10. Assignment of Proceeding
The Assigned Commissioner in this proceeding is Michael R. Peevey and the assigned ALJ is Julie M. Halligan. The February 13, 2003 ACR determined that this was a Ratesetting proceeding and designated the assigned ALJ as the principal hearing officer as defined in Rule 5(l) of the Commission's Rules of Practice and Procedure.
1. In December 2002, Northern California experienced a series of severe storms, with high winds and heavy rainfall.
2. These storms caused significant damage to PG&E's electric distribution and transmission facilities, resulting in 1.97 million customer interruptions.
3. PG&E has an obligation under statute to provide highly reliable electric service at minimal cost.
4. The level of service reliability provided by PG&E during normal conditions from 1999 through 2002, as measured by SAIDI and SAIFI, is consistent with the reliability performance standards identified in D.00-02-046.
5. SAIDI, SAIFI, and MAIFI are useful methods of collecting and assessing data on the frequency and duration of system disturbances.
6. It is not particularly useful to compare reliability performance among utilities based on SAIDI, SAIFI, and MAIFI, since different customer counts, system design, geography, weather patterns, and methods of calculating outage duration of the individual utilities will necessarily result in differing performance.
7. PG&E has not prepared a value of service study for at least ten years.
8. The record in this proceeding does not contain value of service information that sufficiently captures the significant changes that have occurred in the electric industry or the California economy in the last decade.
9. The value of service estimates contained in PG&E's Utility Operations Guideline 12003 do not adequately represent PG&E's customers' current value of service and should not be used as the basis for incentive payments or funding.
10. The significant difference in reliability performance between PG&E's divisions favors adoption of division-level performance indicators.
11. PG&E was authorized $34 million in ratepayer funding for a new OIS in its last GRC and seeks approval for $16 million in this GRC for additional OIS improvements over the term of the GRC.
12. Ratepayers have already funded an OIS and a FAS designed to address single customer outages in a coordinated manner.
13. PG&E's request for $3.05 million in expense to upgrade the software for the mobile data terminals is a one-time activity.
14. PG&E's proposal to amortize the cost of enhancing the mapping associations within its OIS over a period of four years will allow the expense to be recovered over a period of time consistent with the expected length of the effort and the amount of projected expenditures per year and should be approved.
15. Adoption of the division-level reliability reporting requirements included in PG&E/ORA Agreement 1 will prevent system-level measures from masking division level performance.
16. Adoption of division level reliability measures as the primary measure of reliability is unnecessary at this time because the Commission may consider either system level measures or division level measures in its determination of reliability performance.
17. There is a need to address definitions of Excludable Major Event, Major Outage, and Measured Event, as well as the restoration performance standard included in Standard 12 of General Order 166.
18. The record in this case supports the fact that PG&E's customers desire improved storm response.
19. The record in this case does not support the fact that PG&E's customers are willing to pay for increased reliability generally.
20. PG&E and CUE have not shown that the proposed incremental annual revenue requirement will increase reliability beyond the levels reasonably expected to result from PG&E's base TY 2003 GRC request.
21. TURN and ORA have demonstrated that PG&E's reliability performance, as measured by the SAIDI and SAIFI performance indicators, is likely to improve without incentive revenues if PG&E pursues the projects proposed in its base TY 2003 request.
22. Given the fact that PG&E's employee safety performance has been consistently improving there is no need to adopt an employee safety incentive mechanism at this time.
23. The statewide workshops to be instituted under PG&E/ORA Agreement 3 should address whether or not call center standards should be revised to better reflect the use of VRU since neither the ASA standard nor the TSL standard differentiates the response time associated with calls answered by a service representative and calls answered by the VRU.
24. The level of service achieved by an ASA standard is equivalent to the level of service provided by a Telephone Service Level Standard of 80% of the calls answered in 20 seconds.
25. There is value in adopting a set of targeted expectations for SAIDI, SAIFI through a performance incentive mechanism.
1. The Commission is required by Pub. Util. Code § 451 to ensure that PG&E's customers receive reliable electric service at just and reasonable rates.
2. Allowing PG&E to collect and retain more revenue than is reasonably necessary for it to provide safe and reliable utility service would be contrary to the law.
3. PG&E bears the burden of proof to support its application through clear and convincing evidence.
4. PG&E should implement the "improvement initiatives" identified in this decision that would improve PG&E's OIS, thereby improving PG&E's storm response and reliability performance.
