RULES AND REGULATIONS
Title 52--PUBLIC UTILITIES
PENNSYLVANIA PUBLIC UTILITY COMMISSION
[52 PA. CODE CH. 57]
[34 Pa.B. 5135] [L-00030161]
Electric Service Reliability The Pennsylvania Public Utility Commission (Commission), on May 7, 2004, adopted a final-form rulemaking order which amends existing regulations by establishing performance and benchmark standards designed to ensure electric distribution company performance does not deteriorate since passage of 66 Pa.C.S. Chapter 28 (relating to Electricity Generation Customer Choice and Competition Act).
Executive Summary
The Electricity Generation Customer Choice and Competition Act (Act), 1996, Dec. 3, P. L. 802, No. 138 § 4, became effective January 1, 1997. The Act amends Title 66 of the Pennsylvania Consolidated Statutes (''Public Utility Code'' or ''Code'') by adding Chapter 28 to establish standards and procedures to create direct access by retail customers to the competitive market for the generation of electricity, while maintaining the safety and reliability of the electric system. Specifically, the Commission was given a legislative mandate to ensure that levels of reliability that were present prior to the restructuring of the electric utility industry would continue in the new competitive markets.
In response to this legislative mandate, the Commission adopted a final rulemaking order on April 23, 1998 at Docket No. L-00970120, setting forth various reporting requirements designed to ensure the continuing safety, adequacy and reliability of the generation, transmission and distribution of electricity in the Commonwealth. See 52 Pa. Code §§ 57.191--57.197. The final rulemaking order also suggested that the Commission could reevaluate its monitoring efforts at a later time as deemed appropriate.
On June 12, 2002, the Legislative Budget and Finance Committee (LB&FC) issued a Report entitled, Assessing the Reliability of Pennsylvania's Electric Transmission and Distribution Systems. The LB&FC Report made several recommendations regarding the issue of reliability
Shortly thereafter, on July 18, 2002, at M-00021619, the Commission adopted its Bureau of Conservation Economics and Energy Planning's (CEEP) Inspection and Maintenance Study of Electric Distribution Systems dated July 3, 2002. CEEP, in part, recommended that the annual reliability reporting requirements be revised to include the causes of outages and percentages categorized by type as well as the annual reporting of each company's plans for the upcoming year's inspection and maintenance of transmission systems including: 1) vegetation management; 2) distribution and substation maintenance activity; and 3) capital improvement projects. The Commission agreed with CEEP's recommendations in this regard.
The Commission created a Staff Internal Working Group on Electric Service Reliability (Staff Internal Working Group) to conduct a reevaluation of its electric service reliability efforts. The group was comprised of members of Commission bureaus with either direct or indirect responsibility for monitoring electric service reliability. The Staff Internal Working Group prepared a report, entitled Review of the Commission's Monitoring Process for Electric Distribution Service Reliability, dated July 18, 2002, which reviewed the Commission's monitoring process for electric distribution service reliability and provided comments on recommendations from the LB&FC report. The Staff Internal Working Group report also offered recommendations for tightening the standards for reliability performance and establishing additional reporting requirements by electric distribution companies (EDCs).
On August 29, 2002, the Commission issued an Order at Docket No. D-02SPS021 that tentatively approved these recommendations and directed the Commission staff to undertake the preparation of orders, policy statements, and proposed rulemakings as may be necessary to implement the recommendations contained in the Staff Internal Working Group's report. The Staff Internal Working Group was assigned the responsibility to implement the recommendations. The Staff Internal Working Group, with the legal assistance of the Law Bureau, determined which implementation actions could be accomplished internally (with or without a formal Commission Order), and which actions will require changes to regulations.
The Staff Internal Working Group conducted field visits to EDCs to identify the current capabilities of each EDC for measuring and reporting reliability performance. These field visits began in October 2002 and continued intermittently through March 2003. As a result of the field visits, various forms of reliability reports and reliability data were received from the EDCs and analyzed by the Staff Internal Working Group to determine the most effective and reasonable approach for the Commission to monitor electric distribution service reliability.
This Rulemaking Order seeks to implement Staff Internal Working Group's recommendations and sets forth amendments to existing regulations to better govern the reliability of electric service in Pennsylvania and assure that service does not deteriorate after the Act. Specifically, we propose to substitute the term ''operating area'' with ''service territory'' thus altering the definition of a ''major event.'' Additionally, we want to require the EDCs to file quarterly reports as well as the currently required annual reports. We wish the EDCs to report additional information on their reports, i.e., worst circuit information as well as their standards and plans for inspection and maintenance of their distribution systems.
Regulatory Review
Under section 5(a) of the Regulatory Review Act (71 P. S. § 745.5(a)), on September 19, 2003, the Commission submitted a copy of the notice of proposed rulemaking, published at 33 Pa.B. 4921 (October 4, 2003), to the Independent Regulatory Review Commission (IRRC) and the Chairpersons of the House and Senate Committees for review and comment.
Under section 5(c) of the Regulatory Review Act, IRRC and the Committees were provided with copies of the comments received during the public comment period, as well as other documents when requested. In preparing the final-form rulemaking, the Department has considered all comments from IRRC, the House and Senate Committees and the public.
Under section 5.1(j.2) of the Regulatory Review Act (71 P. S. § 745.5a(j.2)), on July 28, 2004, the final-form rulemaking was deemed approved by the House and Senate Committees. Under section 5.1(e) of the Regulatory Review Act, IRRC met on July 29, 2004, and approved the final-form rulemaking.
Public Meeting held
May 7, 2004Commissioners Present: Terrance J. Fitzpatrick, Chairperson; Robert K. Bloom, Vice Chairperson; Glen R. Thomas; Kim Pizzingrilli; Wendell F. Holland
Rulemaking Re Amending Electric Service Reliability Regulations at 52 Pa. Code Chapter 57; Doc. No. L-00030161
Final Rulemaking Order By the Commission:
Today, in conjunction with our Final Order at M-00991220, we reexamine our regulations and seek to significantly improve the monitoring of reliability performance in the electric distribution industry.
