RULES AND REGULATIONS
Title 52--PUBLIC UTILITIES
PENNSYLVANIA PUBLIC UTILITY COMMISSION
[ 52 PA. CODE CH. 57 ]
[38 Pa.B. 5273]
[Saturday, September 27, 2008][L-00040167/57-248]
Inspection and Maintenance Standards for Electric Distribution Companies The Pennsylvania Public Utility Commission (Commission) on May 22, 2008, adopted a final-form rulemaking order which implements minimum inspection, maintenance, repair and replacement standards on electric distribution companies (EDCs) operating in this Commonwealth.
Executive Summary
Section 4 of the Electricity Generation Customer Choice and Competition Act (Act), December 3, 1996 (P. L. 802, No. 138) (Act) became effective January 1, 1997. The Act amends 66 Pa.C.S. 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, 66 Pa.C.S. § 2802(20) provides:
(20) Since continuing and ensuring the reliability of electric service depends on adequate generation and on conscientious inspection and maintenance of transmission and distribution systems, the independent system operator or its functional equivalent should set, and the commission shall set through regulations, inspection, maintenance, repair and replacement standards and enforce those standards.In our final rulemaking order entered May 20, 2004, at L-00030161 Rulemaking Re Amending Electric Service Reliability Regulations at 52 Pa. Code Chapter 57, Final Rulemaking Order, the Commission declined at that time to require specific inspection and maintenance standards reasoning that technological advances continue to improve the inspection and testing process. The Commission asked companies to report their own internal inspection and maintenance standards. The Commission measured the EDCs' progress towards meeting their individual goals and considered this information along with whether the EDCs were meeting their reliability standards to determine whether service was deteriorating or not within a given service territory due to the fault of the EDC.
After the blackout of August 2003, new information arose which caused this Commission to reevaluate the need for specific inspection and maintenance standards. One of the causes of the blackout was the failure of FirstEnergy Corporation to adequately manage tree growth along transmission lines. Final Report on the August 14 Blackout in the United States and Canada, U.S.--Canada Power System Outage Task Force, pp. 17, 57-64 (April 2004).
This final rulemaking order seeks to implement minimum inspection, maintenance, repair and replacement standards on electric distribution companies operating in Pennsylvania. The Commission proposes to require an initial inspection and maintenance plan for upcoming calendar years due by October 1, 2009, for Compliance Group 1 and October 1, 2010, for Compliance Group 2 which shall cover the two calendar years beginning 15 months following October 1. The plan must cover 2 years, and must be filed biennially. The plan must detail a program for the maintenance of electric distribution facilities including: poles, wires, conduits or other fixtures, along public highways or streets for the distribution of electric current, owned, operated, managed or controlled by the company in a format the Commission staff prescribes. These plans are subject to acceptance or rejection by the Commission or its Bureau of Conservation, Economics and Energy Planning if the minimum inspection and maintenance intervals as outlined in Annex A, proposed in § 57.198(n) are not included in the plans without justification. Annex A contains minimum standards for vegetation management, pole inspections, distribution overhead line and transformer inspections, recloser inspections, and substation inspections.
Public Meeting held
May 22, 2008Commissioners Present: Wendell F. Holland, Chairperson; James H. Cawley, Vice Chairperson; Tyrone J. Christy; Kim Pizzingrilli
Revision of 52 Pa. Code Chapter 57 Pertaining
to Adding Inspection, Maintenance, Repair, and
Replacement Standards for Electric Distribution
Companies; Docket No. L-00040167
Final Rulemaking Order By the Commission:
In this final rulemaking order, the Commission is adopting final-form regulations designed to improve the monitoring and achievement of reliability performance in the electric distribution industry by establishing inspection, maintenance, repair and replacement standards (''I & M standards'') and creating a new regulation at 52 Pa. Code § 57.198, requiring biennial filings regarding companies' inspection, maintenance, repair and replacement plans (''I & M plans'') that fit within the standards' intervals.
Since the Electricity Generation Customer Choice and Competition Act (Act), 1996, December 3, P. L. 802, No. 138 § 4, became effective January 1, 1997, we have been examining the EDCs' inspection, maintenance, repair and replacement internal standards and have been evaluating what kind of standards to implement through regulations in order to comply with the 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) and (20), 2804(1) and 2807(d).
By this regulation, beginning October 1, 2009, the EDCs shall be required to biennially file, on or before October 1st every other year, I & M plans explaining their plans for inspection, maintenance, replacement and repair for the upcoming calendar year. The regulation also establishes I & M standards for a variety of activities such as vegetation management, pole inspections, overhead line inspections and substation inspections, based on current industry practices and the comments submitted in this rulemaking proceeding.
However, the regulation will allow the individual EDCs to deviate from the standards set forth in the regulation, provided that such deviation can be justified based on utility-specific circumstances or a cost/benefit analysis. In this fashion, where compliance with a given I&M standard for a specific EDC would not be prudent or cost/benefit justified, the EDC may deviate from that standard provided that it can adequately justify the different I & M interval or approach.
The Commission, therefore, finds that this final-form regulation will comply with the requirements of Chapter 28 and our fundamental obligations to ratepayers of Pennsylvania to maintain adequate service reliability without imposing unjustified costs.
I. Procedural History
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 permit 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. These reporting requirements included, inter alia, descriptions of each major event affecting reliability, the achieved values on various reliability indices (SAIFI, CAIDI, SAIDI and MAIFI), analysis of major outages during the study, and a list of remedial efforts taken for the EDC's worst performing 5% of circuits. However, while the EDCs were obligated to report on their inspection and maintenance goals and actual results, the regulation contained no standards by which those practices would be measured. 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 including: revising and enhancing EDC reliability reporting requirements and performance monitoring standards, clarifying reporting requirements regarding the exclusion of data for major events, requiring formal waivers for EDCs unable to comply with all reporting requirements, and completing the pending inspection and maintenance study by our staff.
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 planned inspection and maintenance activities 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 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 determined which implementation actions could be accomplished internally (with or without a formal Commission order), and which actions will require changes to regulations.
On June 27, 2003, at Docket No. L-00030161, the Commission adopted proposed regulations governing the reliability of electric service in Pennsylvania. On May 7, 2004 a final rulemaking order was entered at Docket No. L-00030161 Rulemaking Re Amending Electric Service Reliability Regulations at 52 Pa. Code Chapter 57. While the Commission did increase its reporting requirements of the EDCs, the Commission declined at that time to require specific inspection, maintenance and repair standards reasoning that technological advances continue to improve the inspection and testing process. The Commission asked companies to progress towards meeting their individual goals and considered this information along with whether the EDCs were meeting their reliability standards to determine whether service was deteriorating or not within a given service territory due to the fault of the EDC.
