2015 General Rate Case

Transcription

1 Application No.: Exhibit No.: SCE-0, Vol. 0, Part 1 Witnesses: M. Stark K. Trainor (U -E) 01 General Rate Case Transmission And Distribution (T&D) Volume, Part 1 Distribution Maintenance Before the Public Utilities Commission of the State of California Rosemead, California November 01

2 SUMMARY This chapter describes SCE s inspection and maintenance activities associated with the distribution grid, including planned and unplanned work. Most of the planned work is performed to satisfy various requirements placed upon SCE by the California Public Utilities Commission (CPUC), as well as various city and county agencies. SCE is requesting $. billion in capital expenditures and $1 million in 01 test year expenses in these categories. Distribution Maintenance Programs O&M Expenses 01 Forecast (Constant 01 $Million, FERC and CPUC Jurisdictional) Transmission & Substation Maintenance (Volume ) $ 1% Safety, Training, and Environmental Programs (Volume ) $ % T&D Other Costs and OOR (Volume ) $ 1% T&D Engineering and Grid Technology (Volume ) $ % Grid Operations (Volume ) $ 1% Customer Driven Prog & Distr. Con. (Volume ) $1 % Pole Loading (Volume, Part ) $ % Distribution Maintenance (Volume, Part 1) $10 0%

3 Distribution Maintenance Programs Capital Expenditures Forecast ($ Millions, CPUC Jurisdictional Only) System Planning Capital Projects (Volume ), $,1, 1% T&D Engineering and Grid Technology (Volume ), $1, 1% Transmission & Substation Maintenance (Volume ), $, % Grid Operations (Volume ), $, % Pole Loading (Volume, Part ), $1,0, % Infrastructure Replacement Programs (Volume ), $,0, 1% Customer Driven Prog & Distr. Con.(Volume ), $,1, % Distribution Maintenance (Volume, Part 1), $,1, 1%

4 SCE-0: Transmission and Distribution Volume 0, Part 1 Distribution Maintenance Table Of Contents Section Page Witness I. INTRODUCTION...1 M. Stark A. Distribution Inspection and Maintenance Program (DIMP) Overview...1 B. Forecast O&M Expenses and Capital Expenditures O&M Expenses.... Capital Expenditures... C. Comparison of 01 GRC Request, Authorized, and Recorded O&M Expenses.... Capital Expenditures... II. Work Descriptions, Recorded Costs And Test Year Forecasts... A. Distribution Equipment Inspection Expenses Annual Patrols, Portion of FERC Account.... a) Cost Forecast.... Overhead Detailed Inspection Program, Portion of FERC Account.... a) Cost Forecast.... Underground Detailed Inspections (UDI), Portion of FERC Account....1 a) Cost Forecast...1 B. Distribution Maintenance Cost Forecast Maintenance Expense (O&M), Portions of FERC Accounts. and Cost Forecast Distribution Maintenance Capital Expenditures...1 -i-

5 SCE-0: Transmission and Distribution Volume 0, Part 1 Distribution Maintenance Table Of Contents (Continued) Section Page Witness C. Vegetation Management, Portion of FERC Account Cost Forecast for Routine Vegetation Management...0. Cost Forecast for Bark Beetle Remediation...1. Big Creek Corridor...1 a) Cost Forecast... D. Miscellaneous Inspection and Maintenance Distribution Transformer Maintenance Expenses, Portion of FERC Account.... a) Cost Forecast.... Graffiti Removal Expenses, Portion of.... a) Cost Forecast.... Distribution Apparatus Inspection & Maintenance Expenses, Portion of.... a) Cost Forecast.... Removal of Idle Facilities Capital Expenditures... a) Cost Forecast... E. Underground Structure Rehabilitation Program Cost Forecast - Underground Structure Field Investigation Expenses, Portion of FERC Account...0. Cost Forecast - Underground Structure Repair Expenses, Portion of FERC Account Cost Forecast - Underground Structure Replacements... F. Overhead Conductor Program... -ii-

6 SCE-0: Transmission and Distribution Volume 0, Part 1 Distribution Maintenance Table Of Contents (Continued) Section Page Witness 1. Cost Forecast... G. Pole Inspection and Replacement... K. Trainor 1. Distribution Pole Inspections, Portion of FERC Account.... a) Cost Forecast.... Deteriorated Pole Replacements Capital Expenditures...0 a) Cost Forecast...1. Aged Pole Replacement Capital Expenditures... a) Cost Forecasts... H. Joint Pole Activities Joint Pole Organization (JPO) Expenses, Portion of FERC Account.... a) Cost Forecast.... Joint Pole Expense Credits, Portion of FERC Account.... a) Cost Forecast.... Joint Pole Replacement Capital Credits...0 a) Cost Forecast...0 I. Wood Pole Disposal...1 a) Cost Forecast... J. Summary of FERC Accounts FERC Account..... FERC Account..... FERC Account.... -iii-

7 SCE-0: Transmission and Distribution Volume 0, Part 1 Distribution Maintenance Table Of Contents (Continued) Section Page Witness Appendix A Witness Qualifications... -iv-

8 SCE-0: Transmission and Distribution Volume 0, Part 1 Distribution Maintenance List Of Figures Figure Page Figure I-1 Distribution Inspection and Maintenance Program O&M Costs Summary Authorized vs. Recorded (Constant 01 $000)... Figure I- Distribution Inspection and Maintenance Program Capital Expenditures Summary Authorized vs. Recorded (Constant 01 $millions)... Figure II- Distribution Maintenance Expenditures Various WBS Recorded and Adjusted 00-01/Forecast ($000) Capital Expenditures...1 Figure II- Removal of Idle Facilities WBS Element CET-PD-CR-IF Recorded and Adjusted 00-01/Forecast ($000) Capital Expenditures... Figure II- Underground Structure Replacements Recorded 00-01/Forecast ($000) Capital Expenditures... Figure II- Deteriorated Pole Replacement, Distribution Portion of WBS Element CET- PD-IR-DP Recorded 00-01/Forecast ($000) Capital Expenditures... Figure II- Deteriorated Pole Replacement, Transmission Portion of WBS Element CET- PD-IR-TR Recorded and Adjusted 00-01/Forecast ($000) Capital Expenditures... Figure II- Age of Distribution Wood Poles... Figure II- Programmatic Pole Replacements... Figure II- Aged Pole Replacement Portion of WBS CET-PD-IR-DP Recorded and Adjusted 00-01/Forecast ($000) Capital Expenditures... Figure II- Joint Pole Credits, Distribution and Transmission WBS Elements CET-PD- CR-JD and CET-PD-CR-JT Recorded and Adjusted 00-01/Forecast ($000) Capital Expenditures...1 Figure II-1 Wood Pole Disposal WBS Element WBS CET-PD-OT-WP Recorded and Adjusted 00-01/Forecast ($000) Capital Expenditures... -v-

9 SCE-0: Transmission and Distribution Volume 0, Part 1 Distribution Maintenance List Of Tables Table Page Table I O&M Expense Forecast... Table I Capital Expenditure Forecasts... Table II- Annual Patrols, Portion of FERC Account. Recorded and Adjusted 00-01/Forecast (Constant 01 $000)... Table II- Overhead Detailed Inspection, Portion of.... Table II- Underground Detail Inspections, Portion of FERC Account. Recorded and Adjusted 00-01/Forecast Table II- Distribution Maintenance Expenses, Portion of. and. Recorded and Adjusted / Forecast (Constant 01 $000)...1 Table II- Vegetation Management, Portion of. (Constant 01 $000)...0 Table II- Bark Beetle Related Vegetation Management, Portion of....1 Table II- Big Creek Expenses, Portion of 1. Recorded and Adjusted 00-01/Forecast (Constant 01 $000)... Table II- Distribution Transformer Maintenance Expenses, Portion of.... Table II- Remove Graffiti from Distribution Equipment Portion of FERC Account. Recorded and Adjusted 00-01/Forecast (Constant 01 $000)... Table II-1 Distribution Apparatus Inspection & Maintenance Expenses, Portion of... Table II-1 Vault Inspection, Repair and Replacement Forecast Summary... Table II-1 Manhole Inspection, Repair and Replacement Forecast Summary...0 Table II-1 Field Evaluation Expenses, Portion of FERC Account. Recorded and Adjusted 00-01/Forecast (Constant 01 $000)...1 Table II-1 Underground Structure Repair Detailed Forecast (Constant 01 $000)... Table II-1 Underground Structure Repairs, Portion of FERC Account. Recorded and Adjusted 00-01/Forecast (Constant 01 $000)... Table II-1 Underground Structure Replacement Forecast (Constant 01 $000)... Table II-1 Overhead Conductor Program Unit Forecast... -vi-

10 SCE-0: Transmission and Distribution Volume 0, Part 1 Distribution Maintenance List Of Tables (Continued) Table Page Table II-0 Overhead Conductor Program, Portion of FERC Account. Recorded and Adjusted 00-01/Forecast (Constant 01 $000)... Table II-1 Distribution Pole Inspections, Portion of FERC Account. Recorded and Adjusted 00-01/Forecast (Constant 01 $000)...0 Table II- Pole Inspection Findings, Transmission and Distribution...1 Table II- Joint Pole Organization Expenses (Portion of FERC Account.) Recorded and Adjusted 00-01/Forecast (Constant 01 $000)... Table II- Joint Pole Credit Expenses Portion of FERC Account. Recorded and Adjusted 00-01/Forecast (Constant 01 $000)... Table II- Joint Pole Credits Forecast by Activity Types...0 Table II- Joint Pole Credit Unit Credit Analysis...1 Table II- Wood Pole Disposal Unit Cost Analysis... Table II- Inspection of Distribution Overhead and Underground Lines and Equipment Summary of FERC Account. Recorded and Adjusted 00-01/Forecast Table II- Planned Maintenance of Distribution Overhead and Underground Lines Summary of FERC Account.; Recorded and Adjusted 00-01/Forecast 01-01(Constant 01 $000)... Table II-0 Distribution Overhead and Underground Breakdown Maintenance Summary of FERC Account. Recorded and Adjusted 00-01/Forecast (Constant 01 $000)... -vii-