Procedural History
The Electricity Generation Customer Choice and Competition Act (Act), 1996, Dec. 3, P. L. 802, No. 138 § 4, became effective January 1, 1997. The Act amends Title 66 of the Pennsylvania Consolidated Statutes (''Public Utility Code'' or ''Code'') by adding Chapter 28 to establish standards and procedures to create direct access by retail customers to the competitive market for the generation of electricity, while maintaining the safety and reliability of the electric system. Specifically, the Commission was given a legislative mandate to ensure that levels of reliability that were present prior to the restructuring of the electric utility industry would continue in the new competitive markets. 66 Pa.C.S. §§ 2802(12), 2804(1) and 2807(d).
In response to this legislative mandate, the Commission adopted a final rulemaking order on April 23, 1998 at Docket No. L-00970120, setting forth various reporting requirements designed to ensure the continuing safety, adequacy and reliability of the generation, transmission and distribution of electricity in the Commonwealth. See 52 Pa. Code §§ 57.191--57.197. The final rulemaking order also suggested that the Commission could reevaluate its monitoring efforts at a later time as deemed appropriate.
On June 12, 2002, the Legislative Budget and Finance Committee (LB&FC) issued a Report entitled, Assessing the Reliability of Pennsylvania's Electric Transmission and Distribution Systems. The LB&FC Report made several recommendations regarding the issue of reliability.
Shortly thereafter, on July 18, 2002, at M-00021619, the Commission adopted its Bureau of Conservation Economics and Energy Planning's (CEEP) Inspection and Maintenance Study of Electric Distribution Systems dated July 3, 2002. CEEP, in part, recommended that the annual reliability reporting requirements be revised to include the causes of outages and percentages categorized by type as well as the annual reporting of each company's plans for the upcoming year's inspection and maintenance of transmission systems including: 1) vegetation management; 2) distribution and substation maintenance activity; and 3) capital improvement projects. The Commission agreed with CEEP's recommendations in this regard.
The Commission created a Staff Internal Working Group on Electric Service Reliability (Staff Internal Working Group) to conduct a reevaluation of its electric service reliability efforts. The group was comprised of members of Commission bureaus with either direct or indirect responsibility for monitoring electric service reliability.
The Staff Internal Working Group prepared a report, entitled Review of the Commission's Monitoring Process For Electric Distribution Service Reliability, dated July 18, 2002, which reviewed the Commission's monitoring process for electric distribution service reliability and provided comments on recommendations from the LB&FC report. The Staff Internal Working Group report also offered recommendations for tightening the standards for reliability performance and establishing additional reporting requirements by electric distribution companies (EDCs).
On August 29, 2002, the Commission issued an Order at Docket No. D-02SPS021 that tentatively approved these recommendations and directed the Commission staff to undertake the preparation of orders, policy statements, and proposed rulemakings as may be necessary to implement the recommendations contained in the Staff Internal Working Group's report. The Staff Internal Working Group was assigned the responsibility to implement the recommendations. The Staff Internal Working Group, which included a representative from the Law Bureau, determined which implementation actions could be accomplished internally (with or without a formal Commission Order), and which actions will require changes to regulations.
The Staff Internal Working Group conducted field visits to EDCs to identify the current capabilities of each EDC for measuring and reporting reliability performance. These field visits began in October 2002 and continued through March 2003. As a result of the field visits, various forms of reliability reports and reliability data were received from the EDCs and analyzed by the Staff Internal Working Group to determine the most effective and reasonable approach for the Commission to monitor electric distribution service reliability.
On June 27, 2003, at Docket No. L-00030161, the Commission adopted the proposed regulations governing the reliability of electric service in Pennsylvania. This Proposed Rulemaking Order was published in the Pennsylvania Bulletin and the Commission received comments from the following parties: the Pennsylvania AFL-CIO Utility Caucus (AFL-CIO), Citizens' Electric Company (Citizens'), Metropolitan Edison Company (Met-Ed), Pennsylvania Electric Company (Penelec), Pennsylvania Power Company (Penn Power), PECO Energy Company (PECO), UGI Utilities, Inc.--Electric Division (UGI), Allegheny Power Company (Allegheny Power), Energy Association of Pennsylvania (EAP), the Attorney General's Office of Consumer Advocate (OCA), Pike County Light & Power Company (Pike County), and PPL Electric Utilities Corporation (PPL). Reply comments were filed by OCA, EAP and PPL. The Commission also received comments on January 21, 2004 from the Independent Regulatory Review Commission (IRRC).
Discussion
Upon due consideration of the comments, we make the following determinations regarding each amendment to the existing regulations at 52 Pa. Code §§ 57.191-- 57.197.
Amendments to existing regulations at
52 Pa. Code §§ 57.191--57.197§ 57.191 Purpose
No changes.
§ 57.192. Definitions.
Circuit and Conductor Definitions
See page 22 of this order regarding Worst Performing Circuits for discussion regarding the addition of these two definitions to the final rulemaking.
Operating Area Definition
In the Proposed Rulemaking Order we proposed deleting the definition of operating area. An ''operating area'' was defined by Section 57.192 as being, ''A geographical area, as defined by an electric distribution company, of its franchise service territory for its transmission and distribution operations.''
Some EDCs used one, system-wide operating area to compute their reliability metrics, while other EDCs subdivided their service territories and used multiple operating areas to compute their metrics. The number, size and composition of operating areas used for metric computations introduced variability into the criterion used to exclude major events from the reliability metrics reported to the Commission. An EDC that subdivided its territory into several small geographic operating areas could exclude major events from its metric calculations based on a criterion of an interruption affecting 10% of the customers in an operating area; whereas another EDC, employing only one, service territory-wide operating area had to meet a much higher criterion of an interruption affecting 10% of the total EDC customer base. We proposed that EDCs should compute and report their reliability metrics to the Commission considering the entire service territory as one operating area and the major event exclusion of an interruption that affects 10% of the entire customer base for a duration of five minutes or longer.
Positions of the Parties
PPL and the AFL-CIO filed comments in support of the Commission's proposal to substitute the term ''service territory'' for the term ''operating area.'' However, OCA urged the Commission to retain the use of operating area information for reliability monitoring purposes. OCA cites its Comments submitted in reference to our Tentative Order at Docket No. M-00991220 as support for its assertion that elimination of monitoring by operating area is not appropriate.