However, after the blackout of August 14, 2003, new information arose which caused this Commission to reevaluate the need for specific inspection and maintenance standards to supplement its existing measures to ensure reliability. In particular, the Commission observed that one of the fundamental causes of the blackout was the failure of FirstEnergy Corporation to adequately manage tree growth along transmission lines. Final Report on the August 14 Blackout in the U.S. and Canada, Canada Power System Outage Task Force, pp. 17, 57-64 (April 2004). The Commission also took note of the language in Section 2802(20) of the Public Utility Code which appears to mandate, through regulations, the establishment of ''inspection, maintenance, repair, and replacement standards'' to ensure the reliability of electric service in Pennsylvania. 66 Pa.C.S. § 2802(20).
On April 20, 2006, the Commission adopted a proposed rulemaking order seeking to implement proposed minimum inspection, maintenance, repair and replacement (''I&M'') standards on EDCs. The comment deadline was extended in order to hold a technical conference at the Commission on January 22, 2007. Presentations were offered by two panels at the technical conference. The first panel consisted of the Office of Consumer Advocate and AFL-CIO--Utilities Caucus that generally supported the proposed regulations. The second panel consisted of UGI Utilities, Duquesne Light Company, Allegheny Power, PPL Electric Utilities Corporation, PECO Energy Company and FirstEnergy. The second panel generally agreed with a requirement to submit I & M plans, but disputed the proposed regulations regarding setting minimum I & M standards.
At the technical conference Commission staff asked questions of the presenters, and supplemental responses to some data requests and other comments were timely submitted by April 16, 2007, by many interested parties including: the Attorney General's Office of Consumer Advocate (OCA), AFL-CIO Utility Caucus (AFL-CIO), Pennsylvania Utility Contractors Association (PUCA), Office of Small Business Advocate (OSBA), Citizens' Electric Company (Citizens'), Wellsboro Electric Company (Wellsboro), Metropolitan Edison Company (Met-Ed), Pennsylvania Electric Company (Penelec), Pennsylvania Power Company (Penn Power)1 , PPL Electric Utilities Corporation (PPL), PECO Energy Company (PECO), UGI Utilities, Inc.--Electric Division (UGI), Allegheny Power Company (Allegheny Power), Energy Association of Pennsylvania (EAP), Pike County Light & Power Company (Pike County), and the IECPA.2 The Commission also received comments on May 16, 2007 from the Independent Regulatory Review Commission (IRRC) and Senator Robert M. Tomlinson.
Our Proposed Rulemaking Order added a regulation at 52 Pa. Code § 57.198 which proposed minimum standards regarding vegetation maintenance, pole, line, reclosers, sub-station inspections, maintenance and repair standards as well as directing EDCs to file biannually plans with annual updates in compliance with the minimum standards.
II. Discussion of General Comments
Comments of the Energy Association of Pennsylvania (EAP)
The EAP commented that the Commission has already mandated, by its existing regulations, reliability performance benchmarks that an EDC must satisfy and that this ensures a reliable distribution system. The Commission has numerous opportunities to review system performance through quarterly and annual reliability reports, customer complaints, customer satisfaction surveys and individual company meetings. Additionally, the Commission can review EDCs' Operation and Maintenance practices through the mandated management effectiveness and operating efficiency audits that must be conducted not less than every 8 years.
The EAP stated that the proposed rulemaking has moved forward without the industry expertise or cost/benefit analysis to support the requirements. The EAP estimates that if the proposed regulations are implemented, the added expense to Pennsylvania ratepayers over and above current inspection and maintenance practices will exceed at least $75 million per year with little or no assurance of improved electric service reliability. EAP alleges that proposal would increase the overall EDCs' operations and maintenance expenses 6.3% without a cost effective result for improving reliability. If mandated, the EDCs would eventually recover their increased operating costs through increased rates. EAP states that the needless increase in cost to the consumer could result in industrial job losses because of the increased electricity prices, the relocation of industry out-of-state, or not investing in present facilities.
The EAP states that there are no studies to support a conclusion that the proposed standards will improve distribution service reliability to Pennsylvania customers. Also, the recently adopted regulations which tightened the Commission's monitoring of EDCs should be given a chance to work before additional needless regulations are imposed upon the EDCs.
Additionally, the EAP claims that Federal Energy Regulatory Commission (FERC) has asserted jurisdiction over all EDC transmission plants. Promulgating regulations governing the transmission plant is legally impermissible, as it is outside the jurisdiction of this Commission. Mandated standards will exacerbate an EDC's trained worker resources shortage and will result in an increase in labor costs for EDCs because of the shortage of trained work force resources. Furthermore, the EAP alleges that 87% of tree-caused customer outages are caused by trees from outside the EDCs' right-of-way over which EDCs have limited control, and these proposed regulations would have no impact on decreasing these out-of-right-away outages. Thus, no substantial reliability would be improved.
Comments of the Pennsylvania Utility Contractors Association (PUCA)
The PUCA commented to our Advance Notice of Proposed Rulemaking that it represents 300 contractors, subcontractors and suppliers throughout Pennsylvania and it believes standards should be established for repair and maintenance of the EDC equipment or facilities critical for system reliability and for the safety of their workers.
Comments of Allegheny Power (AP)
AP commented that standardized industry-wide inspection and maintenance standards are not necessary in order for the Commission to ensure reliable electric delivery in Pennsylvania. AP agreed that it is appropriate for the Commission to require submittal of an EDC's individual plan of inspection and maintenance programs.
Comments of Wellsboro and Citizens'
Wellsboro and Citizens' jointly commented that they have voluntarily been replacing transformers and constructing transmission lines due to their obligations under the Public Utility Code to provide safe, adequate and reliable service to their customers and additional regulatory mandates for specific inspection, maintenance and repair or replacement activities should not be imposed. Citizens' and Wellsboro support the EAP's comments relating to desired flexibility in meeting reliability obligations rather than mandatory Commission-imposed cycles that may not result in cost-effective enhancements to service reliability.