5. Agreements 1, 2, 3, 4, 5, 8 and 9 of the PG&E/ORA Joint Testament are in the public interest and should be approved.
6. PG&E and the other proponents of performance incentives have sustained their burden of proving that the incentives are necessary and appropriate and proposals to implement such incentives, including the joint motion of PG&E and CUE, shall be granted with modifications.
7. PG&E's last value of service study was prepared in 1993, with updated estimates prepared for a September 2000 PBR application.
8. PG&E should be directed to conduct a new value of service study prior to its next GRC.
9. In order to allow ORA to review and comment on PG&E's proposed approach and format for the value of service study, PG&E should file an advice letter that sets forth PG&E's proposed approach to conducting the value of service study and a proposed budget for Commission consideration.
10. Ratepayers should not be forced to fund the same OIS functionality twice.
11. PG&E/ORA Agreement 7 should be modified to remove funding for the single customer outage issue and amortize the expense of funding the software upgrades for the mobile data terminals and the mapping association enhancement project over 3 and 5 years, respectively.
12. PG&E's request for $2.45 million in expense and $0.8 million in capital for programming changes to include single customer outages in the OIS should be denied.
13. Approval of a Reliability Memorandum Account to record the costs of approved upgrades to PG&E's OIS would not result in retroactive ratemaking.
14. PG&E should be permitted to establish a memorandum account to track the costs associated with authorized OIS Improvements.
15. The Commission's Energy Division should convene statewide workshops to review the definitions of Excludable Major Event, Major Outage, and Measured Event with the intention of reviewing, clarifying and combining the definitions in D.96-09-045 and GO 166 into a common definition that clearly standardizes the criterion regarding the percentage of customers, or percentage of facilities, that must be affected before an event is considered excludable, including how percentages are to be calculated (i.e. cumulative or simultaneous) and how the start and end times are to be determined.
16. PG&E's request to change from an ASA metric to a telephone service level metric is reasonable, and should be approved.
IT IS ORDERED that:
1. Pacific Gas and Electric Company (PG&E) shall implement the following customer service and Outage Information System (OIS) improvements:
a. Modify restoration prioritization to balance the length of time small numbers of customers are out of power with the need to restore the largest number of customers as quickly as possible;
b. Simplify the routing of calls from emergency agencies to PG&E to improve the dispatching of PG&E resources to relieve police and fire agency personnel of the need to stand by on site;
c. Develop additional software to enhance the ability within OIS to increase focus on single customer outages during major events to improve communication with customers and reduce outage duration;
d. Link its OIS with the mobile data terminals in the field to accelerate the input of outage cause and damage assessment information into the Operations Emergency Centers and estimated time of restoration data into the OIS to improve the speed of assessing damage and sharing outage information with customers;
e. Integrate the three existing outage databases (the Supervisory Control and Data Acquisitions, OIS and Distribution Operators Logging Information Program) to reduce the number of manual entries an operator must make to improve efficiency and reduce outage duration;
f. Enhance mapping associations within the OIS so that smaller portions of PG&E's circuitry can be pinpointed for purposes of determining on a real-time basis a more accurate number of customers affected by outages and more accurate outage information;
g. Add new toll-free numbers for customers who are without power for more than 48 hours; and
h. Implement a campaign to urge customers to verify the accuracy of the phone number on their PG&E bill.
2. PG&E shall implement Agreements 1, 2, 3, 4, 5, 8 and 9 of the PG&E/Office of Ratepayer Advocates (ORA) joint testimony, as described in Appendix A.
3. PG&E shall submit division-level reliability data annually, concurrent with the system-level reliability report required by D.96-09-045. The reliability measures will include division level average interruption duration, average interruption frequency, customer average interruption duration and momentary average interruption frequency.
4. PG&E shall investigate and report to the Commission when the division level Average Interruption Frequency Index, Customer Average Interruption Duration Index (CAIDI) and Momentary Average Interruption Frequency Index (MAIFI) vary by 10 percent or more in any division from the five-year rolling average of reliability performance.
5. The Commission's Energy Division shall schedule workshops consistent with ORA/PG&E Agreement 3 within 90 days of this decision.
6. PG&E shall perform, or cause to be performed, a customer value of service study prior to its next General Rate Case (GRC). PG&E shall file an Advice Letter with the Commission within 90 days of this decision detailing its proposed value of service study approach and cost estimate for Commission review and approval.
