[34 Pa.B. 5135]
[Continued from previous Web Page] The parties should note that we have adopted the suggestion of PPL that we modify reporting requirements to allow for budget (and thus actual expenditure data for comparison purposes) to be provided by functional activity rather than FERC account. We acknowledge that most EDCs use a responsibility (activity-based) system for internal budgeting and expense collection purposes because it more closely conforms to operations. In these companies, use of the FERC system of accounts is generally limited to Commission annual reports. While revising the language in § 57.195(b)(10--11) to allow for reporting of budget and expenditure data by the EDCs' own functional account codes, we've taken the opportunity to clarify that the required data under paragraphs (b)(7--8) and (e)(7--8) is to be reported by those same internal account codes.
We've also taken the opportunity to add language setting a threshold for required variance explanations under paragraphs (b)(7--8). PPL stated in its comments that it believes the phrase ''any variances'' in the Tentative Order is overly broad and will require unnecessary explanation of insignificant deviations. The Company thus recommended explanation thresholds of $1 million for O & M expenditure variances and $5 million for capital expenditure variances. While we agree that thresholds would be appropriate, PPL's proposed amounts are too high. Further, the thresholds do not vary by company size. We will therefore set the thresholds at 10% or more of each budget line item. This is consistent with variance explanation policies at many companies. We should point out here that we have declined to add PPL's suggested threshold wording for requiring explanations of deviations from established inspection and maintenance goals and objectives in paragraph (b)(6). This wording ''a material change in a T & D inspection and maintenance goal/objective'' leaves too much to judgment. Nevertheless, Commission staff will be reasonable and consider the materiality of variances when reviewing the adequacy of explanations here. We believe the addition of the term, ''by the EDC's own functional account code'' satisfies IRRC's requirement that we specify an alternative acceptable format.
In addition to the issues previously discussed, the Commission will address two other general matters brought up by the parties when commenting on the reporting of T & D inspection and maintenance goals/objectives, and O & M and capital expenditures. The first matter involves comments by Citizens', UGI and a few other industry parties that the requested data is burdensome. We do not find this to be a valid criticism inasmuch as all companies affected by this rulemaking prepare inspection and maintenance goals and budget O & M expenditures annually, and compare them to actual data at least quarterly. Moreover, the Commission has now defined the required items such that the EDCs can literally pull them off the shelf and submit them without a lot of modification. A good example of this is the requirement to submit budgeted and actual expenditures using accounts from their own responsibility accounting systems. As a result of the flexibility granted the EDCs to comply with the data requirements, we do not believe that an excessive burden has been placed on them.
The second general matter brought to our attention by IRRC and the EDCs involves proprietary data claims. Many of the commentators from industry believe that information on goals/objectives and budgeted versus actual expenditures is confidential and thus should not be made available to the public. Further, they feel that such data could be misinterpreted by the public, or worse yet, used by competitors and other outside parties against them. Although the Commission has no intention of actively sharing this type of information with other parties outside the regulatory arena, we find the broad proprietary claims by industry to be largely without merit. First, some of this information (i.e., annual O & M and capital expenditures) is already available to the public in the annual reports filed with the Commission. Second, an EDC's transmission and distribution operations are still fully regulated and thus are not subject to competition from other EDCs. If an EDC wishes to keep specific parts of its reported data confidential, it will have to file a petition requesting proprietary treatment. Merely stamping the data proprietary will not guarantee such treatment.
The proposed regulations did not address the confidential treatment of proprietary data. We acknowledge that the EDCs will now be required to report some transmission and distribution data not heretofore reported; however, we view the reports to be of public concern, and will generally treat the entire reports as being public. We do not want a proprietary and non-proprietary version submitted initially. If the EDC anticipates that portions of its report should remain proprietary, then the burden is on the EDC to apply for a protective order under 52 Pa. Code § 5.423 in advance of its report if it wants portions of its report to remain confidential and proprietary.
Reporting Requirements for Smaller EDCs--§ 57.195(c) and (f)
The Commission proposed annual and quarterly reporting requirements for smaller EDCs in paragraphs (c) and (f) respectively. The smaller EDCs have been defined as those with less than 100,000 customers. In comparison to the large EDCs, the Commission has limited the annual and quarterly reporting requirements for the smaller EDCs. This is to reduce the reporting burdens of these companies given the size, configuration, and operational aspects of their systems.
Positions of the Parties
Comments were filed by the FE Companies pertaining to the reporting requirements and the relative size of Penn Power. It is stated that Penn Power is ''substantially smaller'' than all of the other larger EDCs. Penn Power has approximately 154,000 customers while the next largest EDC has approximately 511,000 customers (Met-Ed). Penn Power asserts that its service territory and the nature of its operations and reliability data far more resemble the smaller EDCs than the larger EDCs. As such, Penn Power requests that the Commission redefine the term ''smaller EDCs'' to include EDCs with less than 185,000 customers. This would allow Penn Power to be classified as a smaller EDC and have the benefit of the limited reporting requirements for smaller EDCs.
In its reply comments, the OCA does not believe that it is appropriate for Penn Power to be classified as a smaller EDC. The OCA points out that the 154,000 customers served by Penn Power is much greater than the number of customers served by those EDCs designated as small EDCs in Pennsylvania. UGI is the largest of the small EDCs, but only serves approximately 61,500 customers. OCA also states that Penn Power has a service territory that is significant in size and part of a much larger electric utility system (the First Energy system). The OCA does not believe that there is any indication of an excessive burden placed on Penn Power in meeting these reporting requirements. For these reasons, OCA states that the Commission should reject the request to have the regulations modified for Penn Power.
