1. 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

2. Substation Reliability

3. 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

4. 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.

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

6. 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

7. 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

8. 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

9. 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

10. 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

11. 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

12. 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

13. 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

14. 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

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

16. 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

17. 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

18. 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

19. 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 &quot;health&quot; 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

20. Combined T&D Substation Financials

21. Performance Overview – Substations
Overall T&D substation spending (O&M and Capital) increased in 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.

22. 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

23. 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

24. T&D Substation Capital Additions per Asset [FERC]
Average total capital spending increased significantly over 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

25. 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

26. 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

27. 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

28. 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

29. 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 %

30. 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 %

31. 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

32. 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

33. 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.

34. 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 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 %

35. 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

36. Staffing, Outsourcing & Management Practices

37. 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.

38. 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

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

40. 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

41. 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

42. 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

43. 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

44. 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

45. 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

46. 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

47. 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

48. 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

49. 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

50. Demographics Impact on Reliability

51. 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

52. 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.

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

54. 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

55. 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

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

57. 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

58. 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

59. 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

60. Substation maintenance planning & Execution

61. 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

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

63. 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

64. Substation maintenance execution

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

66. 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

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

68. Substation maintenance operations

69. 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

70. 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

71. Substation Asset management

72. 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

73. 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

74. Substation Automation initiatives

75. 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 , SG105

76. Thank you for your Input and Participation!
Your Presenters
Ken Buckstaff
Debi Cook
Gene Dimitrov
Rob Earle
Dave Carter Dave Weiler
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.
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77. Appendix

78. 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

79. 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

80. 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

81. 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

82. 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

83. 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