The proposed decision of the ALJ in this matter was mailed to the parties in accordance with Pub. Util. Code § 311(d) and Rule 77.1 of the Rules of Practice and Procedure.
Comments were filed by DRA, PG&E, TURN, and SSJID On July 5, 2006, and reply comments were filed by TURN and PG&E on July 10, 2006. To the extent changes were necessary as a result of the filed comments, they were made in the body of this order.
1. PG&E selected DCSI to provide a Power Line Carrier technology for electric meters and Hexagram, Inc. to provide a fixed network system with radio frequency communication channels owned by PG&E for gas meters. The selection was based on a review of proposals following a detailed request for proposals.
2. The proposed systems meet the Commission's functional criteria for AMI, except that the electric communications system is not an open architecture system. DSCI's system does not create a bottleneck blocking other communications over the electric distribution network. PG&E's contract with DCSI provides for a commercially viable licensing of the technology.
3. PG&E has implemented a project management structure that will provide adequate oversight by senior managers. The proposed stipulation will provide DRA and the Commission's Energy Division the same data available to the Executive Steering Committee that is relevant to monitor project deployment.
4. PG&E and DRA included a provision in a stipulation that might excuse PG&E's actions due to a "transportation accident."
5. PG&E and DRA included a provision in a stipulation that might excuse PG&E's actions during a "labor disputes" with its own workforce.
6. PG&E can evaluate, and when feasible, accelerate the deployment of AMI technology by installing the communications network in new construction if and when there are likely savings by eliminating subsequent up-grades from non-AMI equipped meters to AMI equipped meters.
7. PG&E can avoid unnecessary costs if it defers installing AMI in the territory where the County of Yolo and Cities of Davis, West Sacramento, and Woodland (Yolo/Cities) have contested pending condemnation proceedings. A deferral avoids installing communication modules that may not be used by a new service provider that acquires PG&E service territory and displaces PG&E as the incumbent utility. Installing unnecessary AMI components otherwise raises the cost of compensating PG&E for the acquired territory.
8. The project costs, as stipulated (see Table 1), are reasonable and within the range of a likely litigated outcome. They include a risk based allowance for unforeseen events. PG&E has a system in place to control and authorize the use of the risk based allowance.
9. The stipulation for cost overruns in excess of the adopted budget will share overruns between ratepayers and shareholders. The stipulation provides that PG&E's shareholders will absorb 10% of up to $100 million without a further reasonableness review. The 10% share provides PG&E an incentive to control cost overruns.
10. The useful life of the AMI modules is 20 years. The appropriate depreciation life is 20 years, the same as the useful life.
11. The avoided costs for demand response are reasonably forecast to be $52 per kW year, using PG&E's recommended method of calculation. We can use this method and its results to evaluate the cost effectiveness of the AMI project in this proceeding without prejudicing the outcome in Avoided Cost Rulemaking 04-04-025.
12. The advertising campaign for CPP is reasonably designed and necessary to inform and attract voluntary customers likely to provide the expected demand reductions during critical peak periods.
13. The project benefits, as stipulated (see Table 2), are reasonable and within the range of a likely litigated outcome.
14. A voluntary critical peak pricing tariff for residential and small commercial or industrial customers with under 200 kW demand will provide PG&E with up to 15 critical peak events per summer season for customers to reduce their load in exchange for an incentive pricing option. Certain customers, primarily those with significant air conditioning load, can reduce their total bill by up to 10% in exchange for a 25% reduction in their load just during the critical peak periods. Other customers can benefit too.
15. A bill guarantee, limiting the CPP customer's accumulated bills for the six month CPP season to the total amount otherwise payable under the customer's default rate, provides a participation incentive through a customer's first full summer on the CPP tariff.
16. The demand response benefits from PG&E's proposed CPP will provide positive benefits contributing to the AMI's overall cost effectiveness.
17. Balancing accounts will allow PG&E a reasonable opportunity to recover operating and capital costs as the AMI modules are deployed and put into service. The balancing accounts will also ensure customers receive an offsetting allowance for cost savings as PG&E's operating costs are reduced.
18. AMI will not be fully deployed before PG&E's next general rate case which is scheduled to have a test year 2010. It is beneficial to ratepayers if the Commission considers as an option to continue the balancing accounts in a test year 2010 forecast that omits AMI implementation.
19. The reasonable forecast of operational benefits per activated meter per month are $1.7722/per meter-month for electric and $1.0366 for gas.
20. Conventional rate base amortization of capital costs and annual recovery of operational costs, net of operational benefits, reasonably recovers AMI costs and benefits. Costs and benefits can be reviewed and adjusted in subsequent general rate cases.
