3. Commission Standards for Evaluating Utility Performance

Under current statutes, PG&E enjoys an effective monopoly in the provision of electric and gas distribution service. (C.f., Pub. Util. Code §§ 330(f)(electric) and 328 and 328.2(gas).) In order to prevent abuse of this monopoly, the Legislature has given the Commission broad powers of regulation and investigation. The Commission exercises those powers to assure the public that the prices they pay for electric and gas distribution service are in fact just and reasonable, and reasonably related to costs prudently incurred by efficient, conscientious managers to provide the quality of service we expect. The quality we expect is described in Pub. Util. Code § 364, which requires the Commission to adopt standards for utility distribution systems that provide for high quality, safe, and reliable service. As we stated in Decision (D.) 00-02-046, we intend to hold PG&E to this high standard of service quality, and we expect prudent and effective management of the financial resources we have placed under its control.²

Under the Public Utilities Act, our primary purpose is "to insure the public adequate service at reasonable rates without discrimination..." (Pacific Telephone and Telegraph Company v. Public Utilities Commission (1950) 34 Cal.2d 822,826 [215 P.2d 441]; Pacific Telephone and Telegraph Company v. Public Utilities Commission (1965) 62 Cal.2d 634,647 [44 Cal. Rptr. 1, 401 P.2d 353]; City and County of San Francisco v. Public Utilities Commission (1971) 6 Cal. 3d 119, 126 [98 Cal. Rptr. 286, 490 P.2d 798].) We referred to the high quality of service we expect as "adequate," finding that "adequate service connotes a well-managed and sophisticated firm continuously meeting and exceeding public demand for the firm's output." We also held that "[a] utility which provides adequate service is in compliance with laws, regulations, and public policies that govern public utility facilities and operations." We stated that: "adequate service encompasses all aspects of the utility's service offering, including but not limited to safety, reliability, emergency response, public information services, and customer service," and emphasized that: "adequate service is not pejorative term, and in no way does our use of it imply acceptance of mediocrity in the utility's service offering."³

Furthermore, Pub. Util. Code § 451 requires public utilities to provide "adequate, efficient, just, and reasonable service" in a way that promotes the "safety, health, comfort, and convenience of [their] patrons, employees and the public," but also holds that all charges demanded or received by any public utility for these services shall be just and reasonable. Under §§ 701 and 728, the Commission has the authority to determine what is just and reasonable, and to disallow costs not found to be just and reasonable.

Through several decisions, rules, and general orders, we have provided the utilities with guidance regarding what constitutes a reasonable level of service. During the 1995-1996 storm season, heavy storms throughout PG&E's service territory caused thousands of PG&E customers to experience unusually long electric service outages. In response to those events, we initiated investigations and proceedings to determine improvements that could be made to reduce the future potential for customers experiencing such outages and to develop uniform benchmarks for measuring the utilities' performance during normal operations as well as their performance in restoring service following abnormal events.

In general, the investigations and proceedings resulted in three decisions which sought to assure that all jurisdictional electric utilities: 1) routinely provide the Commission with uniform data regarding their overall service reliability (D.96-09-045); 2) conform to prescribed standards regarding emergency preparedness and coordination (D.98-07-097); and 3) have a mandated benchmark against which the reasonableness of their performance during major outages could be measured (D.00-05-022). In all three decisions, we took great care to assure that the requirements applied uniformly to all utilities affected by the decisions.

In addition to the standards described below, all electric utilities are also subject to Rule 35 of GO 95, which requires utilities to maintain specified clearance between overhead primary lines and vegetation at all times, and GO 165, which sets forth inspection cycle standards and reporting requirements.

3.1 D.96-09-045 - Reliability Standard and Reporting

D.96-09-045 adopted recording and reporting requirements designed to provide uniform methods for assessing data related to the frequency and duration of system outages, circuits that persistently perform poorly, and accidents or incidents affecting reliability. We directed the utilities to record and report system reliability information annually using the following indices:

a. System Average Interruption Frequency Index (SAIFI). A.02-12-027, et al. SAIFI measures the average number of sustained power interruptions⁴ for each customer during a specified time period. It is calculated by dividing the total number of sustained customer interruptions by the total number of customers.

b. System Average Interruption Duration Index (SAIDI). SAIDI measures the average duration of outages per customer. It is calculated by dividing the total minutes of sustained customer interruptions by the total number of customers.

c. Momentary Average Interruption Frequency Index (MAIFI). MAIFI measures the average number of momentary outages per customer. MAIFI is calculated by dividing the total number of momentary interruptions by the total number of customers.