First Energy's Met-Ed, Penelec and Penn Power (collectively referred to as the ''FE Companies'') submitted joint comments. The FE Companies assert that reporting reliability indices on a ''system wide'' basis rather than an ''operating area'' basis is not appropriate for Penelec. The FE Companies state that since Penelec serves about 585,000 customers over an area in excess of 17,000 square miles, it is unlikely that even a severe event and widespread service interruption will affect 10% of Penelec's customers. This means that very few interruptions would be classified as ''major events.'' A reduction in major events will result in Penelec's service reliability appearing to be substantially worse than other EDCs with smaller service territories. Ultimately, the FE Companies claim that it may be difficult for Penelec to achieve its reliability standards. The FE Companies request that the proposed regulations be modified to allow Penelec to have two operating areas for purposes of determining ''major events'' and for meeting its applicable reliability indices.
Disposition
In its comments at Docket No. M-00991220, the OCA submitted that operating area information reflects how an EDC manages its distribution system and utilizes its resources within its system and that worst performing circuit reports are not a suitable proxy for operating area information. The OCA also recognized that the Staff Report noted that some EDCs defined operating areas differently for internal purposes than for PUC reporting purposes. As a result, the OCA suggested that EDCs be required to continue reporting of operating area reliability metrics using operating areas consistent with those used for internal operations and monitoring.
However, we believe that if EDCs are required to report by the operating areas they use for internal operations, then all previous years' operating area reliability metrics would need to be recomputed each time a company reconfigures its internal operations. This would make it more difficult to find pocket areas of reliability concern since a company could continually reconfigure operating areas to cover areas of concern. The circuit analysis proposed eliminates this potential problem and allows for identifying problem areas that are in need of remedial action. Therefore, we will maintain the proposed regulation as written, where companies report reliability metrics using a system wide operating area and detailed information on the worst performing circuits.
Furthermore, we deny the FE Companies' request to modify the proposed regulation to allow Penelec two service territories. We are not persuaded by the FE Companies' argument that Penelec is disadvantaged in its ability to meet its reliability indices. The Commission's recomputation of the reliability benchmarks and standards at Docket No. M-00991220 allowed for the addition of previously excluded data into the calculation of the benchmarks and standards. For example, as referenced in the M-0099120 Order, Penelec's rolling 12-month CAIDI benchmark and standard are changed from 104 and 134 to 115 and 138 respectively, due to the inclusion of outage data that historically was excluded as a ''major event.'' Additionally, the FE Companies' concern that Penelec's service reliability may appear to be worse than other EDCs' appears to be misplaced, since the proposed regulations only measure an EDC's performance against its own historic (1994-1998) performance and not against the reliability metrics, benchmarks or standards of other EDCs.
Major Event Definition
In the ''major event'' definition, all references to ''operating areas'' are replaced with the term ''service territory'' for the reasons previously outlined.
Additionally, as noted in our companion Amended Reliability Benchmarks and Standards Order at M-00991220, we require a formal process to request the exclusion of service interruptions for reporting purposes by proving a service interruption qualifies as a major event as defined by regulations. The Commission is providing EDCs with a form for requesting exclusion of data due to a major event.
Performance Benchmark and Performance Standard Definitions
In our Proposed Rulemaking Order we proposed defining a Performance Benchmark as being ''the average historical performance'' and a Performance Standard as being ''the minimum performance allowed.''
Positions of the Parties
IRRC commented that clarity could be improved by specifying that the performance benchmarks are established by the PUC based on each EDC's historical reliability performance and the performance standards are established by the PUC and tied to each EDC's performance benchmark. OCA recommended more detailed definitions of performance benchmarks and standards to include the methodology used to determine the metrics and where the numerical values for the metrics can be found. Comments provided by PPL recommended that the Commission revise the proposed definition of performance benchmark to identify the time period that was used to establish the benchmark, specifically noting the five-year period 1994-1998.
Disposition
We agree with IRRC, OCA and PPL that the definitions of performance benchmarks and standards should be expanded for clarity. Therefore, we have revised the definitions in § 57.192 as well as incorporated language previously found in § 57.194(h)(1)(2) that pertains to the measures applying to the entire service territory and the Commission's process for establishing the measures. We have also provided language that directs the reader to the Commission's Order at Docket No. M-00991220 for the specific numerical values of the performance benchmarks and standards. In addition, we will incorporate definitions of performance benchmarks and performance standards in the Commission's Order at Docket No. M-00991220 that further define the methodology for determining the measures. We will refrain from incorporating detail on the methodology for computing the performance benchmarks and standards as they may be subject to change by Commission Order in the future.
§ 57.193. Transmission system reliability.
No changes.
§ 57.194. Distribution system reliability.
Through regulations and orders, the Commission has established reporting requirements, benchmarks and standards for EDC reliability performance. Currently, EDCs report their performance on the CAIDI, SAIFI, SAIDI, and (as available) MAIFI1 indices to the Commission on an annual basis. These are generally accepted indices of EDC reliability that measure the frequency and duration of outages at the system or customer level.
The existing regulations at Chapter 57 did not establish the benchmarks or the standards for CAIDI, SAIFI, SAIDI or MAIFI for each company. Instead, the benchmarks and standards were set by Commission Order on December 16, 1999 at Docket No. M-00991220.
Revisions to the language in 57.194(e) and (h)(2)--(4) were proposed in our Proposed Rulemaking Order to clarify the Commission's expectations for reliability performance in relation to performance benchmarks and performance standards. The Commission's expectations for EDC reliability are based on language found at § 2802(12) and § 2804(1) of the Electric Generation Customer Choice and Competition Act (the Act). Section 2802(12) notes that the purpose of the Act, in part, is:
[ T ]o create direct access by retail customers to the competitive market for the generation of electricity while maintaining the safety and reliability of the electric system for all parties. Reliable electric service is of the utmost importance to the health, safety and welfare of the citizens of the Commonwealth. Electric industry restructuring should ensure the reliability of the interconnected electric system by maintaining the efficiency of the transmission and distribution system.Section 2804(1) of the Act sets forth standards for restructuring the electric industry. This section states, ''The Commission shall ensure continuation of safe and reliable electric service to all customers in the Commonwealth . . . .''
