RULES AND REGULATIONS
PENNSYLVANIA PUBLIC UTILITY COMMISSION
[52 PA. CODE CH. 57]
[28 Pa.B. 3385]
[L-970120]
Electric Service Reliability
The Pennsylvania Public Utility Commission (Commission) on April 23, 1998, adopted a final rulemaking to provide for continuing adequacy and reliability and ensuring safety of the generation, transmission and distribution of electricity in this Commonwealth. The contact persons are Patricia Krise Burket, Law Bureau (717) 787-3464 and Blaine J. Loper, Bureau of Conservation, Economics and Energy Programs, (717) 787-3810.
Executive Summary
On June 12, 1997, the Commission promulgated proposed regulations to add Chapter 57, Subchapter N (relating to electric reliability standards) which establishes standards and procedures for assessing the reasonableness of electric service reliability. The proposed amendments were published at 27 Pa.B. 5262 (October 11, 1997) with a 60-day comment period.
At the public meeting held April 23, 1998, the Commission adopted an order which promulgates final-form regulations which are necessary to ensure the continued safety and reliability of electric service in this Commonwealth.
The final-form regulations require electric distribution companies (EDCs) and electric generation suppliers (EGSs) to conform to the requirements of the North American Electric Reliability Council and the appropriate regional reliability council, or successor organizations. The final-form regulations also adopt industry accepted performance indicators for monitoring the performance and reliability of the transmission and distribution systems, and requires annual filings of utility performance results.
Regulatory Review
Under section 5(a) of the Regulatory Review Act (71 P. S. § 745.5(a)), on September 30, 1997, the Commission submitted a copy of the final rulemaking, which was published as proposed at 27 Pa.B. 5262, to the Independent Regulatory Review Commission (IRRC) and the Chairpersons of House Committee Consumer Affairs and the Senate Committee on Consumer Protection and Professional Licensure for review and comment. Under section 5(c) of the Regulatory Review Act, IRRC and the Committees were provided with copies of all comments received, as well as other documentation.
In preparing these final-form regulations, the Commission has considered all comments received from IRRC, the Committees and the public.
These final-form regulations were deemed approved by the House and Senate Committees by June 8, 1998. IRRC met on June 18, 1998, and approved the final-form regulatons in accordance with section 5.1(e) of the Regulatory Review Act (71 P. S. § 745.5a(e)).
Public Meeting
held April 23, 1998
Commissioners Present: John M. Quain, Chairperson; Robert K. Bloom, Vice Chairperson; John Hanger, Statement attached; David W. Rolka; Nora Mead Brownell
Final Rulemaking Order
By the Commission:
On December 3, 1996, Governor Tom Ridge signed into law 66 Pa.C.S. §§ 2801--2812 (relating to Electricity Generation Customer Choice and Competition Act) (act). The act establishes 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.
In response to this Legislative mandate, on January 24, 1997, the Commission instituted a rulemaking proceeding to develop regulations to ensure the safety, adequacy and reliability of the generation, transmission and distribution of electricity in this Commonwealth See 66 Pa.C.S. §§ 2802(12) and (20), 2803, 2804(1), 2805(b)(1)(iii) and 2807(a).
An advance notice of proposed rulemaking was published at 27 Pa.B. 809 (February 15, 1997), with a 30-day comment period. Based upon the comments received, we promulgated proposed regulations to amend Chapter 57 by adding Subchapter N which establishes standards and procedures for assessing the reasonableness of electric service reliability. On September 30, 1997, a copy of the proposed rulemaking was submitted to IRRC and the Chairpersons of the House Consumer Affairs Committee and the Senate Consumer Protection and Professional Licensure Committee. The proposed amendments were published at 27 Pa.B. 5262, with a 60-day comment period.
Comments were received from: John G. Alford, former Commission Secretary; Enron Power Marketing, Inc. (Enron); Ford Motor Land Services Corporation (Ford); the Industrial Energy Consumers of Pennsylvania (IECPA); the International Brotherhood of Electrical Workers' Pennsylvania Utility Caucus (IBEW); IRRC; Lebanon Methane Recovery, Inc. (LMRI); Metropolitan Edison Company and Pennsylvania Electric Company (collectively, GPU Energy); the Office of Consumer Advocate (OCA); PECO Energy Company (PECO); the Pennsylvania Electric Association (PEA); the Pennsylvania Rural Electric Association (PREA); Pennsylvania Power & Light Company (PP&L); the Pennsylvania Rural Electric Association (PREA); and UGI Utilities, Inc.--Electric Division (UGI).
This order discusses the comments received and sets forth, in Annex A, final-form regulations governing the safety and reliability of electric service in this Commonwealth.
Many comments suggested that the proposed regulations adopted by the Commission failed to clearly communicate the basic approach to ensuring reliability. In general, the regulations establish recordkeeping and reporting requirements concerning various aspects of system reliability. However, the 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.