Comments of UGI Utilities, Inc.--Electric Division (UGI)
The UGI is a small EDC and it commented that the Commission should consider carefully the costs and benefits of its proposed regulations at a time when rate caps expire and the EDCs' costs will again be scrutinized. UGI notes that it has been a good performer in reliability indices reports and the proposed regulations would not necessarily have any impact on reliability for the company. Out of the total aggregate industry-wide increase in costs, UGI predicts its cost increase would be $2 million. The compliance cost would increase the UGI's current maintenance expenses by 25% and cost recovery would cause the UGI's transmission and distribution rates to increase by approximately 6%.
The UGI states there is little evidence to indicate the proposed standards will benefit the UGI customers and that the current reliability standards are sufficient to regulate the UGI's performance. As an alternative to the proposed I & M standards, the UGI proposes requiring the EDCs to submit biannual I & M plans which would enable the Commission to monitor the means by which EDCs are ensuring their compliance with the reliability benchmarks and standards without incurring unnecessary costs.
Comments of FirstEnergy
The FirstEnergy companies commented that the proposed standards hinder the EDCs' ability to implement an effective and cost-efficient plan based on the specific circumstances of the EDC. Not only will inspection and maintenance needs vary depending on the system configuration, design, equipment, customer density and condition of each EDC's system, but they will differ within pockets of a system. Further, the reliability benchmarks and standards provide the necessary motivation for EDCs to have adequate inspection and maintenance standards. Imposing additional standards is duplicative and costly.
Comments of Pike County
Pike County commented that the Commission does not have to adopt inspection and maintenance standards in order to ensure reliable electric delivery service in Pennsylvania. Instead of I & M standards, Pike County recommends the Commission establish certain broad reliability criteria and afford individual utilities the flexibility to meet such criteria in the most efficient, cost-effective manner. Any standards adopted by the Commission should not be in conflict with similar standards adopted by the FERC or the PJM Interconnection (PJM).
Pike claims that it is part of a multi-state system which has developed I & M programs internally based on history, practices, and experience. Tailoring its program to meet the proposed standards would be a costly and inefficient use of Pike County's resources according to Pike County. Pike does not support strict uniform I & M standards to assure reliable electric service. Pike argues an EDC's flexibility should be maintained for the development, modification and administration of I & M programs that not only impact reliability but efficiency as well.
Comments of Duquesne Light Company (Duquesne Light)
Duquesne Light supports flexible inspection and maintenance plans and related technology advancements that make strict standards obsolete. Duquesne Light supports the Commission's efforts to establish periodic I & M standards and is supportive of developing rules to support a flexible frame work. Such plans should be submitted every 2 years for Commission review, comment and approval, and utilize the existing quarterly and annual reliability reports as a ''timely'' resource to monitor the activities at the EDCs to ensure that appropriate standards are currently being followed by the EDCs. Duquesne Light commented that the proposed regulations are wrong because more advanced diagnostics with more technical, condition-based, maintenance and life cycle analysis along with proven strategies and best practices should be utilized to improve reliability.
The IECPA, et al. comments.
The IECPA, et al. is comprised of ad hoc groups of large commercial, institutional, and industrial customers receiving electric service from various EDCs throughout Pennsylvania. Because members of IECPA use large amounts of electricity in their various production processes and operations, any changes to the electricity rates paid by these customers can significantly affect their overall costs of production. The IECPA, et al. urged the Commission to refrain from implementing any mandatory I & M requirements unless and until a cost/benefit test is performed. Specifically, IECPA, et al. agrees with the concerns raised by the EAP that if the proposed regulations are implemented, the added expense to ratepayers over and above current I & M program practices will exceed $75 million per year on a Statewide basis with little or no assurance of improved electric service reliability.
While the IECPA cares about reliability of service, it is concerned that the proposed regulations will significantly increase their rates without providing corresponding improvements in reliability. Only after the Commission has determined that the costs of applying these regulations to the EDCs will be equal to or less than the benefits that will be received by the customers should the Commission impose the additional regulations on the EDCs.
Comments of Senator Robert M. Tomlinson
Senator Robert M. Tomlinson commented on May 16, 2007, that the Commission's proposed regulation may bring an additional industry-wide aggregate cost of $75 million in assessments upon the Commonwealth ratepayers as the EDCs claim, with little or no guarantee that there would be a direct benefit to reliability.
While he agreed that companies should file their inspection and maintenance plans, his interpretation of the LB&FC study of June 2002 on reliability, is that the LB&FC did not recommend the Commission adopt detailed and specific standards because all systems are not the same. The audit, however recommended an approach similar to Illinois whereby detailed documentation on programs are submitted. Senator Tomlinson believes this is a better approach as the regulations need to provide for the EDCs to create the appropriate programs and integrate advances in technology into future inspection and maintenance plans. Further, companies not meeting the reliability standards can be ordered to improve reliability.
Comments of the Independent Regulatory Review Commission
The IRRC commented that it is concerned about the fiscal impact of the minimum standards proposed in the regulations. The EDCs' claim that the proposed regulation would cost more than $75 million per year for Pennsylvania ratepayers is of concern when there is no identifiable direct benefit that can be attributed to the proposed regulation. IRRC stated that the Commission failed to submit information concerning costs imposed on the public and private sectors.
Further, IRRC comments that the need for such stringent regulations is not explained in detail. IRRC states that the Commission is already receiving significant information concerning EDCs' I & M programs and has acted upon some companies on a case-by-case basis. Therefore, there needs to be strong justification for an across-the-board regulation.
Also, IRRC commented that the EDCs have reported a loss of skilled technical talent in the electric industry and therefore their current taskforces may be insufficient to meet the needs of the regulation. It may take a few years for the EDCs to recruit, hire and train an adequate workforce that would bring them into compliance with the proposed regulation. If the Commission were to move forward with the regulation, it must address this concern and provide an adequate time period for the EDCs to come into compliance.
Regarding conflict with other regulations, IRRC notes that on March 16, 2007, FERC issued an order entitled ''Mandatory Reliability Standards for the Bulk-Power System'' for a final rule. FERC adopted vegetation management and is using the program developed by NERC. This program does not set forth specific inspection trim cycles but requires utilities maintain minimum clearances. Unlike the proposed regulation, it provides flexibility for utilities, EDCs or transmission owners to develop their own inspections schedules that are of ''sufficient frequency to insure compliance with clearance requirements.'' The proposed regulation is stricter than the FERC rule for bulk power system of 100 kV or more. IRRC requested a strong justification for this rulemaking to go forward.
Finally, IRRC commented that the EDCs need an adequate time period to come into compliance with I & M standards because they will need to recruit and hire adequately strained staff.
