Pacific Gas and Electric Company Advanced Metering Infrastructure Semi-Annual Assessment Report SmartMeter Program Quarterly Report March 2011

Transcription

1 Pacific Gas and Electric Company Advanced Metering Infrastructure Semi-Annual Assessment Report SmartMeter Program Quarterly Report March 0 (CPUC Decisions and 0-0-0) March 1, 0

2 Pacific Gas and Electric Company Advanced Metering Infrastructure Semi-Annual Assessment Report SmartMeter Program Quarterly Report March I. Executive Summary A. Introduction This is Pacific Gas and Electric Company's (PG&E or the Company) ninth semiannual assessment report (Report) regarding the deployment of PG&E's Advanced Metering Infrastructure (AMI) Program (now the SmartMeter 1 Program) and serves as the seventh quarterly report for the SmartMeter Program Upgrade. In Decision (the AMI Decision), the California Public Utilities Commission (CPUC or Commission) approved PG&E s SmartMeter Program, which PG&E proposed in Application In Decision (the Upgrade Decision), the CPUC approved, with certain modifications, PG&E s Application (Upgrade Application) to recover incremental costs associated with the SmartMeter Program Upgrade. Ordering Paragraph 1 of the AMI Decision requires that PG&E provide a semiannual report assessing AMI deployment. Ordering Paragraph of the Upgrade Decision requires that PG&E provide quarterly reports on the implementation progress of the SmartMeter Upgrade. After consultation with the Commission s Energy Division, PG&E has prepared this Report to comply with the requirements of both Ordering Paragraph 1 of the AMI Decision and Ordering Paragraph of the Upgrade Decision. 1 SmartMeter is a trademark of SmartSynch, Inc. and is used by permission. 1

3 The AMI Decision explains that the semi-annual report is intended to update the Commission in the following areas: advances in AMI technology; a self-assessment of AMI system operating performance based on performance criteria established in consultation with the Energy Division and DRA; updated cost-effectiveness review; and the ability to provide real-time usage data and customer interest in such data. PG&E conferred with representatives of the Energy Division and DRA to discuss the scope of topics to be addressed and the metrics by which AMI is to be assessed and incorporated staff comments and suggestions into this Report. B. Update on the SmartMeter Program PG&E's SmartMeter Program continues to progress through its objectives, including deployment of endpoint devices and associated network equipment, as well as implementing new information technology (IT) functionality. This section of the Report provides an overview of Program developments and PG&E's progress on individual elements of the Program during the last six months of Advances in AMI Technology PG&E continues to monitor metering and network collector technologies as the industry advances. PG&E continues to identify and approve engineering solutions using specific technologies and products that enable PG&E to deploy SmartMeters in difficult-to-reach meter locations such as urban areas and remote locations. These solutions may require existing network communication technologies or other technologies not yet available, as conditions dictate. PG&E continues to participate in industry activities related to advanced metering and communication networks, as well as monitoring announcements and activities that are D at pp. -.

4 significant in the industry. These activities allow PG&E to stay actively involved with and aware of industry developments. In the SmartMeter Upgrade Decision, PG&E was granted $.0 million in laboratory and product demonstration costs, with the condition that PG&E can only use those ratepayer-provided funds to the extent that it matches them with funds from other sources. PG&E has identified approximately $,000 in matching funds (within technology assessment areas) and is actively working to secure the remainder of the matching funds. During the first half of 0, PG&E continued a lab-based evaluation of Home Area Network (HAN)-enabled in-home display devices, which includes interoperability, radio frequency, and standards compliance testing. PG&E completed the lab-based evaluation of a selection of In-Home Displays (IHDs) in June, and began evaluating a selection of IHDs in 0 PG&E-employee homes utilizing a lab-based test network. During this phase of testing, completed in October 0, PG&E identified capabilities and limitations of the deployed devices in presenting various message types to better understand the real-world technical challenges of installing and maintaining a HAN (e.g., signal propagation, interference sources, and mitigation techniques). PG&E gathered feedback from the 0 participants on the effectiveness/usefulness of the devices. Knowledge gained will be built upon during future HAN testing. PG&E has expanded its evaluation and testing of enhanced network technologies to support its vision for the Smart Grid of the future. PG&E s vision includes integration of meter data, distribution automation, and automated load control to maximize distribution system reliability using technology as discussed in Section II of this Report. D.0-0-0, Conclusion of Law, p.