Thus, these regulations generally utilize existing performance standards, such as those established under the National Electrical Safety Code (NESC) or by industry organizations, such as the Institute of Electrical and Electronic Engineers (IEEE), the North American Electric Reliability Council (NERC) and regional reliability organizations. IRRC comments that it was unable to determine from the proposed regulations what the performance standards would be or how they would be adopted. The Commission will issue additional orders pursuant to these regulations, from time to time, as necessary or appropriate to adopt specific benchmarks, based upon historic performance or standards, or both, for required performance. The orders will be adopted following the opportunity for interested parties to submit comments. It is noted that historic or benchmark performance may either exceed or fail to meet acceptable performance standards.
It is also important to note the long-standing concept of ''reasonable service'' under traditional utility regulation. Reasonable service always has balanced consumer demands and industry standards. Reliability performance standards must be consistent with this concept of reasonable service. Reasonable service for all consumers, considering the cost of providing the service, is the goal. Perfect service for all consumers, regardless of the cost, has never been the goal, and it cannot now be.
Existing Regulations.
Related existing regulations under §§ 57.13--57.16 remain in effect. The definition of ''service interruption'' under § 57.17 is replaced by the new definitions under § 57.192 (relating to definitions).
We agree with the OCA and IBEW that we cannot simply delete the existing regulations on maintenance and inspection and be consistent with the statutory directive to at least maintain or improve service quality. We have retained § 57.18(a) as § 57.194(c) (relating to distribution system reliability). Section 57.194(b) generally requires conformity with the NESC. While we are adopting the NESC 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.
Section 57.26 is deleted and has been replaced by § 57.193(a) (relating to transmission system reliability) and § 57.194(b).
§ 57.192. Definitions.
Several commentators suggested changes to definitions contained in the proposed rulemaking for clarification. Many of these suggestions have been incorporated in the final rule and are discussed below.
Adequacy
The transition to competition requires that adequacy include the delivery of power from multiple suppliers to customers in the service territory in an efficient open access network. Thus, the definition of ''adequacy'' has been modified.
Interruption Duration
Many commentators recommended modifications to the definitions relating to the duration of interruptions that would substantially change reporting requirements and performance standards. For example, IECPA proposes the adoption of existing IEEE standards, while the PEA proposes the adoption of the proposed IEEE standards. Upon consideration of these comments, we conclude that reference to an objective industry standard without specification of a defined time period is appropriate at this time. Thus, while the industry standard may change, these regulations need not be revised.
Major Event
The PEA and PP&L aver that the cause of a major event should not be limited to weather or unusual equipment failures. They suggest that other potential causes include relatively nonviolent weather conditions, such as thunderstorms and snowstorms, other types of natural disasters, such as earthquakes, floods or fires, and incidents beyond the control of the EDC, such as accidental damage, civil unrest or sabotage. PREA believes that weather conditions which routinely occur in this Commonwealth should be excluded from the definition unless they occur during and are attributable to a disaster emergency as declared by the Pennsylvania Emergency Management Agency (PEMA).
We agree with the PEA and PP&L that measurement of compliance with benchmark or performance standards should not be inappropriately distorted by significant major events beyond utility control. However, all events that are beyond the control of the utility should not be excluded. For example, a normal winter storm is beyond utility control but causes many outages, and the EDC must maintain its distribution system sufficiently to reasonably minimize the likelihood of service outages. Even if major events are not reported in a way which may distort system performance averages, they remain the central reliability issue. These events should be reported and service response to major events must still be adequate. Thus, we will exclude major events, as defined, from inclusion in the performance indices, but will require EDCs to include them in the reporting of all service interruptions.
We believe that the limitation in the definition of ''major event'' to those outages affecting at least 10% of the customers in an operating area during the course of the event for a duration of 5 minutes each or greater is appropriate to ensure that routine outages, even if weather related or otherwise beyond the control of the EDC, are nevertheless considered. It is noted that nothing in these regulations modify existing reporting or operational requirements related to PEMA or emergency operations.
The purpose of identifying a major event is to exclude abnormal events that would skew the data used in the calculation of reliability indices and make it difficult to objectively analyze performance. While there may be several weather and nonweather related causes of random major events, we believe that the key to identifying such an event is the magnitude of the event; that is, the total number of customers affected by the event. Identification of every conceivable unusual occurrence is both impractical and unnecessary. Thus, we have revised this definition to include interruptions which are the results of involuntary factors beyond the control of the EDC. It is noted that under § 57.195(b), the EDC is required to annually provide an assessment of electric service reliability, including a discussion of major events occurring during the preceding calendar year. This will provide the Commission the opportunity to examine the causes of all major events identified by the EDC.
GPU Energy, PEA and PP&L believe that, when a major event affects more than one operating area, the resulting service interruptions for all affected areas should be excluded from the EDC's overall reliability indices, even though the other affected operating areas do not meet the threshold of at least 10% of the customers. We will accept this modification.