Disposition
The FE Companies' request that Penn Power be classified as a smaller EDC is rejected. The reply comments of the OCA identify important facts about the relative size of Penn Power and the resources available to the EDC. Penn Power is much larger in comparison to the smaller EDCs, especially when considering the resources available to Penn Power through FirstEnergy. As part of the FirstEnergy system, Penn Power's reliability performance is monitored and managed through the same organization as the two other larger EDCs in Pennsylvania (Met-Ed and Penelec). The Commission will therefore retain the definition of smaller EDCs for quarterly reporting requirements as any EDC serving less than 100,000 customers.
Submission of Quarterly Reliability Reports--§§ 57.195(d), (e), and (f)
Paragraph (d) proposed the submission of quarterly reliability reports to the Commission on or before May 1, August 1, November 1 and February 1. Paragraph (e)(1--11) specified eleven quarterly reporting requirements for the larger EDCs serving 100,000 or more customers. Among those requirements are a rolling 12-month computation of the reliability indices, a rolling 12-month analysis of circuit reliability, and a description of any remedial action taken to correct the problems. Proposed paragraph (f) limited the quarterly reporting requirements for the smaller EDCs to paragraphs (e)(1), (2) and (5). As noted previously in this rulemaking, the reduced requirements are designed to reduce the reporting burdens of these companies given the size, configuration, and operational aspects of their systems.
The purpose of requiring a quarterly report is to provide more frequent information to the Commission about service reliability. This will enable the Commission to identify potential problems in a timely manner and monitor an EDC's response to problems which may arise between annual reports. The quarterly report requires a description of each major event occurring during the preceding quarter that the EDC has excluded from its reported data.
Positions of the Parties
The EAP, Allegheny Power, Citizens', the FE Companies, PECO, and Pike County submitted comments to the proposed quarterly reports.
The EAP does not believe that some of the quarterly reporting requirements provide meaningful insight to an EDC's reliability performance. The FE Companies state that the benefits of quarterly reporting are miniscule compared to the time, expense, burden and resources the EDCs will have to incur in order to collect, calculate, review and publish the information on a quarterly and annual basis. PECO submits that with the exception of the major outage reporting proposed in paragraph (e)(1) and the rolling indices information proposed in paragraph (e)(2), the other quarterly reporting requirements will not provide any meaningful insights into the reliability performance of the EDCs. The EAP asserts that the quarterly reporting requirements proposed in paragraph (e) are an unreliable means of measuring performance, since the primary measure of performance is an annual target. The EAP references the information required under paragraphs (e)(3) and (e)(5) as statistical information that should not be analyzed based on the performance in any given quarter, but rather an annual basis. Similar concerns have been averred by Allegheny Power, PECO, and the FE Companies noting that reliability performance is best evaluated over a long-term horizon, such as 12 months, rather than on a short-term horizon, such as 3 months.
Of the smaller EDCs, Pike County commented that subjecting smaller EDCs to the quarterly reporting requirements would significantly increase their workload with minimal countervailing benefits. Pike County requests that its quarterly reporting obligation be limited to providing updated SAIFI, CAIDI and SAIDI statistics as proposed in paragraph (e)(2). Citizens' believes that quarterly reporting is excessive and provides little meaningful information, because system reliability can vary significantly in the short term based on isolated local events such as vehicle accidents, storms, etc.
Disposition
We will first address the comments regarding the analysis of reliability performance on a quarterly basis versus an annual basis. The EAP, Allegheny Power, PECO, and the FE Companies have inaccurately characterized the information to be provided in the quarterly reports proposed under paragraphs (e)(2 & 3). These parties have given the impression that the quarterly reports proposed under paragraphs (e)(2 & 3) require reported performance only for the three months in a given quarter. Both paragraphs specifically state that rolling 12-month data is to be reported. This rolling 12-month data is to be reported every quarter. As such, the reliability performance will be evaluated over a period of 12 months. The EAP, Allegheny Power, PECO, and the FE Companies have all indicated that it is best to evaluate reliability performance over a longer term, which is why the Commission has proposed the quarterly reporting of rolling 12-month data in paragraphs (e)(2); (3).
The Commission recognizes an omission in paragraph (e)(5) that was pointed out by the EAP and PECO. As written, paragraph (e)(5) requires a breakdown and analysis of outage causes during the preceding quarter. To be consistent with the other reliability and outage data being reported in paragraphs (e)(2); (3), paragraph (e)(5) has been revised to clarify that a rolling 12-month breakdown and analysis of outage causes is to be reported every quarter. Again, this does not mean that only causal data for the three months of a given quarter are reported. Each quarterly report will break down and analyze the most recent 12-month period of outage causes, including 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. As noted earlier, Citizens' stated that its reliability performance can vary significantly over the short term due to isolated local events such as vehicle accidents. The quarterly reporting of the breakdown and analysis of outage causes will enable EDCs such as Citizens' to identify and explain the situations behind any isolated local events.
Next we will address all comments regarding the overall requirement of quarterly reporting and its appropriateness. The LB&FC Report found that the Commission was not receiving EDC reliability performance information in a timely manner. Additionally, the LB&FC found that the Commission was not requiring EDCs to report the causes of outages along with the reported reliability performance. The LB&FC recommended that the Commission require submission of summary monthly and year-to-date information on the causes of all service interruptions. The LB&FC pointed out that such information is essential to interpret the information in the annual reliability reports and to follow up with the EDCs on the performance they report. The LB&FC also emphasized that current regulations authorize the PUC to require submission of such information. The Commission has considered the merits of the LB&FC findings and recommendations, and we believe the proposed quarterly information in paragraph (e)(5) will satisfy the LB&FC's concerns regarding the timely reporting of causes of service interruptions.
