T&D Substations August 22-25, 2017 Burlington, VT 2017 Transmission & Distribution Benchmarking Community Insights Conference T&D Substations August 22-25, 2017 Burlington, VT Reliability Financials Staffing Demographics Practices

Substation Reliability

Method used to measure/track substation reliability Most companies use substation contribution to SAIFI and SAIDI. Other measures include CAIDI, condition assessment and operational data (counts, interruptions/failures) Legends 20 22 23 24 26 29 30 31 35 36 37 38 42 43 44 45 46 48 49 50 51 53 54 56 59 % of respondents SAIDI or SAIFI Contribution ♦ 92% Transformer failure rate 24% Mean time between failure 4% ID Other Response 30 CAIDI Contribution, Bus Interruption Events, and Traditional Bus Lockouts 42 We track the number of Substation Equipment problems that result in an interruption to a Transmission Connection Point 45 Root Cause Database 29 Condition Based Maintenance 20 Equipment failure counts by equipment type, manfacturer and model using Tableau. 53 All causes except "Equipment" and "Foregin Interference" Subs Rel, pg 17 & 18, SR28

Substation Reliability Profile T&D substation reliability decreased substantially in 2016 over the prior year. Substation equipment was again a major contributor to both SAIFI & SAIDI Transmission transformer failures decreased significantly.

Substation Contribution to SAIFI & SAIDI - Trends Substation reliability declined in 2016 with both frequency and duration across the panel.

T&D Substation contribution to SAIFI: excludes major events T&D substations combined to contribute relatively few interruptions (average about 11 total per 100 customers). Mean 0.113 Q1 0.061 Q2 0.094 Q3 0.178 Dist Rel, pg 37, DR40

T&D Substation contribution to SAIDI: excludes major events T&D substations contributed an average of only about 9 minutes. Mean 8.75 Q1 3.33 Q2 6.77 Q3 11.23 SOURCE: Dist Rel, pg 25, DR30

Distribution Substation contribution to SAIFI: excludes major events Distribution substations contribute an average of about 10 interruptions per 100 customers to SAIFI. Mean 0.097 Q1 0.039 Q2 0.092 Q3 0.146 Dist Rel, pg 37, DR40

Distribution Substation contribution to SAIDI: excludes major events Distribution substations contribute a little less than 8 minutes to SAIDI, on average. Mean 7.63 Q1 2.29 Q2 5.36 Q3 10.45 SOURCE: Dist Rel, pg 25, DR30

Transmission Substation contribution to SAIFI: excludes major events Transmission subs contributed <3 interruptions per 100 customers. Mean 0.026 Q1 0.000 Q2 0.002 Q3 0.030 SOURCE: Dist Rel, pg 37, DR40

Transmission Substation contribution to SAIDI: Excludes major events Transmission stations typically add a total of less than 5 minutes to SAIDI. The average contribution is less than 2 minutes. Mean 1.65 Q1 0.00 Q2 0.03 Q3 1.20 SOURCE: Dist Rel, pg 25, DR30

SAFI Contribution – Allocation: excludes major events Failed equipment is the most significant SAIFI contributor and causes an average of 7 interruptions per 100 customers Sub Rel, pg 15, SR25

T&D Substation Contribution to SAIFI: by Failed Sub Equip & Failed Prot Sys Equip Failed AC equipment continues to contribute a lion’s share to SAIFI for many companies. Sub Rel, pg 5, SR25

sAIFI Contribution (From Failed AC Subs Equipment, Plus Failed Protection System Equipment): Excludes Major Events Failed substation equipment including protection components average 7 outages per 100 customers Mean 0.07 Q1 0.03 Q2 0.04 Q3 0.10 Sub Rel, pg 17, SR25 & DR40

SADI Contribution – Allocation: excludes major events Failed equipment predominates all causes and contributes about 4.5 minutes to SAIDI. Sub Rel, pg 14, SR20

T&D SAIDI Contribution: by Failed Sub Equip & Failed Prot Sys Equip SAIDI contribution by substation equipment ranges from 0% to almost 80%. AC equipment contributes more than 50%. Sub Rel, pg 9, SR20

saIDI Contribution (From Failed AC Subs Equipment, Plus Failed Protection System Equipment: Excludes Major Events) Substation equipment also adds a little less than 5 minutes to the average outage duration. Mean 4.46 Q1 1.42 Q2 2.92 Q3 6.13 Sub Rel, pg 16, SR20 & DR30

