17. Assignment of Proceeding
Rachelle B. Chong is the assigned Commissioner and David K. Fukutome is the assigned Administrative Law Judge in this proceeding.
1. The Commission has already authorized deployment of the HAN gateway for both SDG&E and SCE, and to do for PG&E would ensure statewide consistency as long as their efforts are coordinated. Consistency is important in providing a basis on which the HAN technology can efficiently develop and for providing a large market force that can be influential in developing appropriate standards.
2. There is no evidentiary record on which to judge the merits of a stand-alone HAN gateway device.
3. The most cost effective way to provide HAN access through PG&E's meters, over the long term, would be through PG&E's meter deployment plan rather than through random retrofits.
4. The increased functionality of the integrated load limiting connect/disconnect switch could be used to implement certain demand response programs and to provide area-wide and system-wide relief during peak usage periods that are in the public interest and are not available under PG&E's original AMI program.
5. The integrated load limiting connect/disconnect switch provides significant incremental operational benefits related to field technician labor savings for connect/disconnect services.
6. A number of new capabilities including a HAN gateway device (enabling price signals, load control and near real time data for residential electric customers) and load limiting disconnect switches, and potentially more features in the future, are possible because of the increased processing power, memory storage, programmability, and upgradeability provided by the solid state meter platform.
7. No party disputes the technological merits of the advanced solid state meter.
8. PG&E is not requesting additional funds for either its electric or gas communication networks.
9. Certain technologies, such as that related to communication networks, have evolved over the course of PG&E's SmartMeter project making them more cost effective to employ.
10. PG&E considers any costs and benefits related to its total AMI project (original plus Upgrade) that were not specifically included in the original AMI project cost/benefit analysis to be incremental for the purposes of justifying the cost effectiveness of the Upgrade.
11. DRA believes that Upgrade benefits that could have been achieved by the original AMI system that was approved by the Commission in D.06-07-027, should be excluded from the cost-effectiveness analysis for the Upgrade. TURN and CCSF support DRA's position.
12. The levels of conservation and demand response benefits PG&E claims in the Upgrade cannot be achieved without the further expenditures contained in the Upgrade.
13. DRA's definition of incremental is unduly restrictive in that it results in certain benefits not being recognized at all for cost effective purposes, either in PG&E's original AMI case or the Upgrade.
14. DRA's definition of incremental is essentially at odds with the manner in which the Commission evaluated the AMI requests of SDG&E and SCE.
15. The record in this proceeding is insufficient for determining the cost effectiveness of PG&E's SmartMeter program on a total basis (PG&E's original AMI plus the Upgrade).
16. The Upgrade will facilitate upgrades of both firmware and software and will enable PG&E to update both the functioning of the endpoint and initiate future programs without the necessity of visiting the endpoint. This aspect of the Upgrade should permit the current technology to perform capably well into the future even in the face of major advancements in technology.
17. PG&E's estimate of meter device costs is based on costs derived from an RFP process. Based on responses to that process, PG&E conducted an evaluation of the integrated meter devices from certain vendors to help identify vendor and meter device technologies best suited to serve PG&E and its customers.
18. Details regarding DRA's estimate of meter device costs is limited due to non-disclosure restrictions.
19. The HAN Retrofit involves PG&E deploying 288,000 upgraded meters with load limiting switches and upgrading these meters with HAN gateway devices at a later date.
20. The estimated 20-year life for endpoints is not relevant for purposes of analyzing the economic impact of a deployment scenario.
21. Costs incurred prior to the starting point of a comparative analysis (and recorded benefits) have no impact on the result of the HAN Retrofit comparative analysis, because they would be the same for all scenarios being compared.
22. PG&E's consultant's HAN retrofit suspension analysis was performed before the HAN retrofit aspect of meter deployment began, and was thus available for PG&E's project management to use in determining whether or not to go forward.
23. Despite the significant costs related to the HAN Retrofit, the evidence suggests that lost benefits, due to a meter deployment suspension until the HAN devices became available, would exceed the net reduced costs caused by the suspension.