Also, in IRRC's and Allegheny Power's comments related to paragraph (a) and the submittal date for the annual reliability report, it was noted that the Commission's proposal to add a quarterly reporting requirement will provide reliability performance data in a timely manner. IRRC also argued that the problem of the Commission being unaware of poor reliability 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. As stated earlier, the Commission agrees with IRRC and has adopted the request for an April 30 submission date for the more detailed annual reliability reports given that proposed quarterly reports will be in effect.
The FE Companies have asserted that the time, expense, and resources the EDCs will have to incur to collect, calculate, review and publish the information on a quarterly basis will be a burden to EDCs. These comments leave the impression that EDC management does not routinely measure, record, analyze, and produce internal reports to keep adequately informed of the EDC's reliability performance and compliance with reliability regulations in Pennsylvania. The Commission has not been given this impression in our dealings with the EDCs nor would the Commission view this as prudent management of activities that affect electric reliability. Pike County and Citizens' have also implied that the proposed quarterly reporting requirements will be a burden for smaller EDCs. Although the quarterly reports as proposed may require EDCs to maintain and periodically submit the specified information in a defined format that may be slightly different than is currently maintained and reported internally, it should not be difficult to maintain this information in any off-the-shelf software commonly used by all EDCs. Once the desired format for the information is established and saved electronically, it should not be burdensome to update future reports.
The Commission is requiring the EDCs to periodically report reliability information to the Commission that it should already be maintaining and analyzing. In fact, not all of the EDCs have submitted comments claiming that it will be burdensome to provide the proposed reliability information on a quarterly basis. It has been suggested that the Commission should only need to see this type of information once poor reliability performance has been determined. The LB&FC has already scrutinized this type of approach to monitoring electric reliability and determined it to be unsatisfactory. Therefore, the Commission will retain the requirement of quarterly reporting as proposed in paragraphs (e) and (f) including the breakdown and causes of interruptions. Paragraph (e)(5) has been revised to clarify the reporting of a rolling 12-month breakdown and analysis of outage causes every quarter.
Staffing Levels and Contractor Information--§ 57.195--(e)(9); (10)
Paragraph (e)(9) proposed that quarterly reports filed by the larger EDCs (those serving 100,000 or more customers) include the number of dedicated staffing levels for transmission and distribution operations and maintenance at the end of the quarter, in total and by specific category such as linesmen, technicians, and electricians. Similarly, paragraph (e)(10) proposed that quarterly reports filed by larger EDCs include quarterly and year-to-date information on contractor hours and dollars for transmission and distribution operations and maintenance. The Commission expects to continually monitor staffing levels and the use of contractors to ensure that adequate resources are being devoted to the reliability of electric service.
Positions of the Parties
Comments were filed by the FE Companies as well as PPL. The FE Companies and PPL believe that specific information relating to staffing levels and contractor hours and dollars are proprietary. One of the concerns is that if this information were made available to the public, an EDC's ability to negotiate contracts with third-party vendors and others could be adversely affected. The FE Companies also assert that decisions about required resources to perform transmission and distribution work are dynamic and could change frequently in a typical operating year and budget cycle. Therefore, reporting of this type of information could easily lead the Commission and others to second-guess an EDC's business judgments. The FE Companies urge the Commission to eliminate these reporting requirements from the proposed rules. If the information specified is ultimately required to be filed, the FE Companies believe the regulations should allow the EDCs to limit its dissemination to the Commission and its staff, the OCA and Office of Small Business Advocate (OSBA), subject to a blanket prohibition against public disclosure, and to prohibit such information from being inserted into the Commission's public files. PPL recommends that the Commission either eliminate the proposed reporting requirements, or, in the alternative, permit EDCs to retain this information at their main office, and make it available for Commission review and inspection, as necessary.
Disposition
EDCs must effectively utilize internal and external resources to ensure that reliable electric service is provided to their customers. The Commission recognizes the proprietary nature of contractor information. However, the Commission must understand what resources have been employed by an EDC in order to adequately monitor its reliability activities and performance. Providing this information will prevent the Commission from second-guessing how an EDC determines the resources it needs to ensure reliable service. Second-guessing would occur if the Commission did not receive staffing level and contractor information periodically throughout the year, but then criticized an EDC at year-end when reliability performance appeared inadequate. Periodic review of the resource levels and any accompanying explanations of any changes to staffing levels or arrangements with contractors will enable the Commission to better understand the resource decisions the EDCs must face, and may therefore prevent any unnecessary scrutiny of an EDC's use of internal and external resources for reliability activities.
The Commission does not intend to publish all of the specifics of contractual arrangements made between an EDC and its various contractors used to perform transmission and distribution operation and maintenance activities. However, the information submitted in the reports will be kept in public files and is available for inspection. Additionally, concerns raised by the FE Companies and PPL over the dissemination of this information by other parties who will receive the quarterly reports must be addressed. Under paragraph (d)(1), EDCs are required to submit quarterly reliability reports to OCA and OSBA in addition to the Commission. While we believe it is a reasonable request that the Commission, the OCA and OSBA be prohibited from disclosing the specific details of any contract (i.e., hours and dollars) between an EDC and any contractor an EDC employs for transmission and distribution operations and maintenance, the burden will be upon the EDC to apply for a protective order under 52 Pa. Code § 5.423 in advance of the filing of its report if it wants portions of its report to remain confidential and proprietary.3
The Commission does not see any reason why an EDC's staffing levels for positions such as linesman, technician, and electrician should be considered proprietary. The EDCs are regulated utilities, which are not subject to competition like unregulated entities. Therefore, the disclosure of the staffing levels by an EDC will not negatively affect its ability to operate.