11 I. INTRODUCTION The electrical equipment and structures that make up SCE s distribution grid undergo planned and unplanned inspection and maintenance. Required maintenance is identified through three sources: 1. Scheduled inspections driven by specific regulatory requirements;. Field inspections by personnel while performing other work; and. Inspections after emergencies or in-service failures of equipment. These inspections drive three categories of maintenance repairs made by inspectors (known as RBIs), repairs made by maintenance crews, and replacements made by construction crews. In addition, SCE periodically initiates new programs to target specific issues or to respond to particular regulatory requirements. This volume, along with Mr. Trainor s testimony in Exhibit SCE-0, Volume 0, Part, addresses several such programs, including the Pole Loading Program, the underground structure replacement program, overhead conductor program, and vegetation management programs. A. Distribution Inspection and Maintenance Program (DIMP) Overview In January 00, SCE launched a new distribution inspection and maintenance program (DIMP) that provides for the inspection and maintenance of SCE s distribution facilities. SCE s DIMP was created to comply with Decision (D.) in the Line Maintenance Order Instituting Investigation (OII) and a memorandum of understanding (MOU) with the Safety and Enforcement Division (SED, formerly known as the Commission s Consumer Protection and Safety Division). 1 In addition to satisfying the requirements of the Line Maintenance OII Decision and the MOU, SCE s goal in creating DIMP was to meet the requirements of GOs, 1, and 1 in a way that: (1) is consistent with sound maintenance practices; () enhances public and employee safety and maintains system reliability; and () delivers overall greater safety value for each safety dollar spent. 1 On April, 00, the Commission issued D in I (Maintenance OII). In the Decision, the Commission, among other things, directed that SCE, in consultation with SED (formerly known as CPSD), refine its distribution maintenance program. On August 1, 00, SED and SCE signed a MOU that memorialized the agreedupon principles between SCE and CPSD relating to the development of SCE s new distribution maintenance and inspection program. During this process SCE and SED also solicited input and participation from PG&E and SDG&E to develop a three-level maintenance and inspection Common Platform in the hopes of ultimately developing a model that could be applied to all electric utilities subject to General Orders, 1, and 1. Principles of this Common Platform, which was the foundation for SCE s DIMP program, were adopted in R and added to General Order, Rule 1A. DIMP was discussed in Vol., Part, Chapter XIII of SCE s 00 GRC. 1

12 Most notably, under DIMP, SCE prioritizes work based on the specific condition of each facility or piece of equipment and its probability for impact on safety and reliability, taking into account several factors. As a result, DIMP allows SCE to emphasize a condition s risk to safety and reliability from a wider perspective, and reduces the need to allocate resources to those conditions that pose a lower risk, or no risk at all. Under this approach, SCE can deploy its limited resources more effectively and efficiently to remediate conditions that have higher safety and reliability risks to achieve a higher value for each dollar spent. This approach is consistent with the Commission s direction in the Line Maintenance OII Decision and in accordance with the MOU. DIMP has three maintenance priority levels. During inspections, SCE inspectors identify and rate conditions based on the specifics for that condition, taking into account several factors. These factors include such things as the type of facility or equipment, loading, location, accessibility, climate, and direct or potential impact on safety or reliability. Highest priority items requiring immediate action are assigned Priority 1. Priority items do not require immediate action, but do require action to be corrected within a specified time period. Priority 1 and Priority items may be fully repaired or temporarily repaired and reclassified as a lower priority item. Priority items are lower priority items that involve little or no safety or reliability risk. SCE responds to Priority items by taking action at or before the next detailed inspection, which may include re-inspection, re-evaluation, reassessment, or repair. Since the launch of DIMP in 00, SCE has continued to refine and improve its inspection and maintenance program. For example, beginning in 00, SCE began completing all identified maintenance items at the structure when a qualified worker is performing scheduled work on that structure, irrespective of the additional items due dates or elevation on the structure. In essence, depending upon crew qualifications, SCE will carry out all identified maintenance on the pole when maintenance work is scheduled on the pole. This new approach is consistent with the requirements of the Line Maintenance OII Decision and the MOU, and SCE believes it is the right approach to maintenance. Also, in 00, SCE began notifying communication companies (such as Verizon or Time Warner Cable) of Priority conditions when such conditions are found during an SCE inspection. Communication companies typically own or lease space on the pole in an area below the electrical level

13 that is known as the communication level, and their actions can result in safety or reliability concerns for SCE assets. If these conditions are considered a safety or reliability concern, such as a communication service drop attached to SCE s service drop, SCE sends correspondence to the communication company notifying them of the condition. Pursuant to the Commission s Phase 1 decision in the Disaster Management Rulemaking (R.0--00), a similar requirement has since created reciprocal obligations for all electric and communication companies. In late 00, SCE began receiving, and taking action on, such notifications from telecommunication companies. In 00, SCE began using a new process for identifying, tracking, and evaluating underground structures for repair or replacement. Since 00, SCE has continued to refine and improve upon its programs for the inspection, repair, and replacement of underground structures. In addition, SCE recently expanded this program to include routine inspection and maintenance of underground structures which were previously not included in G.O. 1 inspections because they do not contain electrical equipment. SCE determined that these assets needed to be included as part of the regular DIMP inspections to maintain their structural integrity and provide for accurate record keeping. SCE has also undertaken several projects targeting specific emergent issues. Underground structure inspection and remediation focusing on structural integrity of underground assets, including assets that had previously not required inspection under G.O. 1: These structures are primarily vaults and manholes without equipment. This program will be ongoing during the period. This program is discussed in more detail in section II.A.. Overhead conductor program to evaluate the entire overhead distribution system with a focus on proactively identify potential splice, connector and wire failures under certain operational, environmental, and mechanical conditions. SCE will be identifying, prioritizing, and remediating identified conditions as part of a programmatic effort to reduce potential wire down incidents on SCE s distribution system. Big Creek corridor project to more proactively manage vegetation in proximity to the high voltage lines in the Big Creek area. SCE, through a collaborative effort with the United Continued from the previous page SCE s DIMP was used as the model for G.O., Rule 1A, which was enacted in D as part of the Fire Safety Rulemaking, R See D.0-0-0, new G.O. Rule 1 Part B, effective August 0, 00.

14 1 1 States Forrest Service, is undertaking new vegetation management activities along the right of way for SCE s 0 kv lines in the Big Creek area to comply with new vegetation management standards. Pole loading assessments and associated remediation to comply with G.O. safety standards and heightened internal standards: Proliferation of third-party attachments, new standards, and newer technology indicate the need to assess all the poles on SCE s system for compliance with pole loading requirements and to perform the appropriate remediation, as necessary. SCE has been evaluating the issue since 0, and will begin a formal Pole Loading Inspection Program in 01, which is expected to continue through 0. Further details about this program can be found in Mr. Trainor s testimony in Exhibit SCE-0 Vol. 0, Part. B. Forecast O&M Expenses and Capital Expenditures 1. O&M Expenses Table I-1 01 O&M Expense Forecast (0% CPUC Jurisdictional Constant 01 $ 000) Account Activity 01. Inspection Of Distribution Overhead And Underground Lines And Equipment $,. Planned Maintenance Of Distribution Overhead And Underground Lines And Equipment; Vegetation Management; And Apparatus Inspection And Maintenance $ 1,. Distribution Overhead And Underground Breakdown Maintenance $, Total O&M Expenses $1,

15 . Capital Expenditures Table I Capital Expenditure Forecasts (Total Company Nominal $000) Activity Total Preventive Maintenance 1, 1, 1,, 1,1,0 Breakdown Maintenance,00,,1,,,0 Pole Replacement 1,0,, 1,0 1,0, Joint Pole Credits (0,00) (,0) (1,) (1,) (1,1) (,1) Wood Pole Disposal,0,1 1, 1,,01,0 Underground Structure Replac, 0,,1,0,0, Idle Facility Removal,0,,,1,1, Total Expenditures $ 1,1 $,0 $, $,1 $,0 $,1,

16 C. Comparison of 01 GRC Request, Authorized, and Recorded 1. O&M Expenses Figure I-1 Distribution Inspection and Maintenance Program O&M Expense Summary Authorized vs. Recorded (0% CPUC Jurisdictional Constant 01 $000) 00 1 $1. $.1 $. $. $1. ($0.) Authorized Inspections Pole Assessments Maintenance Breakdown 01 Recorded Inspections Maintenance Breakdown Diff from Auth As shown in Figure I-1, in 01 SCE spent approximately percent of what was authorized within the expense categories included in this exhibit. Distribution inspection, maintenance, and breakdown expenses were all higher than authorized.

17 . Capital Expenditures Figure I- Distribution Inspection and Maintenance Program Capital Expenditures Summary Authorized vs. Recorded (CPUC-Jurisdictional Constant 01 $millions) $ $1 ($1) ($1) ($) $ $ Authorized D Prev Mtce D Bkdwn Mtce Pole Repl UG Structure Repl Misc 01 Recorded D Prev Mtce D Bkdwn Mtce Pole Repl UG Structure Repl Misc Diff from Auth As shown in Figure I-, and despite the late 01 GRC Decision, in 01, SCE spent almost percent of what was authorized within the capital expenditure categories included in this exhibit. Distribution preventive maintenance expenditures were higher than authorized, and distribution breakdown maintenance lower. Between these two work categories, SCE recorded $ million less than authorized as fewer equipment failures or emergency replacements were required. SCE performed fewer intrusive pole inspections in 01 because of the delay in receiving the 01 GRC decision, which also translated to fewer pole replacements in 01. SCE also spent less than authorized on In 01 the number of intrusive inspections being performed has been increased to allow SCE to get back on track with its -year levelization plan.

18 Underground Structure replacements due to uncertainty around available funding, which delayed the ramp-up of that program.