Actions to Reduce the Occurrence Failed Protection System Equipment Equipment maintenance programs (inspection/monitoring, testing, replacement) and root cause analyses of problems/misoperations are the most common approaches used to reduce outages. ID Response 30 Replacement of analog microwave protective communication channels (345kV and above line relaying) and audiotone protective communication channels (138kV line relaying) with fiber optic communications channels. 56 Routine preventive maintenance 28 Identifies and corrects Protection System Misoperations on Bulk Electric System (BES). In accordance with North American Electrical Reliability Corporation (NERC) standard PRC-004-5(i) this includes:? The investigation and identification of 43 Root cause analysis 45 Battery Monitoring/First Trip Analysis T-Breakers 38 Replacement of electromechanical relays as well as replacing faulty model microprocessor relays in the near future. 20 Proactive replacements based off of failure data. 31 Time base maintenance is performed every 5 years on protection relays. Company has adopted standardized relay testing routines to determine health of relays. Also, has adopted the demanding maintenance requirements that NERC mandates across all system rel 23 Inspections 24 Proactive relay upgrades; time-based relay testing Subs Rel., pg xx, SR40

Actions to Reduce the Occurrence of Failed AC Substation Equipment Companies use programmatic maintenance (inspections, repair and replacement) of specific equipment groups and root cause analysis and ID Response 30 Wildlife mitigation program, Wildlife Fence Program, Enhanced Assessments, Insulator Replacement Program, Circuit Breaker Replacement Program, Bus Lockout Program, Bus Hardening Program. 27 ?perform root cause investigations, wildlife protection, TRV capacitors, routine substation inspection rounds, use Equipment Health system (Cascade) to monitor reliability and calculate "health" scores / risk, refurbishment programs 56 Routine preventive maintenance 43 Root cause analysis 45 Improved Varmint Protection D-Breakers 38 Implementing new style breakers 20 Proactive replacements based off of failure data. 31 None 23 Inspections 24 Proactive equipment replacements; time based inspections Subs Rel., pg xx, SR40

Combined T&D Substation Financials

Performance Overview – Substations Overall T&D substation spending (O&M and Capital) increased in 2016 over 2015. Distribution sustainment spending (O&M and capital) was again higher compared to the prior year. Transmission was lower. Capital additions per asset were greater for transmission subs but was lower for distribution.

Substation Spending Profile 2016YE 2015YE   Mean Q1 Q2 Q3 Bars O&M T&D Substation O&M per Customer $14.51 $10.04 $14.47 $17.39 17 $14.22 $9.59 $14.40 $18.12 Distribution Substation O&M per Customer $7.45 $5.66 $7.44 $8.50 27 $8.49 $6.41 $7.74 $11.23 T&D Substation O&M per Installed MVA $629 $284 $392 $611 12 $617 $362 $445 $519 16 Transmission Substations O&M per Installed MVA $347 $197 $246 $434 $459 $220 $254 $423 Distribution Substations O&M per Installed MVA $702 $440 $535 $833 23 $939 $427 $628 $1,243 25 T&D Substation O&M per Total T&D Substation Assets 1.00% 0.71% 1.08% 1.28% 13 1.02% 0.80% 1.01% 1.23% 18 Transmission Substations O&M Expense per Trans Sub Asset 0.92% 0.66% 0.82% 1.05% 0.84% 0.60% 0.83% 0.93% 19 Distribution Substations O&M Expense per Dist Sub Asset 1.45% 1.12% 1.48% 1.74% 1.51% 1.27% 1.47% 1.79% 28 Capital T&D Substation Capital Additions per Asset [FERC] 7.59% 9.21% 7.84% 4.76% 6.61% 7.70% 5.92% 4.71% Distribution Substation Capital Additions per Asset [FERC] 4.65% 6.48% 3.54% 2.79% 24 5.06% 6.36% 4.07% 2.91% 29 Transmission Substation Capital Additions per Asset [FERC] 9.16% 12.27% 8.85% 6.16% 8.27% 20 T&D Substation Capital Spending less Serve New, Expand per Asset [Activity Based] 4.27% 5.25% 4.29% 2.62% 4.38% 5.12% 3.84% 3.31% Distribution Substation Capital Spending less Serve New, Expand per Asset [Activity Based] 4.19% 5.94% 3.12% 2.07% 3.58% 5.56% 2.75% 1.82% Transmission Substation Capital Spending less Serve New, Expand per Asset [Activity Based] 3.73% 4.40% 2.90% 2.26% 14 4.41% Sustainment Spending T&D Substation Sustaining O&M and Capital Spending per Asset [Activity Based] 4.60% 5.74% 4.06% 2.98% 4.51% 5.66% 4.66% 2.37% Distribution Substation Sustaining O&M and Capital Spending per Asset [Activity Based] 5.39% 7.44% 3.89% 3.23% 4.72% 6.67% 3.79% 2.78% Transmission Substation Sustaining O&M and Capital Spending per Asset [Activity Based] 4.02% 5.08% 3.28% 2.15% 15 4.39% 5.44% 2.58% 21