Comments of the Office of Consumer Advocate (OCA)
The OCA commented that the Commission must establish inspection, maintenance, repair and replacement standards because this is required by 66 Pa.C.S. § 2802(20). The OCA acknowledges the standards should allow for flexibility to the EDCs in establishing and improving practices, and should allow an EDC to recognize the unique features of its transmission and distribution system. The OCA submits that adoption of a broad set of inspection and maintenance standards that set forth minimum requirements, coupled with submission and review of individual transmission and distribution maintenance plans will meet the desired goals. A broad set of minimum standards designed to promote high-quality service and a ''best practices'' approach is best.
The OCA states that its proposed standards are designed to ensure that all critical facilities are reviewed and tested on a regular basis and that deficiencies are remedied in a reasonable time. The OCA claims its standards neither limit the use of new technology nor innovation. Appropriate standards will ensure that proper attention is given to critical facilities and that techniques that can improve the efficiency of review, repair and operation are put into place. The OCA argues EDCs can seek waivers from the Commission if the EDC has a particularly unique situation that would make compliance unduly burdensome. The OCA's proposed minimum standards are in line with the union's proposed standards. The OCA believes the EDCs should do more if required to maintain safe, adequate, reliable and reasonably continuous service.
The OCA further comments the minimum standards must work in concert with any Nationally established standards. That does not mean, however, that matters of Pennsylvania reliability need to rely exclusively on national standards as the EDCs suggest. The Commission is required to establish and enforce standards that meet Pennsylvania's requirements. Moreover, the OCA states that FERC has expressed concerns over its authority to enforce its reliability standards and NERC remains a private organization that relies substantially on voluntary cooperation. The OCA also urges the Commission to consider the use of automatic fines and penalties as a means of enforcing compliance with these standards. We note that since the OCA's comment was filed, NERC has been certified as the ERO with legal authority to develop and enforce reliability standards for the bulk power system.
OSBA's Comments
OSBA recommends adding language to the proposed § 57.198 which will state that the Commission's authority is not limited and that it can investigate and adjudicate the reliability of an EDC's distribution service regardless of how that reliability compares to the EDC's reliability on the effective date of 66 Pa.C.S. Chapter 28, and that the Commission still has the authority to reduce or deny a request for rate relief if the EDC has failed, is failing, or is likely to fail to provide adequate service. Further, the OSBA recommends adding a subsection which states that an EDC's adherence to its plan shall not be construed to limit the Commission's authority to investigate under 66 Pa.C.S. § 1501 and adjudicate the reliability of an EDC's distribution service, or under 66 Pa.C.S. §§ 523 and 526, to reduce, or deny a request for rate relief if the EDC has failed to provide adequate service.
Disposition of General Comments
A. Need for I & M Regulations
Electric service reliability is an essential and core regulatory responsibility of this Commission under the Public Utility Code. EDCs have a legal obligation to connect customers, and then provide them safe, adequate, and reliable service at reasonable prices and without unreasonable interruptions or delay. 66 Pa.C.S. § 1501. Moreover, as part of their public service obligation, EDCs are required to undertake prudent operational measures to prevent or avoid outages that are preventable at a reasonable cost, and to inspect, repair and maintain their facilities in a manner consistent with prudent utility practice.
The Electricity Generation Customer Choice and Competition Act (''Act''), 1996, December 3, P. L. 802 No. 138 § 4, became effective January 1, 1997. The Act amended 66 Pa.C.S. (Public Utility Code) by adding Chapter 28 to establish standards and procedures to permit direct access by retail customers to the competitive market for the generation of electricity, while maintaining the safety and reliability of the electric system. At the same time, the Act authorized the Commission to ensure that the levels of reliability that were present prior to the restructuring of the electric utility industry would continue in the new competitive environment. 66 Pa.C.S. §§ 2802(12), 2804(1) and 2807(d). This Commission enforces nationally accepted CAIDI, SAIFI and SAIDI reliability indices standards.3 These are defined in detail in our regulations and in our order entered April 15, 2004 Amended Reliability Benchmarks and Standards for the Electric Distribution Companies, M-00991220, April 15, 2004.
However, in the Commission's judgment, the establishment of reasonable and flexible I & M standards for EDCs will further enhance and will be an important tool to ensure adequate reliability, as required by law. In addition, we cannot ignore the explicit statutory language contained in the Act which also links the reliability of electric service with the establishment, by regulation, of inspection and maintenance standards. Specifically, 66 Pa.C.S. § 2802(20) provides:
(20) Since continuing and ensuring the reliability of electric service depends on adequate generation and on conscientious inspection and maintenance of transmission and distribution systems, the independent system operator or its functional equivalent should set, and the Commission shall set through regulations, inspection, maintenance, repair, and replacement standards and enforce those standards.66 Pa.C.S. § 2802(20). Further, section 1501 of the Public Utility Code requires every public utility to furnish and maintain adequate, efficient, safe and reasonable service and facilities, and to make all such repairs, changes, alterations, substitutions, extensions and improvements in or to such service and facilities as shall be necessary or proper for the accommodation, convenience, and safety of its patrons, employees, and the public. Such service shall be reasonably continuous. 66 Pa.C.S. § 1501. Thus, both section 1501 in general and 66 Pa.C.S. § 2802(20) in particular support the establishment of I & M standards by regulation.
Additionally, in the wake of the August 14, 2003 blackout, the FERC commissioned a study of utility vegetation management practices and this led to a report entitled ''Utility Vegetation Management Final Report'' prepared by CN Utility Consulting, LLC and released by FERC in March, 2004. The report concluded that current oversight of utility vegetation management activities by appropriate agencies or organizations was overwhelmingly inadequate and the report recommended the adoption of vegetation management best practices, schedules and the achievement of reductions in tree-related outages. Report, pp. 68 and 69. While this report is not binding upon this Commission, we consider it in determining whether to establish I & M standards. The Commission also considers the fact that other states like California, Missouri, New York, Connecticut, and Ohio have I & M standards in place.
Finally, the Commission observes that the quarterly and annual reporting requirements under 52 Pa. Code § 57.195 are not a substitute for inspection and maintenance standards within the meaning of § 2802(20). The reporting requirements in § 57.195 of the Pennsylvania Code require EDCs to provide the Commission with inspection and maintenance goals and quarterly reports as to the EDCs' progress in meeting these goals. The establishment of reasonable and flexible I & M standards will provide EDCs with a better understanding of what goals are acceptable to the Commission for their periodic reports and will help EDCs meet these goals. Also, I & M standards are not the same as the reliability indices and standards used to measure current performance. I & M standards are focused on ensuring future reliability and are broader in scope.