24. PG&E has not fully supported and justified the magnitude of its HAN retrofit cost estimate.
25. Electromechanical meters have been deployed in the Kern region, and, as a result of PG&E's Upgrade request, the electromechanical meter costs will become stranded once these meters have been replaced.
26. In our analysis of PG&E's risk based allowance, we have determined that the stranded costs related to the electromechanical meters should be considered as original AMI program costs, specifically under the risk based allowance for the original AMI project.
27. The basis for DRA's proposal for a 30% use of the HomePlug or PLC technology stems from a hypothetical analysis involving cost sensitivity based on a 30% assumption. There is no evidence as to the reasonableness of using 30% to reflect what might actually occur.
28. The determination of who will use the HAN technology and to what extent they will use it is fairly subjective at this point.
29. HAN connectivity on a universal basis makes sense for such purposes as advancing and developing the HAN technology in an efficient manner.
30. It is PG&E's responsibility to achieve HAN connectivity in the most cost effective manner within the costs and risk based allowances provided by this decision.
31. In its supplemental testimony, PG&E indicates that it now expects to begin recruiting AC customers in 2013 and estimates the number of customers for that year to be 18 with increasing amounts thereafter.
32. Regarding IT costs associated with the Title 24 PCT program, PG&E has provided no specific reasons to justify why these costs need to be incurred prior to or in 2011 and why they cannot be shifted commensurate with when the expected recruitment of Title 24 PCT customers is expected to begin.
33. There is significant uncertainty as to when Title 24 PCT program will begin, and the program costs have already been moved by PG&E to 2013, outside the timeframe for cost recovery authorized by this decision.
34. The adoption of PG&E's IT proposal, as a means for addressing significant systems integration challenges, is consistent with the Commission's authorization of the same advanced metering technologies, with the same integration challenges, for SDG&E and SCE.
35. DRA and TURN have not forecasted the PVRR of any Title 24 PCT program costs, not because of any differences in what the estimated costs should be, but because of their positions that neither Title 24 PCT program costs nor benefits should be included in the cost effectiveness analysis of the Upgrade.
36. Reduction of Title 24 program costs related to marketing and incentive costs, commensurate with reductions to program participation, results in adopted Title 24 PCT program costs of $26,174,000 on a PVRR basis.
37. DRA and TURN recommend no PTR program costs, not because of any differences in what the estimated costs should be, but because of their positions that neither PTR program costs nor benefits should be included in the cost effectiveness analysis of the Upgrade.
38. PG&E requests $15.3 million in additional project management costs associated with additional project management efforts that will be required as the industry continues to evolve and offer new technologies.
39. In our analysis of PG&E's risk based allowance, we have determined that PG&E's requested additional project management costs should be considered as original AMI program costs, specifically under the risk based allowance for the original AMI project.
40. PG&E's technology assessment cost request has not been fully justified and appears to be excessive.
41. It is not clear that the currently proposed communication networks are deficient in particular respects, and it is not clear how BPL, MPL or IP would be incorporated into the currently proposed AMI structure.
42. There is potential value in having PG&E monitor market place developments.
43. There is value in pilot testing to ensure that the proposed network can be integrated into the AMI and will work as intended.
44. While laboratory testing and product demonstrations should first be the responsibility of those in private industry who will in the end profit from the various HAN related devices, there is merit to PG&E's alternate proposal to have ratepayers fund certain technology assessment costs in conjunction with matching funds from other sources.
45. Potential problems such as security breaches, interference with bill reading and interruption of customers' service can be avoided by first testing devices in a lab that replicates PG&E's system.
46. There is value in having PG&E provide input to and obtain information from private sector projects and to interact with developers and other utilities as HAN standards are developed.
47. No party disputes PG&E's estimate of incremental training costs.
48. No party objects to the concept of a risk based allowance or contingency.
49. Analysis of risk for the Upgrade should consider the risk profiles specific to the Upgrade, rather than that of the original AMI project.
50. A review of PG&E's proposed risk factors does not cause any specific concerns with the magnitude of the factors or with the cost categories to which they are applied.
51. The types of equipment to be deployed and the number and types of vendors that will be managed during the project are elements of the risk profiles that were considered in determining the reasonableness of PG&E's contingency amounts fort the Upgrade.
