Transcript Slide 1

2014 Transmission & Distribution Benchmarking
Insights Conference
Substation
August 20-22, 2014
Vail, CO
1.Primary power lines
2.Ground wire
3.Overhead lines
4.PotentialTransformer
5.Disconnect switch
6.Circuit breaker
7.Current transformer
8.Lightning arrester
9.Main transformer
10.Control building
11.Security fence
12.Secondary power lines
1
10.Control building
11.Security fence
12.Secondary power lines
Agenda
◼ Key issues
◼ Statistics and System Activity
◼ Financial
◼ Practices and Initiatives
2
Key Benchmarking issues in substations
Industry Issues
◼
◼
◼
◼
Methodology
Regulation
◼
 NERC reporting (TADS)
 NERC compliance FERC
Technology
◼
 Substation Automation
 Age and obsolescence of components
 Problematic equipment
 Smart Grid requirements
◼
Planning to Build Process
 Planning Process
 Estimating tools
 Lead times for major equipment
 Lead times for environmental/permitting issues
 Competing goals of T&D organizations
◼
 Planning/Engineering/Design coordination
Workforce issues
 Contract Management
 Aging workforce
◼
 Availability and quality of internal and contract
resources
 Degree of specialization
2014
• Physical Security
• Storm Threat
• Spending Up
◼
T&D Costs are separated by FERC, but the
"substation" account is not. Costs need to be
allocated
FERC allows some latitude in the distinction
between distribution and transmission substations.
For substations that have T&D facilities, the cost
split is not always consistent
In most organizations T&D Substations are typically
managed in the same department, usually
transmission. But there are T-only or D-only
companies that are interested in separating T-subs
vs. D-subs.
Different voltage levels, purposes, levels of
transformation, rollover schemes, loadings and
designs make benchmarking comparisons
problematic
There is no consensus on normalizing variables:
customers, installed MVA, average of peak load,
assets, and book values.
There is a lag in when capital additions are reported
which is reflected in changes in CWIP accounts,
3
2014 T&D: Capital Projects
CAPITAL SPENDING FORECAST: T&D SUBSTATIONS [ACTIVITYBASED]
Mean Quartile
Mean
0.91
Quartile 1
0.46
Quartile 2:
0.85
Quartile 3:
1.01
Comment
s
Calculation used
( ( CP125.1B + CP125.2B + CP125.3B ) / 3 ) / ( (TF50_ABC
Trans
Subs Cap v14) + (DF55_Dist Subs Cap ABC v.14) )
Page4
Transmission Substation Trends
We see an increase in spending for 2013 . . .
5
Statistics and System Activity
6
Distribution Substations Demographic Profile
Min
Mean
Max
# of Bars
$33.24
8.46
$38.21
16.10
$41.97
32.94
12
11
0.64
2.16
3.86
7
5kV class = >1kV, <=9kV
0.0%
23.4%
76.2%
14
15kV class = >9kV, <=15kV
16.9%
64.1%
99.1%
14
25kV class = >15kV to <=26kV
0.0%
6.5%
60.4%
14
35kV class = >26kV to <=36kV
0.0%
5.5%
27.3%
14
44kV class = >36kV to <=44kV
0.0%
0.5%
6.5%
14
10.06
28%
0%
18.02
52%
11%
63.24
91%
62%
11
10
11
$7,902
$34,744
$60,146
11
Organizational Demographics
Wage Rate: Substation Journey Level Electrician
Substation Staffing: FTEs per $100M Substation Assets
Demographics: Distribution
Distribution Substations per 100 Distribution structure mile
Distribution Substations Transformer Banks by Voltage Level
Installed MVA Capacity per 1000 Customers: Distribution
Average Substation Transformer Loading: Distribution
Percent of Switches outside the substation remotely operated
Financial - Demographics
Distribution Substation Assets per MVA
Transmission Substations Demographic Profile
Min
Mean
Max
# of Bars
0.50
2.74
12.36
10
<69kV class [Subs]
0.0%
0.1%
1.6%
13
69kV class [Subs]
0.0%
30.5%
78.2%
13
100kV class [Subs]
9.2%
48.0%
100.0%
13
200kV Class [Subs]
0.0%
7.9%
27.0%
13
300kV Class [Subs]
0.0%
2.3%
29.4%
13
400kV Class [Subs]
0.0%
11.2%
63.9%
13
Installed MVA Capacity per 1000 Customers: Transmission
7.93
17.66
31.68
10
Average Substation Transformer Loading: Transmission
29%
59%
78%
8
$17,027
$48,193
$131,477
11
Demographics: Transmission
Transmission Substations per 100 Transmission structure
miles
Transmission Substation Transformer Banks by Voltage
Financial - Demographics
Transmission Substation Assets per MVA
Substation Definitions
FERC provides definitions on what constitutes a Transmission vs. Distribution substation
based upon use.
◼ For multipurpose substations, FERC allows either segregating costs, or assigning
based upon predominant use.