For these previously-stated reasons, this Commission rejects comments suggesting that I & M standards are not necessary for Pennsylvania.
B. Approach for I & M Regulations
While the Commission finds that the establishment of I & M standards is necessary, the Commission takes seriously the position of the industry that the I & M regulations should not mandate inspection and inspection intervals that, for a given EDC, are not prudent or would not be cost/benefit justified. The EAP's and EDCs' comments suggest that the costs associated with proscriptive I & M regulations outweigh the benefits of assuring reliability does not deteriorate from service levels in 1997. However, although the EAP claims that the aggregate cost of compliance with the I & M standards in the proposed-form regulations would be $75 million, there are few details to support this estimate at this time. In addition, we observe that the total intrastate revenues for this industry in calendar year 2006 was $11.6 billion. Thus, the $75 million figure, even if sustainable, is about 0.6% of this total.
The EDCs, Senator Tomlinson, and IRRC raise the point of a cost/benefit analysis. As noted previously, we concur, in general, that I & M regulations should reflect cost/benefit concerns. As explained in a recent paper published by the National Regulatory Research Institute (NRRI), an efficient outage policy depends on the value to customers of avoiding a utility outage, as well as the cost to the utility to take reasonable steps to prevent avoidable outages. When an outage occurs, the question then is the value to customers of minimizing its duration and extent, and the cost to the utility of doing so. An efficient policy is one that reflects and achieves a reasonable relationship between the cost and benefit to the customer. Regulatory Policies for Electricity Outages: A Systems Approach, August, 2007, paper published by The National Regulatory Research Institute.
Industrial and commercial customers tend to be more sensitive to and experience greater damage from outage frequency because they are more reliant on digital circuitry in their industrial processes, office equipment and appliances. A power supply disturbance such as a voltage sag, surge, transient or harmonic can result in the customer experiencing an interruption in service, and machines on a manufacturing line can go off, and product and time is lost for the business. Interruption in service can also be a dangerous situation for some companies like chemical plants, hospitals, and airports.
Residential customer outages over eight hours result in loss of heat, air conditioning, use of elevators, and food spoilage. In practice, the calculation of outage costs and outage probabilities is difficult. Different customers in the same class and use category may assign very different costs to outage. NRRI paper at 5. At the technical conference, there was no offering by any party regarding customer survey data to show what values the customers place on reliable service. Neither was there any evidence presented to show the EDCs' costs for pre-outage prevention regarding vegetation management, transmission and distribution facility inspection and replacement and identification and correction of poorly performing circuits.4
The Commission recognize that this is a technology-based industry, and as such, our regulatory policies should be flexible in order to encourage a utility to take advantage of technological advances to bring better service to customers at a lower price. An example of technological advancement is the use of satellites for instant communications as part of the system's monitoring. Creosoted utility poles generally last longer and require less frequent inspections initially than wooden poles. Infra-red monitoring of lines is also a technological improvement over foot patrols.
The exact cost to benefit ratio of implementing any specific I & M standard is still unknown and we do not endorse, at this time, any specific model to determine that ratio. To date, the EDCs discussed general cost figures, but none of their presentations were supported by written documentation offered as evidence at the presentation at the technical conference. The EDCs have alleged that the proposed-form regulations would impose exorbitant cost increases to the EDCs without any measurable or guaranteed betterment of reliability of service. However, these estimates do not address the value customers assign to outage avoidance, nor do they address cost savings the EDCs may have experienced due to cuts in staffing or maintenance, since under a rate cap regime cutting staff and deferring maintenance can be ways to increase net income. OCA stated that it was not able to refute the $75 million aggregate incremental cost increase because OCA did not know the details of how the figure was calculated.
Scott Rubin, Esquire, counsel for AFL-CIO--Utility Caucus, stated at the technical conference of January 22, 2007:
The EDCs combined have I think laid off in excess a thousand people in the last ten years. They've drastically reduced their maintenance and inspection budgets. So we don't view that $75 million as being a terribly significant figure spread out across Pennsylvania, and it appears to us that the EDCs have saved substantially more than that through work force reductions and the elimination or drastic reduction of preventive maintenance.Technical Conference of January 22, 2007, Scott Rubin, p. 19. If the EDCs cut costs including work force and I & M routines after the Act was passed in order to increase net income, their claim that the cost to perform within the proposed draft standards is unpersuasive as they should not have been cutting reasonable inspection and maintenance costs which result in deteriorating service.
The Commission has also observed that in the year 2006, six EDCs (Met-Ed, Penelec, Penn Power, PPL, Pike County and Wellsboro) failed to achieve their rolling three-year SAIFI performance standard. SAIFI measures system-wide average frequency of outages. In 2006, three EDCs (Allegheny Power, Penelec and Penn Power) failed to achieve their rolling three-year CAIDI performance standard. CAIDI measures average duration of customer outages. On the positive side, all EDCs complied with the 12-month CAIDI performance standard and six (Duquesne Light, Penelec, UGI Electric, Citizens, Pike County and Wellsboro) of 11 EDCs performed better than their CAIDI benchmark last year, so that shows some improvement in average performance since 1997.
However, most recently, we have seen some EDCs report indices higher than their rolling 12-months ending December 31, 2007 reliability standards. Specifically, Allegheny Power reported higher indices than all three standards including: CAIDI, SAIFI and SAIDI Penn Power reported indices higher than their rolling 12-month CAIDI standard. Met-Ed and Penelec reported higher indices than their SAIFI standards. These recent reliability performance statistics also support the need for further enhancements to our regulatory efforts to ensure the level of service quality required by law. This Commission published in July, 2007 a report entitled, Electric Service Reliability In Pennsylvania: 2006. Attached to this Final Rulemaking Order are excerpt tables from the report showing each EDCs' performance reliability indices and how they measured against their respective 12-month and 3-year rolling standards. See Attachment A (Table 12-Month Average Electric Reliability Indices for 2006) and B (Three-Year Average Electric Reliability Indices for 2004-2006).