PECO believes that the 10% threshold is unfair to large EDCs and suggests that a 5% threshold is appropriate for PECO (approximately 75,000 customers). PECO alleges that the smaller EDCs will be removing a far greater percentage of events than the larger EDCs and wants assurance that it will be able to compete on a level playing field with the other Pennsylvania EDCs. For the Commission to ensure the continuation of reliable electric service, we intend to identify benchmark performance based on historical performance and new performance standards. Utility performance will be evaluated based on these measures. Thus, we believe, PECO's concern is without merit.
Based on other comments from PEA and OCA, we have made revisions to the definition of ''major event'' to identify when a major event begins and ends, and to clarify that a major event does not include an EDC's actions to interrupt customers on interruptible rate tariffs who agree to interruptions in return for a rate discount.
Reliability Indices
GPU Energy and PP&L recommended that the System Average Interruption Duration Index (SAIDI) be deleted, since SAIDI can be calculated by multiplying Customer Average Interruption Duration Index (CAIDI) by System Average Interruption Frequency Index (SAIFI). Although we agree that SAIDI can be calculated from SAIFI and CAIDI, we believe that the EDC should perform the calculations to avoid questions concerning Commission calculations.
GPU Energy, PEA and PP&L suggested that the requirement for a Momentary Average Interruption Frequency Index (MAIFI) be deleted, since the information needed to calculate this index is difficult and extremely costly to obtain, without any real attendant benefits. We do not intend to require knowledge of every interruption or the expenditure of large amounts of capital to obtain the information. Only the reporting of known interruptions, of any duration, will be required. Thus, we have retained this performance indicator.
Sustained Customer Interruption
Several commentators suggested expanding this definition to clarify the types of service interruptions which are not to be considered sustained customer interruptions for the purpose of calculating the reliability indices. We find that the modified definition of ''major event'' and the exclusion of major events from the calculation of the reliability indices render the detailed and inconsistent qualifications of this definition unnecessary. Additionally, rather than adopting a specific outage duration, we are adopting the IEEE definitions as they may change from time to time.
Worst-Performing Circuits
Many commentators suggested modifications to the definition and use of the concept of worst-performing circuits in order to make it more practical and meaningful. Upon consideration of the comments, we conclude that identification of worst-performing circuits adds unnecessary complication to the regulations without increasing our ability to ensure the maintenance or improvement of system reliability. For example, if only 1% of a utility's circuits fail to meet the reliability standard, focusing on the 5% worst-performing circuits is not useful. The concept is similarly inapt if 10% of a utility's circuits do not meet the performance standards. Thus, the concept of worst-performing circuits has been deleted from the regulations. Instead, the regulations will provide for the establishment of performance standards that identify circuits or operating areas requiring improved performance.
§ 57.193. Transmission system reliability.
The PEA commented that facilities governed by the NESC, while required to meet current the NESC requirements upon their initial installation, are permissibly maintained and operated in conformity with the relevant requirements of the same NESC edition, not the most recent edition. The application of the NESC is limited to new installations and extensions. PEA also states that the NESC requirements relate to the electrical, mechanical and civil engineering aspects of the design, installation and maintenance of the physical transmission and distribution facilities, whereas reliability council policies and requirements relate to continuing, real-time operation of the transmission system.
Our concern here is with applicable requirements, not the applicable edition. It is possible that future editions of the NESC may require the upgrading of some existing system components. It is also possible that an EDC may not operate all aspects of the transmission system directly, as in the case of an independent system operator (ISO), and there may be other entities, such as regulatory commissions or ISOs, which have additional requirements. Thus, we have revised subsection (a) to reflect these concerns.
Subsection (b) of the proposed regulations established comparability standards for an EDC's transmission service provided to wholesale customers. PP&L argued that this subsection should be deleted, since transmission service provided to wholesale customers is a matter wholly within the exclusive jurisdiction of the Federal Energy Regulatory Commission (FERC). IRRC recommended retaining this subsection to help ensure the quality of electric service, upon confirmation of its legality.
We included this section to reflect our legislative mandate under section 2805(b)(1)(iii) of the act (relating to regionalism and reciprocity). While we fully recognize FERC's authority to regulate the rates, terms and conditions of wholesale transmission service, we are nevertheless obligated by statute to ensure comparability of service to electric cooperative corporations and, therefore, reject PP&L's argument.
The OCA and Enron suggested that the Commission actively monitor the use of the transmission system. As we begin the retail open access era, the Commission must know if the transmission system is adequately constructed, maintained and operated in a way which promotes a fully competitive and efficient market. Thus, we have added subsection (c) to annually require an assessment of the performance of the transmission system.
§ 57.194. Distribution system reliability.
The language in subsection (a) has been modified to precisely reflect existing law and standards concerning reasonable service and facilities, see 66 Pa.C.S. § 1501 (relating to character of service and facilities).