5 CPUC Independent Assessment of the SmartMeter TM Program In March 0, the CPUC selected the Structure Group to conduct an independent assessment of PG&E's SmartMeter TM program. Working under the supervision of the CPUC, its evaluation was intended to address the following areas: Whether PG&E's SmartMeter TM system measured and billed electric usage accurately, both now and since meter deployment began; Independent analysis of the high bill customer complaints; and Analysis of PG&E's SmartMeter TM Program's past and current operational and deployment processes, policies, and procedures. The Structure Group began its formal assessment on April, 0 and delivered their report on September, 0. Highlights of the report included: PG&E SmartMeters TM accurately record electric usage within acceptable CPUC tolerances and are being accurately used in customer billing. Meter and billing issues were limited and did not appear to be prevalent in the deployed SmartMeter TM population. Higher than expected bills appeared to be due to an unusual combination of hot weather, changes in customer usage, and recent rate increases. Customer relations and SmartMeter TM acceptance were negatively affected by failures related to PG&E s customer service, including failure to notify customers in advance of meter installations, failure to adequately address customer concerns, and lack of stringent bill quality control mechanisms. PG&E was in compliance with the majority of industry best practices associated with SmartMeters TM.

6 Progress in PG&E s AMI Deployment PG&E continues to deploy solid-state electric meters communicating over the RF mesh network and gas modules communicating over the RF network throughout the service territory. The deployment of the RF mesh network was planned to consist of an initial phase to deploy 1, Access Points (APs) at defined locations throughout PG&E's service territory, followed by subsequent phase(s) to deploy additional APs to strengthen the network where required. As of December 1, 0, 1,0 APs have been installed throughout the PG&E service territory. Of this number, 1,01 make up the initial phase of network deployment and are supplemental installations to increase read performance in certain areas. Installation efforts continue on the Aclara gas RF network, with a total of, data collection units (DCUs) installed through December 1, 0. This number represents approximately percent of an estimated total population of,000 DCUs at project completion. As of December 1, 0, approximately,, meters (approximately,0, electric and,,0 gas) have been converted to, or replaced with, SmartMeter technology, representing approximately percent of the total PG&E set meter population. Of this number, approximately,0, meters were activated and the benefits associated with completed meter reading routes were recorded to the gas and electric SmartMeter balancing accounts ($1. per meter per month for electric and $1.0 per meter per month for gas). Further details of the SmartMeter Program's deployment status are provided in Section III of the Report. PG&E has continued to expand and enhance customer outreach activities to address customers concerns about SmartMeter TM technology. These activities include The $1. per electric meter per month applied through March 00 was raised to $1. in April 00 with the partial implementation of the IT functionality for remote connect / disconnect consistent with the Upgrade Decision.

7 increased customer contacts before, during, and after deployment through not only direct mail but also through mass media, online content, and community outreach events. PG&E has also initiated a Customer Experience Survey, surveying thousands of residential and business customers each quarter. In addition to the outreach activities, meter testing continues with accuracy tests at the manufacturer factories, random sample testing performed by PG&E at its Fremont Meter Shop, and field testing at customer premises. PG&E will field-test any SmartMeter device upon customer request. In addition to the above customer outreach and testing activities, PG&E offered side-by-side testing of customers' electric SmartMeters TM with conventional meters. As of December 1, 0, side-by-side (dual socket) tests were completed.. Program Costs and Benefits SmartMeter Program expenditures through December 1, 0 totaled approximately $,00 million (1 percent) of the $,0 million authorized project amount. Initially, $,0 million of the $,0 million was allocated to workstream budgets covering field deployment, information technology, operations and marketing, and the program management office (PMO). PG&E actively monitors workstream expenditures against budget and determines additional costs and cost savings likely to occur during the Program period. In 0, as recommended by PG&E s SmartMeter Steering Committee, the $1 million risk-based allowance authorized by the Commission was allocated to workstream budgets based on actual and forecasted costs. As of December 1, 0, PG&E had allocated all of the $,0 million to project workstreams, and continued to