On July 3, 2002, at M-00021619, this Commission's Bureau of CEEP prepared an I & M Study which was adopted by the Commission. This study found that the major causes of service outages in 2000 were attributable to equipment failure and tree-trimming related outages. Each reason accounted for about 22% of the total outages the EDCs were experiencing. This conclusion was based upon information provided to CEEP from the EDCs. These types of outages are arguably within the control of the EDCs. Both types of outages are being addressed in Annex A.5
The EAP have cited to industry statistics that of the tree-trimming related outages, approximately 85% at a minimum are caused by trees outside the utility right-of-way and that there is difficulty in negotiating with the landowners of said danger trees. Robert Stoyko, Vice President, Electric-Division--UGI Utilities, technical conference January 22, 2007 transcript p. 26; David E. Schleicher, General Manager Transmission/Distribution PPL Electric Utilities, Corp., p. 70. Some of the utilities negotiate with property owners to remove off-right-of-way trees posing a danger of outages. Wayne Honath, Manager, Reliability and Standards Duquesne Light Company, Transcript p. 37. PPL's presenter, David Schleicher, admitted PPL is looking at reducing their tree trimming cycle from 5 years urban and 8 years rural to 5 years across the board and they are looking at the cost per SAIDI minute of downtime to justify the expense. Transcript at p. 71.
However, we can and should balance the possible rise in operating costs for any given inspection and maintenance approach against the savings to customers in avoiding outages, especially black-outs covering multiple states, and very high numbers of outages over a longer period of time. In the Final Report on the August 2003 blackout, the Task Force concluded that the blackout, caused in part from inadequate vegetation management, had an economic cost of between $4 billion and $10 billion in the United States alone. Canada also sustained a partial black out. This economic impact on businesses and citizens in the United States and Canada, and approximately 55,000 residents of Pennsylvania, was significant. A business that loses power can quickly lose sales revenues and the ability to produce its product. Loss of power is a health and safety issue as well as a financial issue.
The OCA allocated the estimated $75 million aggregate cost over the 11 EDCs operating in Pennsylvania. Putting that estimate into the context of operating budgets and maintenance budgets of $75 to $100 million for some of the largest utilities (those total revenues approaching or in excess of $1 billion), the incremental cost increase did not appear to outweigh the need for I & M guidelines. Also, OCA attempted to calculate the cents per kilowatt-hour impact of the $75 million estimate over all of the kilowatt-hours sold in Pennsylvania in 2005, and it comes out to $.05 per kilowatt-hour, or a half a mill per kilowatt-hour sold. For an average residential customer using 750 kilowatt-hours per month that is $.35 per month. Technical Conference Hearing transcript Tanya McClosky, p. 9.
Several other states have now established I & M standards in the wake of electric deregulation. On March 31, 1997, the California Public Utilities Commission adopted minimum requirements for electric distribution facilities, regarding inspection (including maximum allowable inspection cycle lengths) condition rating, scheduling and performance of corrective action, record-keeping, and reporting, in order to ensure safe and high-quality electrical service, and to implement the provisions of California's statute, Section 364 of Assembly Bill 1890, Chapter 854, Statutes of 1996. California requires annual compliance plans for the inspection and record-keeping by no later than July 1 of each year. The report identifies the number of facilities, by type which have been inspected during the previous period. It must identify those facilities which were scheduled for inspection but which were not inspected according to schedule and shall explain why the inspections were not conducted, and a date certain by which the required inspection will take place. The report also presents totals and the percentage of equipment in need of corrective action, but with a scheduled date beyond the reporting period.
California has minimum standards for three levels of inspection: (1) patrol, meaning a simple visual inspection; (2) detailed, meaning taking the equipment apart and examining each piece for inspection; and (3) intrusive, involving digging up soil to test below soil level as in inspection of poles.
California has maximum intervals of 1-2 years for transformers (patrol inspection) and 5 years for detailed inspections. Overhead conductors and cables have a maximum inspection interval of 1-2 years for patrol and 5 years for more detailed inspections. Wood poles which passed intrusive inspection have a maximum interval for intrusive inspection every 20 years. Wood poles under 15 years, just have a 1-2 year patrol interval, and wood poles over 15 years which have not been subject to intrusive inspection, 1-2 years patrol inspection plus an intrusive inspection at least once every 10 years.
On October 2, 2007, the Missouri Public Service Commission (MoPSC) filed a Proposed Rulemaking adopting 4 CSR 240-23.030--Electrical Corporation Vegetation Management Standards and Reporting Requirements. MoPSC limited the adoption of outside standards, guidelines and procedures to three times: ANSI A300 (Section (4)(A)(2)), which contains standards for vegetation management, ANSI Z133.1 (Section (4)(A)(5)), which contains guidelines for personnel safety, and the National Electric Safety Code (Section (4)(A)(9)), which contains standards for public safety.
MoPSC stated that if the authorities conflict, the EDC should file notice of the EDC's resolution for the conflict and the basis for it. Missouri addressed claims of excessive high costs to comply with proposed regulations. MoPSC altered its proposed rule to lower the cost of compliance and provided a mechanism through which utilities may record the costs associated with compliance and eventually recover the costs in rates. It stated as follows in its proposed regulation:
(4) In the event an electrical corporation incurs expenses as a result of this rule in excess of the costs included in current rates, the corporation may submit a request to the Commission for accounting authorization to defer recognition and possible recovery of these excess expenses until the effective date of rates resulting from its next general rate case, filed after the effective date of this rule, using a tracking mechanism to record the difference between the actually incurred expenses as a result of this rule and the amount included in the corporation's rates, or if there is no identifiable amount included in the corporation's rates, the amount reflected in the appropriate accounts for infrastructure inspection and maintenance on the corporation's books for the test year (as updated) from the corporation's last rate case will be used to determine the amount included in current rates. In the event that such authorization is granted, the next general rate case must be filed no later than 5 years after the effective date of this rule. Parties to any electrical corporation request for accounting authorization pursuant to this rule may ask the commission to require the electrical corporation to collect and maintain data (such as actual revenues and actual infrastructure inspection expenses) until such time as the commission addresses ratemaking for the deferrals. The commission will address the ratemaking of any costs deferred under these accounting authorizations at the time the electrical corporation seeks ratemaking in a general rate case.The Missouri Commission also provided for variances in its rulemaking. The EDCs were allowed to propose and the Commission to approve an alternative infrastructure inspection program varying from the table ''Electrical Corporation System Inspection Cycles (Maximum Intervals in Years).'' If the EDC can establish that the alternative inspection program has previously produced equal to or greater reliability performance than what would be produced under the rule, or that the alternative infrastructure inspection program shall produce equal to or greater reliability performance in the future than what would be produced under the rule, then a variance may be granted for good cause shown.