21. TURN's proposed levelized fixed amortization of lifetime project costs and benefits is not a reasonable alternative.
22. Various societal benefits are likely to accrue as additional benefits from AMI deployment, but they are not quantifiable for cost recovery or necessary to determine that AMI is cost effective.
23. Customers need reasonable access to their energy consumption data. No cost or low cost web-based options are appropriate for small customers.
24. PG&E can examine the possibility of allowing customers or energy service providers to have flexible billing dates. A new tariff for this service will ensure that any incremental costs are borne only by those who use the service.
25. The AMI deployment is not a project subject to CEQA.
1. PG&E met its burden of proof and, with the other parties, presented sufficient credible evidence to find that it is reasonable to authorize PG&E to deploy the AMI project as modified in this decision.
2. It is reasonable to affirm the ALJ determinations on confidential exhibits, transcripts and briefs.
3. There is sufficient credible evidence to adopt as reasonable a project budget of $1.7394 billion, inclusive of a Risk Based Allowance, or contingency, of $128.8 million and $49 million for pre-deployment costs approved in D.05-09-044.
4. It is reasonable to adopt a 20-year life depreciation schedule for the AMI communications module components based upon the system's expected 20-year useful life.
5. It is reasonable to adopt a 10% shareholder and 90% ratepayer risk sharing of cost overruns, not to exceed $100 million beyond the total project costs of $1.6846 billion, and only conduct a post-fact reasonableness review of any costs in excess of $1.7846 billion.
6. The cost overrun stipulation should be modified to clarify that "transportation accidents" can only be included in force-majeure when PG&E can demonstrate that it was neither intentionally nor negligently responsible for any transportation accident-related delays to the project.
7. The cost overrun stipulation should be modified to exclude from force-majeure "strikes or other labor disturbances" as a provision that might excuse PG&E's actions during a labor dispute with its own workforce or its vendors or contractors.
8. The proposed balancing accounts provide and fair and reasonable means for PG&E to recover the costs of deploying AMI and offset existing rates for the forecast operational savings.
9. PG&E's critical peak pricing rate design is a just and reasonable rate to provide economic incentives for ratepayers to participate in a demand reduction program.
10. A voluntary critical peak pricing rate design does not violated Water Code § 80110, provided that the customer receives adequate notice that by signing up for the program the customer waives certain otherwise applicable statutory protections contained in § 80110.
11. It is reasonable to require PG&E to provide notice to customers, in consultation with the Office of Public Advisor, to inform customers that they waive certain statutory rights contained in § 80110 by signing up for the program.
12. CPP rates will provide demand response benefits.
13. There was sufficient credible evidence demonstrating that PG&E's proposed AMI is likely to be cost effective over its useful life.
14. PG&E should defer installing AMI in the territory where the County of Yolo and Cities of Davis, West Sacramento, and Woodland (Yolo/Cities) have contested pending condemnation proceedings to acquire PG&E service territory and displace PG&E as the incumbent utility. This deferral avoids installing communication modules that may not be used by a new service provider and would otherwise raise the cost of compensating PG&E for the acquired territory.
15. PG&E should collect data on voltage measurements to determine if it is feasible to regulate circuit voltage with its AMI infrastructure. PG&E should provide a report on these matters in its next general rate case.
16. PG&E should provide free web access to day-after data for individual customers.
17. Prior to offering more complex real-time access to customer data, PG&E should conduct publicly noticed workshops to consider an automated data exchange. PG&E should file an application to create an adequate record and fairly assign any costs for such a service.
18. PG&E should ensure that all incremental costs for flexible meter reading are borne by those customers that use the service.
19. AMI deployment is not a "project" as defined by § 15378(a). Therefore, no CEQA review is necessary.
IT IS ORDERED that:
1. Pacific Gas and Electric Company (PG&E) is authorized to deploy the proposed Advanced Metering Infrastructure (AMI) project as described and modified by this decision.
2. PG&E's electric and gas allocation proposals are approved. PG&E shall file an advice letter in compliance with this decision in not less than 15 days, or more than 30, to implement PG&E's rate proposals to collect the revenue requirement and modify its preliminary statements for the gas and electric departments establishing the gas and electric balancing accounts as adopted in this decision. The advice letter shall be effective upon its approval by the Commission.
3. PG&E shall include in its compliance advice letter an electric tariff for a voluntary Critical Peak Pricing (CPP) rates, as modified and adopted by this decision, for residential customers and for its small commercial and industrial customers with peak demand of less than 200 kW. The compliance advice letter shall include PG&E's proposal regarding bill protection for customers who opt-out of the CPP program before the end of the bill protection period.
