from annual bill stabilization should be amortized over multiple years, for specific rate classes, if recovery in one year would cause rates to rise by more than 1%, should not be adopted.

21. Customers subject to the February 1, 2011 and November 1, 2011 default dates should have 12 months of interval data before being subject to those processes.

22. The CSOL feature that would aggregate multiple meter information should be available to the large agricultural customers before they are subject to being defaulted to PDP.

23. The CSOL feature that would allow customers to calculate bills under varying scenarios should be available to customers subject to the February 1, 2011 and November 1, 2011 effective dates for defaulting to PDP at least 45 days before their default dates.

24. The Alternative 1 residential PDP proposal is the most reasonable.

25. Customers should be allowed to opt out of the PDP program anytime during the first year that they are on PDP rates.

26. After the first year on PDP, it is reasonable that customers should be limited to switching rate schedules once a year, which is consistent with PG&E's current rules on such switching.

27. With respect to customers opting in or out during the peak season, PG&E should monitor the situation, and if it is determined that there is a significant amount of customer gaming with respect to opting in or out of PDP, PG&E should propose a solution in an appropriate future rate design proceeding.

28. PG&E customers should be allowed to opt out of PDP at any time, if they opt out to enroll in another DR program. PG&E should incorporate this revision to its proposal no later than May 1, 2011.

29. This decision is not the appropriate vehicle for modifying previous Commission determinations in D.09-08-027 with respect to dual participation or the consideration of CPP as an energy payment program.

30. PG&E's PDP tariff should be modified to allow PG&E customers to participate in both the PDP and Day-of dispatchable demand response programs at the same time, to conform to the Commission's rules for dual participation established in D.09-08-027.

31. Auto-DR is being addressed and should continue to be addressed in the demand response proceedings.

32. It is not an effective use of the Commission's resources to deplete previously authorized funds for residential customer acquisition activities, and then have PG&E request the same funding in a later proceeding.

33. DRA's proposal to fund all customer outreach and education for PDP from unspent AMI funds should not be adopted.

34. To reflect the revised meter forecast, the associated delay in customer acquisition expenditures, and the likely availability of more small and medium C&I customer acquisition funds for 2010 due to overlap with the AMI decision, it is reasonable to increase the originally forecasted small and medium C&I customer acquisition expenditure amount of $2.49 million for 2010 by 60%, the anticipated increase in 2010 meter installations over what was originally forecast, and deduct the resulting amount of $3.98 million in determining the small and medium C&I incremental costs for 2010 in this proceeding.

35. PG&E's incremental analysis related to (1) foundational work and (2) large C&I and large agricultural customers is reasonable.

36. PG&E's estimate of the incremental foundational costs for customer outreach and education, which amounts to $5.90 million (excluding contingencies), is reasonable.

37. PG&E's estimate of the incremental costs for large customer outreach and education, which amounts to $5.92 million (excluding contingencies), is reasonable.

38. An estimate of the incremental costs for small and medium customer outreach and education, which amounts to $18.22 million (excluding contingencies), is reasonable.

39. The further segregation of costs for small commercial customers will not likely be that revealing with respect to our outreach and education goals, and DRA's proposal to require such segregation will not be adopted.

40. Rather than establishing an outreach advisory panel, PG&E should (1) work with Energy Division and the Business & Community Outreach group and develop a written customer education and outreach plan, (2) work with the Business & Community Outreach group to determine how the group can assist PG&E in outreach efforts to small and medium customers, and (3) hold quarterly meetings.

41. PG&E should be subject to a number of reporting requirements in order for the Commission to gather information and to provide a means for parties to express concerns and a means to address any such concerns.

42. Since this transition for residential customers has been delayed by one year, it is reasonable to assume the associated costs would be delayed by one year as well. As such, it would be outside of the cost recovery timeframe requested by PG&E for this proceeding.

43. Since there are significantly more residential customers than small and medium C&I customers, it is reasonable to assume that most of the anticipated costs relate to residential customers and should be excluded. Without better evidence, it is reasonable to include $50,000 for SmartRate conversion calls for small and medium C&I customers in 2010 and exclude the remaining $236,000 from cost recovery in this proceeding.

44. The event notification activities and the associated cost estimate of $1.173 million (excluding contingencies), as originally presented by PG&E, are reasonable.