Section 57.195(e)(11) (Call-Out Acceptance Rates)
We proposed to obtain information on monthly call-out acceptance rates for transmission and distribution maintenance workers. The monthly call-out acceptance rates may provide some perspective on reliability performance.
Positions of the Parties
The AFL-CIO does not disagree with the reporting requirement at Section 57.195(e)(11), but suggests a time-based measure (the amount of time it takes the EDC to obtain the necessary personnel) rather than a measure based on the percentage of employees called. The AFL-CIO avers that a time-based measure would better reflect some EDCs' use of automated calling methods, which can obtain the necessary personnel more quickly, even though the percentage of those called who respond affirmatively might be lower.
The AFL-CIO asserted that a low call-out acceptance rate (or a lengthy call-out acceptance time) is an indication there may be a serious management issue within the EDC. Thus, it should prompt a more detailed investigation by the Commission to determine if the utility is properly managing its work force and its outage response efforts.
Citizens' states that in addition to call-out acceptance, many other things contribute to overall restoration time. Thus, focusing solely on the call-out acceptance rate will not necessarily lead to meaningful conclusions regarding reliability or restoration effectiveness.
The FE Companies comment that it is inappropriate to report call-out acceptance rates since there is no uniform method by which EDCs define such rates or report them. They state that by requiring the reporting of call-out acceptance rates, it appears that the Commission believes there is a direct correlation between the call-out response rate and an EDC's reliability performance. The FE Companies do not believe this to be correct and assert that the lack of a standard definition for call-out acceptance, along with the inability to account for variations among the EDC's labor agreements, could lead to unreasonable and inappropriate comparisons. Therefore, the FE Companies believe the requirement to report call-out acceptance rates should be eliminated.
In its reply comments, the EAP submits that reporting of call-out acceptance rates is an excellent example of the type of information that would be irrelevant to reliability evaluations. The EAP states that the Department of Transportation's Federal Motor Carrier Standards Administration issued its final Hours of Service rule in April 2003 and the application of this rule renders comparisons between historical and future call-out rates meaningless. Thus, call-out acceptance rates would provide little insight to the Commission in its review of an EDC's reliability performance. The EAP suggests the elimination of this reporting requirement. However, if the reporting of the information becomes a requirement, the Energy Association states that the information should not be made public.
Disposition
We agree with the AFL-CIO that a time-based measure (the amount of time it takes the EDC to obtain the necessary personnel) should be incorporated into the proposed regulation at Section 57.195(e)(11), in addition to the proposed measure based on the percentage of accepted calls. We will amend Section 57.195(e)(11) to state:
(11) Monthly call-out acceptance rate for transmission and distribution maintenance workers presented in terms of both the percentage of accepted call-outs and the amount of time it takes the EDC to obtain the necessary personnel. A brief description of the EDC's call-out procedure should be included when appropriate.In response to the comments of Citizens', the FE Companies, and EAP that the call-out acceptance rates do not provide consistent and valuable information to the Commission in its review of an EDC's reliability performance, we reiterate that the call-out acceptance rate is only one aspect of an EDC's reliability plans and reports that will be reviewed by the Commission. When analyzing an EDC's reliability performance, Commission staff will consider call-out acceptance rates together with all other quarterly and annual data. In addition, we direct the respondents to the Commission's Final Order at 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.
Section 57.195(i) (Parallel Measurement)
Positions of the Parties
In reply comments, the FE Companies respond to comments by OCA that reliability has deteriorated by noting that it is dangerous to conclude service reliability has deteriorated by a comparison of data collected in two materially different ways. The FE Companies state that because of the vast difference in data quality and quantity subsequent to the installation of the outage management systems, no meaningful trends or benchmarks can be derived from data under the old system compared to data under the new system.
Disposition
We wholeheartedly support the EDCs implementing technology improvements in the systems that gather, analyze and report on reliability performance. However, we cannot accept that with each improvement in the measurement systems the EDC and the Commission lose the ability to have accurate reliability performance trend data as the FE Companies note happened in the past. Therefore, we will add an additional provision to the regulations that requires parallel measurement and analysis whenever changes are made to the reliability measuring systems used by the EDCs. Through the use of parallel measurement and analysis, which entails holding other variables constant and measuring reliability under the old and new systems concurrently for a period of time, the EDC should be able to isolate and quantify any independent influence that the change in measurement methods has on reliability performance index scores. This will enable the EDC and the Commission to separate out the effects of changes in reliability measurement from true changes in reliability performance so that we can accurately assess true reliability performance and trends.
§ 57.196. Generation reliability
No changes.
§ 57.197. Reliability investigations and enforcement
No changes.
Other Issues Raised In Comments
Inspection and Maintenance Standards
In its June 12, 2002 report, the LB&FC noted there was insufficient information to allow the Commission to determine if EDCs are implementing their reliability programs as described by the EDCs. The LB&FC also noted that the Commission was in the process of reviewing the establishment of regulations regarding inspection, maintenance, repair and replacement standards, and that IRRC recommended the Commission evaluate what other states have done or are doing regarding inspection and maintenance standards. The LB&FC review found that other states typically do not have specific minimum performance standards for inspection and maintenance programs that companies must meet, but they do have ongoing and detailed reporting requirements concerning such programs. In this way, the states are able to assess whether companies have reasonable inspection and maintenance programs, if they are implementing their programs, and if not, why not. This information is routinely reported and is available for use by the State Commissions. As such, the LB&FC did not recommend prescriptive standards, but suggested establishment of reporting requirements to permit the Commission to monitor the EDCs' progress in implementing their plans for inspecting and maintaining their transmission and distribution systems.
