[38 Pa.B. 5273]
[Saturday, September 27, 2008]
[Continued from previous Web Page] Subsection (a)(1)--Industry codes, rural and urban areas; I & M intervals
Subsection (a)(1) begins with the statement that the I & M ''plan must be based on industry codes, national electric industry practices, manufacturers' recommendations, sound engineering judgment and past experience.'' IRRC questioned to which industry codes and national electric industry practices did the Commission refer. If the Commission meant the National Electricity Safety Code or code and practices of organizations such as the Institute of Electrical and Electronic Engineers and NERC, then the appropriate codes or organizations should be referenced in the final-form regulation. We agree with this suggestion, and the changes shall be incorporated in § 57.198(b).
IRRC states that the phrase ''sound engineering judgment'' is vague since engineers may respectfully disagree on what is sound. It is IRRC's understanding that the the Commission will determine whether a plan is based on reasonable or sound engineering judgment. Hence, it will be a part of the Commission review of plans under § 57.198(h) and if the the Commission identifies problems in the plan, it will notify the EDC of the plan's deficiencies under § 57.198(j). Therefore, it is not necessary to include the words ''sound engineering judgment'' in the regulation, and IRRC recommends this phrase be deleted. We will adopt IRRC's recommendation.
The final sentence in subsection (a)(1) states: ''The plan must take into account the broad minimum inspection and maintenance intervals provided for in subsection (e).'' IRRC questions why the word ''broad'' is used in this sentence. Since the provisions in new subsection (n) set very specific minimum intervals, the use of the word ''broad'' is confusing. The word ''broad'' will be deleted.
Subsection (a)(1) states that the plan shall be based on industry codes, national electric industry practices, manufacturers' recommendations, sound engineering judgment and past experience. The plan shall be divided into rural and urban areas. The plan shall take into account the broad minimum inspection and maintenance intervals provided for in subsection (e).
AFL-CIO commented that Section 57.198(a)(1) should be revised to state:
The plan must be based on industry codes, National electric industry practices, manufacturers' recommendations, sound engineering judgment and past experience. The plan must be divided into rural and urban areas. The plan must comply with the minimum inspection and maintenance intervals set forth in subsection (e).The AFL-CIO believes these changes are necessary to ensure that all EDCs in Pennsylvania meet at least minimum I& M standards. EDCs should not be permitted to submit plans that do not meet these minimum requirements. The AFL-CIO advocates all EDCs must meet the minimum standards. After considering the EDCs comments regarding the increased costs, differing I & M plans and claims that reliability will not necessarily increase if mandatory minimum I & M standards are applied to large and small EDCs alike, as explained previously, the Commission will adopt minimum I & M standards, but will also include flexibility to allow EDCs to deviate from the I & M standard provided the deviation can be justified by the EDC's unique circumstances or a cost/benefit analysis to support an alternative approach that will still support the level of reliability required by law. Accordingly, we will change the language in (a)(2), now (c) to state as follows:
The plan shall comply with inspection and maintenance standards set forth in subsection (n). However, an EDC may propose a plan that, for a given standard, uses intervals outside the Commission standard, provided that the deviation can be justified by the EDC's unique circumstances or a cost/benefit analysis to support an alternative approach that will still support the level of reliability required by law.The OCA commented that § 57.198, Inspection and Maintenance Standards, should be amended to state that the plan should specify all applicable hardware standards, all applicable operation standards, routine maintenance requirements, emergency maintenance plans and procedures for coordinating with other interconnected systems. We agree in part, and will add the routine inspection and maintenance requirements and emergency maintenance plans and procedures portion of OCA's suggested specifications in the regulation at subsection (d).
The EAP commented that the EDCs need flexibility in determining when vegetation management work must be conducted. Mandating a uniform 4-year tree-trimming cycle for distribution lines accomplishes very little toward improving service reliability. The EAP commented that line clearance is a condition-based activity. Each EDC schedules tree-trimming on its circuits based upon its own individually established criteria. Typically the proximity of tree branches to the wires, the number of customers fed by the circuit, the number of tree-caused outage events recently experienced on the circuit, and the elapsed time since last trimmed are considered.
According to the EAP, trimming too soon results in wasting part of the value of the work done during the last trimming; trimming too late results in poor circuit performance. Cycle length and clearances, have less influence on service reliability, especially in regards to on-right-of-way vegetation caused service outages compared to off-right-of-way trees falling into the lines. California's no contact requirement is not for reliability reasons according to the EAP, but rather to avoid sparking from tree contact that could cause wildfires during their dry season. EAP states that Pennsylvania does not need this requirement. Pennsylvania has drought conditions during the summer months at times also. We are persuaded to change the tree-trimming cycle standard and allow for up to 8 years for a vegetation management standard instead. This will account for the varying the EDC practices and service territory terrains. However, intervals longer than 8 years will require justification and be supported by a cost/benefit analysis.
Finally, to clarify the industry codes and practices that should be followed in developing each EDC's plan, we have decided to change subsection (a)(1) to subsection (b) and it shall state that the plan shall be consistent with the National Electrical Safety Code, Codes and Practices of the Institute of Electrical and Electronic Engineers, FERC Regulations, and the provision of the American National Standards Institute, Inc.
Subsection (a)(2)--Adequate resources.