Consistent with the Act, the Commission's policy is to ensure that EDC reliability performance after implementation of the Act be at least equal to the level achieved prior to the introduction of electric choice. In a series of orders at Docket No. M-00991220, the Commission established reliability benchmarks and standards for each EDC. The benchmarks were based on each company's historic performance from 1994-1998. The benchmarks, therefore, represented each EDC's average historical reliability performance level prior to the implementation of electric choice in 1999. The Commission also established performance standards which took into account the variability in each EDC's reliability performance during the 1994-1998 period. The performance standards were set two standard deviations higher than the benchmarks (lower metric scores equal better performance) to allow for a degree of variability that inevitably occurs in reliability performance from year to year.
We stated in our Proposed Rulemaking Order:
We do not want to send the message that long-term reliability performance that just meets the performance standard is acceptable. Long-term performance that only meets the standard could be significantly worse than the benchmark and thus worse than the historical performance level that existed prior to the introduction of Electric Choice. Such performance would clearly not be consistent with the intent or language of the Act and the Commission's policy objective for maintaining reliability performance after the introduction of Electric Choice at least as good as it was prior to Electric Choice. Therefore, the Commission emphasizes that long-term reliability performance should be at least equal to the benchmark performance.Positions of Parties:
PECO and EAP commented that the Commission should clearly distinguish the consequences of a failure to meet the performance benchmarks from a failure to meet the performance standards. These commentators acknowledge that a failure to meet performance standards constitutes non-compliance by the EDC which may result in further investigation, fines, or penalties. The EAP agrees with the Commission that EDCs should manage their businesses to meet the performance benchmarks but that a failure to meet the benchmarks does not equate to a failure to meet the performance standards. The AFL-CIO recommends that the Commission should make it clear that the goal should be utility performance that equals or exceeds the performance benchmarks.
The Commission also received comments about potential compliance actions from several parties. IRRC recommends that the Commission further explain the actions it may take in response to problems identified in a quarterly reliability report. The FE Companies raise a question about whether the Commission will deem an EDC's reliability performance to be unacceptable if it is trending away from the benchmark but within the performance standard. The OCA comments the regulations should require, at a minimum, that whenever an EDC does not meet the performance benchmark on a three-year average basis, the EDC enter into a formal improvement plan with the Commission with enforceable commitments and timetables.
Disposition
In response to comments by PECO and EAP we will distinguish the consequences of a failure to meet the performance benchmarks from a failure to meet the performance standards. The Commission believes that the EDCs should strive to achieve benchmark performance as well as meet the Commission's performance standards. Therefore we will maintain the insertion of language in § 57.194(e), (h) and (h)(2) that indicates EDCs shall: (1) design and maintain procedures to achieve the reliability performance benchmarks; (2) take measures to meet the reliability benchmarks; and (3) inspect, maintain and operate its distribution system, analyze reliability results, and take corrective action to meet and achieve the reliability benchmarks. This language is consistent with the Commission's view that EDCs should set their goals to achieve or exceed benchmark performance. This viewpoint is shared in part by EAP who commented that they agree with the Commission that EDCs should manage their businesses to meet the long-term performance benchmarks and that the benchmarks provide the EDCs with an important and meaningful long-term performance target.
We will add clarifying language in § 57.194(h)(1) about the consequences of not meeting the performance standards. We state in this section that performance that does not meet the standard will be the threshold for triggering additional scrutiny and perhaps compliance enforcement. The compliance and enforcement language only pertains to instances where an EDC fails to meet the performance standards and not to instances where the EDC fails to meet the performance benchmarks. However, the Commission will carefully monitor an EDC whose reliability performance is not meeting, and is trending away from the benchmark but still falling within the standard even though this will not be cause to initiate compliance and enforcement action.
In response to IRRC's comments requesting that we explain the actions the Commission may take in response to problems identified in a quarterly reliability report, we will add language to § 57.194(h)(1) noting the types of information we may consider for compliance enforcement actions and an array of potential compliance actions the Commission may take in response to an EDC not meeting the performance standard. We view the array of potential compliance actions as among those available to the Commission for addressing noncompliance with Commission performance standards in general, whether such noncompliance comes to the attention of the Commission in a quarterly reliability report or by some other means.
In response to OCA's comments that the regulations should require a formal improvement plan when the three-year average performance standard is not met, we have included an improvement plan among the options available to the Commission for potential compliance enforcement actions. However, we have not made it a requirement in any specific circumstance. While the Commission finds there is a role for improvement plans, we want the flexibility to select an appropriate course of action.
§ 57.195. Reporting Requirements
Submission of Annual Reliability Reports--§ 57.195(a):
Under paragraph (a), we proposed that the annual reliability report be submitted by March 31 of each year. Currently, the EDCs submit reliability performance reports by May 31 following the year being reported on. If an EDC experiences poor performance in the year being reported on, five or more months pass before the Commission has the ability to determine if the EDC has sufficient corrective measures in place. At the time of receiving the performance report in the next year, it is too late for the EDC to effectively revise its reliability program to address any concerns of the Commission. Advancing the required submittal date from May 31 to March 31 of each year will ensure a timely reporting of reliability performance and review of corrective measures being implemented by an EDC if necessary.
Positions of the Parties
PPL filed comments in support of the Commission's proposal to advance the date for submission of the annual reliability report. However, PPL recommended that the Commission modify its proposed date for submission of this report from March 31 to April 30 because of the need to compile, analyze and thoroughly review the service interruption data used to prepare the annual reliability report. Allegheny Power filed similar comments noting that April 30 is also the due date of the Federal Energy Regulatory Commission (FERC) Form 1. A due date of March 31 may not allow sufficient time for EDCs to collect all necessary cost and reliability data in the format requested by the Commission. Allegheny Power also suggested that the additional month should not hinder the Commission's ability to monitor reliability since the Commission will be receiving quarterly reports. IRRC noted in its comments that given the Commission's proposal to add a quarterly reporting requirement, which will provide reliability performance information in a timely manner, the problem of the Commission being unaware of poor performance prior to receiving the annual report should be alleviated. As such, IRRC suggested that the Commission consider adopting the requests for an April 30 submission date for the more detailed annual reliability reports. The AFL-CIO strongly supports improving the timeliness of reporting reliability data.
Disposition
Both PPL and Allegheny Power have made valid arguments for adopting an April 30 submission date for the annual reliability reports. PPL and Allegheny Power recognize the importance of timelier reporting, but also note the importance of accurately collecting the data needed to prepare the annual reliability reports. Further, Allegheny Power and IRRC recognize the importance of the quarterly reporting requirements and the role quarterly reports have in conjunction with the annual reports.