52. The electromechanical meters in Kern County, which have become stranded, were an element of PG&E's original AMI project.
53. Changed timing and scope are elements of the risk profiles that were considered in determining the reasonableness of PG&E's contingency amounts for the Upgrade.
54. Changed scope (i.e., advanced meters with higher functionality) is the driving factor that resulted in the electromechanical meters and associated equipment becoming obsolete.
55. For operation and maintenance, the only category of costs challenged by intervenors is that relating to expected calls to PG&E's call centers concerning the HAN device.
56. DRA recommends reducing PG&E's call center costs by 70% to reflect the fewer calls that will be received as a result of DRA's lower HAN adoption rate, despite its recommendation to reduce PG&E's HAN adoption rate by only 30%.
57. No party has challenged either PG&E's inclusion of field technician labor savings as a benefit or PG&E's quantification of these savings.
58. No party has challenged PG&E's inclusion of reduced bad debt savings as a benefit or PG&E's quantification of these savings.
59. No party has challenged PG&E's inclusion of reduced cash flow savings as a benefit or PG&E's quantification of these savings.
60. Whether the tax retirement benefit for meters is identified as a benefit or a reduction to costs, the net effect with respect to any benefit/cost analysis will be the same.
61. The need for reprogramming advanced meters is caused by the added functionality of the programmable meter itself.
62. The cost savings identified by PG&E, with respect to its remote programmability adjustment, are related to potential costs that never existed. Those costs are avoided because the meter that necessitates the costs can accomplish the task remotely.
63. Conservation benefits were not quantified in PG&E's original AMI proceeding.
64. The 1979 study by McClelland and Cook, used by DRA to reach its conclusion that day-late presentation of usage information affects space conditioning usage, does not provide persuasive evidence to support DRA's conclusions on this issue.
65. The shareholder risk/reward incentive mechanism for energy efficiency programs relates to energy efficiency and not conservation, and the conservation benefits for the Upgrade include both energy efficiency and conservation.
66. PG&E's estimate of 30% IHD penetration and DRA's estimate of 21% are based on new technology acceptance curves for different products (cell phones and CFLs).
67. There is sufficient evidence to determine that customers will use information obtained from IHDs to change their electricity usage patterns.
68. Both PG&E and DRA recommend that the more recent avoided costs should be used for the purpose of estimating electric conservation benefits for the Upgrade.
69. The IHD shows electricity usage, not gas usage.
70. The economic incentive for reducing gas usage is likely a result of a gas bill or an examination of gas rates rather than a customer looking at an IHD and noting electricity usage patterns.
71. With respect to customers that supposedly do not clearly differentiate electric and gas consumption by their appliances, there is no record evidence indicating what proportion of the customer base that might be. Furthermore, there is no record evidence indicating whether such customers would be the type that would even purchase an IHD.
72. With respect to the PTR program design, PG&E proposes a single-tier incentive, while DRA proposes a two tier incentive.
73. A two-tier PTR incentive has been adopted for SDG&E, and a two-tier PTR incentive settlement proposal for SCE has been deferred to SCE's Phase 2 GRC proceeding.
74. Requiring PG&E to propose a two-tier PTR incentive design in its November 2009 rate design window filing, will allow PG&E time to (1) work with DRA and other parties to work out program details; (2) consider the adopted design for SDG&E along with any solutions to practical considerations, if any; and (3) monitor and evaluate what has happened or will happen in SCE's Phase 2 GRC with respect to implementing a two-tier PTR program design.
75. That SEER is not a reliable predictor of energy performance or of demand reduction in California is supported by evidence.
76. There is evidence that there are energy savings ranging from 6% to 33%, associated with upgrading from a lower SEER system to a higher SEER system under different upgrading scenarios, although the number of units achieving expected savings is low (from 8% to 29%).
77. There is no statistically significant difference between the impacts expected from CPP and PTR incentives when estimated based on data from a side-by-side comparison of the two options for the same customer population.
78. The Anaheim study produced PTR program impacts nearly identical to the estimated impacts using the demand models from the SPP.