8 monitor the actual spending against the forecast, as well as issues and risks that could contribute to cost overruns. In late 0 and early 0, the PMO completed a detailed review of all workstream forecasts. As a result, the project is now expected to exceed the CPUC-authorized cost cap by approximately $1 million. The first $0 million of costs above the cost cap falls within the 0 percent customer/ percent shareholder sharing band established by the CPUC. Costs above the sharing band will be borne entirely by shareholders unless PG&E requests recovery and obtains approval from the CPUC. As reported in its financial disclosures, PG&E recorded a reserve of $ million, representing the current forecast of capital-related costs that are expected to exceed the CPUC-authorized cost cap and therefore will not be recoverable through rates. PG&E will continue to update its forecasts as the Project continues and may incur additional non-recoverable costs. As previously noted, the total number of activated meters on December 1, 0 was approximately,,. The related benefit savings credited to the SmartMeter TM Balancing Accounts (SBA - Gas, and SBA - Electric) through this same date totaled $. million. These amounts are consistent with the method for calculating and recording benefits provided in PG&E testimony and in both the AMI and Upgrade Decisions. Further details of the SmartMeter Program's cost and benefit status are detailed in Section IV of this report.. System Performance Criteria System performance metrics are provided in Table V-. In the first half of 0, PG&E also reported on system performance on a public website dedicated to the

9 communication of SmartMeter Program Data, which can be accessed at the following link: ( At this website, PG&E s SmartMeter Program provides metrics on deployment, billing performance, system performance, meter accuracy testing, and customer data usage.. Customer Interest in Accessing Real-Time Usage and Pricing Information PG&E launched its SmartRate Program in May 00. In 0, PG&E called 1 SmartDay events during the May 1 through October 1 season. As of December 1, 0, the SmartRate Program had,0 active residential customers. Details of the SmartRate Program are provided in Section VI of this Report.. SmartMeter Information Technology Progress During the second half of 0, PG&E continued the detailed testing and implementation associated with the development of complex IT systems and interfaces required to support the SmartMeter Program. Highlights of the continuing IT development over the past six months include: Performed hardware upgrades to the Meter Data Management System (MDMS) environment, upgrading to larger P servers. Migrated backup hosting environment to new locations. Increased capability of meter event management. Implemented HAN functionality in PG&E labs. Continued to analyze, test, and validate SmartMeter system scalability from.0 million meters through final deployment at. million meters. With the close of 0, IT Operations and Maintenance efforts within the SmartMeter program have transitioned to PG&E s core business. PG&E s IT

10 development plan for the first half of 0 will include upgrades to several core systems, including the MDMS, to support functionality and process improvements.. SmartMeter Transition to O&M Beginning in 0, those SmartMeter TM project activities that are of a recurring nature (i.e., activities that will continue after the project has been completed) will transition from project-funding to General Rate Case (GRC) funding. To support this upcoming transition, PG&E has initiated significant employee outreach and change management activities to address employee education. The SmartMeter TM Change Management team conducts direct outreach for the general PG&E employee population through Ambassador Toolkits mailed to each employee s and retiree s home, in person Employee Experience Zones containing increased levels of educational material, and written materials to educate impacted classifications in new processes and procedures (where the introduction of the SmartMeter TM technology has directly changed their work). Business departments that are directly affected by this transition and currently receiving training include: Contact Center Operations, Office Services, Meter to Cash, Service Planning, Gas and Electric Meter Shop, Restoration, Customer Field Services, SmartMeter Field Execution team, Energy Service and Solutions, Telecom, Gas and Electric Maintenance and Construction. Working in parallel with these activities, Employee Change Management planning continues to work with the Business Delivery Group, Information Technology, Governmental Relations, and Internal and External Communications departments to ensure employees are well prepared ahead of implementation.