45. With respect to PG&E's requests for an additional $1.170 million in incremental notification costs due to the effect of D.09-08-027, the $0.106 million contingency should be excluded consistent with how contingencies are treated in this decision; $0.407 million in 2010 PDP costs should be adopted since these costs were included in this application, parties had the opportunity to review the costs and no party opposed the costs; and $0.607 million to support customer notification when the voluntary CPP program is replaced with PDP should not be adopted since these costs never were part of this application and parties did not have the opportunity to review the costs.

46. It is reasonable to specify a cut-off time for PDP event cancellation in PG&E's tariffs, and TURN's modified proposal of 4 p.m. on the day before the event is in a reasonable zone.

47. It is reasonable to allow PG&E the opportunity to file an advice letter to explain and support an alternative cut-off time for notification of event cancellation.

48. Because the effective date for defaulting small and medium C&I customers to PDP is deferred from February 2011 to November 2011, it is not necessary for PG&E to facilitate the development of notification equipment as requested.

49. PG&E's proposed incremental CSOL activities are reasonable. Due to the importance of CSOL in successfully implementing PDP, PG&E should verify the results of its activities by filing a Tier 2 advice letter with 30 days after it has completed its proposed incremental CSOL activities. PG&E should provide sufficient information for Energy Division staff to verify that the new PDP functionalities that PG&E has implemented on its website appropriately suit ratepayer needs.

50. With respect to the upgraded CSOL system authorized by this decision, for the "My Account" web presentment, all customers should have access to a screen showing cumulative consumption and their bill to date in the current billing cycle. Additionally, customers on the E-1 tariff or any other tariffs that involve a tiered rate structure should be able to quickly and easily identify what tier they are in at any time during the month. These customers should also be able to review historic data that includes that tier they were in at the end of the month. The web presentment should also include an easily accessible and brief description of the rate for each tier and the percentage over baseline that causes a customer to shift to the next tier.

51. Additionally, all customers should have access to a screen that enables a determination of what their consumption and bill might be at the end of the current billing cycle by utilizing appropriate assumptions regarding their historic usage and applicable rates. This screen should recommend short-term options available to reduce the projected total in the current billing cycle. PG&E should also include tips for conservation, demand response and distributed generation with links that describe other rates or programs that customers may benefit from on a long-term basis.

52. All customers should be able to request alerts based on the conditions of their choice such as a target cumulative consumption threshold and imminent cross-over into a higher tier rate. Customers should have the option of receiving these alerts via e-mail, text message, or voicemail.

53. Regarding the additional CSOL requirements related to residential customers who have SmartMeters and choose to not leave the existing E-1 tiered rate structure, PG&E should work with the Energy Division with respect to implementing or, if necessary, modifying the requirements.

54. PG&E's proposed billing system modification activities and the associated cost estimates of $25,939,290 (excluding contingencies) in capital for 2009-2010 and $1,515,023 (excluding contingencies) in expense for 2008-2009 are reasonable.

55. It is reasonable for PG&E to perform the CSOL re-platforming in conjunction with updating the CSOL functionality for PDP purposes.

56. PG&E's proposed CSOL update changes and the associated cost estimates of $23.270 million (excluding contingencies) in capital for 2009-2010 and $0.018 million (excluding contingencies) in expense for 2008-2009 are reasonable.

57. It is reasonable to approve $31,264,000 for the transition of CC&B from Version 1.5 to Version 2.3 in this case. Actual costs above this amount must be subject to an after-the-fact reasonableness review before they can be recovered in rates.

58. PG&E's proposed incremental M&E activities and the associated expense estimate of $1.321 million (excluding contingencies) for 2009-2010 are reasonable.

59. PG&E's proposed project management activities and the associated cost estimates of $2.389 million (excluding contingencies) in capital for 2009-2010 and $2.397 million (excluding contingencies) in expense for 2008-2010 are reasonable.

60. In this case, due to the significant amount of PG&E's contingency request, it is reasonable to exclude contingency cost effects from rates authorized by this decision. To do otherwise, would be contrary to the Commission's responsibility to ensure just and reasonable rates.

61. The elimination of contingencies should have little effect on PG&E's ability to recover its costs for 2009 and 2010 with the rates authorized by this decision.

62. PG&E's general methodology and results of operations model assumptions for calculation of the revenue requirement are reasonable and should be used for determining the revenue requirement authorized by this decision.

63. Allocating 2010 distribution-related capital costs and related O&M costs by distribution level EPMC-related allocators, and applying that allocation to all distribution customers, including DA customers, is reasonable, with the understanding that the opportunity to reexamine this issue will be provided in PG&E's 2011 GRC Phase 2 Proceeding when the allocation of all costs is considered.