T&D Substation O&M and Capital Additions per Assets [FERC] Substation capex makes up the majority of spending on substations. Mean 9.02 % Q1 5.83 % Q2 9.30 % Q3 10.72 % T&D Subs Fin’l pg 3, DF10,DF30,DF70,TF65,TF10,TF30

T&D Substation Capital Additions per Asset [FERC] Average total capital spending increased significantly over 2015 continuing a generally upward trend since 2013. Mean 7.9 % Q1 9.5 % Q2 8.0 % Q3 4.7 % T&D Subs Fin’l pg 5, DF10,DF70,TF65,TF10

Distribution Substation Capital Spending ex Serve New, Expand per Asset [Activity-based] Not surprisingly, sustain and system improvement capital expenditures make up most of substation budgets for the companies. Mean 4.19 % Q1 5.94 % Q2 3.12 % Q3 2.07 % SOURCE: Dist Subs Fin’l pg 11, DF55,DF70

Transmission Substation Capital Spending ex Serve New, Expand per Asset [Activity-based] For transmission, system improvements consumed a majority of sustainment investment for most companies. Mean 3.73 % Q1 4.40 % Q2 2.90 % Q3 2.26 % SOURCE: Trans Subs Fin’l pg 11, TF50,TF65

Allocation of Capital Spending per Asset ~10% of spending is for new substations (12% & 8%) respectively. The spending is focused on updating existing infrastructure. Distribution Substation Capital per Asset Transmission Substation Capital per Asset

T&D Substation O&M Expense per Asset [FERC] T&D O&M average spend decreased slightly and continued a downward trend. Mean 1.071 % Q1 0.698 % Q2 1.100 % Q3 1.406 % SOURCE: T&D Subs Fin’l pg 7, DF30,DF70,TF65,TF30

Transmission Substation O&M Expense Asset [FERC] Transmission sub O&M increase slightly which lends to a relatively level trend over the last 4 yrs. Trans Subs Fin’l pg 5, TF65,TF30 Mean 0.9 % Q1 0.7 % Q2 0.8 % Q3 1.0 %

Distribution Substation O&M Expense per Asset [FERC] O&M spending is converging (closer to the mean) for distribution substations. Dist Subs Fin’l pg 5, DF30,DF70 Mean 1.5 % Q1 1.1 % Q2 Q3 1.7 %

Allocation of O&M Spending per Asset ~50% of spending is on I&M (65% & 41% respectively). Distribution Substation O&M per Asset Transmission Substation O&M per Asset

T&D Substation Sustaining O&M and Capital Spending per Asset [Activity Based] Total average investment on sustain spending was nearly level to the prior year. Capital continues to dominate spending to maintain the system. Mean 5.17 % Q1 5.86 % Q2 4.06 % Q3 2.78 % SOURCE: SF PG 31, DF55,TF50,DF65,TF60,DF70,TF65

T&D Sustain Capex and o&M vs Reliability Trend Spending and reliability, in the short term, do not appear to be impacting each other.