Missouri proposed maximum intervals of 4-6 years for patrol inspections of wood and non-wood poles and overhead structures, 12 years for detailed inspections of non-wood poles, and 12 years for intrusive inspections of wood poles. Regarding conductors, transformers, reclosers, regulators, capacitors, switching/protective devices, and street lighting, 4-6 years patrol inspections for overhead, and 8-12 years detailed inspections for overhead. Underground-direct buried and conduit had 4-6 year patrol inspections and 8-12 year detailed inspections. Manholes, vaults, tunnels and other underground structures had a 4-6 year maximum interval for patrol inspections, and an 8-12 year maximum interval for detailed inspections.
We are influenced by what states like Missouri and California are doing regarding establishing inspection and maintenance standards. Like Missouri, we find that the alternative of using a reliability-based trimming plan is reasonable under certain circumstances and we will add language to the proposed rulemaking to clarify that utilities may propose a plan that uses intervals outside the standards in lieu of a plan that adheres to the rule, but it must be explained, and the reliability indices that the EDCs are reporting as well as an EDC's prior internal I & M standards will be taken into consideration in approval or rejection of the plan. This change is reflected in subsection (c).
Regarding the issue of whether we have jurisdiction to establish standards regarding transmission lines, it is well-settled that the Commission has concurrent jurisdiction over transmission lines with FERC. The U.S. Supreme Court in New York v. FERC, 535 U.S. 1 (2002), recently reiterated that no federal agency has the power to act, let alone preempt the validly enacted legislation of a sovereign state, unless Congress confers such power upon it manifesting clear Congressional intent to so preempt. 152 L.Ed. 2d at 62-63 (citation omitted). The Supreme Court has unequivocally held ''States retain significant control over local matters even when retail transmissions are unbundled.'' Id. 152 L.Ed.2d at 66.
States have authority over transmission facilities constructed within their borders. States authorize the construction of the transmission facilities and issue certificates to utilities to operate them. The long-standing state authority is preserved by the Federal Power Act (FPA) and cannot be preempted by FERC's actions. Thus, this Commission is fully within its rights in establishing I & M guidelines regarding transmission lines. However, because FERC is in the process of implementing inspection, maintenance, repair and replacement standards regarding transmission wires, we elect not to exercise our concurrent jurisdiction at this time, and will not promulgate regulations regarding transmission lines.
Similar to Missouri, we will abstain from establishing I & M standards at this time regarding high voltage transmission lines in deference to the Federal government's current reliability rulemaking regarding transmission lines. This addresses IRRC's comment that the Proposed Rulemaking seemed more stringent than the FERC rule for bulk power systems of 100 kV or more. Thus, the EDCs will have more flexibility regarding tree-trimming cycles and inspection, repair and replacement intervals regarding transmission lines.
As noted previously, the Commission takes seriously the position of the industry that the I & M regulations should not mandate inspection intervals that, for a given EDC, are not prudent or would not be cost/benefit justified. However, given our obligations under law to ensure electric service reliability, the relative costs involved, and the deteriorating service performance of some EDCs in recent years, we are persuaded that flexible I & M standards should be established by this final rulemaking order. Therefore, in addition to mandating reports regarding transmission and distribution inspection and maintenance plans and the CEEP review/approval process for those plans, this rulemaking will establish flexible I & M standards based upon current industry practices. The I & M schedules will be part of each EDC's annual plan and they must be consistent with the I & M standards established in these regulations.
However, the regulations will allow the individual EDCs to deviate from the standard set forth in the regulation, provided that such deviation/alternative can be justified based on utility-specific circumstances, and a cost/benefit analysis. In this fashion, when compliance with a given I & M standard for a specific EDC would not be prudent or cost/benefit justified, the EDC may deviate from that standard provided that it can adequately justify that different I & M interval or approach. As such, the regulation will provide the leeway necessary for EDCs to avoid unnecessary costs. Further, Commission staff's initial rejection of an I & M plan in whole or in part, can be appealed to the full Commission by means of 52 Pa. Code § 5.44.
In sum, the Commission finds that using a broad set of minimum standards as proposed in the OCA's comments, will promote high quality service and reliability, as required by law, without forcing an EDC to comply with a given I & M benchmark that is not cost/benefit justified for its particular service territory.
Finally, IRRC commented that the EDCs need an adequate time period to come into compliance with I & M standards because they will need to recruit and hire adequately trained staff. We will give the first group of EDCs until October 1, 2009, to file their first biennial plan with the Commission. The plan will cover inspection, maintenance, repair, and replacement plans for calendar years 2011 and 2012. The remaining the EDCs in a second group shall be required to file their first biennial plans on October 1, 2010. Their plans will cover inspection, maintenance, repair, and replacement plans for calendar years 2012 and 2013.
With this procedural schedule, the Commission will have enough time to review and approve the plans. Implementation of the approved plans will occur 15 months after the plan filing deadline. With this 15-month interval, if there are amendments that need to be made to the plans, the EDCs will have adequate notice before the implementation date, and can adjust their financial budgets and operational plans accordingly. The EDCs will then continue to file in staggered years, every 2 years from the date upon which they first filed. We believe this process provides adequate time to comply or explain why they cannot immediately comply with a given standard. The specific EDCs that are in Groups 1 and 2 will be defined by implementation order after this rulemaking is effective.
III. Comments Regarding Specific Sections
Section 57.192. Definitions.
IRRC commented that the definitions of rural area and urban area are problematic. Similarly, many EDCs also stated there is no need for this distinction. The EAP stated that individual EDCs may, for their own vegetation management purposes, designate distribution circuits, or portions thereof, as either ''urban'' or ''rural''; however, there is no value in requiring all EDCs to distinguish between rural areas and urban areas, either by a population threshold of 5,000 or any other means because many distribution circuits cross between proposed urban and rural areas. One circuit may cross multiple times into rural and urban areas. Therefore the request is not practical and no other state Commission makes such a distinction.
The EAP commented that the distinction between urban and rural areas adds no value since circuits can cross many times between rural and urban areas. PPL commented that it classifies any distribution circuit that has an average of 35 or more customers per circuit mile as ''urban'' and those with fewer than 35 customers as rural. As of February, 2007, PPL Electric has 9,600 circuit miles of overhead urban circuits, and 17,700 circuit miles of overhead rural circuits. PPL does have different company-wide standards for vegetation management. For distribution lines, rural areas are on an 8-year trimming cycle and urban are on a 5 year cycle. Other internal standards appear to be the same for both rural and urban areas.