7. PG&E is authorized to establish a memorandum account (consistent with the Reliability Improvement Memorandum Account proposed in PG&E/ORA Agreement 7) to track the following costs associated with funding the following OIS upgrades:
a. $3.050 million in expense, amortized over three years, to link the OIS to the mobile data terminals;
b. $3.250 million in expense to integrate the three existing outage databases (Supervisory Control and Data Acquisitions, OIS and Distribution Operators Logging Information Program; and
c. $7.360 million in expense ($460,000 in 2003 and $2.3 million in each of the years 2004, 2005 and 2006) to enhance the mapping associations within the OIS so that smaller portions of PG&E's circuitry can be pinpointed.
The amount incurred in 2003 is recoverable to the extent that PG&E's actual expenses in Federal Energy Regulatory Commission (FERC) Account 588 exceed 2003 GRC adopted FERC Account 588 expenses by the amount that actual expenses exceed adopted expenses up to the amounts in the Memorandum Account. For the expenses incurred in 2004, 2005 and 2006, the amounts are recoverable up to the above incremental amounts to the extent that PG&E's total electric O&M expenses exceed GRC adopted O&M expenses.
8. PG&E shall be subject to the targeted reliability metrics as outlined in section 7.4 above.
9. Within 10 days of the effective date of a final decision on Phase 1 of PG&E's Test Year 2003 GRC, PG&E shall file revised tariff sheets to implement the revenue requirements and accounting procedures set forth in this decision.
This order is effective today.
Dated , at San Francisco, California.
Appendix A - PG&E/ORA Joint Testimony
Agreement 1: PG&E will supplement its annual reliability report38 system data with reliability measurements by division, but not by area. The reliability measurements will include SAIDI, SAIFI, CAIDI and MAIFI. The format for reporting these division data would be developed in consultation with ORA. PG&E will provide ORA with all filings/submissions related to reliability currently provided to other divisions within the Commission.
Agreement 2: PG&E will investigate and report to the Commission when the previously described reliability performance measures vary by 10 percent or more in any division and/or 5 percent or more at the system level from the five-year rolling average of reliability performance. PG&E will calculate performance variations using values that exclude major events as defined by the prevailing regulation (currently D.96-09-045) and as implemented by PG&E in compliance with this regulation. PG&E will submit investigative reports by May 1 each year. The report will be filed with the Commission's Executive Director, and copies will be made available to interested persons upon request.
In addition, PG&E will investigate and report on all weather-related excludable major events for each division in which reliability performance, as measured by CAIDI, varies by 25 percent or more from the division benchmark. The division benchmark will be calculated from the rolling average of the prior 10 weather-related excludable events, whether the event is excludable at a system-wide level or is division-specific due to a declared state of emergency; or a rolling five-year average, whichever yields more event days. PG&E also agrees to provide such reports for the system when the system performance varies by 10 percent or more from the system benchmark. The system benchmark will be calculated from the rolling average of the prior 10 weather-related systemwide excludable major event dates, or a rolling five-year average, whichever yields more event days.
Agreement 3: PG&E and ORA recommend that the Commission initiate statewide workshops to address definitions of Excludable Major Event, Major Outage, and Measured Event, as well as the restoration performance standard included in Standard 12 of G.O. 166. The list of topics to be considered in the workshops includes:
· Examine if the level of the CAIDI benchmark in G.O. 166 is realistic and, if not realistic, establish realistic, but not necessarily uniform, benchmarks that could actually aid in measuring a given utility's restoration efforts;
· Review, clarify, and/or combine applicable definitions currently in D.96-09-045 and G.O. 166 into a common regulation that clearly standardizes the criterion regarding the percentage of customers, or the percentage of facilities, that must be affected before an event is considered excludable (i.e., how percentages are to be considered, (cumulative or simultaneous), an objective basis for determining the start and end times for an excludable event. etc.);
· Determine how outages incurred through restoration activities during excluding events are to be treated and determine how these additional outages should influence the counts for additional customer interruptions;
· Determine how the organization of the various utilities (i.e., districts, divisions, areas, etc.) affects how reliability is monitored during normal operations and those events that take place during abnormal events and create standards for allowing utilities to exclude outage data, during excludable events, only for those operating areas where the customers themselves actually experienced the event or where field staff from an area are utilized to aid an area where the customers experienced the event;
· Confirm that all utilities consistently interpret and apply the requirements and definitions within D.96-09-045 and G.O. 166 (e.g., in the definition of a G.O. 166 Measured Event, what is exactly incorporated by the range "10 percent simultaneous" and "40 percent cumulative" of customers affected?); and,
· Ensure that the Commission is being provided with complete details from all utilities regarding how each interprets the requirements in Appendix A of D.96-09-045.