Transmission Substation Sustaining O&M and Capital Spending per Asset [Activity Based] Transmission sub total spending, however, decreased last year after a significant increase over 2014. As a result, the spending trend is relatively level. SOURCE: Trans Subs Fin’l pg 7, TF50,TF60,TF65 Mean 4.02 % Q1 5.08 % Q2 3.28 % Q3 2.15 %

Distribution Substation Sustaining O&M and Capital Spending per Asset [Activity Based] Again there is a slight increase in total distribution substation spending although the 3yr trend is relatively flat. Mean 5.39 % Q1 7.44 % Q2 3.89 % Q3 3.23 % SOURE: Dist Subs Fin’l pg 8, DF55,DF65,DF70

Staffing, Outsourcing & Management Practices

Substation Staffing per $100M Assets Outsource estimates narrow the band. Internal FTEs Only Mean 24.14 Q1 11.86 Q2 22.75 Q3 31.92 Source: SO20 Includes an estimate for Outsource FTEs Mean 25.23 Q1 13.19 Q2 22.75 Q3 34.38 Includes an estimate for outsource FTEs except for vegetation mgmt. Companies where we couldn’t reasonably estimate outsourcing FTEs were excluded.

Substation Internal and Outsourcing FTEs per $100M Assets Only a few utilities utilize outsourcing for substations. Field C&M – Internal & Outsource Mean 11.11 Q1 7.33 Q2 9.46 Q3 12.90 Engineering & Design – Internal and Outsource Mean 4.54 Q1 1.53 Q2 2.74 Q3 6.47 Source: SO120A

Average Staffing Allocation Only 13% of substation work is currently outsourced (which typically relates to capital budget and new construction). Outsource In-house

Wages rates & Headcounts Average wage rates increased last year. Headcounts have been increasing steadily. Average Wage Rates: Substation Electrician Substation FTEs per $100M Assets Staffing SO10.3, Pg 9 Staffing SO15, Pg 10

Wage Rate: Substation Journey Level Electrician Wage rates have very little variation. Source: SO pg 4, SO10 Mean $40.20 Q1 $38.00 Q2 $39.34 Q3 $42.47

Substation Outsourcing – Field Construction & Maintenance The utilization of outsourcing is varied. What drives the different approaches? Legends 20 23 31 33 42 45 53 56 59 Avg Field Construction (Dist Subs) Total 96   100 80 28 51% Field Construction (Trans Subs) Total 50 4 81 15 49% Field Maintenance (Trans Subs) Total 3 5 3% Field Maintenance (Dist Subs) Total 2% Civil construction (Trans Subs) 66 78% Electrical construction (Trans Subs) 90 40 70% Civil construction (Dist Subs) 71 8 54% Electrical construction (Dist Subs) 58 6 25 30% Transformer maintenance (Trans Subs) 86 16% Breaker maintenance (Trans Subs) 2 60.5 11% Transformer maintenance (Dist Subs) 1% Breaker maintenance (Dist Subs) Source : SO120A

Percent of Staff that is Retirement Eligible Reporting utilities are anticipating losses of 10 to 25% of staff in the near future. Substation Field Worker Mean 18.38 % Q1 23.00 % Q2 18.50 % Q3 15.50 % Substation Engineering & Design Source: SO pgs 108, 109, SO155

Substation Field Worker Substation Engineering & Design Average Age of FTEs The average age for reporting utilities is 45. Substation Field Worker Mean 44 Q1 46 Q2 Q3 42 Substation Engineering & Design Source: SO pgs 114, 115, SO160

Substation Field Worker Substation Engineering & Design Average Tenure Average tenure is at least 10 years… Substation Field Worker Mean 15 Q1 18 Q2 Q3 12 Substation Engineering & Design Source: SO pgs 120, 121, SO165

OT hours (ex major events): Substations The average employee is working a 64 week year. Mean 570 Q1 369 Q2 532 Q3 676 Substation Electrician Mean 394 Q1 78 Q2 334 Q3 496 Substation Meter Relay Tech Source: SO pg 57, 58, SO65

Performance reporting: Substation Contractor Crews In addition to the listed metrics, one company measures timeliness of invoicing throughout the project. Substations, pgs 16 & 17, SP55

Effective Substation Contractor Management Although all companies measure contractor performance, only a handful use those metrics to manage the contractor. Other reported management practices 36 System called Retro-Entrepreneur. We collect in-site spent hours per activity per location for each contractors 20 Master substation schedule to efficiently schedule and sequence contractor crews to projects 35 Substations management and engineering fulfill project management roles to manage projects. Substations, pgs 18 & 19, SP70