19 1 1 1 II. WORK DESCRIPTIONS, RECORDED COSTS AND TEST YEAR FORECASTS A. Distribution Equipment Inspection Expenses This section describes the distribution system inspection and maintenance programs that incur O&M expenses, and the associated costs, except for those incurred in programs targeting specific asset classes like poles and underground structures. 1. Annual Patrols, Portion of FERC Account. Annual patrols include activities related to inspecting the distribution electrical system in accordance with G.O. 1 and DIMP. Inspectors conduct annual patrols of overhead facilities using a geographical grid based approach. When conducting annual patrols the inspectors also assess visible portions of distribution underground systems including pad-mounted transformers, BURD enclosures, and vault lids. Identified maintenance items discovered during inspections are either repaired by the inspector or prioritized for follow up corrective action in accordance with SCE s DIMP program. Annual patrols are conducted by SCE s Electrical System Inspectors (ESI s) and contract inspectors. Table II- Annual Patrols, Portion of FERC Account. Recorded and Adjusted 00-01/Forecast (0% CPUC Jurisdictional Constant 01 $000) Recorded Forecast Labor $0 $1 $ $ $ $ $ $ Non-Labor $ $ $ $ $0 $0 $0 $0 Total $1,0 $1,1 $1,0 $1,0 $1,0 $1,0 $1,0 $1,0 Grids 0, 0, 0, 0, 0,1 0,1 0,1 0,1 Cost per Grid $ $ $ $1 $0 $0 $0 $0 Ratio of Labor to Total % % 0% % % % % % Basis of Forecast: LYR Basis of Labor/Non-Labor Split: LYR a) Cost Forecast Labor expenses included in this category are for inspectors performing the annual patrols. Non-labor expenses include contract inspector costs, vehicles, and other allocated charges. Table II- shows the recorded costs, number of grids patrolled, and the unit cost (recorded cost divided by grid count) for the period. SCE s territory is comprised of more

20 than 0 thousand grids, or geographical areas, which contain overhead and underground facilities on SCE s distribution electrical system. The number of grids can increase over time as electrical facilities are added to the distribution system. As seen in the table, the unit costs have stabilized since 00 following the launch of SCE s new DIMP. In accordance with D.-1-0, SCE forecasts 01 test year unit costs to be equal to 01 recorded unit costs, which is lower than the four-year average for of $ per grid. The forecast for the number of grids to be patrolled is based on the current number of grids, which is the same as the number of grids inspected in 01. Going forward annual patrols are expected to remain the same as no changes are currently being contemplated for this program. The total expenses in this category were forecast based on last year recorded expenses. The total was split between labor and non-labor based on the 01 recorded ratio of labor to non-labor. The forecasts for are also shown in Table II-.. Overhead Detailed Inspection Program, Portion of FERC Account. The Overhead Detailed Inspection (ODI) program involves activities related to inspecting SCE s overhead distribution electrical system in accordance with G.O. 1 and DIMP. The purpose of the ODI inspection is to perform a close proximity evaluation of SCE s overhead electrical facilities such as poles, capacitors, switches, transformers, conductors, guy wires, and risers to: identify hazardous conditions, or nonconformances with G.O. that require corrective action. Examples could include leaking transformers, broken or damaged equipment, inadequate clearances, deteriorated cross arms, missing or damaged high voltage signs, etc.; determine what the corrective action should be and prioritize follow up corrective actions based on safety and reliability in accordance with DIMP; perform minor repairs at the public level while at the location. For example, inspectors commonly perform repairs such as replacing damaged ground molding at the public level, installing guy guards, removing unauthorized attachments (if appropriate), installing pole tags, etc.; document inspection findings, including pending and completed repairs. GO 1 requires detailed inspection of overhead distribution equipment every five years. ODI inspections are conducted by SCE s Electrical System Inspectors and contract inspectors. The expenses incurred by this program are recorded in FERC Account..

21 Table II- Overhead Detailed Inspection, Portion of. Recorded and Adjusted 00-01/Forecast (0% CPUC Jurisdictional Constant 01 $000) Recorded Forecast Labor $,000 $, $,1 $, $,0 $, $, $, Non-Labor $1, $1,1 $1, $1, $, $,1 $, $, Total $, $,0 $, $,0 $, $, $,0 $,0 Inspections 0,,,,,0,1,1 0, Cost per Inspection ($) $1 $1 $1 $1 $1 $ $ $ Ratio of Labor to Total % 0% % % % % % % Basis of Forecast: Forecast Inspections * LYR cost per inspection + Increment for difficult to access structures Basis of Labor/Non-Labor Split: LYR a) Cost Forecast Labor expenses included in Table II- are the costs incurred by SCE inspectors performing the inspections. Non-labor expenses include contract inspector labor costs, materials, vehicles, and other allocated charges. Table II- shows the historical recorded costs for along with the number of inspections, and the corresponding cost per inspection (recorded cost divided by inspection count). Unit costs have been relatively stable from 00 to 0. In 01, the cost per inspection increased due to changes in work methods and accounting practices. Prior to 01, the ODI supervisors labor and vehicle costs were recorded in an account that was allocated to various activities. Starting in 01, these costs are being charged directly to the overhead detail inspection account. In addition, inspectors began performing inspections in remote areas by helicopter. This activity began in 0, and 01 reflects the first full year of this activity. These changes increased unit costs from an average of $1 per inspection from 00-0 to $1 per inspection in 01. Since these practices will continue in the future, SCE utilized the 01 recorded cost per inspection as the basis to forecast test year expenses. Additionally, the test year cost forecast will increase above 01 recorded due to a program enhancement focused on gaining access to obstructed or difficult to access structures. The majority of these poles are in customers backyards, often behind locked gates or with access to the pole obstructed. Beginning in 01, SCE is requiring inspectors to gain access to every pole in order to complete the detailed inspection rather than

22 completing inspections from a distance using binoculars or similar equipment. Difficult to access poles often involve making contact with the property owners and require inspectors to make multiple trips in order to complete the inspection. In extreme cases SCE could be required to pursue legal action in order to gain access to the pole. In 01, inspectors could perform ODI on approximately 0 poles per day. For the difficult to access poles, SCE expects inspectors to complete 0 poles per day, while maintaining their productivity for accessible poles at 0 per day. The inclusion of difficult to access poles will increase the average unit cost to $ per pole. The total forecasts for this activity in are forecast by multiplying the forecast unit cost per inspection by the forecast number of inspections. The labor and non-labor costs were forecast based on the 01 labor to non-labor ratio. The 01 forecast expense shown is based on the average of forecast expense for The summary of the forecasts are also included in Table II-.. Underground Detailed Inspections (UDI), Portion of FERC Account. This program involves activities for inspecting SCE s underground distribution electrical system in accordance with G.O. 1 and DIMP. The purpose of UDI is to provide close proximity examination of underground and pad mounted distribution equipment as mandated by G.O. 1. Inspectors assess subsurface and pad mounted equipment including enclosures, switches, transformers, visible cables, and associated components to identify safety hazards and nonconformances with G.O. 1. Similar to the ODI program, the UDI inspectors document safety and reliability hazards and prioritize corrective actions in accordance with SCE s DIMP. When possible, they perform routine maintenance or make repairs during the course of the inspection. UDI activities are generally performed by a crew consisting of a lineman and a groundman, both of which have received specialized training to work in underground vaults and in proximity to energized high voltage equipment. See Workpaper entitled Overhead Detail Inspection Difficult to Access Pole Forecast. 1

23 Table II- Underground Detail Inspections, Portion of FERC Account. Recorded and Adjusted 00-01/Forecast (0% CPUC Jurisdictional Constant 01 $000) Recorded Forecast Labor $1,1 $1, $,0 $, $,0 $, $,0 $, Non-Labor $ $ $1,01 $,0 $1,0 $1,00 $ $1,0 Total $, $,0 $,1 $,0 $, $, $, $, Inspections 1,1 1,1 1, 1, 1, 1,1 1,1 1,1 Cost per Inspection $1 $1 $ $0 $1 $1 $1 $1 Ratio of Labor to Total % % % % 1% 1% 1% 1% Basis of Forecast: Forecast Inspections * LYR Cost per Inspection Basis of Labor/Non-Labor Split: LYR a) Cost Forecast Labor expenses in this work category are driven by the inspectors performing the underground detail inspections. Non-labor expenses include materials, vehicle costs, and other allocated charges. Table II- shows the recorded expenses and inspection counts from 00-01, along with the corresponding cost per inspection (recorded cost divided by inspection count). 00 and 00 unit costs are similar, but the cost-per-inspection increased in 0 due to a mid-year change in the field tool used to record UDI activities that altered how inspectors account for their time between inspections and repairs. The cost per inspection increase in 0 is due to a full year of the aforementioned accounting change and the inclusion of more underground structures in the UDI program as discussed below. The cost-per-inspection remained stable in 01. SCE began including structures without equipment in the UDI program in 0, going from inspecting a few structures to over,000 structures in 0, and approximately 0,000 structures in 01. All of these structures will continue to be included in the routine inspections performed under the UDI program going forward. For subsurface structures without equipment, such as vaults and manholes, the cost per inspection is higher than the cost for other structures due to the time required to perform the inspection. Vaults and manholes require a minimum of two employees to conduct the inspection, are often filled with water that must be pumped out, require the inspectors to test and continually monitor air conditions within the enclosure before entering the structure, and require traffic control. The inspection of underground structures without equipment is being performed in 1

24 addition to the inspections conducted in accordance with G.O. 1. Since these underground structure inspections will continue in the future as part of the ongoing UDI program, SCE utilized the 01 recorded cost per inspection as the forecast unit cost for The inspection count forecast for is derived from the number of inspections that will be due each year, as required by G.O. 1 and SCE s DIMP. The total forecasts for this activity in are calculated by multiplying the forecast unit cost per inspection by the number of inspections required to be performed. The labor and non-labor costs were forecast based on the recorded 01 labor to non-labor ratio. The 01 forecast expense shown is based on the average of forecast expense for The summary of the forecasts are also included in Table II-. B. Distribution Maintenance Distribution maintenance includes the cost of labor, materials, and other expenses incurred when repairing or replacing items identified through inspection programs, as part of the normal course of business, and emergency or breakdown activities. It does not include costs related to failures that occur during a storm or from a claim, such as a vehicle damaging SCE poles. Inspection programs driving these activities include overhead detail inspections, underground detail inspections, and annual patrols described above. In addition, when field crews observe problems while performing other work or responding to trouble calls, they perform additional maintenance activities that record to these accounts. Maintenance activities can include the repair, replacement, or relocation of facilities; replacement of signs and cross-arms; repair or relocation of conduit; repair or replacement of conductor or cable, equipment, or pole fixtures; re-fusing line cutouts; repairing grounds, and replacing transformers. In accordance with DIMP, inspectors identify and prioritize deteriorated components or conditions found during inspections for follow up repair or replacement. Every item is evaluated based on the specifics for that condition, taking into account several factors, such as the type of facility or equipment, loading, location, accessibility, climate, and direct or potential impact on safety or reliability. These maintenance activities are performed by electrical crew foremen, linemen, groundmen, and contractor crews who work for SCE s Distribution Construction and Maintenance organization. Costs associated with maintenance activities are either recorded as expense (O&M), or capital, in accordance with established accounting rules. In simplistic terms, repairs or minor replacements are generally Please see Workpaper entitled Underground Detail Inspections. 1