79. Rejection of TURN's proposed 30% elasticity adjustment is consistent with Commission action in D.08-09-039 regarding TURN's similar proposal in SCE's AMI proceeding.
80. While PG&E demonstrates that a non-CAC customer might realize significant savings under the PTR program under certain scenarios, there is no evidence as to suggest what the expected scenario might be and what savings would result from such a scenario.
81. Regarding non-CAC customer participation in the PTR program, there will likely be a response beyond that of those who would participate for environmental or societal reasons.
82. In D.08-09-039, the Commission rejected TURN's proposed demand response guarantee for SCE, which is similar to TURN's proposed demand response guarantee for PG&E.
83. PG&E has produced evidence from which it can be concluded that its cost effectiveness analysis includes HAN facilitated CAC cycling for new Title 24 PCTs beyond the level needed to replace attrition associated with the 305 MW in the A/C settlement.
84. The Commission has no way of knowing whether or not any future CEC assumed costs would significantly affect the cost benefit analysis as it applies to the Upgrade.
85. There is no certainty that the Title 24 PCT regulations will be implemented in 2012, if ever.
86. Whether the amount of voluntary participation will grow, if the Title 24 PCT regulations are not enacted, is uncertain.
87. Regarding PG&E's estimated 0.75 kW/hour savings per customer for the PCT program, while PG&E gives a reasonable explanation of why 0.48 KW/hour savings may be low, it provides no convincing evidence to justify its assertion that different ramping strategies will necessarily result in 0.75 kW/hour savings.
88. Regarding the SmartAC program, while PG&E states that participation has grown to over 75,000 customers with the $25 incentive, and indicates that it is well on its way to achieving the 25% market penetration target, it does not indicate where it is now and how much further it needs to go to meet the 25% target.
89. PG&E has produced no estimate of what a PCT device would cost, while TURN estimates costs to be in the range of $90 to $120, which is significantly higher than the $25 rebate.
90. No party has challenged PG&E's general cost recovery proposal.
91. In general, it is reasonable to allocate distribution infrastructure with distribution level EPMC related allocators.
92. PG&E's cost allocation methodology is consistent with how SDG&E's AMI related costs are allocated.
93. There were a number of settlements in Phase 2 of PG&E's 2007 GRC, which addressed marginal costs, revenue allocation and rate design. In the particular settlement on marginal costs and revenue allocation, Section VII.3 addresses rate changes between GRCs.
94. With respect to benefits recognition, there is no evidence that PG&E is mismanaging funds.
95. Recognizing AMI benefits when the meter is activated is reasonable, because no benefits can be realized until the meter is activated.
96. Regarding TURN's benefits recognition proposal, the Commission rejected a similar ratemaking proposal from TURN in D.06-07-027.
97. While benefits are trending $45 million behind schedule, the costs of the project are trending $161.9 million behind the original schedule.
98. PG&E's current deployment schedule still reflects an overall completion timeframe of five years.
99. No party has disputed the use of PG&E's results of operations model for the purposes of calculating the revenue requirements associated with the Upgrade.
100. DRA's recommendation that PG&E pursue water meter AMR with water utilities in its service territory may result in additional benefits for the SmartMeter project.
101. That the deployment of electric and gas meters might vary, not only from what was originally planned but from updated deployment plans as time goes by, is not unexpected.
102. The manner in which the final deployment of meters evolves will reflect how PG&E is able to manage the effects of factors such as the availability of materials and equipment, the regulatory process, and changes in technology as the deployment of meters is progressing.
1. This is an appropriate time to authorize deployment of HAN gateway devices for PG&E, and PG&E's request to do so is reasonable.
2. PG&E should work with the other major California energy utilities to strive for statewide, easily understandable information and other resources, as appropriate, to increase consumer awareness of commercially available HAN technologies and HAN-enabled benefits and to promote the adoption of such HAN technologies by consumers in order to facilitate their ability to understand their energy consumption and costs and to optimally utilize their discretionary options.
3. The increased functionality and the potential uses of the integrated load limiting connect/disconnect switches justify providing all electric residential customers with such switches.