Subsection (a)(2) states that an EDC shall reduce the risk of future service interruptions by accounting for the age, condition, design and performance of system components and by providing adequate resources to maintain, repair, replace and upgrade the system.
IRRC asks how the Commission will determine if an EDC has provided adequate resources to maintain, repair, replace and upgrade its system. We will delete ''adequate resources'' from the final regulation.
The new subsection (c) shall state that the plan shall comply with inspection and maintenance standards set forth in subsection (n).
Subsection (a)(3)--Vegetation clearance program
This subsection requires that the EDC's I & M plan ''include a program for the maintenance of minimum clearances of vegetation from the EDC's overhead transmission and distribution facilities sufficient to avoid contact under design-based conditions.'' EDCs questioned the need for this provision and called it unreasonable. Incidental contact with vegetation or tree branches does not necessarily cause outages. Given the growth of some trees, this requirement could actually force some EDCs to perform trimming annually and would greatly increase costs with no quantifiable benefit. IRRC commented that the Commission needs to explain the basis and intent for this requirement.
The Commission was concerned that vegetation contact could cause the circuit to overheat and shut off. The blackout report mentioned tree contact with transmission lines played a role in the circuits shutting down and the ultimate blackout of August 14, 2003. However, requiring the EDCs to trim trees more frequently than necessary, may end up costing the EDC and consumer more money without a substantial improvement in reliability. If there is a wider differential between electric rates in Pennsylvania than other states, that may have a negative impact on attracting or keeping businesses to operate in our state. We will remove the language ''sufficient to avoid contact under design-based conditions.''
PECO commented that the Commission should amend proposed Section 57.198(a) to remove subsection 3's requirement for a plan for trimming off right-of-way trees. FirstEnergy commented the phrase ''may cause'' is too vague and open ended when coupled with the requirement to trim off of a right-of-way. PECO has limited authority to trim or remove trees that are outside of the right-of-way.
PECO recommends adopting Connecticut's approach. PECO recommends § 57.198(a)(3) be amended to state:
The plan shall include a program for the maintenance of minimum clearances of vegetation from the EDC's overhead transmission and distribution facilities sufficient to avoid contact under design-based conditions. The plan shall include a program for the trimming of tree branches and limbs located in close proximity to overhead electric wires when the branches and limbs may cause damage to the electric wires.The Commission will eliminate the last phrase ''regardless of whether the trees in question are on or off of a right of way.'' We will keep the ''may cause'' language as it is similar to Connecticut's approach.
Subsection (a)(4)
IRRC commented that § 57.198(a)(4) refers to quarterly and annual reliability reports from an EDC. If these are the reports required by the existing provisions in §§ 57.193(c) and 57.195, then the proposed regulation should include cross-references to these existing provisions. We agree with IRRC and will amend this section into subsection (h) such that references are made to the other sections.
Subsection (b)--Plan review process
This subsection requires EDCs to submit their initial I & M plans by October 1, 2008. The EDCs and IRRC believe that there are not sufficient numbers of trained and experienced people available to meet the I & M schedules set forth in subsection (e). They claim it will take years to recruit and train an adequate workforce to implement the proposed regulation. If the prescriptive requirements in proposed subsection (e) are retained in the final-form regulation, the Commission should carefully examine whether the October deadline is achievable.
In consideration of these comments, the deadline will be changed to October 1, 2009, for group 1 and October 1, 2010, for group 2, and every other year thereafter to allow EDCs time to recruit and train necessary workers. IRRC seeks clarification on the submission of the whole 1-year plan every 2 years. We will amend subsection (b) and make the plan cover the 2-calendar years that follow 15 months from the filing date. Thus, a 2-year period of plans will be covered in each Commission review. This language will be in § 57.198(a).
Subsections (b) and (c)--Designee
These subsections set forth the process for the EDCs to submit plans and revised plans for the Commission review and approval. Both subsections would allow the Commission or its designee to accept or reject the plan or revised plan. Representatives for the EDCs and IRRC suggested that the words ''or its designee'' be deleted from the proposed regulation. PECO specifically commented that the Commission should also remove the language in proposed § 57.198(b) and (c) permitting the Commission's ''designee'' to accept or reject EDC I & M plans.
There is concern that the proposed regulation does not describe or define the designee. Another concern is that the EDCs are not given the ability to appeal or challenge decisions made by the designee. The regulation should be amended to define the designee and specify how the EDCs may appeal the designee's decision, or the term should be deleted from the final-form regulation. We have removed the phrase ''the designee'' and have replaced it with ''the Director of CEEP'' such as to be specific as to which Bureau is being given the authority vested in the Commission to make such a staff determination. Language regarding how the EDCs may appeal any determination by CEEP is in subsection (k).
IRRC commented that the Commission should set forth the update process, procedures and criteria the Commission will use in determining the need for information and plan updates, and for notifying the affected the EDC. Since we are eliminating the update process, this is no longer necessary.
Subsection (c)--Revised plans from EDCs
IRRC's comments state that proposed subsection (c) allows an EDC to revise its plan and submit it to the Commission for review. Like subsection (b), this subsection states that the Commission will have 90 days to review and accept or reject the revisions to the plan. Unlike subsection (b), however, subsection (c) contains no provision stating that the Commission will notify the EDC as to why it rejected the plan nor a provision stating that the revised plan is ''deemed accepted'' absent any action by the Commission within 90 days. IRRC's comments state that these provisions should also appear in subsection (c) in the final-form regulation.