We have modified subsection (b) to refer to the applicable requirements of the NESC instead of the ''most recent edition'' of the NESC. This is consistent with our change to § 57.193(a).
Subsection (e) required EDCs to maintain procedures designed to sustain, at a minimum, the historical level of reliability. PP&L believed that sustaining historically high levels of reliability in a specific operating area may not be practical or cost effective. PP&L recommends that this subsection refer to ''acceptable levels of reliability'' and that ''and cost effective'' should be added after ''where necessary.'' IRRC agreed with adding the cost effective qualifier, but did not concur with PP&L's recommendation concerning the level of service to be sustained, noting that historical levels can be documented.
As discussed further, we will use historical data to establish performance standards which will serve as acceptable electric service reliability. Thus, to avoid confusion with regard to the minimum level of reliability required by this subsection, we have modified subsection (e) to clarify the link between this requirement and the reliability performance standards established under subsection (h).
In response to comments of the PEA, subsection (f) has been revised to reflect the deletion of the term ''worst performing circuits'' and to clarify the EDC's objective for analyzing its circuits.
Subsection (g) required that the EDC maintain a 5-year historical record of service interruptions. GPU Energy, PEA and PP&L commented that the EDC does not always know of service interruptions, especially those of short duration, unless notified by a customer or unless expensive, customer-specific equipment is installed. As discussed earlier, these regulations are not requiring knowledge of every interruption or the upgrade of interruption detection systems at this time. The requirement is to track and report all known interruptions of whatever duration, by category. It is noted that the existing regulations under §§ 57.14 and 57.15 (relating to service voltage; and system frequency) remain in effect and already require a minimum detection standard, although it may be appropriate to revise these standards at a later date. In addition, the EDC will be required to retain all records required to comply with the reporting requirements.
Subsection (h) required an EDC to ''take measures necessary to meet the reliability performance standard set forth by this subsection.'' The provisions refer to the establishment of a numerical benchmark based on historic performance and a performance standard for each reliability index. The regulations adopt a general rule that each EDC must at least maintain the historic benchmark and meet the performance standard.
PEA and PP&L believe that the numerical values for the reliability indices for each operating area should be developed in cooperation with the EDCs and other affected parties. UGI avered that it is incumbent upon the Commission to consider the specific conditions applicable to each operating area before setting that area's initial performance standards. GPU Energy recommended that the Commission use a 5-year historical average to calculate the initial and subsequent values for the reliability indices. IRRC believed that the regulations should either provide the actual standards or criteria for calculating the standards, or at least specify where the standards or criteria can be found. IRRC also suggests that the regulations should provide a timely due process opportunity for affected parties to provide input or raise objections.
It is the Commission's intention to set reliability performance standards in cooperation with the industry. All parties will have an opportunity to provide comments prior to final adoption of the Commission's decision. Since benchmarks based on historical performance of each EDC may vary, both below or above the performance standard established, the Commission may take such history into account as it establishes the benchmarks and performance standards. We have reflected IRRC's comments by clarifying this section with substantial changes. Although we agree with IRRC that actual standards or criteria are preferable, the foregoing comments and the lack of existing data in the record of this proceeding require that we decline to adopt a particular methodology or precise standard in this rulemaking. The parties have not had an opportunity to comment and there may be other specific factors to be considered. Rather, this rulemaking establishes the reporting requirements and the parameters that will permit the adoption of more specific standards and benchmarks in the future.
As discussed above, we will require reporting of all known service interruptions according to the definitions established by IEEE. Both IECPA and PEA indicated support for this result as an alternative to their preferred recommendations. We agree with this approach as being consistent with other aspects of these regulations concerning compliance with NERC, the NESC and other objective standards by reference. While we agree with PEA that it would be expensive and inappropriate to require an EDC to identify all outages, we note that the existing regulations under § 57.17 already require utilities to keep records of outages affecting the entire system or a major division of the system, as brief as 1 minute. As the Commission adopts performance benchmarks and standards, all parties must remain cognizant of the goal of requiring reasonable service without gold-plating, while recognizing that changes in our economy and society may indicate that a different level of performance quality is required to provide reasonably reliable service.
Subsection (h) has been modified to reflect the above discussion.
§ 57.195. Reporting requirements.
Subsection (a) requires an EDC to submit to the Commission, on or before March 31 of each year, a reliability report. PP&L avers that it would be very difficult to prepare and submit the report by March 31, because of the time required to verify and enter end-of-year reliability information into its database, to make the necessary analyses, to plan improvements and to determine the improvement experienced by circuits that were worked on during the previous year. PP&L recommended a 2-month delay in the reporting deadline. Although no other EDC has voiced this concern, we recognize the work required to comply with this and several other annual reporting requirements. To reduce the EDCs' reporting burden, we have moved the reporting deadline to May 31.