Measures of Productivity of Substation Maintenance Crews 2 companies use daily and monthly performance reports. ID Other Response 30 Schedule Adherance 55 Daily and Monthly reports 52 Key Performance reporting data. Daily/monthly system report analysis. Substations, pg 20 & 21, SP75

Demographics Impact on Reliability

Expected Service Life: Distribution Substation Equipment Components in Years Certain components have a large degree of variability in expected service life. Legends 20 22 26 29 30 31 35 36 37 38 42 43 44 45 46 48 49 50 51 52 53 54 55 56 Power Transformers 40 60 High Side Breakers or Switch Fuse Units or BusTies Low Side Breakers or Reclosers or BusTies Relays and Control Wiring 25 83 15 Switch Gear Control Panels DC Components 18 Metering Source : Substations, pg 22, SP80 Calculation : SP80.1 , SP80.2 , SP80.3 , SP80.4 , SP80.5 , SP80.6 , SP80.7

SAiFI vs Age All Equipment redundancy and automatic controls limit the impact of equipment failure. Also, we are only looking at a single year of SAIFI results.

Power Transformers Planned Cycle A number of companies are inspecting transformers annually. Mean 41 Q1 48 Q2 Q3 15 Subs Pg 54 SP185B

Switchgear Planned Cycle time There is a great deal of variability in the duration of switchgear inspections. Subs Pg 55 SP185B.2 Mean 62 Q1 72 Q2 60 Q3 30

Circuit Breakers Planned cycle time 4 companies are looking at switchgear at least every two years. Subs Pg 56 SP185B Mean 49 Q1 60 Q2 Q3 44

Relays Planned cycle time Relays inspections cycles have the most standardization. Subs Pg 57 SP185B Mean 56 Q1 60 Q2 Q3

Cause Codes Auditing All but 5 companies conduct an audit of cause codes. Legends 20 22 23 24 26 29 30 31 33 37 38 42 43 44 45 46 48 49 50 51 53 54 56 59 Yes ♦ No Sub Rel, pg 22, SR45

Actions To reduce Outage Caused By Failed Protection System Equipment Equipment replacement and routine maintenance are done by companies to mitigate protection component failures. Equipment replacement/upgrades 30 Replacement of analog microwave protective communication channels (345kV and above line relaying) and audiotone protective communication channels (138kV line relaying) with fiber optic communications channels. 38 Replacement of electromechanical relays as well as replacing faulty model microprocessor relays in the near future. 20 Proactive replacements based off of failure data. 24 Proactive relay upgrades; time-based relay testing Preventive maintenance (monitoring, inspections, testing) 56 Routine preventive maintenance 28 Oncor identifies and corrects Protection System Misoperations on Oncor’s Bulk Electric System (BES). In accordance with North American Electrical Reliability Corporation (NERC) standard PRC-004-5(i) this includes:? The investigation and identification of 43 Root cause analysis 45 Battery Monitoring/First Trip Analysis T-Breakers 31 Time base maintenance is performed every 5 years on protection relays. Company has adopted standardized relay testing routines to determine health of relays. Also, TEP has adopted the demanding maintenance requirements that NERC mandates across all system rel 23 Inspections Source: Sub Rel, pg 20, SR40

Actions To reduce Outage Caused By: Failed AC Substation Equipment Wildlife mitigation programs are used to reduce substation equipment failures and are routine maintenance and equipment replacement. Wildlife Mitigation 30 Wildlife mitigation program, Wildlife Fence Program, Enhanced Assessments, Insulator Replacement Program, Circuit Breaker Replacement Program, Bus Lockout Program, Bus Hardening Program. 27 Perform root cause investigations, wildlife protection, TRV capacitors, routine substation inspection rounds, use Equipment Health system (Cascade) to monitor reliability and calculate health scores / risk, refurbishment programs 45 Improved Varmint Protection D-Breakers Preventive Maintenance 56 Routine preventive maintenance 43, 27 Root cause analysis 23, 24, 27 Inspections Equipment Replacement/ Hardening 20 Proactive replacements based off of failure data. Replacement programs 24 Proactive equipment replacements; time based inspections None 31 Source: Sub Rel, pg 21, SR40