The Commission agrees to adopt the request for an April 30 submission date for the more detailed annual reliability reports. As such, paragraph (a) has been revised to require an electric distribution company to submit an annual reliability report to the Commission on or before April 30 of each year.
Major Event Exclusion Reporting--§ 57.195(b)(2) and § 57.195(e)(1)
Proposed Sections 57.195(b)(2) and 57.195(e)(1) require EDCs to provide, within their annual and quarterly reports, a description of each major event occurring during the reporting year and preceding quarter that the EDCs have excluded from their reported data. The term ''major event'' is used to identify an abnormal event, for which outage data is to be excluded when calculating service reliability indices. 52 Pa. Code § 57.192.
Positions of the Parties:
PPL states that the requirement to submit a description of each ''major event'' in the EDC's annual and quarterly reliability reports is overly burdensome, redundant and costly. In support, PPL states that EDCs must submit a service interruption report, pursuant to 52 Pa. Code Section 67.1, describing each service interruption which affects 2,500 or 5% of their total customers (whichever is less) due to a single unscheduled interruption of six or more hours duration. PPL submits that under the proposed annual and quarterly reporting requirements, the EDCs will be required to submit the same information for a ''major event'' in three separate reports. As a result, PPL proposes to limit the reporting in Section 57.195 to only the dates of the ''major events'' and the number of customers interrupted.
Allegheny Power believes quarterly reporting of major events on a detailed level duplicates the current process of providing reports to the Commission as the events occur, and adds undue administration to the reporting process.
IRRC noted that several EDCs provided comments indicating that the quarterly and annual reporting of ''major events'' duplicates information filed by the EDCs in the existing service interruption reports under 52 Pa. Code Section 67.1. IRRC believes the PUC should review this proposed regulation in comparison to other existing reporting requirements, and where appropriate, eliminate redundancies. Further, IRRC suggested the Commission further explain the actions it may take in response to problems identified in a quarterly report.
Disposition:
52 Pa. Code Section 67.1 requires utilities to provide notification to the Commission when 2,500 or 5% of its customers (whichever is less) are without service for 6 hours of more. 52 Pa. Code Section 57.192 defines a major event as at least 10% of the customers being without service for at least 5 minutes. Obviously, there is the potential for 2,500 customers to be out of service for more than 6 hours, thus requiring a Section 67.1 report, 52 Pa. Code § 67.1, even though that event would most likely not fulfill the requirements to be classified a major event. Conversely, there is the potential for large numbers of customers to be out of service for less than 6 hours. In this case, the major event criteria may be met, but a Section 67.1 report would not be required. Contrary to PPL's assertion that these types of events are unlikely, they can and have occurred. Thus, tying major event reporting to the Section 67.1 reports does not accomplish this Commission's attempt to ensure the application of 52 Pa. Code Sections 57.195(b)(2) and 57.195(e)(1) in a timely and consistent manner.
Further, PPL and Allegheny Power have characterized the requirement to submit major event exclusion reports as costly and time consuming. However, neither has presented any reasoning for these assertions. In fact, PPL points out the similarities between the information required for Section 67.1 and Sections 57.195(b)(2) and 57.195(e)(1). This Commission is not aware of any arguments that compliance with the currently effective Section 67.1 regulation is costly and burdensome to utility operations. We therefore find PPL's and Allegheny Power's assertions to be without merit.
Regarding what actions we will take in response to problems identified in a quarterly report, we reiterate what we stated in our companion Order regarding Benchmarks and Standards at M-00991220. The Commission will not take compliance enforcement action against any EDC that meets its performance standard. However, once a standard is violated, Commission staff will carefully review all information presented in the EDC's quarterly and annual reliability reports including the EDC's causal analysis, inspection and maintenance goal data, expenditure data, staffing levels and other supporting information and Section 67.1 reports to determine appropriate monitoring and enforcement actions. Depending upon the findings of this review, we may consider a range of compliance actions including engaging in additional remedial review, requiring additional EDC reporting, conducting an informal investigation, initiating a formal complaint, requiring a formal improvement plan with enforceable commitments and an implementation schedule, and assessing penalties and fines.
While overall system performance trends that fall within the range between the benchmark and standard will not be subject to compliance enforcement, the Commission will keep EDCs whose performance is within the standard, but trending away from the benchmark, under review as a precautionary measure.
MAIFI Data--§ 57.195(b)(3), § 57.195(e)(2), and § 57.195(e)(3)
With the increase in the use of more technologically advanced appliances and electrical equipment such as computers, customers are becoming more aware of momentary interruptions. The frequency in which momentary interruptions occur is measured by the Momentary Average Interruption Frequency Index (MAIFI). The requirement to report MAIFI data is discussed in three areas under § 57.195 Reporting Requirements. Paragraph (b) lists different information to be provided in the annual reliability report for EDCs having 100,000 or more customers. Included in this list under subparagraph (3) is the reporting of actual values for MAIFI and the data used to calculate this index, if this data is available. Likewise, paragraph (e) lists different information to be provided in the quarterly reliability reports for EDCs having 100,000 or more customers. Subsections (2) and (3) include the reporting of MAIFI data, if it is available. There are EDCs that do not currently have the necessary equipment to collect this data. Other EDCs have indicated that the equipment needed to collect MAIFI data is not currently in place throughout their entire systems. In recognition of this constraint, the reporting of MAIFI data is to be provided if it is available.
Positions of the Parties
Allegheny Power agrees with the Commission's proposal for EDCs to submit MAIFI data on an ''as available'' basis, and notes that its field equipment does not provide meaningful data for momentary interruptions. Comments filed on behalf of the FE Companies mention that most EDCs do not maintain MAIFI statistics and, for those that do, there is no consistent or uniform protocol for gathering and reporting this information. The FE Companies assert there is a likelihood that the MAIFI numbers will be inaccurate for an individual company and highly misleading if data from two or more EDCs is compared. Therefore, they do not believe MAIFI information should be reported at all.