On August 29, 2002, the Commission adopted a study entitled Inspection and Maintenance Study of Electric Distribution Systems dated August 27, 2002. CEEP agreed with the LB&FC and recommended that the annual reliability reporting requirements be revised to include the routine submission of documentation on 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 recommendations cited in the Inspection and Maintenance Study of Electric Distribution Systems Report were incorporated into the proposed paragraphs of Section 57.195(b)(6, 8, 9, 11, 12); (c); and (e) of this rulemaking. Paragraphs (b)(6, 8, 9, 11, 12) outline annual reliability reporting requirements for the larger EDCs related to T & D inspection and maintenance goals/objectives, significant changes to the inspection and maintenance programs, and T & D capital expenditure budgets. Smaller EDCs are to provide similar annual information per paragraph (c). Paragraphs (e)(6); (8) require that the large EDCs submit quarterly and year-to-date information on their progress in achieving the inspection and maintenance goals/objectives and meeting the capital expenditure budget as provided to the Commission in the annual report. It was felt that these reporting requirements address the suggestions of the LB&FC to require routine detailed reporting to assist the Commission in assuring that the EDCs have reasonable inspection and maintenance programs and are implementing their own capital improvement plans.
Positions of the Parties
The AFL-CIO criticized the Commission for not proposing specific inspection and maintenance standards. In its reply comments, OCA agreed with the AFL-CIO's position, citing 66 Pa.C.S. § 2802(20) which provides:
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.Disposition
In the past, the Commission has evaluated the prospect of implementing prescribed inspection and maintenance standards for all EDCs in Pennsylvania and has stated on several occasions that it did not believe specific inspection and maintenance standards were necessary or appropriate. Instead, the Commission focused its efforts on regulating reliability performance--i.e., comparing data regarding the frequency and duration of outages to benchmarks from a historical period. We addressed this issue in our Final Rulemaking Order of April 24, 1998, at L-970120, 27 Pa.B. 809, which promulgated the regulations at Chapter 57, Subchapter N (relating to electric reliability standards). We declined to require specific inspection and maintenance standards because of the new methods and technologies that utilities were developing to improve the inspection and testing process. However, we directed the Commission's Bureau of CEEP to conduct a study of this issue of developing specific inspection and maintenance standards and to submit recommendations for the Commission's consideration.
Specifically, we stated:
[T]he Commission believes that it is inappropriate, at this time, to establish specific performance standards due to the need to better understand existing performance levels and to permit flexible modification of standards as the competitive market develops.We further stated in our Order:
While we are adopting the NESC [National Electrical Safety Code] as the basic external standard, neither existing regulations nor the NESC provides specific standards for inspection and maintenance. These standards will be adopted in subsequent orders.Id. at pp. 3-4.
Similarly, in our Inspection and Maintenance Study Order of August 29, 2002, at M-00021619, the Commission stated that its effort to protect reliability was ''constantly evolving'' and that it would continue to assess the need for inspection and maintenance standards in the future. Id. at 11.
Shortly after we entered our Proposed Rulemaking Order on July 27, 2003, the August 14, 2003 blackout occurred across portions of Pennsylvania, New Jersey, New York, Michigan, Ohio and Canada. New information arising from the blackout provides a basis for revisiting the need for inspection and maintenance standards. One of the causes noted for the blackout was the failure of FirstEnergy Corporation to adequately manage tree growth along transmission lines located in Ohio. Final Report on the August 14 Blackout in the U. S. and Canada, U. S.--Canada Power System Outage Task Force, pp. 17, 57-64 (April 2004). In the wake of the blackout, the Federal Energy Regulatory Commission (FERC) commissioned a study of a utility vegetation management practices. 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, among other things, that the ''[c]urrent oversight of UVM [utility vegetation management] activities by appropriate agencies or organizations is overwhelmingly inadequate'' (Report p. 68). To remedy this inadequacy, the report recommended:
2. DEVELOP CLEAR UVM PROGRAM EXPECTATIONS FOR UTILITY COMPANIESOversight organizations should work with the utility companies, the UVM industry, and other stakeholders to develop measurable and achievable program objectives. The development of these expectations will require a joint effort to identify what specifically can be done to ensure the reduced likelihood of future tree and power line conflicts. Given the myriad of site-specific UVM related variables throughout North America, we would expect that these expectations may differ based on local environmental conditions and other factors. With that caveat, we offer the following three examples of items that could be included as part of these expectations:* Adoption of specific UVM Best Practices* Development of, and adherence to comprehensive UVM schedules* Achieving specific reductions in tree-related outages(Report, pp. 68-69). While it is not binding on this Commission, this report should not be ignored as the Commission considers how to preserve reliability.
Therefore, we will direct Law Bureau to issue an advance notice of proposed rulemaking on inspection and maintenance standards. The purpose of this proceeding will be to determine whether the Commission should now adopt specific inspection and maintenance standards, and if so, what types of standards would be appropriate.
In the meantime, the Commission is putting into effect the reporting requirements on inspection and maintenance activities in Annex A. While it may be argued that these requirements do not go far enough, there is no harm in implementing them while the Commission considers the adoption of specific inspection and maintenance standards. If the Commission ultimately promulgates regulations establishing specific inspection and maintenance standards, the reporting requirements issued today can be modified in the future.