64. PG&E's proposed cost recovery mechanism, as it relates to this decision, is reasonable.

65. The ratemaking treatment for recording PDP costs into the DPMA should be extended beyond 2010 to provide recovery through the DRAM of the revenue requirement associated with (1) any additional PDP costs above the amount approved in this case after the additional costs are determined reasonable by the Commission, and (2) any costs that are authorized by this decision for 2010, but are actually incurred in 2011, provided it is shown that such costs are not included in PG&E's 2011 GRC authorization.

66. PG&E's proposal to coordinate cost recovery where there is overlap between costs approved in earlier proceedings and the incremental costs in this proceeding is reasonable.

67. Additional costs that are above the amounts found reasonable in this case for PDP implementation proposed by PG&E, shall be subject to reasonableness review before they can be recovered in rates.

68. With respect to any elements of this decision that change PG&E's PDP proposal (scope of work, as well as reporting, presentation, evaluation, and consultation requirements) and result in increased costs, PG&E may request recovery of such costs through an after-the-fact reasonableness review application.

69. With respect to potential stranded PDP capital costs, PG&E should be able to recover expenditures as long as the expenditures were made pursuant to, and consistent with, the specific dynamic pricing spending authority and guidance provided by the Commission. Such expenditures should be identified in PG&E's immediately following GRC.

70. With respect to the PDP program, there is no demonstrated need for additional cost effectiveness reporting requirements at this time.

71. PG&E should file a 2012 RDW application in February 2012.

72. DRA's Request for Official Notice of Documents, dated January 11, 2010, is reasonable and should be granted.

73. In order to determine whether or not incurred costs are reasonable, it is necessary to consider whether or not the costs were necessary and, if so, whether or not they were optimally incurred.

74. The scope of the reasonableness reviews authorized by this decision should not be limited as requested by PG&E.

ORDER

IT IS ORDERED that:

1. The following rates shall be effective by May 1, 2010:

· For large commercial and industrial customers, default Peak Day Pricing rates that include time-of-use rates during non-Peak Day Pricing periods. Such customers can choose to opt out to a time-of-use rate or other time-variant rate; and

· For agricultural and small and medium commercial and industrial customers with advanced meters, optional Peak Day Pricing rates that include time-of-use rates during non-Peak Day Pricing periods.

2. The following rates shall be effective by February 1, 2011:

· For large agricultural customers that have access to at least 12 months of interval billing data, default Peak Day Pricing rates that include time-of-use rates during non-Peak Day Pricing periods. Such customers can choose to opt out to a time-of-use rate or other time-variant rate;

· For small and medium agricultural customers that have access to at least 12 months of interval billing data, default time-of-use rates. Flat rates will no longer be available to these customers; and

· For residential customers with advanced meters, optional Peak Day Pricing rates that include time-of-use rates during non-Peak Day Pricing periods. Prior to February 1, 2011, the current E-RSMART option available to residential customers shall remain in effect. On February 1, 2011, an E-RSMART customer shall be moved to the new residential Peak Day Pricing rates unless the customer opts to return to a non-time differentiated residential tiered rate.

3. The following rates shall be effective by November 1, 2011:

· For small and medium commercial and industrial customers that have access to at least 12 months of interval billing data, default Peak Day Pricing rates that include time-of-use rates during non-Peak Day Pricing periods. Such customers can choose to opt out to a time-of-use rate or other time-variant rate. Flat rates shall no longer be available to these customers.

4. Peak Day Pricing rates, with the exception of that for Schedule A-10, and time-of-use rates, as specified in Exhibit 7, Tables 2-3 through 2-5, and Table 2-6, Alternative 1 are adopted. The adopted Peak Day Pricing rate for Schedule A-10 is $0.90 per kWh.

5. An annual minimum of 9 and a maximum of 15 Peak Day Pricing calls, as well as Pacific Gas and Electric Company's proposal for enforcing the Peak Day Pricing call bounds by raising or lowering the temperature thresholds, are adopted.

6. Pacific Gas and Electric Company's proposed first year bill stabilization/protection proposal is adopted.

7. Under- and over-collections due to first year bill stabilization/protection and the variation in the number of Peak Day Pricing events shall be allocated to all customers by class, by spreading adjustments on an even percentage basis among all generation demand and energy charges.

8. Pacific Gas and Electric Company's proposed capacity reservation option and alternating day and six-hour window options to mitigate bill volatility for those customers that do not have a capacity reservation option are adopted.