4. PG&E's decision to ubiquitously deploy the advanced solid state meter for the SmartMeter Upgrade is reasonable.
5. PG&E should provide quarterly reports on the implementation progress of the SmartMeter Upgrade to the Commission's Energy Division and any interested parties.
6. PG&E should select the communication network(s) that provide the necessary functions in the most reasonable cost-effective manner.
7. PG&E's definition of incremental for cost effectiveness analysis purposes of the Upgrade is reasonable.
8. Any future requests to upgrade the SmartMeter Program should be critically reviewed with the understanding that our interpretation of cost effectiveness in this proceeding is appropriate for the circumstances that exist today and may well be inappropriate for circumstances that exist in the future.
9. The use of a total cost effectiveness analysis should be limited to showing whether or not the cost effectiveness of PG&E's SmartMeter program is in the range or generally comparable to that of SDG&E and SCE.
10. It would be inappropriate to impose DRA's proposed meter device costs on PG&E without assurance that the related meter devices provide the necessary functions, without assurance that the vendors are capable of providing the equipment when needed, and without knowledge of the type of warranties that are associated with the costs.
11. PG&E's decision to proceed with the HAN retrofit was reasonable.
12. To account for uncertainties and attempt to ensure that ratepayers only fund appropriate costs, it is reasonable to reduce adopted funding for the HAN retrofit by $5,500,000 (plus $550,000 for the related risk based allowance).
13. For the electromechanical meter upgrade, a cost of $18.8 million for the upgraded system is reasonable.
14. PG&E's general direction in attempting to deploy a solution that would bring the highest probability of transmitting a signal from the electric meter to an interior wall of the customer's premises is reasonable.
15. PG&E should adapt the implementation of HAN connectivity over time consistent with approaches and solutions that are being addressed and developed, currently and in the future, by those in the industry that are addressing these issues.
16. Because we have included the benefits of the PTR program in evaluating the cost effectiveness of the Upgrade, it is also appropriate to include the $4.0 million in IT costs related to the PTR program, in rates, as requested by PG&E.
17. IT costs associated with the Title 24 PCT program should be recovered in conjunction with PG&E's cost recovery of the Title 24 PCT program costs.
18. Because we have included the benefits of the Title 24 PCT program in evaluating the cost effectiveness of the Upgrade, it is appropriate to include the costs of Title 24 PCT program in that evaluation.
19. Since this decision approves a two-tier PTR incentive structure that will be detailed by PG&E in a November 2009 rate design window filing, it would be more appropriate to address the costs of such a program at the same time, rather than as part of this decision.
20. It is reasonable to use PG&E's estimated PVRR amount of $27,592,000 that is associated with a single tier PTR incentive structure, for the purpose of evaluating the cost effectiveness of the Upgrade in this decision.
21. Since we have adopted DRA's proposed HAN adoption rates, which were derived by applying a 0.7 scalar to PG&E's proposed adoption rates, it is reasonable to apply the same 0.7 scalar to PG&E's proposed call center costs, resulting in an adopted call center estimate of $319,000, which is $136,000 less than projected by PG&E.
22. With respect to devices that would enable home computers to function as in-home displays, technology assessment costs should be borne by those in private industry who will, in the end, profit from the device.
23. PG&E's proposed risk base allowance methodology along with the specific factors themselves and the categories of cost to which they are applied are reasonable.
24. It is reasonable that the additional project management costs requested by PG&E as part of the Upgrade should instead be covered by the risk based allowance adopted in D.06-07-027.
25. With respect to laboratory testing and product demonstrations, it is reasonable that ratepayers provide at least some of those costs related to protecting PG&E's system from such potential problems as security breaches, interference with bill reading and interruption of customers' service, which can be avoided by first testing devices in a lab that replicates PG&E's system.
26. It is reasonable to allow $6 million as the ratepayers' share of laboratory testing and product demonstration costs, with the understanding that PG&E can only use those ratepayer provided funds to the extent that it matches those funds from other sources. Any unspent funds for this particular category should be credited back to ratepayers.
27. Since the decisions to deploy the electromechanical meters in Kern County were made by PG&E in conjunction with the original AMI authorization, it is appropriate that the consequences of those decisions should be reflected as part of that same authorization.