Until new regulations are promulgated, the proposed reporting requirements for inspection and maintenance goals/objectives and capital expenditure budgets established today will enable the Commission to assess whether companies have reasonable inspection and maintenance programs and capital improvement plans, if they are implementing those programs and plans, and if not, why not. Proper industry practices must be adhered to by the EDCs to ensure reliable service. We intend to continually examine the reasonableness of utility reliability plans and expect the EDCs to adhere to proper industry practices.
Bureau of Consumer Services Letter of October 17, 2003
Positions of the Parties
PECO and EAP filed comments stating that the October 17, 2003 letter to EDCs from the Commission's Bureau of Consumer Services (BCS) is inappropriate, unreasonable, premature and should be withdrawn. In response, the OCA commented that EAP's comments about the BCS letter are without merit and not appropriate in the Rulemaking Docket. OCA notes that the purpose of the letter as stated is to inform the EDCs of a change BCS is making to the Commission's process for investigating informal service quality complaints filed with the Commission. OCA draws a distinction between a process for handling individual consumer complaints as contained in the letter, and this rulemaking which should be viewed as a means for the PUC to ensure that the EDCs are managing their systems on an overall basis consistent with the Act.
Disposition
We adopt the position of the OCA that the October 17, 2003 letter from BCS to EDCs about a change in the process for investigating informal quality service complaints is not germane to this rulemaking.
Overall, we believe that the regulations, as herein amended in consideration of comments received, and Annex A, are consistent with the public interest and shall be adopted at this time through final order. Annex A reflects the cumulative changes made to Annex A of this Commission's Proposed Rulemaking Order entered on June 27, 2003. Accordingly, under authority at Section 501 of the Public Utility Code, 66 Pa.C.S. § 501, and Sections 201, et seq., of the Commonwealth Documents Law, 45 P. S. §§ 1201, et seq., 66 Pa.C.S. §§ 2801 et seq. and the regulations promulgated thereunder at 52 Pa. Code §§ 57.191--57.197; and sections 201 and 202 of the act of July 31, 1968 (P. L. 769, No. 240) (45 P. S. §§ 1201 and 1202) and the regulations promulgated thereunder at 1 Pa. Code §§ 7.1, 7.2 and 7.5; section 204(b) of the Commonwealth Attorneys Act (71 P. S. § 732.204(b)); section 5 of the Regulatory Review Act (71 P. S. § 732.204(b)); and section 612 of The Administrative Code of 1929 (71 P. S. § 232) and the regulations promulgated thereunder at 4 Pa. Code §§ 7.251--7.235, we adopt the regulations set forth in Annex A; Therefore,
It Is Ordered That:
1. 52 Pa. Code, Chapter 57 is amended by amending §§ 57.192, 57.194 and 57.195 to read as set forth in Annex A, with ellipses referring to the existing text of the regulations.
2. The Secretary submit this final rulemaking order and Annex A for review and approval by the designated standing committees of both houses of the General Assembly, and for review and approval of IRRC.
3. The Secretary shall submit this Order and Annex A to the Governor's Budget Office for review of fiscal impact.
4. The Secretary shall submit a copy of this order and Annex A to the Office of Attorney General for review as to legality.
5. The Secretary certify this order and Annex A and deposit them with the Legislative Reference Bureau to be published in the Pennsylvania Bulletin.
6. The amendments to Chapter 57 embodied in Annex A shall become effective upon final publication in the Pennsylvania Bulletin.
7. A copy of this order and Annex A be filed in the folder regarding benchmarks and standards at M-00991220.
8. The contact persons for this rulemaking are (technical) Thomas Sheets, Director of Bureau of Audits, (717) 783-5000 and (legal) Elizabeth H. Barnes, Law Bureau, (717) 772-5408.
9. A copy of this order and Annex A be served upon all electric distribution companies operating in this Commonwealth, the Office of Consumer Advocate, the Office of Small Business Advocate, the Energy Association of Pennsylvania and the Pennsylvania AFL-CIO--Utility Caucus.
10. The Law Bureau prepare an Advance Notice of Proposed Rulemaking regarding Inspection and Maintenance Standards under 66 Pa.C.S. § 2802(20).
JAMES J. MCNULTY,
Secretary(Editor's Note: For the text of the order of the Independent Regulatory Review Commission, relating to this document, see 34 Pa.B. 4528 (August 14, 2004).)
Fiscal Note: Fiscal Note 57-228 remains valid for the final adoption of the subject regulations.
Annex A
TITLE 52. PUBLIC UTILITIES
PART I. PUBLIC UTILITY COMMISSION
Subpart C. FIXED SERVICE UTILITIES
CHAPTER 57. ELECTRIC SERVICE
Subchapter N. ELECTRIC RELIABILITY STANDARDS § 57.192. Definitions.
The following words and terms, when used in this subchapter, have the following meanings, unless the context clearly indicates otherwise:
Adequacy--The ability of the electric system to supply the aggregate electrical demand and energy requirements of the customers from various electric generation suppliers at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements.
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.
Control area--An electric system or systems, bounded by interconnection metering and telemetry, capable of controlling generation to maintain its interchange schedule with other control areas and contributing to frequency regulation of the interconnected systems.
EDC--Electric distribution company--An electric distribution company as defined in 66 Pa.C.S. § 2803 (relating to definitions).
Electric generation supplier or electricity supplier--An electric generation supplier or electricity supplier as defined in 66 Pa.C.S. § 2803.
FERC--Federal Energy Regulatory Commission.
IEEE--Institute of Electrical and Electronic Engineers.