25 recorded to expense, and the replacement of equipment or facilities are recorded to capital. Maintenance activities for repairs (O&M) and replacements (capital) are forecast separately in the sections below. 1. Cost Forecast Maintenance Expense (O&M), Portions of FERC Accounts. and. Labor costs are driven by the work performed by SCE field personnel in this work activity. Non-labor costs are driven by the contract crew charges, materials, vehicles costs, and other allocated costs. Preventive maintenance expenses for distribution assets driven by inspections or field observations are recorded in.; breakdown maintenance expenses are recorded in.. Both preventive and breakdown maintenance are driven by the age and condition of the distribution electrical system, can be similar in nature, and are completed by the same personnel. Hence, they are being forecast together. The historical expenses incurred in this activity are shown in Table II-. The total costs recorded in this category have increased from 00 to 00 due to increasing maintenance work resulting from the second year of DIMP, and an increase in emergency or breakdown maintenance activity associated with SCE s aging electrical system. Under DIMP, items can be prioritized to be repaired within months. Some of the items prioritized for repair in 00 were not due until 00, so 00 was the first full year of maintenance under the new DIMP. From 00 to 0 costs decreased due to a reduction in emergency and breakdown activity. Since 0, the costs in this activity have continued to increase each year as both planned and emergency maintenance work has increased with the expanding and aging infrastructure. Going forward, SCE expects to continue to perform the same types of activities in this area, with continuing upward pressure driven by the expanding and aging infrastructure. Given this upward trend, in accordance with D. -1-0, SCE forecasts expenses in these activities to be equal to 01 recorded expenses in constant 01 dollars. Since work levels, contractor utilization, and other charges are also expected to follow the same trends as in 01, SCE has estimated the labor and non-labor expenses in 01 to 01 using the 01 labor to non-labor ratio. The forecasts are also summarized in Table II-. 1

26 Table II- Distribution Maintenance Expenses, Portion of. and. Recorded and Adjusted / Forecast (0% CPUC Jurisdictional Constant 01 $000) Recorded Forecast Labor $,0 $,1 $,1 $, $1, $1, $1, $1, Non-Labor $, $,1 $,1 $, $1,0 $1,0 $1,0 $1,0. Labor $1, $0,0 $1, $0, $1, $1, $1, $1, Non-Labor $0, $,1 $0,0 $,0 $,0 $,0 $,0 $,0 Total $,1 $0,1 $, $, $, $, $, $, Labor $,1 $0, $,1 $1, $, $, $, $, Non-Labor $,001 $, $,1 $,1 $,00 $,00 $,00 $,00 Ratio of Labor to Total % % % % % % % % Basis of Forecast: LYR Basis of Labor/Non-Labor Split: LYR Cost Forecast Distribution Maintenance Capital Expenditures As discussed earlier, the costs recorded in this account are driven by the work performed by SCE field personnel and contract crews, materials, equipment, vehicles costs, and other allocated costs. Like maintenance repairs, both preventive and breakdown maintenance are driven by the age and condition of the distribution electrical system, can be similar in nature, and are completed by the same personnel. Therefore, SCE forecasts these two capital expenditure categories together. The historical expenditures incurred in this activity are shown in Table II-. The total costs recorded in this category decreased from 00 to 00, primarily due to a decline in breakdown replacement along with a decrease in emergency replacements. From 00 to 01 expenditures have been steadily increasing due to the ongoing DIMP and the continually expanding and aging infrastructure. Going forward, SCE expects to continue to perform the same types of activities in this area, with continuing upward pressure driven by the expanding and aging infrastructure. Due to this upward trend, and in accordance with D. -1-0, SCE forecasts 1

27 expenditures in this activity to be equal to 01 recorded expenditures in constant 01 dollars. See Figure II-. Additionally, in 01 SCE is performing additional maintenance activities that have been identified within the local Regions and Districts. These projects involve maintenance activities driven by safety, operations, or reliability issues that have been identified by these local jurisdictions. Projects are selected based on known local conditions, and although these projects by themselves would not typically rise to the system level today, they could ultimately become larger issues in the future if not corrected. Examples can include projects to re-conductor and rebuild lines to critical assets such as police, fire, and forest communications systems, create critical system ties, rebuild systems that have performed poorly, and rebuild systems that caused multiple outages in small pockets of the system. 1

28 Figure II- Distribution Maintenance Capital Expenditures Various WBS Recorded 00-01/Forecast (0% CPUC-Jurisdictional $000) $00,000 $0,000 $00,000 $,000 $0,000 $0,000 $ Nominal $ 0,0,1 1,,1,, 0,,1 1,1, Constant 01 $, 1,1,0,,,,,,, Nominal $ Constant 01 $ Forecast 1 In D , SCE s 01 GRC Final Decision, the Commission asked SCE to include with any request for additional funding of Asset Based Preventative Maintenance, a description of how many replacements were performed annually after 0, the number of new replacements identified, and the number, priority, and estimated cost of backlog replacement projects, if any. In the 01 GRC, SCE presented the counts of overhead transformers, underground transformers, overhead conductors, and underground conductors replaced under this activity as a proxy for all work performed in this category. For example, when SCE replaces a mile of cable, it could include other equipment types such as switches, capacitors, regulators, pull boxes, conduit, fuses, and sump pumps, but for the purpose of that analysis SCE only counted the mile of cable. In the previous GRC, these counts were used to forecast the volume of work and associated costs for the entire activity. WBS elements CET-PD-BM-BD, CET-PD-IR-EP, CET-PD-IR-NP, CET-PD-IR-PM, and CET-PD-BM-EP. 1

29 In practice, instead of asset counts, SCE utilizes notifications to track preventative maintenance work identified through inspections and field observations. Notifications generated by inspection programs are assigned a priority in accordance with SCE s DIMP program. The actual assets replaced under any notification could encompass more than these four equipment types. Therefore, SCE is unable to provide a complete listing of the information as requested. The activity termed Asset Based Preventive Maintenance in the 01 GRC, is the same activity referred to as Preventive Maintenance in this GRC. SCE has not created its forecast using an asset based replacement methodology in this GRC. Instead, SCE is using its last year recorded costs to forecast its future costs. SCE does not currently have a backlog of preventive maintenance replacement projects. C. Vegetation Management, Portion of FERC Account. Vegetation management includes all of the expenses associated with tree trimming, tree removal, and weed abatement in proximity to distribution high voltage lines. It also includes costs incurred in planting different species of trees as replacements and in handling preventive soil treatment. The majority of costs in this area are from a fixed price contract with SCE s tree trimming contractor, which requires them to maintain compliance for the approximately 1. million trees throughout SCE s territory that exist in proximity to energized conductors. Annual tree trimming costs increased at the end of 00 as a result of the Commission s change in the vegetation clearance requirements in High Fire areas, which became effective August 0, 00. The 01 GRC authorized recovery of these increased costs. GO and Public Resources Code Sections and require SCE to manage vegetation near its wires. SCE engages a contractor to trim and remove trees and weeds, as well as other activities, to facilitate compliance with these requirements. All of the trees in inventory are inspected annually to comply with the applicable requirements. During these inspections, any trees or vegetation that require trimming to maintain the required distances from high voltage lines are scheduled for trimming or removal. In addition, hazard trees, such as overhangs in high fire areas, dead, diseased or dying trees are also identified for trimming or removal. In some cases it is necessary to trim trees more frequently to meet the Commission s requirements. For example, fast-growing species, or trees in areas designated as high risk for wild fires may need more frequent trimming to meet the Commission standards. See D Decision in Phase 1 Measures to Reduce Fire Hazards in California Before the 00 Fall Fire Season. 1

30 In addition to routine vegetation management, in this GRC, SCE is requesting funding for bark beetle related vegetation management. As discussed in Exhibit SCE-, Vol. 1, Part, in 00 the Commission authorized SCE to recover costs for Bark Beetle remediation work through Catastrophic Event Memorandum Account (CEMA) filings. Since that time, SCE has been recording its O&M expenses associated with the inspection and removal of dead, dying or diseased trees that may fall or contact SCE s electrical facilities as a result of the bark beetle emergency. Since expenses related to bark beetle remediation have become more predictable, SCE has determined that recovery through CEMA will no longer be necessary and is requesting on-going costs to be included in base rates. If recovery of the bark beetle costs in this GRC application is adopted, SCE will discontinue recording any bark beetle related costs into the Bark Beetle CEMA as of January 1, Cost Forecast for Routine Vegetation Management Labor expenses in this category are driven by the work performed by SCE arborists and employees that manage the vegetation management program. Non-labor costs include contractor costs and other allocated charges associated with the vegetation management program. As previously discussed, costs increased in 00 due to the Commission s change in the vegetation clearance requirements in High Fire areas. Costs peaked in 0, and have since stabilized. SCE expects to continue to perform the same level of activities in this area going forward. As a result, the forecast for these expenses is based upon 01 expenses, the last recorded year. See Table II-. Table II- Vegetation Management, Portion of. Recorded and Adjusted / Forecast (0% CPUC-Jurisdictional Constant 01 $000) Recorded Forecast Labor $, $,0 $,1 $, $, $, $, $, Non-Labor $, $,1 $, $, $,0 $,0 $,0 $,0 Total $, $0, $,1 $0, $, $, $, $, Ratio of Labor to Total % % % % % % % % Basis of Forecast: LYR Basis of Labor/Non-Labor Split: LYR 0