A new subsection (j) has been added to address these concerns. CEEP will be obligated to notify the EDC, in writing, of any deficiencies in the plan; the EDC will have the opportunity to file either a revised plan or an explanation as to why the plan is not deficient. Absent action by the Commission within 90 days, the revised plan is deemed to be accepted by the Commission.
Subsection 57.198(b) and (c)
PECO commented regarding subsection (b) that the Commission should remove the language permitting the Commission's designee to accept or reject the EDC's plan because it does not clearly describe the official or entity designee that will have the authority to approve or reject the plan. The regulation is too vague and could include an Administrative Law Judge or staff person. PECO is concerned it won't be able to challenge the decision and bring the issue before the entire Commission.
IRRC commented that § 57.198(b) and (c) set forth detailed procedures and time periods for Commission review and approval of plans and revised plans. If the the Commission intends to retain the ability to request that the EDCs update previously-approved plans, then a new and separate subsection clarifying this process should be added to the final-form regulation. It should set forth the process, procedures and criteria that the Commission will use in determining the need for information and plan updates, and for notifying the affected the EDC. It should also include provisions similar to those in subsections (b) and (c) for Commission review and approval of plan updates.
Upon consideration of these comments, we will change the language to specify the Director of CEEP will have the authority to accept or reject the EDCs' plans. The Director's decision would constitute a staff determination that could be appealed to the Commission under 52 Pa. Code § 5.44. Staff action, under authority delegated by the Commission, will be deemed to be the final action by the Commission unless appealed to the Commission within 20 days after service of action. Petitions for appeal from the Director's action will be addressed by the Commission at Public Meeting. 52 Pa. Code § 5.44(j). If the Commission itself makes the determination, then the EDC may file a petition for reconsideration under 52 Pa. Code § 5.572 or, alternatively, file an appeal directly to Commonwealth Court. This will be addressed in subsection (k) of Annex A.
The Commission is also adding language to subsection (l) which states that an EDC may request approval from the Commission for revising an approved plan. An EDC shall submit to the Commission, as an addendum to its quarterly reliability report, prospective and past revisions to its plan and a discussion of the reasons for the revisions. Within 90 days, the Commission or the Director of CEEP will accept or reject the revisions to the plan.
Subsection (d) Recordkeeping
This subsection requires an EDC ''maintain records of its inspection and maintenance activities sufficient to demonstrate compliance with'' the timeframes for I & M programs set forth in subsection (e). IRRC commented that the Commission needs to provide examples of the types of records that would be ''sufficient.'' Would this include date-stamped records signed by EDC staff that performed the tasks?
To address this concern, additional language has been added to provide examples. Receipts from independent contractors showing when and what type of inspection, maintenance, replacement and/or repair work was done is also sufficient.
Subsection (e) minimum time frames for I & M activities
This subsection sets specific Statewide minimum schedules for several different types of I & M activities including vegetation management, and inspection of poles, overhead lines and substations. IRRC comments that the EDCs contend there is no basis for setting specific minimum requirements and that they are not cost-effective.
IRRC also mentions that I & M inspection schedules or time frames for different EDCs may depend on the regions where their systems are located, the different types of plants and geography in those regions, fluctuating weather patterns, variations in equipment or infrastructure, and other factors. IRRC commented that the Commission needs to respond to the EDCs' concerns about mandated annual foot patrol inspections of distribution lines, and the need for foot patrols when the lines run parallel to roadways and could be inspected from vehicles. The Commission agrees that foot patrols are not necessary especially since vehicle patrol carrying testing equipment is available for proper testing. We will replace the word ''foot'' with the word ''ground.'' This is addressed in Annex A.
The EAP commented that by the nature of their function, electric transmission and distribution systems have thousands of parts of varying degrees of complexity and importance dispersed over a large geographic area. Maintaining systems in a cost effective manner requires maintenance programs that take into account the characteristics of component parts, the environment in which they operate, and the electrical and mechanical stresses they experience. The EDCs need flexibility to invest in technological improvements. Mandated labor-intensive programs with high costs impairs the EDC's flexibility to invest in improvements that would produce greater benefits to the consumer. For example, advancements in sensor technology has brought about smaller, more powerful sensors available at increasingly lower prices.
The rapid pace of advancement in communications has also made it possible to monitor sensors remotely and accumulate technical information at central points such as main office buildings, service centers, substations, and on poles and towers. Also, technology has improved with computer applications that should improve reliability because new systems allow the EDCs to identify more specific areas to address and then sort out the best course of action.
Allegheny Power commented that approximately 97% of its customer interruptions were caused by distribution faults of which 70% directly resulted from external events unaided by frequent inspections, such as off-rights-of-way fallen trees, vehicles hitting poles, and the like. The remaining 30% of outages include indirect effects of severe weather and other causes targeted by AP's current maintenance programs. Recloser failures made approximately 1% of total customer interruptions, overhead transformer failures were linked to approximately 1 to 1.5% of customer interruptions, poles were related to .8% of customer interruptions and underground transformers caused .25% of customer interruptions.