Interruption duration--A period of time measured to the nearest 1-minute increment which starts when an electric distribution company is notified or becomes aware of an interruption, unless an electric distribution company can determine a more precise estimate of the actual starting time of an interruption, and ends when service is restored. Interruptions shall be categorized, based on duration, such as momentary or sustained interruptions, or by similar descriptions, as adopted by the IEEE or similar organization identified by the Commission. This subchapter requires tracking, reporting and evaluation of two categories of interruption duration that will incorporate any changes in the terms used or the definitions of those terms as adopted by the IEEE or Commission order.
Major event--
(i) Either of the following:
(A) An interruption of electric service resulting from conditions beyond the control of the EDC which affects at least 10% of the customers in the EDC's service territory during the course of the event for a duration of 5 minutes each or greater. The event begins when notification of the first interruption is received and ends when service to all customers affected by the event is restored.
(B) An unscheduled interruption of electric service resulting from an action taken by an EDC to maintain the adequacy and security of the electrical system, including emergency load control, emergency switching and energy conservation procedures, as described in § 57.52 (relating to emergency load control and energy conservation by electric utilities), which affects at least one customer.
(ii) The term does not include scheduled outages in the normal course of business or an electric distribution company's actions to interrupt customers served under interruptible rate tariffs.
Momentary customer interruption--
(i) The loss of electric service by one or more customers for the period defined as a momentary customer interruption by the IEEE as it may change from time to time.
(ii) The term does not include interruptions described in subparagraph (ii) of the definition of ''major event,'' or the authorized termination of service to an individual customer.
NERC--North American Electric Reliability Council--An organization of regional reliability councils established to promote the reliability of the electricity supply for North America.
Performance benchmark--A numerical value that characterizes an EDC's average historical reliability performance for a specific time period in the past. The benchmark is based on an EDC's performance for the entire service territory and is a reference point for comparison of future reliability performance. The Commission will, from time to time, establish benchmarks for each reliability index and each EDC. The performance benchmarks are established by Commission Order at Docket No. M-00991220.
Performance standard--A numerical value that establishes a minimum level of EDC reliability allowed by the Commission. The performance standard is a criterion tied to the performance benchmark that applies to reliability performance for the EDC's entire service territory. The Commission will, from time to time, establish new performance standards for each reliability index for each EDC. The performance standards are established by Commission Order at Docket No. M-00991220.
* * * * * § 57.194. Distribution system reliability.
(a) An EDC shall furnish and maintain adequate, efficient, safe and reasonable service and facilities, and shall make repairs, changes, alterations, substitutions, extensions and improvements in or to the service and facilities necessary or proper for the accommodation, convenience and safety of its patrons, employees and the public. The service shall be reasonably continuous and without unreasonable interruptions or delay.
(b) An EDC shall install, maintain and operate its distribution system in conformity with the applicable requirements of the National Electrical Safety Code.
(c) An EDC shall make periodic inspections of its equipment and facilities in accordance with good practice and in a manner satisfactory to the Commission.
(d) An EDC shall strive to prevent interruptions of electric service and, when interruptions occur, restore service within the shortest reasonable time. If service must be interrupted for maintenance purposes, an EDC should, where reasonable and practicable, attempt to perform the work at a time which will cause minimal inconvenience to customers and provide notice to customers in advance of the interruption.
(e) An EDC shall design and maintain procedures to achieve the reliability performance benchmarks and minimum performance standards established by the Commission.
(f) An EDC shall develop and maintain a program for analyzing the service performance of its circuits during the course of each year.
(g) An EDC shall maintain a 5-year historical record of all known customer interruptions by category of interruption duration, including the time, duration and cause of each interruption. An EDC shall retain all records to support the reporting requirements under § 57.195 (relating to reporting requirements) for 5 years.
(h) An EDC shall take measures necessary to meet the reliability performance benchmarks and minimum performance standards established by the Commission.
(1) The performance standard shall be the minimum level of EDC reliability performance allowed by the Commission for each measure for all EDCs. Performance that does not meet the standard for any reliability measure shall be the threshold for triggering additional scrutiny and potential compliance enforcement actions by the Commission's prosecutorial staff.
(i) The Commission will consider historical performance levels, performance trends, and the number and type of standards violated when determining appropriate additional monitoring and compliance enforcement actions. The Commission will consider other information and factors including an EDC's outage cause analysis, inspection and maintenance goal data, operations and maintenance and capital expenditure data, and staffing levels as presented in the quarterly and annual reports as well as in filed incident reports.
(ii) Additional monitoring and enforcement actions that may be taken are 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, requiring an implementation schedule, and assessing penalties and fines.
(2) An EDC shall inspect, maintain and operate its distribution system, analyze reliability results, and take corrective measures as necessary to achieve performance benchmarks and performance standards.
§ 57.195. Reporting requirements.
(a) An EDC shall submit an annual reliability report to the Commission, on or before April 30 of each year.
(1) An original and six copies of the report shall be filed with the Commission's Secretary and one copy shall also be submitted to the Office of Consumer Advocate and the Office of Small Business Advocate.
(2) The name, title, telephone number and e-mail address of the persons who have knowledge of the matters, and can respond to inquiries, shall be included.
(b) The annual reliability report for larger EDCs (those with 100,000 or more customers) shall include, at a minimum, the following elements:
(1) An overall current assessment of the state of the system reliability in the EDC's service territory including a discussion of the EDC's current programs and procedures for providing reliable electric service.
(2) A description of each major event that occurred during the year being reported on, including the time and duration of the event, the number of customers affected, the cause of the event and any modified procedures adopted to avoid or minimize the impact of similar events in the future.