31 . Cost Forecast for Bark Beetle Remediation Bark beetle activities have declined since the inception of this program as the number of affected trees have been controlled and stabilized. SCE expects to continue to perform the same level of activities in this area going forward. In accordance with D. -1-0, SCE is basing its forecast on 01 expenses, the last recorded year. See Table II-. Table II- Bark Beetle Related Vegetation Management, Portion of. Recorded and Adjusted / Forecast (0% CPUC-Jurisdictional Constant 01 $000) Recorded Forecast Labor $0 $ $0 $0 $ $ $ $ Non-Labor $, $, $, $,01 $,0 $,0 $,0 $,0 Total $,1 $,0 $, $,0 $,0 $,0 $,0 $,0 Ratio of Labor to Total % % % % % % % % Basis of Forecast: LYR Basis of Labor/Non-Labor Split: LYR Big Creek Corridor On December 1, 0, NERC submitted a petition for FERC approval of Reliability Standard FAC-00- (Transmission Vegetation Management), along with new corresponding Violation Risk Factors and Violation Severity Levels for tree encroachments. The new transmission vegetation management standard, effective July 1, 01, includes more prescriptive standards for vegetation management programs and more stringent penalty provisions. In conjunction with this new standard and in an effort to more proactively manage vegetation in the Big Creek area, SCE is undertaking new vegetation management activities in the Big Creek (BC) Corridor to comply with these new standards. The BC Corridor encompasses more than 0 miles of high voltage lines in the BC hydroelectric system, a system that dates back to the early 100s. The BC system is located in the Sierra Nevada Mountains, often within land located in the National Forest and under jurisdiction of the United States Forrest Service (USFS). The right of way for SCE s 0 kv lines in the mountainous region of the BC corridor traverse areas of steep and rugged terrain, bordered by large trees. For years SCE has been trimming trees along the Big Creek Corridor, but a lack of collaboration with the USFS limited 1

32 SCE s ability to manage the right of way (ROW) and vegetation along the BC Corridor. During this time, removals have been difficult, and often performed only under emergency conditions. In 0, an incident occurred where a tree fell into the BC line from outside the right of way (ROW). Since that time, SCE has been working with the USFS to perform more work in the BC area. Today, the USFS is working with SCE in a collaborative manner and they are supportive of SCE s efforts to more proactively manage vegetation in the BC area. As a result, SCE is launching an initial effort this September to more proactively manage the BC corridor and vegetation in proximity to the lines. Going forward, SCE plans to incorporate the information and best practices learned during this initial effort to help better manage and remediate what is identified as the high risk areas along the BC ROW. These activities are necessary to comply with the requirement to manage vegetation to prevent encroachments, including fall-ins, as required by NERC FAC-00-. a) Cost Forecast The cost forecast for this program involves the removal of small trees and large shrubbery underneath the high voltage lines, the removal of large trees adjacent to the lines, and associated work. The process for removing a tree within the transmission ROW in Big Creek consists of four steps: felling (cutting the tree down), buck/slash (cutting off all of the limbs), chip/haul (chipping of limbs), and log disposal. SCE will also perform brushing, mowing, grading, and herbicide activities on the ROW. In addition to these activities, cost estimates also take into account environmental activities due to the sensitive habitat and potential for archeological sites in the BC area. Activities will be prioritized to remediate the highest risk areas first. The cost estimates are based on contract costs from SCE s bark beetle program, which involved similar activities. See Table II-. See Workpaper entitled Big Creek Corridor NERC FAC-00-.

33 Table II- Big Creek Expenses, Portion of 1. Recorded and Adjusted 00-01/Forecast (Total Company Constant 01 $000) Recorded Forecast Labor $0 $0 $0 $0 $0 $0 $0 $0 Non-Labor $0 $0 $0 $0 $0 $1,0 $,1 $,1 Total $0 $0 $0 $0 $0 $1,0 $,1 $,1 Ratio of Labor to Total 0% 0% 0% Basis of Forecast: Contract rates * forecast activities Basis of Labor/Non-Labor Split: Forecast 1 D. Miscellaneous Inspection and Maintenance 1. Distribution Transformer Maintenance Expenses, Portion of FERC Account. When distribution transformers fail in service, a small portion of them can be refurbished and returned to service. This account records the cost of labor, materials used and expenses incurred in the repair of distribution transformers performed by specialized crews in SCE s Shop Services and Instrumentation Division (SSID). Table II- Distribution Transformer Maintenance Expenses, Portion of. Recorded and Adjusted / Forecast (0% CPUC-Jurisdictional Constant 01 $000) Recorded Forecast Labor $1,0 $ $1,1 $1,00 $1,0 $1,1 $1,1 $1,1 Non-Labor $ $ $ $ $ $ $ $ Total $, $1, $1,1 $,0 $1,1 $1,1 $1,1 $1,1 Ratio of Labor to Total % % % % % % % % Basis of Forecast: YA Basis of Labor/Non-Labor Split: YA

34 a) Cost Forecast The expenses recorded in this account are a function of the number of transformers that can be refurbished in a given year. Since these costs have fluctuated from 00 to 01, SCE utilized used a five-year average as the basis for its test year forecast. The labor and nonlabor split is based on the five-year average ratio of labor to non-labor. See Table II- above.. Graffiti Removal Expenses, Portion of. Graffiti removal involves the painting of equipment and structures in conjunction with SCE s graffiti abatement program. Graffiti abatement is an ongoing issue among the cities and counties served by SCE. Several communities have enacted, or are considering, graffiti abatement ordinances for utility equipment and structures, often with stringent requirements and penalties. Since 00 SCE has been aggressively confronting this growing issue with help from its Local Governmental Affairs organization, and by contracting for service territory wide graffiti abatement services. a) Cost Forecast SCE s graffiti abatement contractor provides graffiti abatement services throughout SCE s 0,000 square-mile service territory under a fixed price agreement, which will be renegotiated before the end of 01. New rates will become effective in 01. Ongoing expenses are expected to track labor and non-labor escalation rates. Therefore the test year forecast is based on the constant dollar recorded costs shown in 01 (Table II-). Table II- Remove Graffiti from Distribution Equipment Portion of FERC Account. Recorded and Adjusted 00-01/Forecast (0% CPUC-Jurisdictional Constant 01 $000) Recorded Forecast Labor $ $ $1 $ $0 $0 $0 $0 Non-Labor $ $ $ $1 $1 $1 $1 $1 Total $0 $ $ $ $1 $1 $1 $1 Ratio of Labor to Total 1% % % % % % % % Basis of Forecast: LYR Basis of Labor/Non-Labor Split: LYR

35 1. Distribution Apparatus Inspection & Maintenance Expenses, Portion of. Distribution Apparatus includes the cost associated with the inspection and testing of all overhead and underground distribution apparatus, such as fixed and automatic capacitors, network protectors, fault interrupters, and automatic re-closing switches used for line protection and sectionalizing, as well as the resulting maintenance performed by the apparatus crews. Two- and three-person apparatus crews with specialized training perform these inspections using technical diagnostic equipment. Apparatus equipment is predominantly found on the overhead distribution system, and is inspected on a five-year cycle consistent with GO 1. Work performed by apparatus crews varies from year to year according to this inspection cycle, and type of work performed, which can cause costs to vary between repair expenses and capital expenditures. The frequency and cost of repairs, and the portion of repairs that are maintenance expenses versus capital expenditures, vary from year-to-year. Table II-1 Distribution Apparatus Inspection & Maintenance Expenses, Portion of. Recorded and Adjusted / Forecast (0% CPUC-Jurisdictional Constant 01 $000) Recorded Forecast Labor $, $,0 $,00 $,0 $,1 $,0 $,0 $,0 Non-Labor $1,1 $,01 $1,0 $1,0 $0 $1,0 $1,0 $1,0 Total $,0 $,1 $,00 $, $,001 $, $, $, Ratio of Labor to Total % % % % 1% % % % Basis of Forecast: YA Basis of Labor/Non-Labor Split: YA a) Cost Forecast As described above, the cost for distribution apparatus inspection and maintenance expenses fluctuate from year-to-year due to the number of inspections performed, complexity and type of maintenance activity performed, and number of repairs versus replacements. As a result of equipment inspections, crews will identify repairs that are either capital or expense, depending upon the extent of the work. The type of repair, capital versus expense, and the complexity of the expense repairs results in fluctuations in the historical expenses for this activity. For the test year

36 forecast SCE utilized the five-year average of labor and non-labor costs recorded for distribution apparatus maintenance (Table II-1). Labor expenses in this category include the costs incurred by SCE for the distribution apparatus management, supervisors, and the apparatus crews. Non-labor expenses include material costs, vehicle costs, and other allocated costs.. Removal of Idle Facilities Capital Expenditures SCE removes idle assets that are no longer used or useful, typically because a customer has left a facility that therefore no longer requires electrical service. SCE dismantles these assets and removes them from rate base. Figure II- shows recorded and forecast expenditures for the removal of idle facilities. a) Cost Forecast Expenditures in this activity increased from 00 to 00 due to a distribution transformer bank replacement program that was undertaken in 00. Expenditures remained at a high level through 0 as the transformer bank replacement program continued. Under this program a transformer bank that was no longer serving customer load could be removed as an idle facility, instead of being replaced, if there was no foreseeable use for those facilities in the near future. With the completion of this program, idle facility removal expenditures reduced to more normal levels in 0 and remained steady in 01. Going forward the level of activity in this account is expected to continue to remain steady as SCE does not anticipate any new programs, such as the distribution transformer bank replacement program, that would impact this account. As a result, SCE expects the volume of work in this activity to remain at 0-01 levels, and therefore SCE utilized recorded 01 expenditures as the basis for its forecasts.