GPU Energy, PEA and PP&L suggested revisions to our proposed subsection (e), which required information regarding worst-performing circuits that fail to meet the performance standards. GPU Energy and PEA recommended that the reporting requirements of this subsection apply only for an operating area that fails to meet the standards established for the operating area. PP&L believed that circuits should be evaluated on a utility systemwide basis, not on an operating area basis.
GPU Energy also pointed out a recent action by the New York Public Service Commission (NYPSC), which eliminated a worst-performing circuits reporting requirement, since it had ''become something of a post-review exercise in that utilities were merely compiling and documenting corrective actions that had already been taken. This requirement has become a time consuming exercise of little benefit to the companies.'' The revised NYPSC standards only require a description of the company's program for analyzing worst-performing circuits and a summary of the results of the program. (Order Adopting Changes to Standards on Reliability and Quality of Service, Case 96-E-0979, Issued February 26, 1997, NYPSC.)
Consistent with our previous discussion, we have deleted this requirement.
§ 57.196. Generation reliability.
Subsection (a) required an electric generation supplier EGS to conform to the operating policies and standards of NERC and the appropriate regional reliability council. PEA strongly believed that EGSs must also be required to become members of NERC and regional councils, since membership will enhance their active participation in cooperation with and adherence to the full range of council activities and requirements, and subject them to council direction and discipline necessary to preserve electric service reliability. IBEW also agreed with mandatory membership. PEA suggested that brokers and marketers be exempt from the requirement of membership. IRRC agreed with PEA's position and recommended that the Commission impose a membership requirement, but couple it with an exemption provision for financial hardship.
At its January 6-7, 1997, Board of Trustees meeting, NERC voted unanimously to obligate its regional councils and their members to promote, support and comply with all NERC reliability policies and standards. The regional councils are currently in the process of revising their bylaws and agreements to conform with NERC. NERC and the regional councils are also developing appropriate mandatory compliance monitoring and enforcement mechanisms, including penalties for noncompliance. Although compliance is mandatory for members, membership is voluntary.
We agree with PEA and IRRC that EGSs must be required to be members of appropriate regional councils for the new enforcement mechanisms to be effective. We also recognize that the definition of electric generation supplier is quite broad. Some suppliers will not operate generating plants or schedule transmission directly. Moreover, mandatory membership beyond that which is required by such entities, may impose a financial hardship on smaller EGSs, which may become a barrier to participation in the generation market. Therefore, we have added a new subsection (d) to require membership in an appropriate regional reliability council or other reliability entity, as required by such entity.
Subsection (b) provided for the maintenance of appropriate generating reserve capacity by EGSs. The IECPA argued that the Commission must allow the competitive market to establish appropriate levels of generation reserves. The IECPA suggested that the level of generation reserves necessary to ensure supply of electricity to a customer should be dictated by the level of reliability desired by the particular customer. IRRC suggested that the reserve requirement standards apply only to an EGS's firm service obligations.
Although the competitive market should, in time, provide the appropriate price signals necessary to ensure adequate levels of generation reserves, ISO and market information is just beginning at this time. We find it necessary and appropriate during this transition period to require compliance with all regional council policies and standards, including generation reserves. This is also our mandate under sections 2804(1) and 2809(e) of the act (relating to standards for restructuring of electric industry; and requirements for electric generation suppliers). Furthermore, interruptible loads are routinely factored out when determining the reserve obligations of EGSs. Thus, we have not revised subsection (b).
§ 57.197. Reliability investigations and enforcement.
Enron suggested that subsection (b)(2) be revised to provide for penalties less than revocation of the supplier's license. Enron also points out that the regional reliability councils are currently in the process of establishing penalties for EGSs that are noncompliant and, therefore, no additional Commission enforcement is necessary.
Inasmuch as we have the authority to impose civil penalties, under 66 Pa.C.S. § 3301 (relating to civil penalties for violations) and, to provide the ability for the Commission to assess less severe penalties, we will adopt the suggestion of lesser penalties. To the extent that the regional reliability councils have implemented their own penalties for noncompliance, we will defer to them with regard to those matters clearly within their purview. We have also made some minor changes to clarify this section. In addition, we have modified the regulations to make clear that Commission staff may initiate investigations as necessary.
Other Issues
IRRC pointed out that other commentators raise a number of issues which could have a direct bearing on the success of competition in electric generation. IRRC does not, however, believe these issues should be addressed in this rulemaking, but should be the subject of future rulemakings to insure that affected parties will have an adequate opportunity to provide input to the Commission.
Power Quality
IECPA and Ford argued that the Commission must establish specific reliability criteria related to voltage and frequency variations and mandate that the EDCs track and rectify interruptions of less than 30 seconds in duration. According to IECPA, these power quality problems are especially troublesome to sensitive manufacturing equipment such as computers, motors, heating elements, adjustable speed motor drives and programmable logic controllers.