4. PG&E shall provide the Division of Ratepayer Advocates (DRA) and the Energy Division a regular summary report of the following information as is provided to PG&E's Executive Steering Committee on the status of the Project: (1) Project status; (2) Progress against baseline schedule including equipment installation and key milestones; (3) Actual Project spending vs. forecast; and (4) Risk-based contingency allowance draw-down status. Unless more frequent reports are necessary, these shall be monthly.
5. PG&E shall report to DRA and the Energy Division within 60 days of the end of each CPP season the best estimate of demand response achieved during each CPP event, if any, including the number of customers (by class) on the CPP tariff and the participation rate of those customers during CPP events.
6. PG&E shall provide disclosure notices about specific provisions of the CPP program, as described in Section 10.1.1. PG&E must consult with the Office of the Public Advisor and obtain that office's approval of the precise language to be used in these notices. In addition, PG&E must consult with the Office of the Public Advisor about the marketing and promotional materials it plans to use in connection with the CPP program. PG&E shall include in those marketing and promotional materials such disclosure language as the Office of the Public Advisor may require.
7. PG&E may not deploy AMI technology in the territories where the County of Yolo and Cities of Davis, West Sacramento, and Woodland (Yolo/Cities) while there are pending condemnation proceedings to acquire PG&E service territory and displace PG&E as the incumbent utility. PG&E may not install AMI components if the November 2006 election approves annexation without a further order of this Commission. If the annexation election fails, PG&E may not install AMI components until any legal challenge of the election is final.
8. PG&E shall evaluate and then accelerate the deployment of AMI technology by installing the communications network in new construction whenever there are savings by eliminating subsequent up-grades from non-AMI equipped meters to AMI equipped meters. PG&E shall timely record the costs of early deployment in the balancing accounts and shall recognize the per-meter benefits after the AMI modules are activated.
9. The cost overruns stipulation is modified to clarify the "force-majeure" provisions that "transportation accidents" can only be included in force-majeure when PG&E can demonstrate that it was neither intentionally nor negligently responsible for any transportation accident-related delays to the project.
10. The cost overruns stipulation is modified to exclude from "force-majeure" provisions "strikes or other labor disturbances" as a provision that might excuse PG&E's actions during a labor dispute with its own workforce or its vendors or contractors with respect to the cost overrun stipulation.
11. PG&E must file by advice letter a new tariff provision to provide free web-access for individual customers to have access to day-after consumption data.
12. PG&E shall conduct publicly noticed open workshops prior to filing an application for authority to implement an Automated Data Exchange to allow customers and customer-authorized third parties access to detailed account data. PG&E shall file the Automated Data Exchange application in not less than 180 days from the effective date of this decision.
13. PG&E shall collect data on voltage measurements to determine if it is feasible to regulate circuit voltage with its AMI infrastructure. PG&E shall provide testimony on these matters in its next general rate case.
14. PG&E shall serve testimony in its next general rate case to report on its evaluation of customer acceptance, and measurements of the level of participation, for the CPP rates adopted herein.
15. PG&E shall serve testimony in its next general rate case to present as an option, continuing for the rate case cycle, the balancing accounts and cost savings benefits as adopted herein (appropriately escalated and adjusted). This testimony shall present an alternative to forecasting the full impact on the test year of the ongoing AMI deployment.
16. PG&E shall provide the Chief Administrative Law Judge, Energy Division, DRA and all other parties in this proceeding a semi-annual report assessing AMI deployment as set forth herein, beginning six months after the effective date of this decision.
17. PG&E shall conduct an annual workshop in conjunction with the California Energy Commission as described herein.
18. Application 05-06-028 is closed.
This order is effective today.
Dated July 20, 2006, at San Francisco, California.
MICHAEL R. PEEVEY
GEOFFREY F. BROWN
DIAN M. GRUENEICH
JOHN A. BOHN
RACHELLE B. CHONG
I reserve the right to file a concurrence.
/s/ JOHN A. BOHN
William B. Marcus
(END OF APPENDIX A)
LIST OF ACRONYMS AND ABBREVIATIONS
Administrative Law Judge
Advanced Metering Infrastructure
Commercial and Industrial Customers
California Environmental Quality Act
Customer Preference Market Research
Critical Peak Pricing
Distribution Control Systems, Inc.
Division of Ratepayer Advocates
Operating and Maintenance Costs
Pacific Gas and Electric Company
Present Value of Revenue Requirements
Request for Proposal
Sacramento Municipal Utility District
Statewide Pricing Pilot
The School Project for Utility Rate Reduction
The South San Joaquin Irrigation District
The Silicon Valley Leadership Group
Time of Use
The Utility Reform Network
The County of Yolo and Cities of Davis, West Sacramento, and Woodland
(END OF APPENDIX B)