28. It is reasonable that the stranded costs related to the electromechanical meters deployed as part of PG&E's original AMI project should be covered by the risk based allowance authorized by D.06-07-027 for the original AMI project.
29. PG&E's estimates of field technician labor savings, reduced bad debt savings, improved timing of cash flow savings, and the tax benefit from meter retirement are reasonable and should be adopted.
30. To assign the PG&E identified remote programmability benefit as an incremental benefit in the cost effectiveness analysis of the Upgrade is illogical and inappropriate.
31. Rather than reducing PG&E's estimate of electric conservation benefits by 12% as recommended by DRA, it would be appropriate, when the future of the energy efficiency incentive mechanism is clarified and if further incentives are authorized, for PG&E to ensure, through testimony in that future energy efficiency proceeding, that there is no double counting of energy efficiency embedded in the conservation benefits related to the Upgrade.
32. It is reasonable to be conservative and to adopt DRA's IHD penetration estimate of 21%, partly because of the speculative nature of the forecasts and partly due to TURN's legitimate concerns regarding the cost of the IHD devices.
33. It is reasonable that the more recent avoided costs should be used for the purpose of estimating electric conservation benefits for the Upgrade.
34. Since we do not feel that customers' decisions as to whether they should limit or curtail gas usage are significantly enhanced by the presence of IHDs that only display electricity usage patterns, zero gas conservation benefits should be used in the cost effectiveness analysis of the Upgrade.
35. For statewide consistency purposes, it is reasonable to impose a two tier PTR incentive design on PG&E and to require PG&E to propose such a design in its November 2009 rate design window filing.
36. Consistent with our acceptance of PG&E's definition of "incremental" for purposes of determining Upgrade costs and benefits, it is appropriate to include PTR benefits that result from PG&E's SmartMeter project and that were not quantified in PG&E's original AMI proceeding.
37. Even though the climate and other factors particular to California are not the same as that assumed for SEER purposes, it is reasonable to assume that as manufacturers attempt to make more efficient systems to comply with upgraded SEER levels, there will be some effect of demand reductions and energy savings in California.
38. It is reasonable to reduce TURN's proposed SEER adjustment by 50% to reflect increased AC efficiencies that result from increased SEER requirements.
39. Regarding non-CAC customer participation in the PTR program, it is reasonable to split the difference between the PG&E and TURN forecasts, resulting in a non-CAC customer participation rate of 35.5%.
40. For the same reasons expressed by the Commission in D.08-09-039, in rejecting TURN's proposed demand response guarantee for SCE, it is appropriate to reject TURN's proposed demand response guarantee for PG&E.
41. Similar to what was required for SCE in D.08-09-039, PG&E should report to the Commission on the energy savings and associated financial benefits of all DR, load control, energy efficiency, and conservation programs enabled by AMI, including PCT programs, Peak Time Rebate programs, and other dynamic rates for residential customers.
42. It is not appropriate to completely dismiss the use of Title 24 PCT benefits in the Upgrade cost effectiveness analysis, as proposed by both DRA and TURN.
43. Regarding Title 24 PCT benefits, it is reasonable to split the difference between the PG&E and TURN forecasts, resulting in a PVRR of $83,428,000 as opposed to PG&E's estimate of $129,401,000.
44. PG&E's general cost recovery proposal is reasonable.
45. For the Upgrade, it is reasonable to continue the use of the cost allocation methodology adopted by the Commission for PG&E in D.06-07-027.
46. Parties are not precluded from raising issues related to the allocation of SmartMeter costs in PG&E's next Phase 2 GRC proceeding.
47. In order to honor the settlement process, we have no alternative but to impose the principles for rate changes between GRCs, as identified in PG&E's TY 2007 Phase 2 marginal cost and revenue allocation settlement, in allocating the Upgrade related revenues to customer classes, including the street light class.
48. It is not necessary to change the benefits recognition procedures as proposed by DRA.
49. PG&E's reasons for rejecting TURN's $44.8 million ratepayer credit proposal are persuasive.
50. The use of PG&E's results of operations model for the purposes of calculating the revenue requirements associated with the Upgrade is reasonable.
