Word Document

Decision 96-11-021 November 6, 1996


Commission Order Instituting Investigation

into the rates, charges, service, and practices

of Pacific Gas and Electric Company.

(U 39 M)


(Filed February 22, 1995


This decision proposes standards for electric distribution system inspections. We invite the parties to comment on them within 25 days and intend to adopt final standards shortly thereafter. In general, our proposed rules would specify certain inspection intervals for overhead and underground electric distribution facilities and establish criteria for maintenance and replacement of those facilities. At this time and with the information thus far evaluated, we find that performance standards are more appropriate measures of utility reasonableness in maintenance and replacement of distribution facilities. We also propose that the utilities maintain data and submit annual compliance reports.

I. Background

A. History of Proceeding

We initiated this investigation of electric utility distribution system standards in Decision (D.) 95-09-043. In that decision, we reviewed Pacific Gas and Electric Company's (PG&E) performance during severe rainstorms in early 1995 which caused widespread outages and system damage and which imposed on PG&E customers considerable cost, inconvenience, and risk. In that decision, we concluded, among other things, that we did not have standards or benchmarks by which to judge utility practices with regard to inspecting and maintaining distribution plant. We found that such standards were necessary as the utilities increasingly become subject to competition in their generation markets. D.96-09-045 confirmed this view more recently in this proceeding where we adopted certain standards for systemwide reliability and addressed the scope of this proceeding in more detail.

D.95-09-043 directed Commission staff to conduct workshops as part of our effort to develop standards for the utilities' distribution systems. Accordingly, Commission Advisory and Compliance Division (CACD)(1) oversaw workshops in early 1995 which explored numerous issues relating to electric distribution system service and safety. CACD issued a report on the of the workshops in February 1996. Shortly thereafter, the assigned Administrative Law Judge (ALJ) held a prehearing conference to determine how the Commission should proceed to set distribution system inspection, maintenance, and replacement standards. The assigned ALJ directed the respondent electric utilities to submit proposed standards. They submitted those proposals on May 31, 1996 and refer to them as "Inspection and Maintenance Plans." Subsequently, the parties filed comments on the proposals and the utilities thereafter filed responsive comments.

Since the time we initiated this effort, the State Legislature has endorsed the need for electric distribution system standards and our ongoing evaluation of whether the utilities have complied with them. Newly enacted Section 364 of Assembly Bill (AB) 1890 states:

"(a) The Commission shall adopt inspection, maintenance, repair, and replacement standards for the distribution systems of investor-owned electric utilities no later than March 31, 1997. The standards, which shall be performance or prescriptive standards, or both, as appropriate, for each substantial type of distribution equipment or facility, shall provide for high quality, safe and reliable service.

"(b) In setting its standards, the commission shall consider: cost, local geography and weather, applicable codes, national electric industry practices, sound engineering judgment, and experience. The Commission shall also adopt standards for operation, reliability, and safety during periods of emergency and disaster. The commission shall require each utility to report annually on its compliance with the standards. That report shall be made available to the public.

"(c) The commission shall conduct a review to determine whether the standards prescribed in this section have been met. If the commission finds that the standards have not been met, the commission may order appropriate sanctions, including penalties in the form of rate reductions or monetary fines. The review shall be performed after every major outage. Any money collected pursuant to this subdivision shall be used to offset funding for the California Alternative Rates for Energy Program."

The Legislature further expressed its support for these efforts to assure system safety and reliability by granting the utilities additional funds for maintenance programs.

Earlier in 1996, the Legislature considered this matter as part of the Supplemental Report of the 1996 Budget Act as follows:

"Standards for Electric Distribution. On or before December 21, 1996, the Commission shall prepare and adopt specific, measurable, and enforceable standards for electric distribution system maintenance and operations to ensure system reliability and to minimize or prevent service interruption due to storms, earthquakes, fire and other disasters. The standards shall specify tree trimming and brush clearing requirements, consistent with existing laws, which ensure that the electric distribution system is protected from damage. The standards shall require the Commission to investigate and take appropriate action against utilities which fail to meet the standards. The Commission shall report to the Legislature on the adoption of these standards on or before January 1, 1997."