Allegheny Power claims the Proposed Rulemaking would increase Allegheny Power's costs by $8.4 million and $2 million in start up costs. The AFL-CIO and OCA proposals add an additional $4.5 million and $5.5 million, respectively. Allegheny Power recommends allowing NERC standards and PJM to ensure continued high reliability of transmission grids without increasing costs. Regarding substations, AP recommends eliminating the time-based I & M requirements to allow advanced analysis and technologies to be implemented. AP further recommends allowing EDCs to submit individualized cost and operationally effective I & M plans to target resources to areas in need of reliability improvements, and allow for changes to the plans as technologies are implemented.
In response to these concerns and to IRRC's concerns regarding rigid minimum standards for I & M activities, the Commission has adopted a flexible approach that will permit an individual EDC to deviate from the I & M standards set forth in these regulations provided the deviations can be justified by the EDC's unique circumstances or a cost/benefit analysis. This will allow implementation of these regulations to take into consideration the various differences among EDCs regarding geography, age of facilities, technologies employed and other factors that bear on the reasonable and prudent intervals that should be used for the proper inspection and maintenance of their facilities.
Lastly, for critical maintenance issues, items that threaten short-term reliability of facilities, AP is comfortable with a 30-day standard. For noncritical issues, the most effective method is to schedule repair/replacement in the following budget cycle. We agree with AP and include 30-day repair requirements to § 57.198(n)(3) and (5).
(e) An EDC shall maintain the following minimum inspection and maintenance plan intervals.
As stated earlier, rather than rigid minimum I & M standards, the Commission will establish standard intervals, based on current industry practices. If however, a given EDC believes that a deviation is appropriate, it may seek to justify an alternative approach. The following are charts compiled by the Commission from data offered to the Commission by the EDCs which compare the EDC's I & M standards from 1990, 1995, 2000, to current and the claimed incremental cost of meeting the proposed standards.
The charts are followed by comments and a discussion regarding the specific (sometimes bolded) proposed language above the charts.
Proposed: 52 Pa. Code § 57.198(e)(1): Vegetation management. The Statewide minimum inspection and treatment cycles for vegetation management are 4 years for distribution facilities and 5 years for transmission facilities.
Company 1990 1995 2000 Current Incremental Cost Allegheny No set cycle for distribution or transmission. Distribution trim cycles in urban areas from 2 to 4 years and from 4 to 8 years in rural areas. No set cycle for transmission. Distribution trim cycles in urban areas from 2 to 4 years and from 4 to 8 years in rural areas. No set cycle for transmission. Four-year cycle for distribution circuits. No set cycle for transmission. $4,100,000 Duquesne No established cycles. No established cycles. Distribution cycle > 6 years; transmission cycle > 7 years. Actual average distribution cycle = 5.63 years; actual average transmission cycle = 7.04 years. $2,750,000 Met-Ed Not readily available. Not readily available. Distribution cycle of 4 years; transmission cycle of 6 years. (2001) Distribution cycle of 4 years; transmission cycle of 5 years. NA Penelec Not readily available. Not readily available. Distribution cycle of 4 years; transmission cycle of 6 years. (2001) Distribution cycle of 4 years; transmission cycle of 5 years. NA Penn Power Not readily available. Not readily available. Distribution cycle of 4 years; transmission cycle of 6 years. (2001) Distribution cycle of 4 years; transmission cycle of 5 years. NA PECO Distribution practices not consistently applied; 5-year transmission cycle in 1992. Distribution cycle of 4 years; transmission cycle of 5 years. Distribution cycle of 5 years; transmission cycle of 5 years. Distribution cycle of 5 years; transmission cycle of 5 years. $5,000,000 PPL No company-wide standard for distribution and transmission. Changes in policy for transmission unknown; no company-wide standard for distribution. NA Distribution cycles 8 years rural and 5 years urban; transmission inspected every 3 to 5 years. $14,300,000 UGI Circuits are prioritized after inspection. Circuits are prioritized after inspection. Circuits are prioritized after inspection. Circuits are prioritized after inspection. $2,000,000 increase in operating expenses for all categories. Citizens' As deemed necessary. As deemed necessary. As deemed necessary. As deemed necessary. $20,000 Wellsboro NA 12 years. 8 years. 8 years. $195,000 Pike County Distribution--3 years. Distribution--3 years. Distribution--3 years. Distribution--3 years. NA
Regarding distribution facilities, PECO has I & M programs with varying length and it wants to retain this flexibility. Shifting to a 4-year cycle for distribution lines, will cost an additional $4.5 to $5 million per year with no real increase in reliability associated with that increased cost. PECO cites to Dr. Googenmoos who reviewed the National Grid System in the Northeast U.S. Dr. Googenmoos stated that a proposal to standardize the grid's vegetation management to standard right-of-way widths constitutes an inefficient use of resources, costing 30%--70% more than using site-specific prescriptions.
PECO commented that it currently employs a 5-year vegetation inspection and treatment plan for its transmission facilities based on its judgment, experience and the vegetation conditions it has observed. However, PECO submits that with regard to transmission facilities, a reasonable and appropriate approach would be for the Commission to monitor the ongoing development of transmission standards by FERC and NERC and to decline to adopt mandatory standards at this time. Recently, FERC issued a Notice of Proposed Rulemaking proposing to approve 83 of 107 reliability standards developed by NERC. Some of the regulations specifically address transmission line inspections.