Disposition
The Commission's purpose in reviewing MAIFI data is not to compare MAIFI performance among the EDCs, but rather to assess how frequently momentary interruptions are affecting the customers of a particular EDC and take note of any remedial actions that the EDC believes are necessary to reduce the frequency of those interruptions. We will therefore keep the reporting requirement for MAIFI data if it is available. If MAIFI data is not currently collected and used, an EDC can simply state that fact in the reports. For EDCs that collect MAIFI data and use it in conjunction with other reliability performance measures (e.g., SAIFI, CAIDI, etc.), the MAIFI data should be included in the reports. For EDCs that collect MAIFI data only on a limited basis, the EDCs can explain how MAIFI data is collected and used along with an explanation as to why they believe the reporting of MAIFI data may not accurately reflect MAIFI performance for their systems and/or at the circuit level.
Causes of Interruptions--§ 57.195(b)(4)
Paragraph (b), subsection (4) requires EDCs to report a breakdown and analysis of outage causes during the year being reported on, including the number and percentage of service outages and customer interruption minutes categorized by outage cause such as equipment failure, animal contact, and contact with trees. Proposed solutions to the identified service problems are to be reported as well.
Positions of the Parties
The FE Companies noted that they can provide a ''breakdown'' of the causes of outages as required, but it is unclear to them what further ''analysis'' is intended or required. In order to avoid confusion or a possible issue about non-compliance, the FE Companies request that the word ''analysis'' be eliminated from this subsection. PPL recognizes the Commission's need for causal information; however, because the definitions of outage causes differ among the EDCs, PPL noted that caution should be used if comparisons among EDCs are being considered for causal analysis.
Disposition
First we will address the FE Companies' uncertainty with regard to the Commission's requirement for an ''analysis.'' EDCs compile causal data in order to identify the most common causes of service interruptions in their systems. In addition to this identification of service interruption causes, the EDCs typically perform some type of analysis to determine what the contributing factors are behind a particular type of cause. For example, an EDC may have experienced an increase in the number of equipment-related interruptions, and upon further analysis, the EDC determines that the main contributor to these equipment-related interruptions is a certain type of equipment that has malfunctioned. Another example is the differentiation between tree-related outages that occur on rights-of-way versus off right-of-ways. EDCs have more control over the prevention of tree-related interruptions on rights-of-way than off right-of-ways. An EDC's causal data may indicate that trees were the primary cause of service outages. However, upon further analysis, it may be determined that only a small number of tree-related outages occurred on rights-of-way and therefore were preventable. This type of analysis would be included with the breakdown of outage causes proposed under paragraph (b)(4), as well as the proposed solutions, if any, to the identified service problems.
Such an analysis will also address some of the concerns that PPL has made regarding comparison of outage causes among the EDCs. The purpose of obtaining this information is not to compare the causes of interruptions among EDCs, but rather to identify what the primary causes are for service interruptions experienced by an EDC and to determine which causes, if any, can be prevented in the future through proposed solutions. The Commission would like to further clarify the details to be reported under paragraph (b)(4). Included with the breakdown of outage causes during the year being reported on is to be the number and percent of service outages, the number of customers interrupted, and the customer interruption minutes categorized by outage cause such as equipment failure, animal contact, tree related, and so forth. Proposed solutions to identified service problems shall be reported. The Commission will retain the requirement for an analysis concerning the breakdown of service interruption causes proposed under paragraph (b)(4).
Worst Performing Circuits--§ 57.195(b)(5) and § 57.195(e)(3--4)
Since the Commission desires to examine electric reliability on a service territory basis, rather than on an operating area basis, we had determined that a review of the worst performing circuits would be an appropriate approach to monitoring the efforts of the EDCs to improve service performance in specific areas of the service territory. It was therefore proposed in Section 57.195(e)(3) that EDCs report the worst performing 5% of the circuits in the system on a quarterly basis. In addition, we had proposed that the EDCs include in their annual report a list of the remedial efforts that have been taken or are being planned for the circuits that have been on the list of worst performing circuits for a year or more.
Positions of the Parties
The AFL-CIO suggests that the definition of a circuit be added to the regulation. They suggest incorporating the definition of a circuit from the National Electrical Safety Code: ''a conductor or system of conductors through which an electric current is intended to flow.'' (IEEE, National Electrical Safety Code, 1997 Edition, section 2 (definitions of special terms).) Conductor, in turn, is defined as ''a material, usually in the form of a wire, cable, or bus bar, suitable for carrying an electric current.'' In its Reply Comments, the Energy Association concurs with the AFL-CIO concerning this proposed addition to the regulation.
PPL recommends that the proposed reporting requirement at Section 57.195(b)(5) be revised as follows: ''A list of the major remedial efforts taken to date and planned for circuits that have been on the worst performing 5% of circuits list for a year or more.'' In support of this, PPL submits that although it tries to identify all repair work performed, there may be situations where additional work is performed because a crew identifies a specific problem while on routine patrol. That work, because of its general nature, may not be tracked. However, the work may result in a performance improvement to the circuit.
Allegheny Power states that providing a list of the 5% worst performing circuits more frequently than annually is not practical. Allegheny states that action plans are established for circuit reliability on an annual basis based upon trends and that quarterly circuit reporting is not useful.
The FE Companies aver that the worst performing circuits may not necessarily involve large numbers of customers or warrant higher priority for remediation than other circuits not on the 5% list. The FE Companies state that since much of the companies' service territory is rural in nature, it is not unusual for the worst performing circuits to be rural lines serving a couple of hundred customers. They request that the proposed regulations explicitly recognize that these types of lines could appear on the worst performing circuit list more often than non-rural lines, but the cost to achieve standard reliability performance levels for these lines could be substantial, and may not be justifiable. Further, the FE Companies maintain that the Commission should not interject itself into the day to day business judgments about how and when to address the worst performing circuits.
PECO submits that neither the proposed statutory language nor the discussions in the Tentative Order and Proposed Rulemaking provide clear insight into what the Commission expects from the EDC's worst performing circuit reports and programs. PECO states that EDCs have different worst performing circuit programs and acknowledges that it is difficult to draft statutory language that not only provides sufficient guidance on what is expected but also retains the flexibility needed to accommodate the EDCs' varied programs. PECO supports the EAP's suggestion that to effectively meet the Commission's monitoring goal and provide sufficient guidance to the EDCs while retaining the requisite flexibility, the proposed regulation should be modified to provide that the worst performing circuits report should: (1) describe the EDC's worst performing circuit program, (2) list the 5% worst circuits and (3) describe the EDC's performance relative to its worst performing circuits program.