9. The anticipated February 1, 2011 default process shall not begin until Pacific Gas and Electric Company's implementation processes meet the requirement that affected customers have access to 12 months of recorded interval billing data at least 45 days prior to their default date.

10. Pacific Gas and Electric Company's Alternative 1 residential Peak Day Pricing proposal is adopted.

11. Regarding person-to-person outreach, Pacific Gas and Electric Company shall ensure that a customer service representative directly contacts at least the 10% of small and medium customers whose bills are likely to be increased by the largest percentage based on previous year's usage, if they are defaulted to and stay on the PDP rate. PG&E shall include a description of how utility representatives will engage theses customers in it Customer Education and Outreach plan.

12. Pacific Gas and Electric Company shall work with Energy Division and the Business & Community Outreach group and develop a written customer education and outreach plan. The utility shall post the plan to the service list within 60 days of the final decision. Pacific Gas and Electric Company shall provide parties to the proceeding the opportunity to provide comments and feedback on the plan. Pacific Gas and Electric Company must include the plan and may include revisions based on feedback from parties in the advice letter required in Ordering Paragraph 15. The plan shall be submitted with the advice letter for informational purposes only and the utility may begin implementing the plan prior to a resolution on the advice letter. The plan shall include:

· Education goals the utility expects to have achieved with customers by the time they reach their default date;

· A list of monthly timelines for activities, the types of activities that will be conducted (i.e., mailings, e-mails, calls, workshops, meetings with business or agricultural leaders or organizations), as well as the geographic area, customer groups, and market segments that will be targeted, including ethnic and traditionally "hard to reach" customers;

· The methods that will be used to directly educate the 10% of small and medium customers whose bills are likely to be increased by the largest percentage based on previous year's usage if they stay on the Peak Day Pricing rate;

· A description of how customers will be educated about the tools and programs available to enable them to reduce energy consumption when a peak event is called, including energy efficiency and distributed generation and storage (effort should be made to coordinate this approach with other integrated marketing approaches); and

· A summary of other outreach and education plans, models or strategies around the country that PG&E can incorporate into its proposal to increase the number of small and medium customers that experience person to person interactions.

The Director of the Energy Division may direct the utility to make additions to the plan if necessary.

13. Pacific Gas and Electric Company shall work with the Commission's Business & Community Outreach group to determine how the group can assist Pacific Gas and Electric Company in outreach efforts to small and medium customers.

14. Pacific Gas and Electric Company shall issue a request for proposals in 2011, in order to engage a third party to conduct an evaluation in 2012 of the effectiveness of customer education and outreach efforts of small and medium customers. Pacific Gas and Electric Company shall work with the Demand Response Evaluation and Measurement Committee, which will have input into the project design and scope of work for the request for proposals and also take part in scoring proposals and reviewing the final report.

15. Pacific Gas and Electric Company shall:

· File a Tier 3 advice letter within 120 days of this final decision clearly identifying and describing the specific performance measurements, for each of its customer classes, which it will use to determine that its outreach and education campaign is successful;

· Prepare a monthly report to be provided to the Energy Division and posted on a public website. This monthly report shall include a breakdown of cost categories and money spent on education and outreach as well as a narrative description that describes the costs. Pacific Gas and Electric Company shall work with the Energy Division to design an appropriate format for the reports. Reports should be filed until customer outreach and education activities approved in this decision and the 2011 general rate case are completed;

· Provide a semi-annual written report to all parties on the service list, which includes foundational research conducted and findings, all outreach activities that have occurred, including number of customers that have received person to person contact, lessons learned from interactions, performance measurements that have or have not been met and if necessary modifications to outreach efforts going forward. The form and content of the report should be coordinated with the Energy Division and should be modified as necessary on an ongoing basis. The first of these reports should be completed and served on all parties no later than June 1, 2010, and reports should continue until six months after customer outreach and education activities approved in this decision and in the 2011 general rate case are completed;

· Hold quarterly progress report presentations. Two of the meetings shall be with Energy Division, the Division of Ratepayer Advocates and the Business & Community Outreach group. Two of the meetings shall be in conjunction with the semi-annual written reports and open to all parties on the service list;

· Provide to the Commission's Business & Community Outreach group, Pacific Gas and Electric Company's schedule of outreach events, at which Pacific Gas and Electric Company staff will be educating customers about Peak Day Pricing and time-of-use rates. (Events include workshops, industry meetings, and meetings with members of Chambers of Commerce, or other industry or customer segments that may not be represented by Chambers of Commerce, etc.) To the extent possible, Pacific Gas and Electric Company should coordinate such events with the Business & Community Outreach group; and

· After each of the presentations to parties on the service list, provide an addendum to the semi-annual written report to parties on the service list. The addendum shall include a workshop report describing recommendations and issues raised and how Pacific Gas and Electric Company will proceed as a result of the discussions and recommendations.