PECO further commented that the Commission should allow utilities the ability to implement condition-based vegetation management programs that are not constrained by the cost inefficiencies of standardized cycles. PECO suggests the following language,
Vegetation management. As part of the plan required by § 57.198(b), an EDC shall submit a condition-based plan for vegetation management for its distribution system facilities.FirstEnergy practices a 4-year tree trimming cycle on its distribution lines and a 5 year cycle on its transmission lines. FirstEnergy believes its cycle standard is reasonable. FirstEnergy requests Commission regulations that supersede local city, borough and other municipal ordinances that may attempt to limit tree trimming, removal of vegetation, the use of herbicides or that require stump removal, all of which are impediments to completing required and essential vegetation management in a cost effective and timely manner. Additionally, intrastate agency cooperation between the PUC, Game Commission, Department of Environmental Protection and Department of Conservation and Natural Resources would be helpful to the EDCs. Generally, FirstEnergy supports the EAP's comments which advocate eliminating a minimum vegetation standard altogether and keeping a requirement that vegetation management be addressed in the plans.
Duquesne Light commented there should not be rigid minimum intervals between vegetation maintenance periods. Pennsylvania has four distinct plant hardiness zones defined by the United States Department of Agriculture. Because of these distinct zones, different areas of the state have different native trees which grow at different rates. Thus, varying maintenance requirements should be employed. Also, some utilities have different right-of-way maintenance widths and this influences the necessary maintenance intervals. Territories with wider right-of-way widths do not need to maintain the vegetation on the edges through pruning as frequently as those with narrower widths. Urban rights-of-way, usually within municipal rights of way, are generally narrower than those in rural areas where private property owners have granted rights. For these reasons, Pennsylvania should adopt an average cycle instead of a minimum cycle.
The Commission is attempting to balance the need for stricter vegetation management cycles for the EDCs that have had difficulty in the past meeting their reliability standards even with the stricter internal vegetation management standards, as opposed to other EDCs that have longer internal vegetation management standards, yet are more compliant in staying within their reliability standards. For example, the FirstEnergy companies have in the past violated their reliability standards, yet those companies now have 4 and 5 year tree-trimming cycles. FirstEnergy has recently been improving in its ability to stay within its reliability standards. PPL is traditionally a good performer, usually falling within its reliability standards each quarter, yet it has the longer tree-trimming interval of 8 years for distribution lines in rural areas. PPL was able to maintain its reliability benchmark between 2001 and 2005 using a 5 year urban and an 8 year rural trim cycle. Although PPL admits shorter cycles will improve reliability, ultimately, it reaches some point of diminishing return. (January 22, 2007 Technical Conference Transcript. pp. 63 and 64).
Further, other states are not as strict with a minimum 4 and 5 year tree trimming interval standard. Texas has no requirements for tree-trimming, vegetation management or right-of-way clearance, but rather is guided by the provisions of the American National Standards Institute, Inc., the National Electrical Safety Code and other national standards. Ohio has in a limited fashion asked the utilities to set their vegetation goals, and New York reviews plans for transmission-specific and EDC-specific clearance requirements and reviews the plan. Massachusetts requires tree-trimming by utilities, and then has them report the results. For these reasons, and because the incremental cost increases seem to be high if we were to stay with the 4 and 5 year vegetation management standards, we will amend the rulemaking to substitute a standard of no longer than an 8-year cycle for distribution lines and will eliminate the transmission line requirement altogether at this point.
AFL-CIO commented § 57.198(e)(1) should be revised to read:
(1) Vegetation management. The statewide minimum inspection and treatment cycles for vegetation management are 4 years for distribution facilities and 5 years for transmission facilities. In addition if a circuit experiences five or more trips during a 12-month period, it shall be scheduled for an immediate vegetation inspection. Finally, utilities are encouraged to increase the frequency of their vegetation inspection cycles if an area experiences a wetter than normal growing season.The added language reflects the fact that vegetation management programs must be dynamically managed. An EDC should not be able to simply establish a cycle and claim that it has acted reasonably. Vegetation plans must be adapted to growing conditions and an EDC must actively respond if a circuit experiences vegetation-related problems. While we generally agree that EDCs should be encouraged to increase their frequencies of vegetation inspection cycles during wetter than normal growing seasons, an ''encouragement'' statement doesn't belong in a regulation. Regulations should be unambiguous rules which are objective and easy to enforce, not vague and ambiguous.
Citizens' claims it performs a trimming needs assessment on its entire system each year, and targets a 4-year trimming cycle; however, some locations are trimmed more frequently and some less frequently depending on the tree species, weather, line construction type and other factors. Wellsboro is not on a 4-year cycle and projects that a mandatory 4-year cycle will result in a 50% increase in its present right of way program budget. Neither Citizens' nor Wellsboro project an appreciable enhancement of service reliability as a result of 4-year tree trimming cycle standards.
The OCA commented that the 4 and 5 year standards are the current cycle standards for the FirstEnergy companies. A cost/benefit analysis must look at the long-term and must take into account unquantifiable benefits of safe and reliable service. To the extent that the range of 4-5 years is unduly burdensome for the EDC, the EDC can seek a waiver from the Commission through the appropriate procedures.
Disposition
Upon consideration of these comments, we will adopt language similar to the language proposed by PECO regarding a ''condition-based plan'' for vegetation management. However, based on our review of industry practices statewide and reliability results, we will also establish an interval standard of between 4-8 years for vegetation management on distribution lines. If an EDC believes that an alternative interval is appropriate, it may seek to justify that deviation by its unique circumstances or a cost/benefit analysis when it submits its plan.