We have already begun the process of developing these standards in two recent decisions. D.96-09-045 adopted reporting and recording requirements for electric system reliability and for individual circuit that persistency perform poorly. It also adopted procedures for utility reporting of accidents and incidents which affect public safety or system reliability, and ordered the submission of emergency response plans. In D.96-09-073, we proposed standards for tree trimming and vegetation management around utility distribution and transmission facilities in urban and suburban areas. We there stated our intent to adopt interim standards for tree trimming this year and take comment before adopting permanent standards.

This decision builds upon these earlier efforts and confirms our commitment to improved distribution quality, safety, and reliability. Through this decision, we propose prescriptive standards for distribution system inspection for all California investor-owned electric utilities. At this time and with the information thus far evaluated, prescriptive standards for distribution system maintenance , repair, or replacement are appropriately subsumed by the enforceable systemwide reliability measures. Performance standards for maintenance, repair, or replacement will be proposed in individual utility ratemaking cases.

II. Utility Plans, Intervenor Comments, and Industry Practice

A. Method for Considering Standards

In assessing standards to propose here, we have considered the information provided by Inspection and Maintenance Plans (plans) submitted by each utility, associated comments of intervenors, reply comments by the utilities and industry documents. A recent study by Black and Veatch Associates provided a great deal of useful information for our review here. PG&E contracted for the study in 1995. It provides summaries of programs of 15 utilities and relevant information about industry practices and engineering standards. Black and Veatch used survey information to develop standards regarded as "best in class," which reflect the most stringent practices in the industry and which we believe are good indicators of practices regarded throughout the industry as more than prudent.

The documents we have reviewed were useful in investigating and understanding distribution system standards. Nevertheless, the record in this proceeding leaves us with a considerable range of options. We have no prior statistical information upon which to determine the reasonableness of various proposals, and little engineering analysis can be obtained until standards are put into place for particular distribution systems. Empirical data is needed to draw conclusions about the appropriate balance of costs and benefits for various prescriptive maintenance, repair, or replacement standards. For that reason, we seek comment on the proposed General Order, recognizing our ongoing responsibility to refine the standards we ultimately adopt as the industry gains more experience and provides better information. As we explain more fully below, we also establish guidelines and procedures which permit utility programs to be tailored to suit specific circumstances.

B. Utility Inspection and Maintenance Plans

The jurisdictional utilities submitted their plans on May 31, 1996. The plans provide detailed overviews of maintenance practices. Generally, they address inspection, maintenance, and replacement cycles for each of several categories of plant and in some cases provide substantial information about the process of conducting inspection and maintenance programs.

The utilities originally proposed that the Commission "adopt" their plans and permit them to modify them subject to consultation with Commission staff. The cycles proposed are summarized in Table 1.

1. PG&E's Plan

PG&E provides a detailed plan which generally provides that all distribution facilities be inspected at least once every three years. PG&E has a rating system for facilities that have been inspected according to condition, a corrective action schedule, and a system of tracking program activities and inspection results.

2. Southern California Edison Company's (Edison) Plan

Edison describes its program as "Reliability Centered Maintenance" under which Edison assesses the performance of individual components, such as past failure rates, then revises maintenance priorities based on that experience. The program standards submitted are, Edison observes, dynamic and subject to change according to industry practices, ongoing analyses, and equipment improvements. It emphasizes the need for management flexibility to respond to changing circumstances. It uses a condition rating scale for equipment to evaluate maintenance requirements and timing.

3. San Diego Gas & Electric Company's (SDG&E) Plan

SDG&E inspects overhead facilities every four years and corrects unacceptable conditions within 12 months. It performs external inspections of pad- mounted facilities, vaults, manholds, and handholds every four years but does not open the facilities for inspections except on ten year cycles. SDG&E inspects wood poles every 15 years and replaces those that cannot be repaired with reinforcement within 12 months. SDG&E maintains data bases for its inspection and maintenance programs.

4. Pacific Power and Light's (PP&L) Plan

PP&L performs simple visual inspections every two years, more detailed inspections every ten years. It tests and treats poles every ten years. PP&L has a program called the "Digital Pole Inspector" which is a data base for pole inspections. It rates the condition of facilities and includes the ratings in the data base. PP&L audits its inspection and maintenance program routinely.