37 Figure II- Removal of Idle Facilities WBS Element CET-PD-CR-IF Recorded 00-01/Forecast (0% CPUC-Jurisdictional Capital Expenditures $000) $1,000 $,000 $,000 $,000 $,000 $,000 $ Nominal $,,1,1,1,1,0,,,1,1 Constant 01 $,,0,,1,1,1,1,1,1,1 Nominal $ Constant 01 $ 1 E. Underground Structure Rehabilitation Program Utilities construct underground concrete vaults to house energized equipment including switches, transformers, and cable splices which may run under streets and other surface structures. Like vaults, manholes are underground concrete structures, but they are smaller and typically contain no equipment, only spliced cable. As these underground vault and manhole structures (hereafter structures ) deteriorate they need to be repaired or replaced. G.O. 1 requires periodic inspections of underground equipment. Additionally, SCE has underground structures with no equipment that were not included in SCE s historical G.O. 1 distribution inspection and maintenance program. In 0, SCE began inspecting underground structures without equipment. By the end of 01, SCE had inspected nearly 1,000 additional vaults and manholes. Going forward, all underground structures are included in

38 SCE s routine inspection programs, irrespective of whether they contain equipment or not. This has also led to an increase in the number of underground structures identified for repair and replacement, the costs of which are included in this section. This program focuses on the detailed field assessment, and the resulting repair or replacement of underground structures. During underground detailed inspections, SCE inspectors determine whether deterioration of the underground structure warrants a follow-up field investigation. This follow-up field investigation is performed by a structural engineer and the results are used to determine whether the underground structure needs to be repaired or replaced. The number of underground structures forecast to be repaired and replaced each year is determined by the number of structures to be inspected, the expected percentage of inspected structures found to be deteriorated, and the expected percentage of deteriorated structures determined to require replacement as a result of the follow-up field investigations. Table II-1 summarizes the assumptions used to forecast vault repairs and replacements. Historically,. percent of vaults inspected have been found to be deteriorated. SCE expects this rate to decline to four percent as vaults are re-inspected after the current three-year inspection cycle. Of the vaults identified as deteriorated, percent undergo field investigations in the same year as the initial inspection, while the remainder is scheduled for field investigations in the following year. Historically, percent of field investigations in any given year result in vault replacements, and 1 percent result in vault repairs. Additionally, percent of the vaults identified for replacement will require shoring to stabilize the structure until it can be replaced. See Section II.A. for a discussion of costs related to SCE s underground detailed inspection program. See Workpaper entitled Underground Structure Rehabilitation Program Historical Analysis.

39 Table II-1 Vault Inspection, Repair and Replacement Forecast Summary Vault UDI,,0,,1, % failing.%.%.%.00%.00% Total failing 0 Field Investigations (FI) Vaults failing UDI 0 % undergoing same-year FI % % % % % FI from current year FI from previous year 1 Total FI completed New Vault Replacements Identified Vaults undergoing FI % to be replaced % % % % % Total to be replaced 0 1 Vault Replacements with Shoring Vaults requiring replacement 0 1 % to be shored % % % % % Total to be shored 0 1 Repairs Identified Vaults undergoing FI % to be repaird 1% 1% 1% 1% 1% Total to be repaired Table II-1 summarizes the assumptions used to forecast manholes repairs and replacements. Historically,. percent of manholes inspected have been found to be deteriorated. As with vaults, SCE expects this rate to decline after the current three-year inspection cycle. Of the manholes identified as deteriorated, 0 percent undergo field investigations in the same year as the initial inspection, while the remainder is scheduled for field investigations in the following year. For manholes, percent of field investigations in a given year result in a replacement and percent result in a repair.

40 Table II-1 Manhole Inspection, Repair and Replacement Forecast Summary Manhole UDI,01,1 0 1, % failing.0%.0%.0%.00%.00% Total failing 0 Field Investigations Manholes failing UDI 0 % undergoing same-year FI 0% 0% 0% 0% 0% FI from current year 1 1 FI from previous year 1 Total 1 1 New Replacements Identified Field Investigations completed 1 1 % needing replacement % % % % % Total needing replacement 1 Repairs Identified Field Investigations completed 1 1 % needing repair % % % % % Total to be repaired The field investigations, repair, and replacement forecasts shown in Table II-1 and Table II-1 form the basis for the O&M and capital forecasts related to the underground structure remediation program. Section II.E.1 describes the expenses associated with follow-up field investigations; Section II.E. describes the expenses associated with underground structure repairs. Section II.E. shows the capital expenditures associated with underground structure replacements. 1. Cost Forecast - Underground Structure Field Investigation Expenses, Portion of FERC Account. Follow-up field investigation expenses include the non-labor costs of an SCE-approved contractor who performs the investigation and the labor costs of SCE employees who provide access to the structure (Table II-1). The labor costs are for SCE crews who perform the traffic control, test, and monitor air quality levels within the structures, help ensure the safety of anyone entering the underground structures and working in proximity to energized high voltage equipment, and secure the 0

41 structures upon departure. In late 01, contract negotiations resulted in lower rates for field investigations by contractors, which slightly reduced the cost per investigation from 0 to 01. The cost per field investigation in 01 reflects a full year of this reduced cost. 1 The forecast count of field investigations is calculated based on the number of underground detail inspections performed multiplied by the historical rates of structures failing inspection (percentage found deteriorated), as shown in Table II-1 and Table II-1. Table II-1 Field Investigation Expenses, Portion of FERC Account. Recorded and Adjusted 00-01/Forecast (0% CPUC-Jurisdictional Constant 01 $000) Recorded Forecast Labor $0 $0 $0 $ $00 $ $ $1 Non-Labor $0 $0 $0 $ $ $1,0 $1 $ Total $0 $0 $0 $ $1,1 $1, $0 $ Investigations , Cost per Investigation $0 $1, $1, $1,1 $1,1 $1,1 Ratio of Labor to Total 1% 1% 1% 1% 1% Basis of Forecast: Forecast Investigations * Cost per Investigation Basis of Labor/Non-Labor Split: LYR. Cost Forecast - Underground Structure Repair Expenses, Portion of FERC Account. The underground structure repair expense forecast (Table II-1 and Table II-1) combine the costs of shorings and repairs resulting from field investigations as shown in Table II-1 and Table II- 1. The cost per repair is forecast to be $0,000 for vaults and $1,000 for manholes, while the cost per shoring is forecast to be $,000 for vaults and manholes. 1 Unit costs for repairs and shoring are based on 01 recorded costs. The 01 forecast expense is based on the average of forecast expense for Please refer to Workpaper entitled Underground Structure Field Investigation Cost Forecast. 1 Please refer to Workpaper entitled Underground Structure Repair Cost Forecast. 1

42 Table II-1 Underground Structure Repair Detailed Forecast (Constant 01 $000) Vaults Repairs Identified 0 1 due same year 1 prior year rollover 01 Repairs Completed 0 1 Cost per Repair ($000) $ 0 $ 0 $ 0 $ 0 $ 0 Subtotal ($000) $ 1, $ 1, $ 1,1 $ 1, $ 1, Shorings Identified 0 1 due same year 0 1 prior year rollover Shorings Completed Cost per Shoring ($000) $ $ $ $ $ Subtotal ($000) $ $ $ 0 $ 1 $ 0 Manholes Repairs Identified 1 1 due same year prior year rollover 1 Repairs Completed 1 1 Cost per Repair ($000) $ 1 $ 1 $ 1 $ 1 $ 1 Subtotal ($000) $,0 $,0 $ $,1 $, Shorings Identified due same year prior year rollover Shorings completed Cost per Shoring ($000) $ $ $ $ $ Subtotal ($000) $ $ - $ - $ - $ - Total $ 1,1 $, $ 1,0 $ 1, $ 1, average $ 1,

43 Table II-1 Underground Structure Repairs, Portion of FERC Account. Recorded and Adjusted 00-01/Forecast (0% CPUC-Jurisdictional Constant 01 $000) Recorded Forecast Labor $0 $0 $0 $ $ $1, $, $1, Non-Labor $0 $0 $0 $1 $, $1,0 $0, $1, Total $0 $0 $0 $0 $, $1,1 $, $1, Ratio of Labor to Total % % % % % Basis of Forecast: Forecast repairs * cost per repair + Forecast shoring * cost per shoring Basis of Labor/Non-Labor Split: LYR Cost Forecast - Underground Structure Replacements 1 Underground structure replacements are forecast based on the historical failure rates from field investigations, as shown in Table II-1 and Table II-1. Due to their size, complexity, and location, underground structure replacements can involve long lead times to complete the design and construction. Additionally, SCE must acquire permits and coordinate with local authorities to mitigate impacts on residents; thus, this planning process can greatly lengthen the time required to complete underground structure replacements. As of year-end 01, the underground structure replacement program has identified underground structures for replacement. Table II-1 shows the schedule for completing these currently identified underground structure replacements as well as those that are forecast to be identified during future field investigations. As of June 0, 01, SCE has completed structures designs and 1 structure replacements. Based on current forecasts, SCE would reach steady state replacement rates by 0 for vaults and 01 for manholes. Table II-1 and Figure II- show the expenditures associated with these replacements. 1 WBS CET-PD-IR-UG.

44 Table II-1 Underground Structure Replacement Forecast (Constant 01 $000) Structure Replacement Forecast Vault Replacements Queue - Year Start Added 0 1 Completed () (1) (1) (1) (1) Queue - Year End Cost per Vault $000 $00 $00 $00 $00 $00 Vault expenditure ($000) 1,000,00,00,00,0 Manhole Replacements Queue - Year Start Added 1 Completed () () (0) (0) (1) Queue - Year End 1 Cost per Manhole $000 $ $ $ $ $ Manhole expenditure ($000) 1,00 1,00,000,000,00 Total ($000),00,00,00,00 1,00 1 The unit costs for replacing a vault are estimated at $00 thousand, while the unit costs for replacing a manhole are estimated at $ thousand. These estimates are based on similar work performed in previous years.

45 Figure II- Underground Structure Replacement Capital Expenditures WBS Element CET-PD-IR-UG Recorded 00-01/Forecast (0% CPUC-Jurisdictional $000) 1 1 F. Overhead Conductor Program As previously discussed, SCE is continually refining its inspection and maintenance programs. One such example is SCE s new overhead conductor program, developed with SCE s engineering department, which will evaluate the entire overhead distribution system over the next seven years. This program will focus on identifying potential splice, connector, and wire failures under certain operational, environmental, and mechanical conditions to mitigate the risk of downed conductors. Beginning in the fourth quarter of 01, SCE will start documenting and analyzing information regarding splices, connectors, conductor type, and conductor size on SCE s distribution system. SCE will use this information to analyze, identify, and prioritize conditions for remediation as part of an effort to reduce potential incidents of downed wire on SCE s distribution system. The analysis will consider the number and type of splices on a particular span, wire size, distance of conductor from the substation, age of the circuit, and branch line fuse protection for the conductor, among many other items.