In addition, the Commission will monitor what the Federal Energy Regulatory Commission is doing regarding the promulgation of federal regulations regarding vegetation management around transmission lines. We will coordinate with the Department of Environmental Protection, Department of Conservation and Natural Resources and Game Commission regarding these issues.
Proposed: 52 Pa. Code § 57.198(e)(2): Pole inspections. Distribution poles shall be visually inspected every 10 years.
Company 1990 1995 2000 Current Incremental Cost Allegheny 10 years. 10 years. 12 years. 12 years. $700,000 Duquesne No formal pole testing program. Pole testing equipment acquired. Pole testing program established; implemented on 12-15 year cycle. Poles tested every 12-15 years; Infrared inspection every 5 years. NA Met-Ed Not available. Not available. 13 years. 13 years. NA Penelec Not available. Not available. 13 years. 13 years. NA Penn Power 10 years. 10 years. As required. As required. NA PECO Variable divisional programs with 9-year target. Variable divisional programs with 9-year target. 10 years. Poles inspected every 10 years after 12th year. NA PPL Initial inspection at 25 years; subsequent inspections from 1 to 9 years. Initial inspection at 25 years; subsequent inspections from 1 to 9 years. NA Initial inspection at 25 years; subsequent inspections from 1 to 9 years. One-time cost of $3,000,000 UGI 10 years. 10 years. 10 years. 10 years. See 'UGI' above. Citizens' No inspections performed. No inspections performed prior to 1998. 10 years. 10 years. NA Wellsboro NA 12 years. 10 years. 10 years. NA Pike County None. None. None. None. $25,000 The AFL-CIO proposes § 57.198(e)(2) should be revised to read:
(2) Pole inspections. Distribution poles shall be inspected every 10 years. Pole inspections shall include drill tests at and below ground level, a shell test, visual inspection for holes or evidence of insect infestation, a visual inspection for evidence of unauthorized backfilling or excavation near the pole, visual inspection for signs of lightning strikes, and a load calculation. If a pole exhibits 67% or less of the strength of a new pole of comparable size, then it shall be replaced within 60 days. If a pole fails the groundline (or butt) inspection, shows dangerous levels of rot or infestation, or otherwise exhibits dangerous conditions or conditions that affect the integrity of the circuit, it shall be replaced as soon as possible, but no later than 30 days.AFL-CIO argues a visual inspection is insufficient to determine the integrity of the pole especially if 10 years lapse between inspections. Second, the regulation should set specific standards and deadlines for replacing poles that are seriously deficient or dangerous. The OCA also commented that more specifications should be added to this section and that the detailed inspection every 10 years should include drill tests at and below ground level, a shell test, a load calculation, visual inspection for holes, evidence of insect infestation, evidence of unauthorized backfilling or excavation, lightening strikes and other problems. Poles with major deficiencies should be replaced within 60 days according to the OCA.
Duquesne Light commented that it can agree to visually inspect poles every 10 years. PECO also commented that it does not oppose this inspection standard. The EAP argues increased pole inspections do not increase reliability because there is no causal relationship between increased frequency of pole inspections and reliability and customer service outages due to pole failures are extremely rare. The EAP states that the proposed 10-year cycle for pole inspection will increase the cost of electricity yet will have no impact on electric service reliability. The EDCs and their customers would experience $4.4 million of increased costs annually if the proposed 10-year inspection requirement is adopted. I & M cycle times are EDC and region specific and also vary by the type of pole and initial preservation treatment. Therefore, the EAP argues, the EDCs should be permitted to develop their own cycles for inspection of utility poles.
West Virginia has rules governing pole inspection. However, inspections are to be done with reasonable frequency. Kentucky requires a utility to construct and maintain its plants and facilities in accordance with good accepted engineering practices. The Kentucky Commission also adopted national standards including NESC ANSI-C-2, National Electric Code ANSI-NFPA-70, American National Standard Code for Electricity Metering ANSI-C-12-1, USA Standard Requirements for Instrument Transformers ANSI-Standard C.57.13 National Electrical Code. The EAP suggests following the lead of West Virginia and Kentucky if we want to mandate pole inspections.
PPL's' General Manager--Transmission/Distribution, David E. Schleicher, P. E., testified that new Southern Yellow Pine (SYP) creosoted utility poles do not need as frequent tests as other poles like Penta and CCA initially. He stated the SYP creosoted pole needed an initial test at 25 years, and other poles needed testing initially every 10 years, then subsequently 1-9 years afterwards based upon the results of the prior year's testing. (January 22, 2007 Technical Conference Transcript, p. 60.) The Commission agrees that the inspection should be more than a visual one, and the Commission will incorporate some OCA's and the AFL-CIO's proposed language, but given PPL's testimony and EAP's comments, we will lengthen the general standard for wooden poles to be a range from 10-12 years.
Disposition
Upon consideration of these comments, we will amend the 10 years interval standard to allow for the creosoted pole to be inspected initially at 25 years to account for the new poles that are being installed by PPL and which do not need inspection for the first 25 years. We will add in language such that distribution poles shall be inspected at least as often as every 10-12 years except for the new SYP creosoted utility poles which shall be initially inspected within 25 years, then within 12 years annually thereafter.