5. Sierra Pacific Power Company (Sierra Pacific)

Sierra Pacific has established inspection cycles and priorities for corrective action. It states it tracks program compliance using written forms. It emphasizes that it must balance performance, reliability, and safety with costs.

C. Comments by Intervenors

Division of Ratepayer Advocates (DRA), Toward Utility Rate Normalization (TURN), and California Utility Employees (CUE) filed comments on August 14, 1996. The utilities filed responsive comments on September l0, 1996.

1. DRA's Comments

By action of the Executive Director DRA ceased to exist as a staff unit on September 10, 1996. The functions it performed as a participant in this proceeding now reside with the Office of Ratepayer Advocates. DRA filed comments on the utility plans and standards more generally. It concurs with the Commission's policy in these matters and states its comments reflect its review of utility practices, those of other utilities, and review of the Black and Veatch study. It recommends that all utility programs should include specific inspection cycles, condition rating systems, priority- setting for corrective action, specified inspector qualifications, recordkeeping protocols, and management control tools. DRA recommends the Commission issue an order which adopts certain criteria for maintenance and inspections, and direct the utilities to conform their programs to the criteria. It recommends that the Commission, in effect, adopt utility plans and permit changes to them through the advice letter process. It also recommends that the Commission staff undertake site visits at utility facilities within 60 days of a decision to assess the actual procedures used to correct facility problems.

DRA also reviews each utility plan in some depth and offers specific suggestions for changes to each. Generally, DRA finds the plans of each utility to be comprehensive, well-documented, and adequate. It raises concerns about the inspection cycles of Sierra Pacific. We do not elaborate on DRA's specific proposals here but consider them in developing the standards we propose today.

2. Utility Safety Branch's (USB) Comments

USB expresses concerns that some of the utility-proposed inspection cycles are insufficient to prevent equipment failure. USB states it has observed corrosion in pad-mounted equipment and other facilities during field audits. It believes all utilities should make accommodation in their plans, as Edison has done, for equipment requiring shorter inspection cycles, such as those in coastal areas or close to irrigation equipment. It does concur with PG&E's inspection cycles generally except that it objects to PG&E moving from an annual patrolling of inspection cycles to a four year cycle. It also opposes Sierra Pacific's proposal to inspect underground transformers and switches every 15 years and its proposal to inspect poles over 20 years old every 20 years.

3. TURN's Comments

TURN comments generally that the utilities' maintenance plans are crucial components of regulatory accountability. TURN observes that the plans should provide for "opportunistic" inspections of overhead facilities by tree trimmers. It comments that maintenance plans should be designed to prevent problems rather than simply respond to them.

TURN specifies only one objection to PG&E's plan, namely, that three- year inspection cycles for underground and overhead facilities may leave violations of Commission rules unattended for as long as three years.

TURN argues that Edison's plan fails to identify explicit cycles for inspections, referring to inspections "as needed" in conjunction with other work. TURN believes this maintenance philosophy will not assure sound practices.

TURN believes SDG&E's cycles are too long and the program fails more generally both in spirit and in detail.

4. CUE's Comments

CUE observes that PG&E's plan is the most thorough and stringent. In addition to the short inspection cycles, CUE approves of the plan's clear delineation of responsibility for program elements and clear definitions of terms. CUE objects only to PG&E's proposed qualifications for inspectors. Instead of permitting an apprentice lineworker to perform inspections, PG&E should, according to CUE, permit only qualified electric workers to inspect utility facilities.

CUE observes that Edison's plan fails to assure that the utility will perform inspections according to the plan. CUE believes that Edison has deferred maintenance on its system. It believes some of Edison's inspection cycles are too long, including those for underground transformers. It observes that Edison proposes to replace certain faulty equipment "as soon as practicable," a standard which CUE believes is not adequate to protect public safety or system reliability.

CUE opposes elements of SDG&E's plan as well, including its proposal to never inspect dead front transformers, its failure to assure the quality of an inspection, its proposal to perform some maintenance "as soon as practical," and its failure to describe qualifications for personnel performing inspection and maintenance work.

III. Proposed Distribution Inspection Standards

We propose specific inspection standards to be set forth in a new General Order, and these standards are prescriptive in nature and need to be enforceable without undue disagreement or confusion over their applicability. The inspection standards should be flexible, meaning they are subject to compliance until or unless changed by later decisions. Moreover, they should promote cost-effective provision of high quality, safe, and reliable service.