We agree with the concerns of IECPA and Ford. We note that customers of all classes are using more sensitive equipment that can be adversely affected by power quality problems. However, the Commission does not have the record of data at this time to establish specific new standards for voltage or frequency variations or performance benchmarks or standards concerning the interruptions. In the meantime, the standards under §§ 57.14 and 57.15 are being retained, not eliminated, although it may be appropriate to modify them in the future.
Inspection and Maintenance Standards
IBEW reiterated its plea for the Commission to adopt specific inspection and maintenance standards. The IBEW avered that, without the standards, distribution systems would be allowed to deteriorate to the point where actual problems are being experienced. IBEW also pointed out that the NESC lacks requirements for the inspection and maintenance intervals for each type of equipment. IRRC recommended that the Commission reconsider this matter, including an evaluation of what other states have done or are doing regarding inspection and maintenance standards.
In our Proposed Rulemaking Order, we declined to require specific inspection and maintenance standards, because of the new methods and technologies that utilities are developing to improve the inspection and testing process. We hesitate to impose excessive requirements upon the EDCs and to engage in what may be considered micromanagement. Nevertheless, we believe that this matter is worthy of further consideration. Therefore, we shall direct the Commission's Bureau of CEEP to conduct a study of the issue of developing specific inspection and maintenance standards and submit recommendations for the Commission's consideration.
We find that the revisions to our proposed regulations, as delineated above, and as set forth in Annex A, to be necessary and appropriate to ensure the continued safety and reliability of electric service in this Commonwealth. Accordingly, under 66 Pa.C. S. §§ 501, 524, 1102, 1103, 1501, 1504, 1505, 2802, 2804, 2807 and 2809, and the Commonwealth Documents Law (45 P. S. § 1202 et seq.) and the regulations promulgated thereunder at 1 Pa. Code §§ 7.1--7.4, we hereby amend Chapter 57 by adding Subchapter N, as set forth in Annex A hereto, which establishes standards and procedures for assessing the reasonableness of electric service reliability; Therefore,
It Is Ordered that:
1. The regulations of the Commission, 52 Pa. Code Chapter 57, are amended by deleting §§ 57.17, 57.18 and 57.26 to read as set forth at 27 Pa.B. 5262; and by adding §§ 57.191--57.197 to read as set forth in Annex A.
2. The Secretary shall certify this order, 27 Pa.B. 5262 and Annex A and deposit them with the Legislative Reference Bureau for publication in the Pennsylvania Bulletin.
3. The Secretary shall submit this order, 27 Pa.B. 5262 and Annex A to the Office of Attorney General for approval as to legality.
4. The Secretary shall submit this order, 27 Pa.B. 5262 and Annex A to the Governor's Budget Office for review of fiscal impact.
5. The Secretary shall submit this order, 27 Pa.B. 5262 and Annex A for review by the designated standing committees of both Houses of the General Assembly, and for review and approval by the Independent Regulatory Review Commission.
6. A copy of this order, 27 Pa.B. 5262 and Annex A shall be served upon the Office of Consumer Advocate, the Office of Small Business Advocate, all jurisdictional electric utilities and all parties of record.
7. These final-form regulations shall become effective upon publication in the Pennsylvania Bulletin.
8. That the Bureau of Conservation, Economics and Energy Planning conduct a study of the issue of developing specific inspection and maintenance standards and submit recommendations for the Commission's consideration.
By the Commission
JAMES J. MCNULTY,
Secretary
Statement of Commissioner John Hanger
This rulemaking does not address directly the issue of generation adequacy. Some have argued that regulatory authorities should play no role in insuring generation adequacy. Market forces, it has been said, will insure that the supply of generation meets demand.
Other voices have been raised to say that regulatory authorities or private organizations like Independent System Operators must set minimum generation adequacy standards. If one accepts this view, the questions are many. Who should set the standards? How should the standard be set? What should be the standard? These are but a few of the questions raised.
In Pennsylvania, those electric suppliers doing business in the PJM market must comply with an installed capacity requirement designed to create a loss of load probability of one day in ten years. The electric suppliers doing business in the ECAR region of Pennsylvania utilize an operating reserve requirements combined with dependence on supplemental capacity resources (DSCR) of less than 10 days per year as a generation adequacy standard.
In my opinion, this Commission must soon formally examine these differing standards, their relevance, their adequacy, and any possible necessary modifications as Pennsylvania begins electric generation competition.
Fiscal Note: Fiscal Note 57-185 remains valid for the final adoption of the subject regulations.
Annex A
TITLE 52. PUBLIC UTILITIES
Subchapter C. FIXED SERVICE UTILITIES
CHAPTER 57. ELECTRIC SERVICE
Subchapter N. ELECTRIC RELIABILITY STANDARDS
Sec.
| 57.191. | Purpose |
| 57.192. | Definitions. |
| 57.193. | Transmission system reliability. |
| 57.194. | Distribution system reliability. |
| 57.195. | Reporting requirements. |
| 57.196. | Generation reliability. |
| 57.197. | Reliability investigations and enforcement. |
§ 57.191. Purpose.