The Commission will also include language that pole inspections shall include drill tests at and below ground level, a shell test, visual inspection for holes or evidence of insect infestation, a visual inspection for evidence of unauthorized backfilling or excavation near the pole, visual inspection for signs of lightening strikes and a load calculation. If the pole fails the groundline inspection, shows dangerous conditions or conditions affecting the integrity of the circuit, it shall be replaced within thirty days of the date of inspection.
Proposed: 52 Pa. Code § 57.198(e)(3): Overhead line inspections. Transmission lines shall be inspected aerially twice per year in the spring and fall. Transmission lines shall be inspected on foot every 2 years. Distribution lines shall be inspected by foot patrol a minimum of once per year. If problems are found that affect the integrity of the circuits, they shall be repaired or replaced no later than 30 days from discovery. Overhead distribution transformers shall be visually inspected annually as part of the distribution line inspection. Aboveground pad-mounted transformers and below-ground transformers shall be inspected on a 2-year cycle. Reclosers shall be inspected and tested at least once per year.
Company 1990 1995 2000 Current Incremental Cost Allegheny Aerial patrols twice-year on 345 kV to 500 kV; annually for all other voltage levels. All patrols performed aerially. Aerial patrols twice-year on 345 kV to 500 kV; annually for all other voltage levels. All patrols performed aerially. Aerial patrols for all transmission voltages minimum of once per year; comprehensive patrol for 345-500 kV every 5 years and for 100--230 kV every 10 years. Aerial patrols for all transmission voltages minimum of once per year; comprehensive patrol for 345-500 kV every 5 years and for 100--230 kV every 10 years. $1,450,000 Duquesne No VM aerial or foot patrols. No VM aerial patrols; no thorough transmission line inspections for VM-related issues. No VM aerial patrols; VM inspections > 7 years. Lines > 200 kV aerially inspected 2 times per year; lines 200 kV and below aerially patrolled once a year. $600,000 Met-Ed Not available. Not available. Annual. Annual. $360,000 for the 3 FE companies Penelec Not available. Not available. Annual. Annual. See above. Penn Power Every 4 months. Every 6 months. Every 6 months. Every 6 months. See above. PECO Aerial inspections twice a year; foot inspections every 3 years. Aerial inspections twice a year; foot inspections every 3 years. Aerial inspections twice a year; foot inspections every 3 years. Aerial inspections once a year; annual ground patrol for areas not accessible to helicopter. NA PPL Uncertain. Uncertain. NA Annual ''quick fly-over annually; aerial inspections every 4 years; ground inspections every 4 years. $12,000,000 UGI Annual. Annual. Annual. Annual. See 'UGI' above. Citizens' No transmission. No transmission. No transmission. No transmission. NA Wellsboro No transmission. No transmission. No transmission. No transmission. NA Pike County No transmission. No transmission. No transmission. No transmission. NA
AFL-CIO commented § 57.198(e)(3) should state:
(3) Overhead line inspections.
(i) Transmission lines shall be inspected aerially twice per year in the spring and fall. Transmission lines shall be inspected on foot every 2 years. If problems are found that affect the integrity of the circuits, they shall be repaired or replaced no later than 30 days from discovery.(ii) Distribution lines shall be inspected by foot patrol a minimum of once per year. If problems are found that affect the integrity of the circuits, they shall be repaired or replaced no later than 30 days from discovery.(iii) Overhead distribution transformers shall be visually inspected annually as part of the distribution line inspection. A visual inspection shall include checking for rust, dents or other evidence of contact, leaking oil, broken insulators, and any other conditions that may affect operation of the transformer.(iv) Above-ground pad-mounted transformers and below-ground transformers shall be inspected on a 2-year cycle. An inspection shall include, as appropriate, checking for rust, dents or other evidence of contact, leaking oil, installation of fences or shrubbery that could affect access to and operation of the transformer, and unauthorized excavation or changes in grade near the transformer. In addition, the load on each transformer shall be calculated at least once every 2 years.(v) Reclosers in the distribution system shall be inspected and tested at least once per year.(vi) The integrity of transmission towers shall be inspected and tested at least once every 25 years.The AFL-CIO argues these previous underlined changes are necessary to improve the reliability of the regulation by adding subparagraphs for each type of facility and clarification.
The OCA had similar comments to AFL-CIOs regarding this section. The OCA believes transmission lines and all attached equipment should be inspected aerially twice per year in the spring and fall and if problems are found that affect the integrity of the circuits, they should be repaired or replaced within 30 days from discovery. The OCA requests distribution lines undergo a detailed inspection every 5 years including infrared scanning. The OCA wants the load on transformers to be calculated at least once every 2 years and if problems are found, then the equipment should be repaired or replaced within 30 days from discovery. The OCA agrees reclosers should be tested at least once per year, but the OCA recommends adding the requirement that if problems are found that affect the integrity of the equipment, they should be repaired or replaced within 30 days from discovery. The OCA adds requirement subparagraph (vi) which states as follows:
(vi) Other critical Facilities shall be tested and inspected either annually or every 2 years. Switches shall be inspected and tested annually. Relays, sectionalizers, and vacuum switches shall be inspected and tested every 2 years. If problems are found that affect the integrity of the equipment, they shall be repaired or replaced within 30 days from discovery.Comments of OCA, November 6, 2006.