We do not "adopt" utility Plans. Utility Plans, as they have been submitted to us are in effect operating manuals. They are too complex and subject to too much change to become documents which we would formally adopt. The utility Plans provide considerably more information than what would be defined as regulatory "standards." For example, the utilities' reports present information about the types of techniques and processes used to inspect and maintain equipment. Most provide information about the organizational procedures used to implement maintenance efforts. While this information is educational to us and essential to the utilities, it is not our intention to dictate the details of the utilities' technical or organizational process for management of their systems in the absence of a finding of mismanagement and imprudence In such a case, we might tighten our oversight. Instead, we endeavor to propose broad inspection standards designed to promote high quality service and a distribution system that is safe and reliable for the public. Additionally, by leaving utilities more flexibility in the techniques and processes they use, our standards will accommodate cost-effective innovation in inspection technologies, as well as information and communication systems for collecting and organizing data on facility conditions. In short, by focusing on acceptable maximum cycles for inspection, we would allow industry practices to continue developing, rather than locking them in.

In developing the standards we propose today, we recognize that we may in some instances impose more rigorous programs on the utilities than they have been conducting. We would do so only after reviewing the information before us, weighing the advantages of modifications to utility programs against the disadvantages of retaining the status quo, and considering comments and exceptions. The standards we adopt will be those which we believe will in the long run be cost-effective. That is, though they may impose short-term costs on the utilities, their program improvements will represent investments which will pay off over the coming years by requiring fewer facility replacements, timely and more cost effective maintenance obtained through the observation of facilities' condition, reduced liability, and improved system reliability.

We recognize that there are variations inherent between and within the utilities' systems. That is, distribution plant may require different types of attention over varying periods according to the terrain in which it is located, local climate and weather patterns, its vintage, the type of inspection or maintenance conducted, the type of technology used, the quality of the particular equipment, and the nature and quality of maintenance performed in previous years. For example, we would not expect a utility to inspect or replace a wood pole located in a desert with the same frequency it would inspect or replace one located near a marsh. Recognizing the safety needs and economic values of different areas, a utility might logically be more concerned about the condition of a transformer located in a highly populated area than the condition of one located far from population centers or heavy vegetation. PU Code Section 364(b) also recognizes the need for professional judgment in this area by citing several criteria for determining the appropriateness of distribution system standards, among them, cost, geography, weather, and industry standards.

For these various reasons, we propose a set of inspection standards which we believe are, on average, reasonable in light of industry practice. We are aware that they may be too stringent or too lenient in specific circumstances and for specific facilities. We intend to adopt general inspection standards and place the burden on utilities to request and define legitimate exceptions.

Exceptions will need to be very specific and supported because of enforcement consequences. The inspection standards we will adopt will be presumptively reasonable and failure to observe them could lead to penalties pursuant to PU Code Section 364(c). If we receive data or other information to suggest that the utility system as a whole is performing poorly, we may impose rate of return reductions, or other penalties in connection with investigations of particular events. (D.96-09-045, p. 11.) If we find that an unreasonable level of incidents is occurring or a substantial amount of wear or damage exists on the system, we could direct the utility to improve, and may impose prescriptive maintenance, repair, or replacement standards tailored to the situation. Therefore, comments upon the proposed rules that seek to describe legitimate exceptions should be well defined, and not subject to later dispute with enforcement staff over their scope.

A. Inspection Cycles

In developing the standards we propose today for facilities inspections, we distinguish between three levels of inspection. The lowest level is patrolling or simple visual inspections, which consist of walking, driving, or flying by equipment to identify obvious structural problems and hazards such as leaning power poles, damaged equipment enclosures, and vandalism. The next level is detailed inspection, where structures are opened as necessary, and individual pieces of equipment are carefully observed and their condition noted, recorded, and the recorded information is centrally consolidated. The highest level of inspection is intrusive, and involves moving soil, taking samples for analysis or using more sophisticated diagnostic tools beyond visual inspections or simple meter or instrument reading.