46 Through the overhead conductor program, SCE seeks to elevate public safety through proactively inspecting for drivers behind potential incidents involving downed wire. 1. Cost Forecast Using a seven-year assessment cycle, SCE will inspect overhead conductor spans associated with approximately 0,000 poles per year. 1 The expenses in this category are driven by the cost of inspections, planning and analysis, and crew charges for the completion of repairs. Based on previous assessments, it is estimated that approximately percent of conductor spans will include splices and 0 percent will contain connectors. Of the splices identified, it is estimated that percent will require a repair expense for remediation based on previous assessments. Likewise, for connectors, it is estimated that percent will require a repair expense for remediation. Table II-1 summarizes the assumptions used to forecast splice and connector remediation activities. Table II-1 Overhead Conductor Program Unit Forecast Inspections 1,00 0,000 0,000 0,000 0,000 Splices Splices identified (% ),,0,0,0,0 Splices to remediate (% ) 1,0,,,, Connectors Connectors identified (0% ),00 1,00 1,00 1,00 1,00 Connectors to remediate (% ) 1,00,,,, N o te : only a po rtion of the re m e d ia tion a c tivitie s w ill b e c om ple te d in the ye a r ide ntifie d Table II-0 shows the forecast expenses for these remediation activities. 1 The forecasts include incremental cost associated with the inspection, assessment, and remediation of identified items. The program will begin inspections in 01, with remediation activities continuing to ramp up over time, and is forecast to reach a steady state of remediation activities by 01. The 01 forecast expense is based on the average of forecast expense for See SCE-0, Vol. 0, Pt.. This is based on the number of poles to be assessed for pole loading. Executing these programs together will improve efficiency. 1 See Workpaper entitled Overhead Conductor Program Cost Forecast.

47 Table II-0 Overhead Conductor Program, Portion of FERC Account. Recorded and Adjusted 00-01/Forecast (0% CPUC-Jurisdictional Constant 01 $000) Recorded Forecast Labor $0 $0 $0 $0 $0 $1 $1, $, Non-Labor $0 $0 $0 $0 $0 $ $ $1 Total $0 $0 $0 $0 $0 $1 $1,1 $,0 Ratio of Labor to Total % % % G. Pole Inspection and Replacement Inspection, repair, and replacement of SCE s over 1. million poles have many drivers. Most of these are to maintain pole strength, which might be compromised due to pole deterioration or pole loading. The programs to assess and remediate pole deterioration are included in this section. The Pole Loading Program is discussed in detail in Exhibit SCE-0, Volume, Part. SCE also performs pole replacement while constructing line extensions to provide service, after storms, when vehicles or other external factors damage poles, or when poles need to be relocated, to name a few. The costs associated with these activities are included in the relevant accounts for those activities, and are not included here. 1. Distribution Pole Inspections, Portion of FERC Account. SCE established the distribution pole inspection program to comply with G.O. 1, which became effective in 1. G.O. 1 requires intrusive inspections for all poles at least 1 years old to be completed within years of program inception. Thereafter, it requires all poles to be intrusively inspected by the time they are -years old and then re-inspected at least once every 0 years. SCE completed its first cycle of intrusive inspections in 00. G.O. 1 defines intrusive inspections as involving movement of soil, taking samples for analysis, and/or using more sophisticated diagnostic tools beyond visual inspections or instrument reading. Intrusive inspections involve drilling into the pole s interior in order to identify and measure the extent of internal decay, if any, which is typically undetectable with external observation alone. SCE s inspection standards describe six types of inspections satisfying this definition which

48 apply different combinations of digging, boring, and sounding depending on the type of pole and its setting. SCE inspectors may also perform a visual inspection on poles that are in the inspection grid but that are younger than 1 years old to look for signs of obvious external damage such as damage from vehicles or woodpeckers. Poles due for inspection under G.O. 1 guidelines in any given year are spread over SCE s 0,000 square-mile service territory, often requiring significant drive time between poles. Moreover, the number of inspections that are due any year can vary significantly from year-to-year, depending on the ages of the poles and when the last inspections were performed, which in turn can lead to significant variation in the number of pole replacements required from one year to the next. Both of these are inefficient for resource allocation. These inspections are somewhat technical in nature and having inspectors with proper training and experience is important. As a result, maintaining a stable inspection workforce is key to a successful intrusive inspection program. In 00, SCE began performing inspections on a grid basis to reduce travel time per inspection and to levelize the number of inspections (and therefore replacements) required per year. In addition to inspecting every pole due under the minimum G.O. 1 requirements, SCE began inspecting all poles within a defined region or grid during the same year. As a result, all poles receiving intrusive inspections within the grid will be due for their next inspection in the same future year. In 00, SCE also began transitioning to a ten-year inspection cycle that meets and exceeds G.O. 1 requirements and matches industry best practices. The other two California IOUs, SDG&E and PG&E, have also transitioned to -year pole inspection cycles. SCE performs both a visual and an intrusive inspection on every pole due for an intrusive inspection under G.O. 1. For poles that will not be due for an intrusive inspection until the next inspection cycle, SCE only performs a visual inspection. For example, a new pole might be installed within a grid three years after that grid underwent intrusive inspections; seven years later, all poles in that grid will be inspected again. To meet G.O. 1 requirements, this pole must be intrusively inspected at least once before the end of its th year. However, under the grid-based system it will be inspected twice, once at age and again at age 1. In this case, SCE performs a visual inspection in the pole s th year and an intrusive inspection in its 1th year, thus meeting G.O. 1 s requirement.

49 a) Cost Forecast Maintaining the grid-based inspection system and a ten-year inspection cycle requires that percent of the wood distribution pole population be inspected every year (approximately,000 poles). Transitioning to the grid-based system required more inspections per year for a short period in order to align the inspection cycles of poles in each grid. When this transition began in 00, SCE performed approximately 1,000 intrusive pole inspections. In 0, SCE inspected approximately,000 poles. In 0, SCE inspected,000 poles, lower than a long-term run rate as O&M was constrained and had to be diverted to other emergent issues. In 01, O&M was constrained due to uncertainty related to the delayed 01 GRC decision, and inspections fell to approximately,000 poles. In order to remain on the ten-year grid cycle, SCE plans to inspect approximately 1,000 poles in 01, 1,000 poles in 01, and 1,000 poles in 01. Pole inspections are performed by contract personnel, and therefore most of the costs recorded for this activity are non-labor expenses. SCE contracts provide different rates for inspections depending on type and sequence of inspections. Rates for intrusive inspections are higher than rates for visual inspections, and rates for non-grid inspections are higher than rates for grid-based inspections. The reduction in unit costs shown in Table II-1 reflects the transition to grid-based inspections, reductions in contract rates, and an increase in the ratio of visual to intrusive inspections. The forecast unit rate is based on the forecast mix of inspection types. 1 Total costs in this activity were forecast by multiplying the forecast unit rate by the forecast units. The labor to non-labor allocation is based on 01 recorded allocations. 1 Please see Workpaper entitled G.O. 1 Pole Inspection Cost Forecast.

50 Table II-1 Distribution Pole Inspections, Portion of FERC Account. Recorded and Adjusted 00-01/Forecast (0% CPUC-Jurisdictional Constant 01 $000) Recorded Forecast Labor $ $0 $ $ $0 $1,0 $ $ Non-Labor $,0 $, $,1 $,0 $, $, $, $, Total $,1 $,0 $, $,1 $,1 $, $, $,000 Inspections 1,,,,01,0 1, 1, 1, Cost per Inspection $ $1 $ $ $ $ $ $ Ratio of Labor to Total % % % % % % % % Basis of Forecast: Forecast Inspections * Cost per Inspection Basis of Labor/Non-Labor Split: LYR Costs associated with distribution poles are shown in Table II-1. Transmission wood pole intrusive inspections are performed on both a grid and circuit basis in accordance with SCE s maintenance practices on file with the California Independent System Operator. For Transmission wood pole inspection costs, please see Mr. Kedis s testimony in Exhibit SCE-0, Volume 0.. Deteriorated Pole Replacements Capital Expenditures This section includes the costs associated with distribution and transmission pole replacements that are based on inspection results from the program described previously. After inspection, the poles that are identified as needing replacement are prioritized based on the extent of deterioration. The priority ratings are 1. Priority 1 if the pole needs to be replaced within hours of inspection. Priority A, if the pole needs to be replaced within one year of inspection. Priority B, if it needs to be replaced within two years of inspection. Priority C, if it needs to be replaced within three years of inspection Poles are also identified for replacement by field crews and planners during Overhead Detailed Inspections or while performing other work, if they are found unsuitable for climbing or for supporting new equipment. 0

51 Table II- shows the results of intrusive inspections as requested by the Commission in D.1--01, Ordering Paragraph results reflect data collected as of May 01. These inspection findings are compiled and quality checked during the course of the year. Therefore, the priority categories of the inspections performed in 01 are not yet available. Table II- Pole Inspection Findings, Transmission and Distribution Distribution Results Transmission Results P1 P1 P - 1yr 1, P - 1yr 1 P - yr P - yr 1 P - yr 1, P - yr Pass 0, Pass, Total,0 0,1 1,,0 a) Cost Forecast In any given year, the number of poles that are replaced under this program are the sum of all the poles that have a replacement due date for that year. Figure II- and Figure II- show the forecasts for pole replacements by year for transmission and distribution poles. 1 These forecasts are derived from the number of inspections completed in previous years, number of inspections forecast in future years, and historical failure rate by priority. The 01 recorded cost per pole replacement was used to forecast unit costs. 0 1 In addition, we direct SCE to provide in the next GRC information about how many priority 1,, and conditions were identified by the actual number of intrusive inspections performed in 01 and 01 so that the Commission may evaluate the utility of an accelerated inspection program. D.1--01, pp See Workpaper entitled Capital Pole Replacement Forecast. 0 See Workpaper entitled Pole Replacement Unit Cost Forecast. 1

52 Figure II- Deteriorated Pole Replacement, Distribution Capital Expenditures Portion of WBS Element CET-PD-IR-DP Recorded 00-01/Forecast (0% CPUC-Jurisdictional $000)

53 Figure II- Deteriorated Pole Replacement, Transmission Capital Expenditures Portion of WBS Element CET-PD-IR-TR Recorded 00-01/Forecast (Total Company $000) 1. Aged Pole Replacement Capital Expenditures As shown in Figure II-, SCE must transition from an average of fewer than,000 poles replaced per year under the deteriorated pole program in 01 to,000 pole replacements per year in 01 resulting from both the deteriorated pole program and the Pole Loading Program. 1 This increase 1 See, SCE-0, Vol., Pt..