In its comments, the EAP suggests that the proposed regulation regarding worst performing circuits is impermissibly vague, has already been ruled by the Commission to be of little or no value, and has also been interpreted as such by other Commissions as well.
In its Reply Comments, the OCA disagrees with the EAP's request to remove the proposed worst performing circuits reporting requirement. The OCA submits that PECO best summarized the value of worst performing circuit information to the EDC by stating the following:
PECO Energy, for example, has long recognized that it can achieve the dual objectives of improving system reliability indices and reducing the likelihood of customer complaints: (1) by examining in detail the reliability history of the 5% of its circuits on which the largest share of customer service interruptions occur; and (2) concentrating its efforts on improving the reliability of those circuits. The specific circuits change from year to year, but PECO Energy and many other EDCs have found that remedial attention to 5% of its circuits each year is a cost-effective and manageable way to improve reliability. (PECO Comments, p. 11-12).The OCA, in addressing the EAP's comment, notes that the Commission previously rejected the reporting of worst performing circuit information when it ruled that reporting of operating area information would be required. Here the Commission is proposing to replace operating area information with the worst performing circuit information.
The OCA recommends that the Commission consider the recommendations for clarification of the reporting requirement and the need for flexibility so that the reporting requirement reflects the EDC's worst performing circuit program. The reporting requirement should be structured to minimize the burden on the EDCs and to match each EDC's worst performing circuits program.
Disposition
We agree with the AFL-CIO and the EAP that the definition of a circuit needs to be established. Therefore, we will adopt the AFL-CIO suggestion that the National Electrical Safety Code definition of a circuit be added to the regulation. We will add the following to Section 57.192:
Circuit--a conductor or system of conductors through which an electric current is intended to flow.Conductor--a material, usually in the form of a wire, cable, or bus bar, suitable for carrying an electric current.Additionally, we accept PPL's reasoning in its request for a modification to the proposed reporting requirement at Section 57.195(b)(5) to include the reporting of only major remedial efforts on the worst performing circuits list. The proposed regulation at Section 57.195(b)(5) is modified to read:
(5) A list of the major remedial efforts taken to date and planned for circuits that have been on the worst performing 5% of circuits list for a year or more.In response to EAP's, Allegheny Power's and the FE Companies' assertions that the submission of worst performing circuits data provides no useful information to the Commission in its review of an EDC's reliability and FE Companies' assertion that the Commission should not interject itself into the day to day business judgments about how and when to address the worst performing circuits, we reiterate that analysis of an EDC's worst performing circuits is only one aspect of reliability that is proposed to be reviewed by the Commission. Analysis of an EDC's worst performing circuits, along with an integrated analysis of all other quarterly and annual data, will be used to perform a review of an EDC's reliability performance. Moreover, we direct the respondents to the Commission's Final Order at Docket No. M-00991220. The section of the Order that discusses the Commission's potential enforcement actions provides additional support and explanation for our position on this issue. Finally, we find the OCA's discussion in this matter compelling as well.
We acknowledge PECO's comments that the regulation should be modified to include a (1) description of the EDC's worst performing circuit program, (2) listing of the 5% worst circuits and (3) description of the EDC's performance relative to its worst performing circuits program; but we observe that Sections 57.195(e)(3--4) already require that information. Therefore, we see no need to modify the proposed regulations, since the requested modifications are already subsumed within the proposed regulations.
Reporting of T & D Inspection and Maintenance Goals and Program Changes, and T & D Operation, Maintenance and Capital Expenditures--§ 57.195(b)(6--12), (c), and (e)(6--8)
As noted in the Proposed Rulemaking Order, a staff study completed by the Bureau of CEEP recommended that the EDCs be required to submit documentation on transmission and distribution (T & D) inspection and maintenance activities in lieu of the Commission prescribing specific standards for those activities. Thus, in paragraphs (b)(6, 9, 12) of the regulations outlining the contents of the annual reliability report for large EDCs, we proposed that they provide a comparison of budgeted T & D inspection and maintenance goals/objectives to actual results achieved for the year being reported on, budgeted goals/objectives for the current year, and any significant changes to the inspection and maintenance programs previously submitted. Smaller EDCs are to provide similar annual information per paragraph (c). We also proposed, in paragraph (e)(6) relative to the new quarterly reliability reports, that the large EDCs submit quarterly and year-to-date information on their progress in meeting the inspection and maintenance goals/objectives that would be provided to the Commission via the annual report. It was felt that further reporting requirements in this area would assist the Commission staff in assuring that the EDCs are actively engaging in and carrying out plans that have a direct impact on reliability.
In addition to the inspection and maintenance data, proposed paragraphs (b)(7, 8, 10, 11) relative to the annual reliability report require that the large EDCs provide comparisons of budgeted to actual T & D operation and maintenance (O & M) expenditures and T & D capital expenditures for the year being reported on, as well as budgeted T & D O & M expenditures and capital expenditures for the current year. Again, paragraph (c) requires similar annual information for the smaller EDCs. For the quarterly reliability report, we proposed in paragraphs (e)(7--8) that only the large EDCs submit quarterly and year-to-date information on budgeted versus actual T & D O & M and capital expenditures. This expenditure data, along with the inspection and maintenance data, would provide Commission staff with a informed and timely perspective on the commitment of resources for system maintenance and upgrades.
Positions of the Parties
PECO, the FE Companies, Allegheny Power, UGI, and EAP take issue with the requirements to report on T & D inspection and maintenance goals/objectives, and T & D operations and maintenance and capital expenditures. They generally believe that such information is proprietary, that it does not provide any meaningful insight into (or does not necessarily have a direct relationship to) reliability performance, and that it should only be required upon identification of an actual reliability problem. The parties further argue that the requested information is subject to wide variations over the course of a year, inasmuch as an EDC's business plans and priorities can and do change. They are specifically concerned that tracking variances in this information could be highly misleading and could put the Commission in the inappropriate position of second guessing or micro-managing an EDC's routine business judgments. Citizens', while noting that it is important to assign a cost to efforts aimed at improving reliability, feels that the annual reporting of inspection and maintenance data and expenditure data is burdensome.
IRRC recommends that the Commission specify the procedures for identifying and protecting the confidentiality of the proprietary information provided. IRRC further questions whether we have considered allowing the reporting of the transmission and distribution operation and maintenance expenses and capital expenditures in an alternate format than the Federal Energy Regulatory Commission (FERC) account format in order to accommodate EDC operational practices. IRRC believes the PUC should either specify the acceptable alternate formats in the final-form regulation or include a cross-reference to the procedures outlined in 52 Pa. Code § 1.91 (relating to Applications for waiver of formal requirements).