We propose standards here for the following types of major or substantial type of distribution facilities:

*0 Transformers

*1 Switching and Protective Devices

*2 Regulators

*3 Capacitors

*4 Conductors and Cables

*5 Street Lighting

For each of these, we further distinguish between overhead facilities and underground facilities, including those which are pad-mounted. Wood power poles are a separate category, the only one subject to the highest level of inspection. We distinguish between these various types of facilities because they present somewhat different problems and inspection requirements. Overhead facilities are particularly subject to the effects of wind and weather; on the other hand, it is well separated from the public under most conditions, and is fairly easy to access and repair. Underground facilities are protected from weather, but is harder to access and repair. Pad-mounted facilities may be similar to underground facilities in accessibility, but resemble overhead facilities in most other respects.

We also divide standards according to a facility's location and the relative population density. "Rural" areas are those less populous rural or suburban areas outside of a standard metropolitan statistical areas (SMSA's). "Urban" or more populous areas are those within an SMSA. Urban areas, by definition, pose safety and reliability consequences to greater numbers of people. Rural areas can be subject to severe fire hazards, more interference from vegetation, and can pose special reliability consequences (e.g., water supplies dependent upon electric pumping).

First, we consider the need for simple visual inspections of the utility system, or "patrols." We are concerned that proposed utility inspection cycles are too long. We consider regular patrolling to be a crucial part of protecting public safety, not to mention the reliability of electric supply. Patrolling can identify obvious hazards, such as leaning poles, vandalized equipment, stray wires, and the growth of vegetation that threatens power lines. To some extent, The public can help identify obviously hazardous conditions as they occur in utility systems. The general public, however, is not trained to notice subtle or technical indications of problems and is not responsible for the condition of the system. As moderate as California's climate is generally, it is nevertheless subject to dramatic weather patterns with some regularity and in some regions. Moreover, some visual inspections can be conducted in the course of routine business, by utility personnel who are already out in the field (such as meter readers), potentially reducing some of the cost of simple visual inspections.

On the basis of these considerations and the information before us, we proposed that all major distribution facilities be subject to annual patrolling cycles in urban areas and two-year intervals in rual areas.

We next consider intervals for detailed inspection, where individual pieces of equipment are inspected and their condition noted, recorded, and the information is centrally collected. Nine of the sixteen utilities polled for Black and Veatch's report inspected in this manner on a cycle of five years or less, while only one utility that inspected at all established a longer cycle. Utility proposals in this proceeding vary between three and ten years. Industry practice suggests that ten years between inspections could cause equipment to deteriorate beyond acceptable levels. For these reasons, we propose that the utilities be required to undertake detailed inspections of major distribution overhead facilities every five years.

Similarly, we propose a three-year urban and rural cycle for detailed inspections of major underground facilities. The practices of respondent utilities and those surveyed by Black and Veatch differ substantially. The Black and Veatch survey results suggest tighter inspection cycles for underground vaults than for overhead equipment. Twelve of the sixteen surveyed utilities inspect vaults at least every year. By contrast, proposals by respondent California utilities would establish inspection cycles from 3 to 15 years.

Surveyed utilities had longer cycles for pad-mounted facilities than for underground equipment, but five inspected at least every three years, while ten inspected at least every five years. These industry cycles support our proposal for inspections every five years in urban and rural areas.

We also propose a ten-year inspection cycle for intensive inspection of power poles older than 15 years. Such inspection involves the technical equivalent of excavating earth from around the base of polls, and taking core samples to assure that the poles retain adequate strength. The federal Rural Electrification Administration recommends cycles of 10 to 12 years for California's climate zones. Our proposal is consistent with this recommendation.

We will consider exceptions to the inspection cycles where the utility identifies specific facilities facing unusual weather conditions or restricted access. Exceptions must be narrowly delineated. We will reject vague references to geography or facilities. Comments should propose these exceptions or suggest a procedural vehicle for reviewing exceptions over time. Such suggestions must meet our goal of safeguarding ready enforceability and clear obligations, without undue burdens for staff.

Finally, we clarify that utilities have a continued obligation to undertake reasonable inspection (and maintenance, repair or replacement) of all facilities, whether or not we list them here as major or substantial types of facilities. Only the major facilities listed above and in the General Order are subject to annual compliance reporting, as proposed in a subsequent section.