11 II. Advances in AMI Technology A. Introduction Industry interest in AMI technology continues. In 0, PG&E continued its investigation of extending the AMI communications network to support Distribution Automation (DA) applications, including distribution line sensors and voltage measurement applications. The initial evaluation concluded that these applications are in fact suitable for the AMI network. PG&E will continue the development of more extensive testing and integration plans. B. PG&E Distribution Automation Investigations In its July 00 Report, PG&E noted its evaluation of both the implementation of Communicating Faulted Circuit Indicators (CFCI) and the S&C Electric Company s Intelli-TEAM auto-reconfiguration system. PG&E continues to work with both the communications manufacturers and traditional CFCI vendors to facilitate joint manufacture. The development of a low-cost CFCI will improve PG&E s ability to respond quickly to outages and the additional fault information will make it possible to deploy the correct equipment and personnel immediately. PG&E s Intelli-TEAM product currently has non-ssn radios. PG&E evaluated SSN radios but has deferred field testing pending evaluation of the full system architecture. Finally, PG&E will continue to work with other fault indicator vendors. The next steps regarding distribution automation investigation include testing of the radio traffic generated in integrated AMI/DA applications, completing a review of data model options, and creating use cases to be used for system integration.

12 C. Technology Industry Updates PG&E continues to lead and participate in industry activities related to advanced metering and communication networks, including membership in professional organizations and attendance at conventions and trade shows. During the second half of 0, PG&E participated in the following industry events: Plug-In conference (July) Smart Energy International (September) Autovation (September) American Association of Blacks in Energy (October) Greenlining Institute (October) Green:Beat (October) Next Generation Utility conference (November) Behavior, Energy, and Climate Change conference (November) PG&E actively participates in the following significant activities as part of the Company s commitment to an open and inter-operable Smart Grid: UCA Open Smart Grid (Chair) Providing oversight over UCA s Utili-App, Utili- Ent, Utili-Sec, and Utili-Comm groups. The UCA Open Smart Grid committee (a utility leadership committee) has been integral in setting utility requirements in UCA and providing them to the appropriate standards bodies. UCA Open Auto DR (Chair) Transforming the Lawrence Berkeley National Laboratory Automated Demand Response requirements from a specification to a standard. Institute of Electrical and Electronics Engineers (IEEE) 0.1. Tg (Chair) Producing IEEE 0 standards for Smart Utility Networks.

13 UCA OpenHAN Setting technology independent requirements to technology alliances. UCA Utili ENT Setting standards for the AMI Enterprise. UCA Utili SEC Establishing open security standards for the Smart Grid. UCA ADE Defining a common interface for exchange of information between utilities and third parties for customer data. SAE J Setting the communication standards between Vehicle and Grid for purposes of energy transfer. PG&E continues to believe that making these standards inter-operable through a comprehensive certification process should be one of the industries highest priorities. PG&E will continue to work with major industry stakeholders and the above organizations in assisting with that challenge. In the last six months of 0, there were a number of significant industry deployments. Announcements about these deployments may be found at the following links: ( ( ( ( ( ( 1

14 III. Progress in PG&E s AMI Deployment A. Overview PG&E continues to manage its meter and network deployment activities in parallel with the development and implementation of the IT systems and interfaces necessary to support SmartMeter functionality. The deployment schedule is dependent upon the availability of a trained workforce, an effective supply chain to maintain an efficient installation process, and customer premise access to make the necessary changes at each service location. Deployment planning adjustments may be required due to any number of factors, including adverse customer impacts, supply chain considerations, labor availability, and technology considerations, which could affect the scheduling of meter endpoint installations. As of December 1, 0, PG&E had converted or installed approximately. million meters (including retrofits) with SmartMeter technology. As noted above, the Upgrade Decision approved PG&E s plan to replace all electric meters that lack Upgrade technology, and PG&E has deployed, SSN retrofit endpoints to replace PLC endpoints. PG&E s progress as of December 1, 0 is summarized in Table III

15 Table III - 1 Progress Toward Completion As of December 1, 0 Total At Completion Actual Percent Complete Electric Network - RF Network Gas Network Collectors Electric Network Enabled Locations Electric Meter-module Installations* Electric Meter-module Activated Gas Network Enabled Locations Gas Meter-module Installations Gas Meter-module Activated 1, 1,0,000,,0,1,,,0,,0,,0,1 1,,01,,00,,,,00,,0,,00,, % % % % % % % % 1 1 *Includes installation of retrofitted SmartMeters. Meter growth occurring in 0 and 01 is funded in the 0 General Rate Case and is not included in the table above. B. Infrastructure Installations PG&E continues to make progress in the deployment of gas and electric network infrastructure, the installation of gas and electric meters and communication modules, and the activation of gas and electric meters. The following Tables III- through III- summarize the progress of PG&E s SmartMeter Program implementation in each respective area through December 1, 0. The percent-of-plan refers to the total (five-year) Program completion and provides perspective on PG&E s installation progress. PG&E reports actual and projected deployments and installations on a calendar year (CY) basis. Note that meter growth occurring in 0 and 01 is funded in the 0 General Rate Case and is not included in the table above. 1