Substation maintenance planning & Execution

Approach Used for Planned Inspection and Maintenance Programs A time-based maintenance approach is used most commonly as the basis for equipment maintenance except for switchgear. # Companies Reliability-Centered (1) Time-based (2) Condition-based (3) Operations Count (4) Other (5) Power Transformers 17 3 5 Switchgear 1 8 12 Circuit Breakers Relays 24 Other approaches reported are primarily combinations. ID Response 27, 35, 45 Combination of time and condition based programs 56 Switchgear has no apporach due to the way the equipment is utilized in our system. Circuit breaker maintenance has both a time-based and an operations count-based approach. 55 Combination of reliability-centered, time-based and condition-based Substations, pg 35, SP185A

Unplanned maintenance work As much as 20% of maintenance work is unplanned. Power Transformers Relays Switchgear Circuit Breakers

Number Maintenance Activities Completed As a whole, unplanned activity represented 15% of total maintenance. Equip Activity 22 23 24 26 30 31 36 37 38 42 43 44 45 46 48 49 50 51 52 54 55 56 Avg Power Trans Planned 375 3,281 2 1,775 6,909 233 2,891 995 40 545 948 1,271 201 540 670 498 1,100 392 1,099 398 836 1,139   Unplanned 90 265 5 250 164 436 225 10 336 949 129 4 20 144 110 165 359 650 186 1,380 292 Swchgr 12 166 1,934 1,333 11 25 357 1 3 614 117 15 7 6 66 Circuit Brkrs 440 12,878 1,055 3,562 103 3,051 1,401 150 1,014 1,127 1,540 200 216 590 575 701 800 206 950 162 1,024 1,512 60 1,400 35 300 33 518 340 976 370 80 28 100 215 160 380 109 608 Relays 799 4,300 75 3,800 3,696 998 1,117 24,000 845 787 1,801 411 1,378 1,800 1,098 1,000 549 2,600 519 275 2,592 192 4,047 276 327 105 151 156 83 296 903 374 Substations, pg 48 & 49, SP190

Substation maintenance execution

How Maintenance plans are organized Companies focus on specific components across all substations or they use a bundled approach Substations, pg 23, SP85

Tool Used for Scheduling Substation Work Cascade and SAP are the most common. ID Other Response 30 The primary scheduling tool used for T&S Work is Projectview 27 Artemis ProjectView 29 CMMS 20 We use Cascade to dump into a configurable spreadsheet for scheduling Substations, pgs 30 & 31, SP156

Scheduling Organization for substation work A form of centralized scheduling is in place at all but one company. Substations, pg 32 & 33, SP160

Substation maintenance operations

Mobile Stations Utilized (Currently In Service) per 1000 Substations A four-fold difference between companies in the active use of mobile stations. Mean 11 Q1 3 Q2 7 Q3 14 Substations, pg 25, ST85,ST90,SP95

Method to Maintain Electric Service: Refurbishing Single Transformer Substations Companies use all of the listed operating techniques to maintain service continuity with load transfer to an another substation being used by all. Substations, pg 52, SP215

Substation Asset management

PERCENT OF SUBSTATION COMPONENTS REPLACED OR PLANNED TO BE REPLACED Battery, meter and circuit breaker replacements have been emphasized over the past 5 years. The community is projecting increased replacement rates for all substation components except for meters and circuit breakers over the next five years % Replaced Past 5 Years % Replaced Next 5 Years Source: AM Pg 17, AM50 Source: AM Pg 19, AM55

Substation components - Calculated average replacement cycles for community Total (last 5 plus next 5) replacement percentages translate to replacement cycles exceeding 50 years for most components. Calculated replacement cycle for bus and secondary communications exceeds 100 years. Calculated Average Replacement Cycle (Years) Like the chart requested on page 10. Just want one chart showing the community averages for each component Source: AM50, AM55

Substation Automation initiatives

Current status of substation automation technology Average Status Score Microprocessor controlled relays, LTC position indicators and digital fault recording systems are the most widely implemented substation automation technologies Legend 24 29 30 31 36 38 42 45 53 56 59 Avg. RTU replacement 2 4 3 1 3.0 On-Line Monitoring 2.7 LTC Position Indicators 3.1 IDigital Fault Recording Systems Microprocessor Protective Control Relaying Systems 3.3 Equipment/Facility Monitoring Systems 2.5 Other 4 = installed on a wide-scale basis Source: SG Pg. 34-40, SG105