FirstEnergy commented that it does not believe that EDCs should be required to distinguish between rural versus urban in its plans. While systems that are rural may differ from systems that are urban, to draw distinctions based on the definitions provided in the proposed rulemaking would be arduous and costly with little to no benefit to be realized. Additionally, a single circuit can cross between rural and urban areas multiple times. The companies do not distinguish their systems based upon the population threshold of 5,000 and FirstEnergy encourages the Commission to eliminate this designation in any final rules.
Allegheny Power commented that urban/rural census definition is not appropriate for planning transmission and distribution inspection and maintenance activities. Line equipment (reclosers, transformers, conductor, fuses, and the like) functions in the same manner regardless of an urban setting or rural setting. Inspection and maintenance practices are the same regardless of population density. Similarly, pole inspection cycles are independent of population density. Vegetation management cycles may be tailored to the needs of cities or towns. The cycle and practice differences are typically governed by agreements with individual municipalities and are independent of discrete population size boundaries. Allegheny Power has many long circuits that cross into ''urban'' and ''rural'' areas often several times. Tailoring work practices to portions of individual circuits is inefficient and does not promote improvement.
Duquesne Light sees no legitimate reason for distinguishing between urban versus rural circuits. The standards proposed for maintenance intervals are not dependent on whether the circuits are rural versus urban. Duquesne does not distinguish its plans between communities with a population of less than 5,000 people and those having a population of 5,000 or more.
Pike County commented that it does not support the urban versus rural concept. However, since the entire Pike service territory is predominantly rural and less than 5,000 customers anyway, Pike County believes it should only have to submit one plan for the whole service territory.
The OSBA commented that population density is a better measure than total population and the OSBA noted that the General Assembly is considering House Bill 2347 which would codify a uniform definition of ''rural area'' and by implication ''non-rural area.'' Accordingly, the OSBA recommended the Commission revise the proposed definitions in § 57.192 to reflect HB 2347.
Disposition
Given the previous comments, we will eliminate the rural/urban definitions as only PPL appears to differentiate its standards between rural and urban areas at this time, and that is only with regard to one internal standard regarding the distribution line tree trimming practices.
Section 57.198 Inspection and Maintenance Standards
Subsection (a). This subsection states that an EDC shall have a plan for the periodic inspection and maintenance of poles, overhead conductors and cables, wires, transformers, switching devices, protective devices, regulators, capacitors, substations and other facilities critical to maintaining an acceptable level of reliability in a format the Commission prescribes. The Commission may require an EDC to submit an updated plan at any time containing information the Commission may prescribe.
IRRC states that the first sentence in § 57.198(a) is long and confusing. It contains a list of ten specific items to be included in the I & M plan and the words ''other facilities critical to maintaining an acceptable level of reliability.'' To improve clarity, it should be enumerated. Additionally, IRRC commented that the examples of the type of equipment or facilities ought to be provided. We will comply with IRRC's suggestion to enumerate the specific items to be included in the I & M plan. We will eliminate the phrase ''other facilities.''
Further, IRRC questioned when and how will the EDCs be notified of the prescribed format the Commission wants to see in the plans. Format requirements will be addressed in a Secretarial Letter that will be issued by the Commission to the EDCs prior to the date the first plan is due.
The second sentence of subsection (a) states: ''The Commission will review each plan and may issue orders to ensure compliance with this section.'' The intent of this sentence is unclear according to IRRC and it appears to be redundant and should be deleted.
IRRC further commented that the final sentence of Subsection (a) states that the PUC ''may require an EDC to submit an updated plan at any time containing information the Commission may prescribe.'' IRRC is unclear how and when the PUC would notify an EDC to update its plan. Under what circumstances, would it be necessary to update a plan? How would the PUC notify the EDC of the information that the PUC is prescribing be contained in the plan? After the EDC submits its updated plan, when would the PUC notify the EDC that the update was approved?
Disposition
Subsection (a) shall be revised to state:
(A) Filing date and plan components. Every 2 years by October 1, each EDC shall prepare and file with the Commission a biennial plan for the periodic inspection, maintenance, repair, and replacement of its facilities that is designed to meet its performance benchmarks and standards pursuant to 52 Pa. Code §§ 57.191--57.197. EDCs in compliance group 1, as determined by the Commission, shall file their initial plans on October 1, 2009. EDCs in compliance group 2, as determined by the Commission, shall file their initial plans on October 1, 2010. Each EDC's biennial plan shall cover the 2 calendar years beginning 15 months after filing, be implemented 15 months after filing, and shall remain in effect for 2 calendar years thereafter. In preparing this plan, the following facilities are critical to maintaining system reliability: (1) poles; (2) overhead conductors and cables; (3) transformers; (4) switching devices; (5) protective devices; (6) regulators; (7) capacitors; and (8) substations.IRRC's suggested numeration is followed. We are grouping the EDCs into two compliance groups and staggering their filing deadlines to facilitate timely administrative review. The plans will cover the 2-calendar years beginning 15 months after filing because the EDCs requested the plans be amended well in advance of implementation dates so that budgets may be adjusted accordingly.
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1 Collectively, Met-Ed, Penelec and Penn Power are referred to as FirstEnergy.
2 The IECPA et al. consists of Duquesne Industrial Intervenors, Met-Ed Industrial Users Group, Philadelphia Area Industrial Energy Users Group, Penelec Industrial Customer Alliance, PP&L Industrial Customer Alliance and the West Penn Power Industrial Intervenors.
3 SAIFI (System Average Interruption Frequency Index) is the number of sustained interruptions experienced by an average customer on the system. SAIDI (System Average Interruption Duration Index) is the number of minutes of sustained interruption experienced by an average customer on the system. CAIDI (Customer Average Interruption Duration Index) is the average duration of a sustained interruption experienced annually by a customer on the system. This is measured in minutes. As the indices figures rise, it indicates poorer performance.
4 Anecdotal information is available showing that EDCs have cost/benefit data. PECO was quoted in a recent news article as having recently spent $1 million on squirrel guards to stop outages from squirrels. As a result, PECO reports its squirrel-related outages have fallen from 11,605 in 2003 to 1,345 in 2006. www.usatoday.com/news/nation/2007-03-11-suicide-squirrels_N.htm.
5 Additionally, at the January 22, 2007, technical conference, we asked the industry to provide us with their internal inspection, maintenance and repair standards prior to the Electric Competition Act of 1997. Responses to this request were received and they are incorporated in tables throughout this order regarding each individual standard.
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