Reliable electric service is essential to the health, safety and welfare of the citizens of this Commonwealth. The purpose of this subchapter is to establish standards and procedures for continuing and ensuring the safety and reliability of the electric system in this Commonwealth. The standards have been developed to provide a uniform method of assessing the reasonableness of electric service reliability.
§ 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.
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.
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.
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 electric distribution company which affects at least 10% of the customers in an operating area 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. When one operating area experiences a major event, the major event shall be deemed to extend to all other affected operating areas of that electric distribution company.
(B) An unscheduled interruption of electric service resulting from an action taken by an electric distribution company 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) A major event 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--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. 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.
Operating area--A geographical area, as defined by an electric distribution company, of its franchise service territory for its transmission and distribution operations.
Regional reliability council--An organization established to augment the reliability of its members' bulk electric supply systems through coordinated planning and operation of generation and transmission facilities. The following regional reliability councils impact the bulk electric supply systems within this Commonwealth:
(i) The East Central Area Reliability Coordination Agreement (ECAR).
(ii) The Mid-Atlantic Area Council (MAAC).
(iii) The Northeast Power Coordinating Council (NPCC).
Reliability--The degree of performance of the elements of an electric system that results in electricity being delivered to customers within accepted standards and in the desired amount, measured by the frequency, duration and magnitude of adverse effects on the electric supply and by considering two basic and functional aspects of the electric system: adequacy and security.
Reliability indices--Service performance indicators which measure the frequency, duration and magnitude of customer interruptions, excluding outages associated with major events.
(i) CAIDI--Customer Average Interruption Duration Index--The average interruption duration of sustained interruptions for those customers who experience interruptions during the analysis period. CAIDI represents the average time required to restore service to the average customer per sustained interruption. It is determined by dividing the sum of all sustained customer interruption durations, in minutes, by the total number of interrupted customers. This determination is made by using the following equation:CAIDI = riNiNi = SAIDISAIFI
where:
i = an interruption event
ri = restoration time for each interruption event
and Ni = number of customers who have experienced a sustained interruption during the reporting period
(ii) MAIFI--Momentary Average Interruption Frequency Index--The average frequency of momentary interruptions per customer occurring during the analysis period. It is calculated by dividing the total number of momentary customer interruptions by the total number of customers served. This determination is made by using the following equation:MAIFI = MiNT
where:
Mi = number of customers who have experienced a momentary interruption during the reporting period
(iii) SAIDI--System Average Interruption Duration Index--The average duration of sustained customer interruptions per customer occurring during the analysis period. It is the average time customers were without power. It is determined by dividing the sum of all sustained customer interruption durations, in minutes, by the total number of customers served. This determination is made by using the following equation:SAIDI = riNiNT
where:
NT = total number of customers served for the area being indexed
(iv) SAIFI--System Average Interruption Frequency Index--The average frequency of sustained interruptions per customer occurring during the analysis period. It is calculated by dividing the total number of sustained customer interruptions by the total number of customers served. This determination is made by using the following equation:SAIFI = NiNT
Security--The ability of the electric system to withstand sudden disturbance such as electric short circuits or unanticipated loss of system elements.
Sustained customer interruption--The loss of electric service by one or more customers for the period defined as a sustained customer interruption by IEEE as it may change from time to time. This 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.
§ 57.193. Transmission system reliability.
(a) An electric distribution company shall install and maintain its transmission facilities, and ensure that its transmission facilities are operated, in conformity with the applicable requirements of the National Electrical Safety Code. An electric distribution company shall operate its transmission facilities in conformity with the operating policies, criteria, requirements and standards of NERC and the appropriate regional reliability council, or successor organizations, and other applicable requirements.
(b) The reliability of an electric distribution company's transmission service provided to wholesale customers, such as electric cooperative corporations and municipal corporations, shall be comparable to the reliability which the transmission supplier provides at the wholesale level, taking into account the nature of each service area in which electricity is delivered to the customer, the delivery voltage and the configuration and length of the circuit from which electricity is delivered.
(c) An electric distribution company shall submit to the Commission, on or before May 31, 1999, and May 31 of each succeeding year, information concerning the performance of the transmission system, as built and operated, to serve a fully competitive generation market efficiently. The report shall include available transfer capability, total transfer capability and the use, in general, of the transmission system. The report shall include an assessment of the past performance of the transmission system and an appraisal of future transmission system performance. In complying with this requirement, electric distribution companies operating under a single system operator may submit a joint report by an independent system operator, or other appropriate transmission system operator.
§ 57.194. Distribution system reliability.
(a) An electric distribution company 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, employes and the public. The service shall be reasonably continuous and without unreasonable interruptions or delay.