16 Electric Network Equipment Installed 1 Table III Cumulative Electric Network Installations: Substation Communication Equipment (SCE) & RF Mesh Access Points,000 0% Plan Key Actual thru Dec ' Mesh Electric Network Plan - Access Points 1,00 1, ,0 1,1 Electric Network build to date - SCE Actuals Thru Dec- 0 % 1,0 1,1 1,1 1% 0% % 0 Total Electric Network Installations Year 1 (ITD to Dec-0) Year 00 Year 00 Year 0 Year - 0 1

17 Gas Network Collection Units Installed 1 Table III - Cumulative DCU Network Installations,000,000 0%, Plan Key Actual thru Dec ',000,000 0% 0%,,0, %,00 1,00 % 1,0 % 0 Total Data Collection Units (DCU) Installations Year 1 (ITD to Dec-0) Year 00 Year 00 Year 0 Year 0 1

18 Table III - 1

19 Electric Electric Gas Electric Gas Electric Gas Gas 1 Table III - Cumulative Meter-Module Installations (in 000s) 0%,, 0% 0% Plan Key Actual thru Dec ',, %,,,, 0% 0% 0% 0% %, %,,0,0, 0%,0 % 1, 1% % % 0% Electric Gas 1 1 % % Year 1(ITD to Dec- 0) % Year 00 Year 00 Year 0 Year 0 Year 01 1

20 Electric Gas Electric Gas Electric Gas Electric Gas 1 Table III - Cumulative Meter-Modules Activated (in 000s),K Total 0%,, 0% 0% Plan Key Actual thru Dec ',0,1 % %,, 0% 0% %,,0 % % 0%,000 1,,1 %,000,1 % 0% Electric Gas 1 1% 1% % Year 1(ITD to Dec-0) 01 1% 1, % Year 00 Year 00 Year 0 Year Year

21 IV. Program Costs and Benefits A. SmartMeter Program Costs The SmartMeter PMO maintains governance over the allocation of both the annual budget and budget-to-completion for each of the respective workstreams. The workstreams are summarized into four major categories in this Report: Field Delivery, Information Technology, Customer & SM (SmartMeter ) Operations, and PMO. The Program budget also includes a risk-based allowance, which was authorized to provide for unanticipated costs necessary to complete the defined Program work scope. For the SmartMeter Program, only the officer-led Steering Committee can approve a workstream expenditure that requires a draw against the risk-based allowance funding category. If a draw against the risk-based allowance is approved, the workstream budget is shown with an increase in approved funds, and the risk-based allowance category with an equal offsetting amount. In addition, the PMO recommends other reallocations, both increases and decreases, within and among workstream budgets, as circumstances require. Table IV-1 indicates the approved adjustments to the workstream budgets. Through December 1, 0, the SmartMeter Program has incurred costs of approximately $,00 million ($1, million in capital and $0 million in expense). Of this total amount, the percentage amounts by workstream as shown in Table IV-1 are: Field Delivery activities - approximately $1,0 million ( percent); IT-related activities - approximately $ million ( percent); Customer & SM Operations activities - approximately $1 million ( percent); and PMO activities - approximately $ million ( percent). 0

22 The Program's CPUC-authorized cost is based on the combined project cost authorization of the AMI and Upgrade Decisions. Table IV - 1 The Customer & SM Operations category includes $. million specifically authorized in the AMI Decision for the purpose of marketing Critical Peak Pricing programs. As of December 1, 0, approximately $1. million of the $. million has been spent in support of SmartRate marketing efforts from inception to date. (Thousands of Dollars) SmartRate Marketing & Education and Customer Web Presentment 00 Actual 00 Actual 00 Actual 00 Actual 00 Actual 0 Actual Total 0 1,1,,,00 1,1 1 1 Tables IV- through IV- show PG&E s incurred costs since inception through December 1, 0, for the SmartMeter Program, as well as each respective budget category. The percent-of-expenditures refers to the total incurred expenditures as of December 1, 0 as a percentage of the adjusted workstream budgets. 1 1