Thank you for your Input and Participation! Your Presenters Ken Buckstaff Ken.Buckstaff@1QConsulting.com 310-922-0783 Debi Cook Debi.Cook@1QConsulting.com 760-272-7277 Gene Dimitrov Gene.Dimitrov@1QConsulting.com 301-535-0590 Rob Earle Rob.Earle@1QConsulting.com 315-944-7610 Dave Carter Dave Weiler Dave.Carter@1QConsulting.com Dave.Weiler@1QConsulting.com 414-881-8641 607-761-6778 About 1QC First Quartile Consulting is a utility-focused consultancy providing a full range of consulting services including continuous process improvement, change management, benchmarking and more. You can count on a proven process that assesses and optimizes your resources, processes, leadership management and technology to align your business needs with your customer’s needs. Visit us at www.1stquartileconsulting.com

Appendix

Distribution Substation O&M Expense per Customer [Activity-based] I&M makes up the largest percentage of I&M for distribution stations for most companies. A few companies report a higher percentage for operations. Dist Subs Fin’l pg 26, DF65,ST5 Mean $7.44 Q1 $5.57 Q2 $7.35 Q3 $8.44

T&D Substation Maintenance per Substation [Activity-Based] Companies spent an average of about $44k per station which was split fairly evenly between T and D subs. Mean $43,944 Q1 $18,493 Q2 $48,661 Q3 $60,847 SOURCE: T&D Subs Fin’l pg 27, DF65,TF60,ST85,ST90

T&D Substations Equipment I&M and Repair/Replace Capital Spending Per Asset Sustainment investments are, as is typical, dominated by capital expenditures for most companies. Higher spending companies are using predominantly capital to maintenance their subs. Mean 2.19 % Q1 1.25 % Q2 1.73 % Q3 2.80 % SOURCE: T&D Subs Fin’l pg 28, DF55,TF50,DF65,TF60,DF70,TF65

T&D Substations Equipment I&M Spending Per Asset There is a wide range in spending for inspection and maintenance expenses with about a threefold difference across the panel of companies. Mean 0.59 % Q1 0.33 % Q2 0.43 % Q3 0.90 % SOURCE: T&D Subs Fin’l pg 29, DF65,TF60,DF70,TF65

Location of Mobile Stations when Not in Use Inactive mobiles are stored about equally between a central or regional facility. Substations, pg 27 & 28, SP105 ID Other Response 29 Various Locations 20 Strategically located at secure locations to manage regional usage and response

Role of spares/mobiles in overall strategy Mobiles are used temporarily for two reasons: emergencies and maintenance/capital work. ID Response 27 We have a 230 to 34 & 230 to 13 mobiles used in emergencies. We have 34 to 4 mobiles used to facilitate maintenance activities. 56 Our plan and use of mobile substations are for critical power restoration efforts where stationary substation resources are inadequate or non-existent. They are also used for temporary load services during the commissioning of new substation sites. 42 Mobile transformers are utilized for customers and stations without spare tranformers. 43 Used in emergency situations and/or equipment 45 Emergency backup for failed transformers 38 Replacement of lost load 20 Mobiles are primarily used for maintenance and construction activities. At times they are used as a spare as an option of last resort 35 The operational strategy related to a mobile substation is to have a mobile substation available for emergency standby power for locations that do not have redundant contingency transformation capacity at the substation. New substation design criteria require redundant transformation capacity. 55, 52 Mobiles are used in construction projects and emergency restoration. Mobiles are used to supply load while permanent equipment is out of service. 31 We have 2 mobile transformers that can back up most of our distribution subs having 138kV or 46kV high side voltages and 13.8 kV or 13.2kV or 4kV lowside capabilities. We use the mobiles for outage restoration, serve load for planned maintenance and const 24 Mobiles act as a temporary measure to serve load for a transformer failure or to serve critical customers while isolating peripheral load while permanent improvements are made 51 Used for mtce, captial work support and resulancy/emergency restorations. Source: Substations, pg 29, SP130 Calculation: SP130.1