PG&E and ORA agree that no further reporting regarding major outages or excludable major events is required beyond the Commission's current requirements. In addition, PG&E agrees that modifications to its Utility Operations Electric Emergency Operations Plans will be made in consultation with ORA and Energy Division.
Agreement 4: PG&E will install as many additional sets of overhead fuses in 2003 to fully utilize the GRC requested amount of $5.4 million in MWC 49. This is expected to result in the installation of no fewer than 2,000 overhead fuses in 2003 associated with this MWC. PG&E will report to the Commission, including ORA, on the number of overhead fuses installed and unit costs associated with MWC 49 in 2003 through 2006.
In addition, beginning in 2004, PG&E agrees to continuously maintain three years of annual budget cycle submittals, final budget authorization, actual expenditures, and the number of installations for all work performed in MWC 08,09, and 49. PG&E will provide these documents upon request of the Commission, including ORA.
Agreement 5: PG&E will modify current restoration practices to balance length of outages with number of customers affected and will keep ORA actively involved and informed in the process of developing this policy.
Agreement 6: PG&E will perform an assessment of value of service values (a "VOS assessment") by December 31, 2004 that will address the following issues:
· Based on a survey of prior VOS studies, the parties have noted significant differences within and among those studies. The significant differences include value of service between customer classes and between different approaches within the same customer class. The magnitude of these differences is likely to overshadow the differences attributable to changes over time (e.g., those that would be captured by a new VOS survey). The VOS assessment shall analyze and critically appraise these differences, and shall appraise the relative merit of the willingness to pay versus willingness to accept results.
· With respect to storm response management, PG&E will make its best efforts to quantify the effect of critical additional resources on restoration time.
· PG&E agrees that the VOS assessment will set forth balanced and complete reasoning in the derivation of proposed VOS values and the VOS assessment shall be conducted in such a way that it does not simply attempt to justify the values currently contained in UO Guideline G12003.
· PG&E shall attempt to have the VOS assessment peer-reviewed, but is not required to do so. If the VOS assessment is peer-reviewed, PG&E shall append peer comments to the VOS assessment.
The VOS assessment shall include the following:
· PG&E will recommend as many different VOS values as the Company believes is necessary;
· Documentation showing how each VOS measure has been translated into PG&E's recommended VOS measures;
· For purposes of investment planning, PG&E will set forth its findings and recommendations for the weighting of differences between customers classes;
· PG&E may additionally recommend as many different ways to use VOS as best reflect its operations; and
· PG&E will make its best efforts to investigate a VOS approach that is workable and useful for application to storm response management and for service guarantees.
PG&E and ORA agree that conducting a VOS survey is not warranted at this time. ORA and PG&E anticipate that the VOS assessment envisioned by the parties can be performed within PG&E's existing resources. If PG&E recommends a survey, PG&E will file an advice letter that: 1) Sets forth a proposed budget; and, 2) states that PG&E shall enter the costs of said survey into a memorandum account for future potential rate recovery. PG&E would consult with ORA and obtain agreement prior to filing the advice letter.
Agreement 7: PG&E will establish a Memorandum Account to record the costs associated with specific upgrades to PG&E's OIS and associated emergency response systems for an amount up to $9.0 million in 2003, and $2.3 million for each of the years 2004, 2005 and 2006 (2003 nominal SAP dollars). The amount incurred in 2003 is recoverable to the extent that PG&E's actual expenses in Federal Energy Regulatory Commission (FERC) Account 588 exceed 2003 GRC adopted FERC Account 588 expenses by the amount that actual expenses exceed adopted expenses up to the amounts in the Memorandum Account. For the expenses incurred in 2004, 2005, and 2006, the amounts are recoverable up to the above incremental amounts to the extent that PG&E's total electric O&M expenses exceed GRC adopted electric O&M expenses.
Agreement 8: PG&E will monitor and report to ORA on its implementation of the existing measures in its action plans as well as its investigations into additional technical measures to improve the accuracy of its Voice Response Unit (VRU) systems and potential methods to prevent its Safety Net line from being overburdened during high-call-volume emergencies.
Agreement 9: PG&E and ORA agree on a mutual approach to monitoring and reporting to ORA on any needed adjustments to its Outage Information System (OIS), Customer Information System (CIS), Field Automation System (FAS), VRU and all customer interface and response systems that would aid PG&E in making resource deployments to address outages.
38 The report required by Decision 96-09-045 which is filed annually on March 1.