23 Table IV -

24 Table IV - Field Delivery Costs ($ Millions) Key 1.0B 1.B $1 1% $ Plan as of Dec ' Actual thru Dec ' $1 0% $1 % $ % $ $ % $ 1.00B $ $ 0.B 1,0,000,000 1,,000,000 1,,000, B 0.B 0.00B Total Field Delivery - Strategic Relationships Endpoint Installation Field Delivery Office Network Installation

25 Table IV -

26 Table IV - Customer and SM Operations Costs ($ Millions) $1 Key % $ $M % $1 Plan as of Dec ' Actual thru Dec ' $ $1 $0M $ $1 0% $ $0M $0M Total Customer and SM Ops Customer Communications and Outreach Change Management SM Operations

27 Table IV -

28 Table IV - Total SmartMeter TM Project Costs By Year ($ Millions) $,00 $,000 $1,00 $,0 1% $,00 Plan as of Dec ' Key Actual thru Dec ' Excludes GRC funded operational costs in 0 and 01 $ $0 $00 $00 $0 $0 $1,00 $00 $1 $00 $ $00 Project Costs Year 1 (to Dec-0) Year 00 Year 00 Year 0 Year 0 Year 01

29 B. Operational Benefits Realization The Program realizes benefits primarily when meters fitted with SmartMeter technology are installed, transitioned, and become activated. After installation, gas and electric meters transition when: (1) the communications network infrastructure is in place to remotely read them; () the meters are installed, remotely read, and utilize SmartMeter data for billing; () and the remote meter reads become stable and reliable for billing purposes. Once enough customers on a particular route string transition to SmartMeter billing, manual reading of the meters on that route string ceases, and those meters are considered activated. As reported in PG&E s January 00 Report, the first meter activations occurred in December 00. Since then, and as of December 1, 0, approximately. million meters have been transitioned, and approximately.1 million meters have been activated. Total cumulative benefits recorded as credits to the balancing accounts as of December 1, 0 are $. million, which represent both activated meter benefits and mainframe software licensing benefits. Such amounts are consistent with the calculation methodologies and savings rates adopted in the final CPUC Decisions. Table IV- shows activated meters and the corresponding benefits based on the average savings rates adopted in the AMI and Upgrade Decisions. These benefits include $1. per meter per month for electric and $1.0 per meter per month for gas. 1

30 Table IV Total Meter Benefits by Year ($ Millions) $1. Key $. Plan as of Dec ' Actual thru Dec ' $ benefits mechanism will be determined in 0 GRC Decision $. $.1 $0 $1.1 $. $0 Total Meter Benefits $1. Year 1 (to Dec-0) Year 00 Year 00 Year 0

31 V. System Performance Criteria Metrics System performance criteria and metrics are measured and reported on an ongoing basis as meter installations progress. As stated in previous reports, PG&E may modify these criteria and metrics after it has collected and analyzed actual system performance parameters in order to better characterize system performance. In Table V-1, PG&E has summarized SmartMeter Program Data metrics for timely and estimated bills for the fourth quarter of 0. Table V The performance criteria presented in Table V- are based on the number of actual reads retrieved by PG&E s Customer Care and Billing (CC&B) system versus the expected number of reads provided by PG&E s head-end systems. Deployment in areas with poor cellular coverage degrades performance, while firmware upgrades and supplemental network designs for existing and new installations improve performance. PG&E s monitoring of SmartMeter billing continues to indicate performance that meets and/or exceeds PG&E s established criteria. 1 0