16. The effectiveness of the utility's education and outreach efforts shall be a factor in approving requests for additional funding for customer education and outreach for Peak Day Pricing in future proceedings.

17. Within 60 days of the issuance of this decision, Pacific Gas and Electric Company shall file an advice letter to explain and support an alternative cut-off time for notification of event cancellation. Parties shall have the opportunity to respond. If no protests are filed, Pacific Gas and Electric Company's proposed cut-off time will be adopted and should be included in its tariffs. If protested, the cut-off time will be determined by Commission resolution.

18. Pacific Gas and Electric Company shall file a Tier 2 advice letter 30 days after it has completed its proposed incremental Customer Service On-line activities. Pacific Gas and Electric Company shall provide sufficient information for Energy Division staff to verify that the new Peak Day Pricing functionalities that Pacific Gas and Electric Company has implemented on its website appropriately suit ratepayer needs. The anticipated February 1, 2011 and November 1, 2011 Peak Day Pricing default processes shall not begin until affected customers have had access to the verified Peak Day Pricing-related customer service on-line tools for at least 45 days.

19. For cost recovery of Customer Care and Billing transition costs from Version 1.5 to Version 2.3, above the amount authorized by this decision, Pacific Gas and Electric Company shall file a reasonableness application within 120 days of completing the transition to Customer Care and Billing Version 2.3.

20. Any costs related to the Customer Care and Billing transition from Version 1.5 to Version 2.3 shall be removed from Pacific Gas and Electric Company's test year 2011 general rate case proceeding.

21. To the extent that actual expenditures, except those related to the Customer Care and Billing Version 2.3 upgrade provided for in Ordering Paragraph 17, exceed the amounts authorized by this decision, Pacific Gas and Electric Company may request cost recovery in an after-the-fact reasonableness review application to be filed by March 31, 2011 or included as part of the Customer Care and Billing Version 2.3 upgrade application authorized in Ordering Paragraph 18.

22. Pacific Gas and Electric Company shall use its results of operations model to calculate the revenue requirements related to the costs adopted by our decision today, and shall include details of the calculations when requesting rate recovery through its Annual Electric True-up advice filing process.

23. The adopted incremental expenditures that shall be used in determining the revenue requirements for this decision total $123,585,000 for the years 2008-2010.

24. Pacific Gas and Electric Company's proposal to use the Dynamic Pricing Memorandum Account to record Peak Day Pricing costs and the Distribution Rate Adjustment Mechanism for recovery of the associated revenue requirement through 2010 is adopted. This cost recovery mechanism may be extended beyond 2010 to recover the revenue requirement associated with (1) any additional costs above the amount approved in this case after the additional costs are determined reasonable by the Commission, and (2) any costs that are authorized by this decision for 2010, but are actually incurred in 2011, provided it is shown that such costs are not included in Pacific Gas and Electric Company's 2011 general rate case authorization.

25. Pacific Gas and Electric Company shall develop an analysis of the projected bill impacts under time-of-use rates for a 10,000 customer sample of agricultural customers by November 2010. The information should be provided to the Energy Division and the Agricultural Energy Consumers Association and the availability of the information should be made to the service list.

26. Pacific Gas and Electric Company shall file a 2012 Rate Design Window application in February 2012, to address the following:

· An assessment of the performance of the 2010 and 2011 summer season Peak Day Pricing programs, in terms of customer participation and achieved demand response, with proposed adjustments, if any, to improve program performance;

· Proposed adjustments to Peak Day Pricing charges and credits, to reflect marginal costs adopted in the 2011 General Rate Case Phase 2; and

· Proposed new time-of use and time-of-use/Peak Day Pricing rates for medium commercial and industrial customers, intermediate in time-differentiation between the proposed A1-TOU and A6-TOU rate designs.

27. The January 11, 2009 Motion of the Division of Ratepayer Advocates for Official Notice of Documents is granted.

28. Application 09-02-022 is closed.

This order is effective today.

Dated February 25, 2010, at San Francisco, California.

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