B. Maintenance, Repair, and Replacement Standards

Section 364 requires that we adopt standards for the maintenance and replacement of utility facilities. Section 364 provides that standards for maintenance and replacement should reflect cost, local geography and weather, applicable codes, national electric industry practices, sound engineering judgement, and experience. Our investigation thus far reveals no prescriptive standard that can be readily acknowledged as sound industry practice and would adequately balance these other criteria. Additionally, among the statutory criteria, we would weight experience as a major factor in determining upon inspection whether further maintenance or replacement was warranted.

Consistent with the option provided us in Section 364, we believe that, for the time being, standards for maintenance, repair, or replacement should be based on performance, leaving greater management discretion and recognizing that this discretion does not render maintenance, repair, and replacement decisions beyond future regulatory reform or penalties.(2) We therefore decline to propose further prescriptive maintenance and replacement standards at this time. Instead, we will rely on system-wide measures of reliability, prescriptive inspection standards, investigations following major outages, or other event specific reporting and investigation.(3) Major outages are those affecting 10% or more of the customers in the distribution utility's territory. We will adopt PBR (performance-based ratemaking) standards in rate proceedings for maintenance, repair, replacement of major distribution facilities. In designing PBRs utilities should note our preliminary opinion that experienced inspection is best able to make decisions concerning the serviceability of a facility. Utilities are strongly encouraged to design PBRs that place the incentive (balanced reward-penalty) at the level of inspection. We therefore propose that no later than July 1, 1999, each distribution utility shall have filed a PBR which provides a balanced reward and penalty rate mechanism for maintenance, repair and replacement of major facilities listed in the General Order. The combined effect of all such rewards and penalties should not exceed $10 million in revenue requirement and should be compatible with other statutory restrictions on rates.

C. Reporting Requirements

We propose to require the utilities to submit an annual report regarding their compliance with the rules we adopt. The reports would be submitted annually beginning July 1, 1997 and would be available to the public. We distinguish such a report from the utilities' efforts to manage and record information about their distribution systems. In general, we believe the utilities are in the best position to determine the most cost-effective methods of maintaining information on inspections, as well as maintenance, repair or replacement. Nevertheless, we require that detailed information necessary to substantiate required reports on inspections shall be maintained such that it is available to staff or parties to relevant proceedings upon reasonable notice of not less than 30 days.(4)

The annual compliance report should provide information showing utility compliance with inspection standards at the "district" level. We do not require reporting on a facility-specific basis, even though that information must be maintained. By "district" we mean a geographical sub-division of the system larger than individual circuits, smaller than regions or divisions, and appropriately tailored to the utilities' existing grid identification scheme. We expect those reports to identify, under penalty of perjury, which facilities have been inspected, and to call out any exceptions, providing a detailed explanation of the exception and a commitment to a date certain by which inspection shall occur. The reports should aggregate data at the level presented in the General Order for each district. Utilities should maintain at a minimum information identifying the person that did the inspection, the date, and the facility.

E. Standards for Emergencies and Disasters

PU Code § 364 requires us to develop standards for "operation, reliability, and safety during periods of emergency and disaster." It also requires that we review utility performance following major outages to determine whether the utility has complied with the standards. We will pursue the development of these standards and a procedure for reviewing utility performance in this docket. Specifically, we will direct all electric utilities in the state to submit proposed standards for emergency situations and disasters in its decision adopting inspection standards. As part of their submittals, utilities shall propose reliability standards during emergency situations and disasters. For investor-owned utilities, these standards should be congruent with the emergency response plans ordered in D.96-09-045 (p. 40, Ordering Paragraph 8). Utilities should note the distinction herein between maintenance "plans" and adoptable "standards" when proposing emergency and disaster standards.

Investor-owned utilities should also propose procedures for Commission review "after every major outage." A subsequent ALJ ruling will set forth a comment and reply comment period for these standards.

D. Procedures for Formalizing Standards

The prescriptive inspection standards we adopt will be included in a General Order. Parties should file comments within 25 days, and identify any reasonably specific exceptions to the general standards and the basis for them. Reply comments will be accepted 10 days after comments.

V. Initiation of Rulemaking

We initiate a formal rulemaking in a companion order issued today, consistent with D.96-09-043. The rulemaking will be the procedural vehicle by which we will continue our development of service reliability and safety standards for electric utility distribution system.

Findings of Fact

Conclusions of Law

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