32 Table V Performance Criteria Jul' thru Dec' Jan' thru Jun' Jun 0 thru Dec 0 Jan 0 thru Jun 0 Jul 0 thru Dec 0 1. Electric meter/module failure 0.% 0.0% 0.% 0.1% 0.0% rate. Gas module failure rate 0.0% 0.1% 0.% 0.% 0.0%. Electric network failure rate 0.% 0.% 0.% 0.% 0.%. Gas network failure rate 0.1% 0.1% 0.% 0.% 0.0% Electric billing data collection failure rate. Gas billing data collection failure rate 0.% 0.% 1.1% 0.1% 0.% 0.% 0.1% 0.% 0.0% 0.1% The definitions of the system performance criteria presented in Table V- follow: Electric meter/module failure rate: Counts incidence of meters being removed specifically for suspected meter hardware failure. Examples would be blank display, meter/module hardware errors, and non-communicating meters. Does not count external causes like broken cover, customer damaged meter, or tampering/theft. These meter/modules are then submitted through the Return Material Authorization (RMA) process for further investigation. Gas module failure rate: Counts incidence of module being removed specifically for suspected hardware failure. Examples would be bad battery/poor charging pattern, bad module circuit, and non-communicating module. Does not count external causes like damaged meter, SMC, dog damage, customer damage, etc. These modules are then submitted through the RMA process for further investigation. Electric network failure rate: Counts incidence of network component removals and submission for RMA, such as AP and relays failing to communicate and failure to maintain charging capacity. Also includes component failure on the Substation 1 Communication Equipment. 1

33 Gas network failure rate: Counts incidence of gas network component removals and submission for RMA, including failure to maintain charging capacity, drifts off frequency, cellular failure, and failed electronic boxes. Electric billing data collection failure rate: The number of electric SmartMeters from which complete data (complete backhaul data, daily anchor, and complete set of intervals) were not retrieved, divided by the total number of electric SmartMeters. This metric addresses the percentage of complete daily data sets, one good anchor and complete good intervals, averaged over the period defined. Any service point with an estimated anchor and/or estimated interval(s) fails the metric and is excluded. Failure of this read metric does not necessarily lead to an estimated bill an accurate bill can be generated in most cases. Gas billing data collection failure rate: The number of gas SmartMeters from which a daily cumulative read was not retrieved, divided by the total number of gas SmartMeter devices. Failure of this read metric does not necessarily lead to an estimated bill; an accurate bill can be generated in most cases. VI. Customer Interest in Accessing Real-Time Usage and Pricing Information PG&E s SmartRate Program, a critical peak pricing tariff option that requires interval data to administer, was launched in May 00. It supports a customer s ability to manage energy usage during hot summer days when SmartDay events are triggered when temperatures surpass a preset threshold. As of December 1, 0, the SmartRate Program had,0 active residential customers. Decision -0-0, which adopted Peak Day Pricing (PDP) rates, ordered 1 small to medium business customers currently on SmartRate to transition to PDP rates on May 1, 0. The decision also ordered residential customers on SmartRate

34 to be defaulted to PDP on February 1, 0. PG&E requested, and was granted, an extension to November 1, 0 for this transition. As a result, the SmartRate Program was extended until October 1, 0. In April, PG&E will publish its 0 Load Impact Evaluation report for Pacific Gas and Electric Company s Residential SmartRate Peak Day Pricing and TOU Tariffs and SmartAC Program, which will include information on the 0 season performance of the SmartRate population. Preliminary findings include: There were 1 SmartDays during the 0 season (May 1 through October 1). On average, participants reduced peak electricity use by 1. percent across the 1 event days. August 0 offered the season s highest average reduction: an average of 1. percent. In general, participants with central air conditioning reduced peak electricity use more than those without it. Across all geographic planning regions, low income customer peak electricity consumption was similar to that of standard tariff customers during non-event days. Additionally, the following are highlights from a customer satisfaction perspective: 1 percent of 0 customers report being very satisfied with SmartRate. A higher share of low income respondents, 1percent, reported that they were very satisfied with SmartRate. percent of respondents perceived that they were saving energy during their SmartRate participation and more than 0 percent actually experienced lower costs.

35 percent of 0 SmartRate customers planned to continue on SmartRate in 0. percent of SmartRate customers would recommend SmartRate to a friend. In 0, PG&E made changes to the SmartRate marketing strategy to account for the program s end in 0 and the CPUC decision to default all SmartRate customers to Peak Day Pricing in February 0. Now that SmartRate has been extended into demand response season 0, and with further regulatory uncertainties, PG&E will assume this same approach for 0 and will seek to maintain the current population of participants.