Notably, with some relatively minor exceptions, PPL did not take issue with providing the inspection and maintenance data nor the expenditure data for the periods requested, and made no claim that this particular information is proprietary. Moreover, the remaining large EDC, Duquesne Light, filed no comments opposing the submission of the data. Comments filed by the AFL-CIO support all of the proposed reporting requirements, but suggest that the inspection and maintenance goals/objectives be supplemented by enforceable inspection, maintenance, repair, and replacement standards. The OCA commented that the proposed regulations vastly improve the reporting requirements, and feels that we should go even further by requiring the EDCs to submit comprehensive T & D maintenance plans to the Commission annually and provide their customers with an annual report on reliability performance. This would be in addition to the annual report that the Commission is proposing to issue under § 57.195(j).
Several parties, including the FE Companies, Allegheny Power, PPL, and EAP, indicated in their comments that many EDCs do not budget either T & D O & M expenditures or capital expenditures by FERC account. We had proposed the annual reporting of such budget information under paragraphs (b)(10--11), with obvious carryover implications for all budget to actual comparisons to follow under (b)(7--8) and (e)(7--8). PPL suggests that we modify these reporting requirements to allow for budget information by functional activity.
In joint reply comments filed by the FE Companies, they reject OCA's suggestion that the EDCs be required to submit an annual report to customers. They argue that the amount of, and confidentiality of, data to be included in such a report via bill inserts (or the like) would render the idea undoable. The EAP, in its reply comments, argues that the budget to actual data comparisons, and OCA's proposed annual reports to customers, have little or no probative value to the Commission's ability to analyze reliability performance. It therefore has offered revisions to the proposed regulations that would eliminate the budget to actual expenditure data from the annual reliability reports of all EDCs and from the quarterly reports of the larger EDCs. The quarterly comparisons of inspection and maintenance goals/objectives to actual results achieved would also be eliminated for large EDCs.
The OCA states in its reply comments that, despite the EDC claims to the contrary, the additional information requested by the Commission is related to reliability and can be very useful to the Commission in meeting its monitoring obligations. Further, the OCA feels there is no basis for keeping this information from the public view since it is often part of a base rate case filing and thus often subject to significant public scrutiny. In the OCA's view, the ratepayers have a right to know how their dollars are being spent and whether they are receiving adequate service at a reasonable cost.
Disposition
The Commission will retain its proposal to have the EDCs report on their T & D inspection and maintenance goals/objectives as provided for in § 57.195(b)(6), (9), (c) and (e)(6).2 Although we are not prescribing enforceable inspection, maintenance, repair and replacement standards for EDCs as favored by the AFL-CIO nor requiring comprehensive T & D maintenance plans as suggested by the OCA, we do believe it is vital for each company to establish and carry out individual goals/objectives for these activities. Such goals and objectives provide a ''game plan'' for completing inspection and maintenance efforts throughout the year, and thus are directly related to short-term and long-term reliability performance. The Commission desires to monitor the accomplishment of each large EDC's plan at various points during the year as a way of ensuring that reliability matters remain a priority. We recognize, and concur with some of the commentators, that the best-laid plans will change in a year's time due to any number of unforeseen events. However, requiring that large EDCs report their progress against the established goals and objectives on a quarterly basis will ensure that Commission staff has more timely knowledge of these unforeseen events and their potential impact on reliability performance. Waiting until there is an actual reliability problem to get the data (as favored by the some of the industry parties) is not acceptable. Moreover, it is inconsistent with one of the LB&FC's recommendations that the Commission be more proactive in its approach to monitoring reliability.
We note that similar to the O & M and capital expenditure quarterly data proposed under paragraphs (e)(7--8), the quarterly and year-to-date information for the inspection and maintenance goals/objectives required under paragraph (e)(6) of the regulations need only be submitted for the first, second, and third quarters. The necessary wording to convey our intentions in this regard had inadvertently been omitted from the Tentative Order.
The Commission will also retain its proposal to have the EDCs report their T & D O & M and capital expenditure data as provided for in § 57.195(b)(7, 8, 10, 11), (c), and (e)(7, 8). We concur with several of the commenting parties that increases or decreases in O & M and/or capital expenditures can occur from quarter to quarter or year to year for a variety of reasons that are not directly related to reliability. However, we cannot agree with some of the parties that this data does not provide any meaningful insight into reliability performance. This would only be true if such data were being looked at in a vacuum and were only provided in summary amounts. The Commission seeks to have the EDCs report both budgeted and actual O & M and capital expenditures in the level of detail that is already reported to operations management personnel on an annual and quarterly basis. This level of expenditure data, when evaluated side by side with other data on inspection and maintenance goals and objectives, staffing levels, contractor usage, and outage causes, can be very useful for gaining a perspective on, and ascertaining trends in, reliability investment by the EDC. Our intent is not to micro-manage or second-guess management as suggested by certain parties, but to be fully informed about reliability matters in a timely manner. Again, waiting until there is an actual problem to obtain this information does not fulfill our regulatory obligation to proactively monitor reliability at the EDCs.
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1 CAIDI is Customer Average Interruption Duration Index. It is the average interruption duration of sustained interruptions for those customers who experience interruptions during the analysis period. CAIDI represents the average time required to restore service to the average customer per sustained interruption. It is determined by dividing the sum of all sustained customer interruption durations, in minutes, by the total number of interrupted customers. SAIFI is System Average Interruption Frequency Index. SAIFI measures the average frequency of sustained interruptions per customer occurring during the analysis period. SAIDI is System Average Interruption Duration Index. SAIDI measures the average duration of sustained customer interruptions per customer occurring during the analysis period. MAIFI (Momentary Average Interruption Frequency Index) measures the average frequency of momentary interruptions per customer occurring during the analysis period. These indices are accepted national reliability performance indices as adopted by the Institute of Electrical and Electronics Engineers, Inc. (IEEE), and are defined with formulas at 52 Pa. Code § 57.192.
2 See Attachment A to the Tentative Order entered on June 27, 2003 at Docket No. M-00991220 for a report in the form preferred by the Commission.
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