(3) A table showing the actual values of each of the reliability indices (SAIFI, CAIDI, SAIDI, and if available, MAIFI) for the EDC's service territory for each of the preceding 3 calendar years. The report shall include the data used in calculating the indices, namely the average number of customers served, the number of sustained customer minutes interruptions, the number of customers affected and the minutes of interruption. If MAIFI values are provided, the number of customer momentary interruptions shall also be reported.
(4) A breakdown and analysis of outage causes during the year being reported on, including the number and percentage of service outages, the number of customers interrupted, and 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.
(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.
(6) A comparison of established transmission and distribution inspection and maintenance goals/objectives versus actual results achieved during the year being reported on. Explanations of any variances shall be included.
(7) A comparison of budgeted versus actual transmission and distribution operation and maintenance expenses for the year being reported on in total and detailed by the EDC's own functional account code or FERC account code as available. Explanations of any variances 10% or greater shall be included.
(8) A comparison of budgeted versus actual transmission and distribution capital expenditures for the year being reported on in total and detailed by the EDC's own functional account code or FERC account code as available. Explanations of any variances 10% or greater shall be included.
(9) Quantified transmission and distribution inspection and maintenance goals/objectives for the current calendar year detailed by system area (that is, transmission, substation and distribution).
(10) Budgeted transmission and distribution operation and maintenance expenses for the current year in total and detailed by the EDC's own functional account code or FERC account code as available.
(11) Budgeted transmission and distribution capital expenditures for the current year in total and detailed by the EDC's own functional account code or FERC account code as available.
(12) Significant changes, if any, to the transmission and distribution inspection and maintenance programs previously submitted to the Commission.
(c) The annual reliability report for smaller EDCs (those with less than 100,000 customers) shall include all items in subsection (b) except for the requirement in paragraph (5).
(d) An EDC shall submit a quarterly reliability report to the Commission, on or before May 1, August 1, November 1 and February 1.
(1) An original and six copies of the report shall be filed with the Commission's Secretary and one copy shall also be submitted to the Office of Consumer Advocate and the Office of Small Business Advocate.
(2) The name, title, telephone number and e-mail address of the persons who have knowledge of the matters, and can respond to inquiries, shall be included.
(e) The quarterly reliability report for larger companies (those with 100,000 or more customers) shall, at a minimum, include the following elements:
(1) A description of each major event that occurred during the preceding quarter, including the time and duration of the event, the number of customers affected, the cause of the event and any modified procedures adopted in order to avoid or minimize the impact of similar events in the future.
(2) Rolling 12-month reliability index values (SAIFI, CAIDI, SAIDI, and if available, MAIFI) for the EDC's service territory for the preceding quarter. The report shall include the data used in calculating the indices, namely the average number of customers served, the number of sustained customer interruptions, the number of customers affected, and the customer minutes of interruption. If MAIFI values are provided, the report shall also include the number of customer momentary interruptions.
(3) Rolling 12-month reliability index values (SAIFI, CAIDI, SAIDI, and if available, MAIFI) and other pertinent information such as customers served, number of interruptions, customer minutes interrupted, number of lockouts, and so forth, for the worst performing 5% of the circuits in the system. An explanation of how the EDC defines its worst performing circuits shall be included.
(4) Specific remedial efforts taken and planned for the worst performing 5% of the circuits as identified in paragraph (3).
(5) A rolling 12-month breakdown and analysis of outage causes during the preceding quarter, including the number and percentage of service outages, the number of customers interrupted, and 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.
(6) Quarterly and year-to-date information on progress toward meeting transmission and distribution inspection and maintenance goals/objectives (for first, second and third quarter reports only).
(7) Quarterly and year-to-date information on budgeted versus actual transmission and distribution operation and maintenance expenditures in total and detailed by the EDC's own functional account code or FERC account code as available. (For first, second and third quarter reports only.)
(8) Quarterly and year-to-date information on budgeted versus actual transmission and distribution capital expenditures in total and detailed by the EDC's own functional account code or FERC account code as available. (For first, second and third quarter reports only.)
(9) Dedicated staffing levels for transmission and distribution operation and maintenance at the end of the quarter, in total and by specific category (for example, linemen, technician and electrician).
(10) Quarterly and year-to-date information on contractor hours and dollars for transmission and distribution operation and maintenance.
(11) Monthly call-out acceptance rate for transmission and distribution maintenance workers presented in terms of both the percentage of accepted call-outs and the amount of time it takes the EDC to obtain the necessary personnel. A brief description of the EDC's call-out procedure should be included when appropriate.
(f) The quarterly reliability report for smaller companies (those with less than 100,000 customers) shall, at a minimum, include paragraphs (1), (2) and (5) identified in subsection (e).
(g) When an EDC's reliability performance is found to not meet the Commission's established performance standards, as defined in § 57.194(h) (relating to distribution system reliability), the Commission may require a report to include the following:
(1) The underlying reasons for not meeting the established standards.
(2) A description of the corrective measures the EDC is taking and target dates for completion.
(h) An EDC shall, within 30 calendar days, report to the Commission any problems it is having with its data gathering system used to track and report reliability performance.
(i) When an EDC implements a change in its outage management system for gathering and analyzing reliability performance that has the potential to affect reliability index values, the EDC shall conduct parallel measurement and analysis to isolate and quantify the influence that the measurement change exerts on reliability index values. The length of the parallel measurement period shall be sufficient to isolate and quantify the independent effects of the measurement change.
(j) The Commission will prepare an annual reliability report and make it available to the public.
[Pa.B. Doc. No. 04-1709. Filed for public inspection September 17, 2004, 9:00 a.m.] _______
3 In addition, Section 219 of the Commission's Procedures Manual gives utilities the ability to file confidential documents and seek protective orders when the allegedly proprietary information is sought by the public.
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