Finally, OCA commented § 57.198(e)(4) should state:
(4) Substation inspections and repair. Substation equipment, structures and hardware shall be inspected monthly. An inspection that includes infrared scanning shall be conducted annually. Substation circuit breakers should undergo operational testing at least once per year, diagnostic testing at least once every 4 years, and comprehensive inspection and maintenance on a 4-year cycle. Deficiencies identified should be repaired or addressed within 30 days if serving transmission lines and within 60 days if serving distribution lines.PPL commented that overhead equipment failure caused the most outages in 2006. It argues the I & M standards should be customized for each EDC to account for its unique asset structure, service area, technological sophistication, and performance. It should also easily adapt over time to changing technology, work methods, costs and structures. PPL suggests EDCs should be divided into two groups, each submitting custom plans in alternate years. The Commission would review and identify changes if necessary. Any approved plan would set the standards for that particular EDC. The Commission would then enforce compliance with the approved plan as well as compliance with reliability standards. We do not see any need to split the EDCs into two groups. Staff can review the plans as they are submitted on October 1 of each year.
Senator Tomlinson commented that requiring two men to walk a transmission line, or aerial overviews of lines appears to be cost-prohibitive and unduly burdensome. Further, the Senator urged the Commission to consider revising its standards and mandated time cycles. To take the regulation from no mandated cycles to highly restrictive standards seemed to be too restrictive to the Senator.
Duquesne Light commented that aerial inspection of transmission lines on an annual basis is sufficient. If significant events occur such as major storms, aerial inspections may be performed more frequently than annually. Duquesne performs biannual aerial inspections on transmission lines greater than 200 kV and critical circuits, while transmission lines below 200 kV are aerially inspected once a year, and it is sufficient to locate and repair problems.
Duquesne Light further commented that the Commission should question whether it has full authority to regulate reliability standards for transmission. NERC and FERC have been very active with transmission reliability and Pennsylvania's standards for transmission reliability are inconsistent with FERC's proposed regulations. Further, newer transmission lines are less in need of annual inspections than older lines. A minimum standard does not account for this and unnecessary costs will be expended to annually inspect the new lines. PECO's 5-year plan for distribution lines falls within the Commission's new proposed guidelines of 4-8 years. We will decline to regulate inspection cycles on transmission lines at this time and will monitor FERC's Advanced Proposed Rulemaking regarding transmission lines.
PECO commented that the Commission should decline to adopt mandatory I & M regulations relating to transmission lines. PECO currently inspects its transmission lines by aerial patrol once a year, in the spring, and this is supplemented by a ground patrol by foot or vehicle in areas that cannot be inspected by air or that need follow-up. PECO believes that inspecting twice a year is unnecessary and would not increase the reliability of the transmission line system and instead would only result in a significant increase to its transmission inspection costs.
Disposition
Upon consideration of these comments, we will decline to promulgate a standard regarding transmission lines and will monitor FERC's rulemaking proceeding at this time. Although we believe we have jurisdiction to create inspection, maintenance, repair and replacement standards regarding transmission lines, FERC has a rulemaking underway addressing these issues. However, we would still like the EDCs to include their I & M plans with their tree-trimming cycles and other inspection and maintenance cycles detailed with regard to transmission lines just so that we may monitor I & M efforts in Pennsylvania.
Proposed: 52 Pa. Code § 57.198(e)(3): Overhead line inspections. Transmission lines shall be inspected aerially twice per year in the spring and fall. Transmission lines shall be inspected on foot every 2 years. Distribution lines shall be inspected by foot patrol a minimum of once per year. If problems are found that affect the integrity of the circuits, they shall be repaired or replaced no later than 30 days from discovery. Overhead distribution transformers shall be visually inspected annually as part of the distribution line inspection. Aboveground pad-mounted transformers and below-ground transformers shall be inspected on a 2-year cycle. Reclosers shall be inspected and tested at least once per year.
Company 1990 1995 2000 Current Incremental Cost Allegheny Inspected every 10 years. Inspected every 10 years. Inspected every 12 years. Inspected every 12 years. $1,500,000 Duquesne No formal inspection program. No formal inspection program. Infrared inspection on a 5-year cycle. Infrared inspection on a 5-year cycle. $750,000 + initial investment of $300,000 Met-Ed Not available. Not available. Not available. Not available. $1,950,000 for the 3 FE companies Penelec Not available. Not available. Not available. Not available. See above. Penn Power Not available. Not available. Not available. Not available. See above. PECO Variable divisional programs with 1 year target. Variable divisional programs with 1 year target. Drivable portion patrolled every year. Ground patrol inspection using thermography every 2 years; areas not accessible by vehicle inspected by foot patrol. NA PPL As required. As required. NA No fixed interval; based on CPI. Included in transmission line cost. UGI NA NA NA NA See 'UGI' above. Citizens' Annually. Annually. Annually. Annually. NA Wellsboro NA 5 years. 5 years. 3 years. $88,000 Pike County No foot patrol; infrared inspection annually for 3-phase and 3 years for other lines. No foot patrol; infrared inspection annually for 3-phase and 3 years for other lines. No foot patrol; infrared inspection annually for 3-phase and 3 years for other lines. No foot patrol; infrared inspection annually for 3-phase and 3 years for other lines. $55,000
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