The measures above are typically calculated for a one-year period and may be calculated at the system level or at subsystem levels, such as the area or division level. We did not adopt specific performance targets, but held that "a minimum level of reliability for statutory purposes is the level that has historically been found reasonable, as measured by indices in use at the time by each utility."⁵ We also held that, "although system measures of reliability may give us the means for holding utilities accountable to measurable criteria, satisfaction of system measures (meeting historically reasonable levels) is not a shield that can stave off liability for damages in other forums or individual customer complaints in this forum."⁶ We also found that "system measures may mask more localized problems, and the utility may still be found to have acted unreasonably with respect to maintenance or replacement of some portion of the system."⁷ To address this concern, we directed the utilities to record the reliability indices using a portion of the system (circuit, division, region, or district), or smaller time periods, and provide this information to any interested person upon request. Since system design and recording capability differs among the utilities, we directed the utilities to record information at whichever of these levels their then current information collecting capacities existed.

We also required the utilities to include in the annual reports the number of poorly performing circuits, defined as those in which at least one customer experiences more than 12 outages in any 12-month period. This measure was intended to identify circuits that require evaluation and create an incentive to reduce poor circuit performance.

In order to avoid skewing the data with infrequent and unusual events, we allowed the utilities to exclude certain "Excludable Major Events" defined as events caused by earthquake, fire, or storms of sufficient intensity which result in a state of emergency being declared by the government. Absent the declaration of a state of emergency, any other natural disaster may be excluded only if it affects more than 15% of the system facilities or 10% of the customers, whichever is less for each event.

3.2 D. 98-07-097 - GO 166

In D.98-07-097, the Commission established GO 166, which set forth eleven standards relating to electric service reliability and/or safety. The purpose of GO 166 is to ensure that jurisdictional electric utilities are prepared for emergencies and disasters in order to minimize damage and inconvenience to the public that may occur as a result of electric system failures, major outages, or hazards posed by damage to electric distribution facilities. GO 166 contains detailed requirements for emergency planning as well as performance during emergencies. The standards are intended to facilitate our investigations into the reasonableness of the utility's response to emergencies and major outages. GO 166 defines "Major Outage" as an event when 10% of the electric utility's serviceable customers experience a simultaneous, non-momentary interruption of service. GO 166 requires that an investigation be conducted following every major outage.

3.3 D. 00-05-022 - GO 166: Standards 12 and 13

D.00-05-022 added Standards 12 and 13 to GO 166 and defined "Measured Event." Standard 12 sets a restoration time performance benchmark for major utilities. The benchmark is a Customer Average Interruption Duration Index (CAIDI) value of 570 minutes. CAIDI, which is calculated by dividing the total number of customer minutes of interruption by the total number of customer interruptions, measures the average duration of the outages experienced by customers. Under Standard 12, a utility's restoration performance would be considered unreasonable if it exceeded 570 minutes. Standard 13 requires utilities to meet a call center performance benchmark measured by the percent of customer calls receiving a busy signal during a Measured Event, a "percent busies" standard. Under Standard 13, the percent busies is presumed reasonable if it is 30 percent or less over a 24-hour period, and presumed unreasonable if it is 50 percent over the day, plus 5 percent in each of six one-hour segments. A Measured Event is defined as a Major Outage resulting from non-earthquake, weather-related causes, affecting between 10% (simultaneous) and 40% (cumulative) of a utility's electric customer base.

3.4 PG&E Specific Standards

While the standards adopted in the three decisions discussed above apply to all jurisdictional utilities, three other decisions adopted standards that apply specifically to PG&E. In response to PG&E's performance during the January and March 1995 storms, D.95-09-073 required PG&E to implement specific improvements to its call center operations and emergency preparedness. We adopted an Average Speed of Answer (ASA) standard, which requires PG&E to achieve an average wait of less than 20 seconds to speak with a call center representative. We also adopted a "percent busies" standard that requires PG&E to maintain a busy signal occurrence of less than 1% during normal operations and less than 3% during outages.⁸ In D.96-11-014, the Commission explained that compliance with the percent busies requirement is calculated on a calendar month basis, excluding days affected by abnormal circumstances. We also directed PG&E to make several other improvements to its call center operations and emergency preparedness.

Seven quality assurance standards for residential ratepayer customer service were adopted in D.00-02-046, addressing: 1) missed appointments; 2) non-emergency service investigations and repairs; 3) emergency service investigations and repairs; 4) complaint resolution; 5) new installations; 6) response to service disruptions; and 7) restoring service. The standards were accompanied by credits to customers if the standards are not met. These standards do not apply during significant emergencies, such as the December 2002 storms. PG&E reports that since their inception in the year 2000 through 2002, it provided customer credits totaling approximately $1.6 million.

D.03-02-041, which resulted from a Commission investigation into the power outage that occurred within PG&E's system on December 8, 1998, requires PG&E to provide the Commission's Energy Division and Consumer Protection and Safety Division with quarterly reports detailing statistics related to SAIDI and SAIFI values, Maintenance Repair and Replace Outages (MR&RO), along with root cause reports, specifying actions being taken and work completed related to distribution outages, for San Francisco and system-wide. In addition, PG&E is required to keep OSHA reporting information available upon request. After three years from the effective date of this decision, PG&E is allowed to request termination of the reporting requirements adopted therein.