51. PG&E's results of operations model should be used to calculate the Upgrade revenue requirements using the costs adopted by our decision today.
52. DRA's recommendation that PG&E pursue water meter AMR with water utilities in its service territory is reasonable.
53. In order to pursue AMR for water meters, PG&E should work with the water utilities in its service territory, either through multi-party workshops or direct dialogue and report back to the Commission on a quarterly basis until completed.
54. It would not be an efficient use of Commission resources to reopen the record to consider all aspects of the information contained in the Attachment A, a process that might require additional evidentiary hearing and briefs.
55. DRA's Motion to Reopen the Record should be denied.
IT IS ORDERED that:
1. Pacific Gas and Electric Company (PG&E) is authorized to proceed with the proposed SmartMeter Upgrade, subject to the conditions and costs specified in this decision.
2. PG&E's general cost recovery proposal is adopted.
3. PG&E shall file an advice letter no later than 30 days from the effective date of this decision, to implement rates for 2009 to cover the costs of the SmartMeter Upgrade.
4. PG&E shall use its results of operations model incorporating the costs adopted in this decision to determine the appropriate revenue requirements for the SmartMeter Upgrade project. Detailed results shall be included in PG&E's advice letter that implements rates for the SmartMeter Upgrade.
5. PG&E shall work with the other major California energy utilities to strive for statewide, easily understandable information and other resources, as appropriate, to increase consumer awareness of commercially available HAN technologies and HAN-enabled benefits and to promote the adoption of such HAN technologies by consumers in order to facilitate their ability to understand their energy consumption and costs and to optimally utilize their discretionary options.
6. In its next general rate case (GRC) for test year 2011, PG&E shall make an affirmative showing that it has avoided double recovery of any authorized SmartMeter Upgrade costs, and that any requested costs in its 2011 GRC are consistent with the limits of recovery adopted in this decision.
7. PG&E shall provide quarterly reports on the implementation progress of the SmartMeter Upgrade to the Commission's Energy Division and any interested parties. PG&E shall consult with the Energy Division to determine what information to provide and to coordinate reporting requirements ordered in Decision 06-07-027.
8. When the future of the energy efficiency incentive mechanism is clarified and if further incentives are authorized, PG&E shall ensure, through testimony in that future energy efficiency proceeding, that there is no double counting of energy efficiency embedded in the conservation benefits related to the SmartMeter Upgrade.
9. A two-tier peak time rebate incentive design is adopted for PG&E. PG&E shall present a proposal to implement such a design in its November 2009 rate design window filing. The proposed rate design shall be consistent with the rate design guidance in D.08-07-045.
10. Similar to what was required for Southern California Edison Company in Decision 08-09-039, PG&E shall report to the Commission on the energy savings and associated financial benefits of all demand response, load control, energy efficiency, and conservation programs enabled by advanced metering infrastructure, including programmable communicating thermostat programs, Peak Time Rebate programs, and other dynamic rates for residential customers. PG&E shall file annual reports in April of each year until 2019. PG&E shall work with Energy Division to develop a reporting format for this information, and to determine where the reports should be filed. PG&E may request recovery for the incremental costs of this reporting requirement in appropriate cases.
11. In order to pursue automated meter reading for water meters, PG&E shall work with the water utilities in its service territory, either through multi-party workshops or direct dialogue. PG&E shall report back to the Commission on the status of its efforts and results of its discussions on a quarterly basis, beginning April 11, 2009, until completed.
12. The Division of Ratepayer Advocates Motion to Reopen the Record, filed February 17, 2009, is denied.
13. Application 07-12-009 is closed.
This order is effective today.
Dated March 12, 2009, at San Francisco, California.
MICHAEL R. PEEVEY
President
DIAN M. GRUENEICH
JOHN A. BOHN
RACHELLE B. CHONG
TIMOTHY ALAN SIMON
Commissioners
************** PARTIES ************** |
Nina Suetake |
Aloke Gupta |
Ben Boyd Jeff Francetic |
Roger Levy
|
Larry Nixon
|
Theresa L. Mueller
|
Patrick J. Forkin Iii, Cpa |
(END OF APPENDIX A)