54 1 1 1 in workload has significant implications on operations across multiple disciplines planning, scheduling, contract strategy, construction, quality assurance, and work-order closing. In order to create a viable transition, SCE has undertaken a program to replace poles that have reached approximately 0 years of service. This program will develop the operational capability required to complete the replacement of,000 poles beginning in 01. By replacing the aged poles, SCE is able to more smoothly ramp up to the number of pole replacements and get operationally ready for the Pole Loading Program. To develop this program, SCE examined wood pole failures in SCE s distribution and transmission systems and correlated the likelihood of pole failure increases to pole age. Using a sample of distribution poles, SCE determined that mean time to replacement due to in-service failure or inspection failure for its wood poles to be years. After this age, pole failure rates increase dramatically. Poles reaching the age of 0 are projected to have an percent or greater chance of either failing in service or failing their next inspection by age 0. Currently SCE has over,000 poles aged 0 or older in its distribution system Figure II-. Please see Workpaper entitled Pole Failure Rates.

55 Figure II- Age of Distribution Wood Poles 1 Given the high risk of failure of these poles, SCE will begin proactively replacing poles aged approximately 0 and older in 01 until the total pole replacements from the deteriorated pole program and the Pole Loading Program reaches,000 poles per year, as shown in Figure II-.

56 Figure II- Programmatic Pole Replacements 1 1 a) Cost Forecasts As described above, the number of poles to be replaced under this program is based on the need for operational readiness for a longer term pole replacement program. As shown in Figure II-, SCE is ramping up pole replacements to 1,00 poles in 01,,0 poles in 01, and,000 poles in 01. The counts for aged pole replacements were derived as the difference between the total number of poles SCE needs to replace each year and the poles that are forecast to be replaced under Deteriorated Pole and Pole Loading Programs. The total number of poles expected to be replaced under the Aged Pole Replacement Program is, from The remaining aged poles will be assessed and replaced under the Pole Loading Program. SCE forecast the same unit cost per replacement for both the aged and deteriorated pole replacement programs (Figure II-). In both cases, 01 recorded cost per pole replacement were used to forecast unit costs. See Workpaper entitled Pole Replacement Unit Cost Forecast.

57 Figure II- Aged Pole Replacement Capital Expenditures Portion of WBS CET-PD-IR-DP Recorded 00-01/Forecast (0% CPUC-Jurisdictional $000) 1 H. Joint Pole Activities 1. Joint Pole Organization (JPO) Expenses, Portion of FERC Account. JPO is responsible for the execution and administration of all joint pole agreements where SCE shares the ownership of electric poles with other utilities. JPO is also responsible for the execution and administration of agreements to lease pole space to other utilities. Both joint ownership and lease arrangements fulfill SCE s requirement to provide non-discriminatory access under D.-.0. JPO generates invoices and receives payments from joint pole users for all capital investments and maintenance-related expenses. JPO receives invoices from other joint pole owners, validates the amounts and makes payment. JPO works with all parties on the Southern California Joint Pole Committee to establish policies and resolve issues that affect all committee members. JPO also

58 establishes, monitors, and updates joint pole policies and procedures related to joint pole use and billings. JPO performs audits on poles to identify safety deficiencies and unauthorized attachments. Table II- Joint Pole Organization Expenses (Portion of FERC Account.) Recorded and Adjusted 00-01/Forecast (0% CPUC-Jurisdictional Constant 01 $000) Recorded Forecast Labor $, $,1 $, $, $, $,01 $,01 $,01 Non-Labor $ $0 $0 $1 $1 $ $ $ Total $,01 $, $, $, $,0 $,0 $,0 $,0 Ratio of Labor to Total % % % % % 0% 0% 0% Basis of Forecast: 01 Recorded with additional headcount Basis of Labor/Non-Labor Split: Forecast based a) Cost Forecast As shown in Table II-, the expenses in this account have remained stable since 00. Two administrative aides who are currently working as contract employees will be hired as SCE employees in 01. Hence, SCE proposes to use the 01 recorded expenses to develop the forecast for 01. The costs for the two administrative aides will move from non-labor to labor expenses.. Joint Pole Expense Credits, Portion of FERC Account. For poles jointly owned with other utilities (e.g., a telephone or wireless company), SCE recovers some of the costs from these utilities for activities such as pole inspections or replacements. SCE tracks and records the net annual debits and credits between SCE and other participants in accordance with joint pole agreements. Joint Pole Expense Credits are driven by three operational activities: pole inspections, pole maintenance, and penalties. When SCE performs an inspection or performs O&M maintenance activities on a pole that is jointly owned, the expense incurred is shared with the other joint owner(s). In addition, when SCE-owned poles are used by other parties without permission, penalties are levied against them. These penalties are recorded as credits in this FERC Account. See Workpaper entitled. Joint Pole Support Workpaper.

59 Table II- Joint Pole Credit Expenses Portion of FERC Account. Recorded and Adjusted 00-01/Forecast (0% CPUC-Jurisdictional Constant 01 $000) Recorded Forecast Labor $ - $ - $ - $ - $ - $ - $ - $ - Non-Labor $ (0) $ (1) $ (1,01) $ (1,1) $ (,0) $ (,) $ (1,) $ (,0) Total $ (0) $ (1) $ (1,01) $ (1,1) $ (,0) $ (,) $ (1,) $ (,0) Ratio of Labor to Total 0% 0% 0% 0% 0% 0% 0% 0% Basis of Forecast: LYR credits per unit work * units of work Basis of Labor/Non-Labor Split: LYR 1 1 a) Cost Forecast Table II- shows the recorded and forecast credits from intrusive inspections, pole maintenance, and penalties. The intrusive inspection credits were forecast using the distribution pole inspection counts discussed previously and the forecast credit per pole inspection. The recorded credit per pole inspection fluctuates based on the type of pole, type of inspection, and the number of joint owners the cost can be shared with. Therefore SCE has used a five-year average unit cost to forecast the credit per pole inspection in the future. Pole maintenance credits are also driven by the number of poles maintained, type of pole, and number of joint owners on each pole. These credits have increased from 00-01, and in accordance with D. -1-0, SCE has used 01 recorded credits as the basis for the forecast. Penalty credits depend on how many unauthorized attachments SCE finds and shows an upward trend from 00 to 01. Therefore, SCE has used 01 recorded penalty credits as the basis for the forecast. Table II- summarizes the joint pole expense credits.

60 Table II- Joint Pole Credits Forecast by Activity Types a Inspection Credits (01 $) (,) (,) (,) (,) (1,,) (1,,0) (,0) (1,1,) (1,1,) (1,0,001) Pole Inspections 1,,,,01,0 1, 1, 1,, 1, Credit per pole inspection (01 $) () () () () (1) () () () () () Forecast unit cost based on average b Pole Maintenance Credits (01 $) (,) (0,) (0,1) (,0) (,) (,) (,) (,) (,) (,) Forecat based on 01 recorded c Penalty Credits (01 $) (,) (,01) (,) (,) (,0) (,0) (,0) (,0) (,0) (,0) Forecat based on 01 recorded a+b+c Total Joint Pole Expense Credits (01 $) (0,0) (0,) (1,01,) (1,,1) (,01,) (,,1) (1,,01) (,0,1) (,0,) (,,) Average (,0,1) Joint Pole Replacement Capital Credits As discussed in the previous section, for certain activities, such as when SCE replaces a distribution or transmission pole, it recovers some of the costs from joint owners. The capital credits included in this section reflects the net payments SCE receives from joint owners for pole replacement. SCE tracks and records the net annual debits and credits between SCE and other participants in accordance with joint pole agreements. a) Cost Forecast The forecast joint pole credit per pole replaced was estimated based on historical pole replacements under deteriorated pole program and other programs and the total credits received from 00 through 01. Table II- and Figure II- show the recorded count of poles replaced under these programs and the credits recorded as a result of those pole replacements. Other programs that result in pole replacements include line extensions to provide service, storms, when vehicles or other external factors damage poles, or when poles need to be relocated. The average credit per pole from 00 through 01 was $ in constant 01 dollars. SCE used $00 as the forecast credit per pole replaced. Note the joint pole credits resulting from the Pole Loading Program are not forecast here. Those credits can be found in SCE-0, Vol. 0, Pt.. See Workpaper entitled Capital Pole Replacements in Other Programs (for forecast of poles replaced in other programs). 0

61 Table II- Joint Pole Credit Unit Credit Analysis Total Credits (01 $000) (,) (1,1) (,) (,01) (1,) (1,00) (,00) (1,00) (1,00) (1,00) Deteriorated Poles,,1,1,,,00,00,,000,000 Aged Poles ,000 1,00 1, - - Other Programs,,1,1,,,000,000,000,000,000 Total Replacements 1,0 1, 1, 1, 1,,00 0,0 1,000 1,000 1,000 Unit cost (01 $000) $ (0.1) $ (0.) $ (0.) $ (0.) $ (0.0) $ (0.00) $ (0.00) $ (0.00) $ (0.00) $ (0.00) Figure II- Joint Pole Credits, Distribution and Transmission Capital Expenditures WBS Elements CET-PD-CR-JD and CET-PD-CR-JT Recorded 00-01/Forecast (0% CPUC-Jurisdictional $000) 1 I. Wood Pole Disposal When wood poles are removed from service, they must be appropriately disposed of to mitigate adverse environmental impact. Disposal is complicated, as all poles have been treated with chemical 1