(b) An electric distribution company shall install, maintain and operate its distribution system in conformity with the applicable requirements of the National Electrical Safety Code.
(c) An electric distribution company shall make periodic inspections of its equipment and facilities in accordance with good practice and in a manner satisfactory to the Commission.
(d) An electric distribution company 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 electric distribution company 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 electric distribution company shall design and maintain procedures to achieve the reliability performance standards established under subsection (h).
(f) An electric distribution company shall develop and maintain a program for analyzing the service performance of its circuits during the course of each year.
(g) An electric distribution company 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 electric distribution company shall retain all records to support the reporting requirements under § 57.195 (relating to reporting requirements) for 5 years.
(h) An electric distribution company shall take measures necessary to meet the reliability performance standards adopted under this subsection.
(1) In cooperation with an electric distribution company and other affected parties, the Commission will, from time to time, establish numerical values for each reliability index or other measures of reliability performance that identify the benchmark performance of an electric distribution company, and performance standards.
(2) The benchmark will be based on an electric distribution company's historic performance for each operating area for that measure. In establishing the benchmark, the Commission may consider historic superior or inferior performance or system-wide performance.
(3) The performance standard shall be the minimal level of performance for each measure for all electric distribution companies, regardless of the benchmark established.
(4) An electric distribution company shall inspect, maintain and operate its distribution system, analyze performance and take corrective measures necessary to achieve the performance standard. An electric distribution company with a benchmark establishing performance superior to the performance standard shall maintain benchmark performance, except as otherwise directed by the Commission.
§ 57.195. Reporting requirements.
(a) An electric distribution company shall submit to the Commission, on or before May 31, 1999, and May 31 of each succeeding year, a reliability report which includes, at a minimum, the information prescribed in this section.
(1) An original and 5 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 and telephone number of the persons having knowledge of the matters, and to whom inquiries should be addressed, shall be included.
(b) The report shall include an assessment of electric service reliability in the electric distribution company's service territory, by operating area and system-wide.
(1) The assessment shall include a discussion of the electric distribution company's programs and procedures for providing reliable electric service.
(2) The assessment shall include a description of each major event, 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.
(c) The report shall include a table showing the actual values of each of the reliability indices, and other performance measures required by this subchapter or Commission order, for each operating area and for the electric distribution company as a whole for each of the preceding 5 calendar years.
(d) When an electric distribution company's reliability performance within an operating area is found to be unacceptable, as defined in § 57.194(h) (relating to distribution system reliability), the report shall include the following:
(1) An analysis of the service interruption patterns and trends.
(2) An analysis of the operational and maintenance history of the affected operating area.
(3) A description of the causes of the unacceptable performance.
(4) A description of the corrective measures the electric distribution company is taking and target dates for completion.
§ 57.196. Generation reliability.
(a) An electric generation supplier shall operate and maintain its generating facilities in conformity with the operating policies, criteria, requirements and standards of NERC and the appropriate regional reliability councils, or successor organizations.
(b) An electric generation supplier shall maintain appropriate generating reserve capacity in compliance with any applicable reserve requirement standards set forth by the appropriate regional reliability council, successor organizations or other entity or agency with jurisdiction to establish the requirements.
(c) An electric generation supplier shall abide by applicable Commission regulations, procedures and orders, including emergency orders.
(d) An electric generation supplier shall maintain membership, to the extent required by any regional reliability council, independent system operator or similar organization, in the appropriate regional reliability councils, or successor organizations.
§ 57.197. Reliability investigations and enforcement.
(a) The Commission staff may initiate an investigation, or may do so upon complaint by an affected party, to determine whether an electric distribution company is providing service in accordance with §§ 57.193 and 57.194 (relating to transmission system reliability; and distribution system reliability).
(1) Based upon the record developed in such an investigation, the Commission may enter an order directing the electric distribution company to take reasonable corrective action necessary to improve the reliability of electric service.
(2) If the Commission directs an electric distribution company to make expenditures to repair or upgrade its transmission or distribution system, the electric distribution company may seek an exception to the limitations in 66 Pa.C.S. § 2804(4) (relating to electric utility rate caps).
(b) The Commission staff may initiate an investigation, or may do so upon complaint by an affected party, to determine whether an electric generation supplier is providing reasonable service in accordance with § 57.196 (relating to generation reliability).
(1) Based upon the record developed in such an investigation, the Commission may enter an order directing the electric generation supplier to take the corrective action the Commission deems necessary to improve the reliability of service.
(2) If the corrective action is not taken within the period of time designated by the Commission in an order entered under paragraph (1), the Commission may elect to impose a penalty up to and including the revocation, either temporarily or permanently, of the license of the electric generation supplier, obtained under 66 Pa.C.S. § 2809(a) (relating to requirements for electric generation suppliers).
[Pa.B. Doc. No. 98-1148. Filed for public inspection July 17, 1998, 9:00 a.m.]
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