For purposes of this survey, we generally will recommend a low side definition based upon
a 45kV or below as a distribution substation.
◼ We understand that a typical Canadian practice would be to define a substation based
upon high side voltage (e.g. 115kv to 12kv stations are defined as transmission).
Based upon predominant use, these still can be classified as transmission substations.
◼ It is unrealistic to ask utilities to redefine their cost or reliability reporting on the basis of
these definitions. We will rely on each utility’s self-assigned definitions. However, a
utility that has very different definitions may want to restate these statistics to better
compare their performance.
Transmission Voltage Classes:
<69kV
69kV class (>=69kV <100kV)
100kV class (>=100kV <200kV)
200kV Class (>=200kV <300kV)
300kV Class (>=300kV <400kV)
400kV and above
Distribution Voltage Classes:
5kV (>1kV, <=9kV)
15kV (>9kV, <=15kV)
25kV (>15kV, <=26kV)
35kV (>26kV, <=36kV)
44kV )>36kV, <=48kV)
Note: We will have transmission-only and distribution-only entities participating in this survey.
Undoubtedly their voltage levels will not necessarily line-up with the above definitions.
9
2014 T&D: Statistics
DISTRIBUTION SUBSTATION TRANSFORMER BANKS BY VOLTAGE
LEVEL
Comment
s
Calculation used
ST80.2 / (Dist Transformer Banks) * 100 , ST80.1 / (Dist
Transformer Banks) * 100 , ST80.3 / (Dist Transformer
Banks) * 100 , ST80.4 / (Dist Transformer Banks) * 100 ,
ST80.5 / (Dist Transformer Banks) * 100
Page10
2014 T&D: Statistics
TRANSMISSION SUBSTATION TRANSFORMER BANKS BY
VOLTAGE
Comment
s
Calculation used
ST85.3 / (Trans Transformer Banks) * 100 ,
Transformer Banks) * 100 , ST85.4 / (Trans
Banks) * 100 , ST85.5 / (Trans Transformer
ST85.6 / (Trans Transformer Banks) * 100 ,
Transformer Banks) * 100
Page11
ST85.2 / (Trans
Transformer
Banks) * 100 ,
ST85.1 / (Trans
2014 T&D: Statistics
INSTALLED MVA CAPACITY: DISTRIBUTION
Mean Quartile
Mean
18.02
Quartile 1
12.70
Quartile 2:
13.58
Quartile 3:
14.77
Comment
s
Calculation used
ST100.1 / ( (ST5_T&D Dist End Use Customers) / 1000
)
Page12
2014 T&D: Statistics
INSTALLED MVA CAPACITY: TRANSMISSION
Mean Quartile
Mean
17.66
Quartile 1
11.75
Quartile 2:
16.85
Quartile 3:
22.18
Comment
s
Calculation used
ST105.1 / ( (ST5_T&D Dist End Use Customers) / 1000
)
Page13
2014 T&D: Statistics
AVERAGE SUBSTATION TRANSFORMER LOADING AT PEAK:
DISTRIBUTION
Mean Quartile
Mean
52 %
Quartile 1
49 %
Quartile 2:
51 %
Quartile 3:
56 %
Comment
s
Calculation
used
ST100.5
Page14
2014 T&D: Statistics
AVERAGE SUBSTATION TRANSFORMER LOADING AT PEAK:
TRANSMISSION
Mean Quartile
Mean
59 %
Quartile 1
46 %
Quartile 2:
62 %
Quartile 3:
74 %
Comment
s
Calculation
used
ST105.5
Page15
2014 T&D: Statistics
ANALYSIS: T&D PLANT IN SERVICE PER DISTRIBUTION ENDUSE CUSTOMER [FERC]
Mean Quartile
Mean
$4,648
Quartile 1
$4,057
Quartile 2:
$4,769
Quartile 3:
$4,927
Comments
This graph does not represent a performance measure, but
instead is used for data validation and analysis.
#24, 34 did not include
Transmission expenses
and will not be shown on
subsequent slides.
Calculation used
( DF70.1 ) / (ST5_T&D Dist End Use Customers) , ( DF70.2 +
TF65.2 ) / (ST5_T&D Dist End Use Customers) , TF65.1 /
(ST5_T&D Dist End Use Customers)
Page16
2014 T&D: Statistics
ANALYSIS: T&D SUBSTATION PLANT IN SERVICE PER
INSTALLED MVA
Mean Quartile
Mean
$39,936
Quartile 1
$28,810
Quartile 2:
$34,778
Quartile 3:
$49,300
Comment
s
Calculation used
DF70.2 / ( ST100.1 + ST105.1 ) , TF65.2 / ( ST100.1 + ST105.1
)
Page17
2014 T&D: Statistics
ANALYSIS: DISTRIBUTION SUBSTATION PLANT IN SERVICE PER
INSTALLED MVA
Mean Quartile
Mean
$34,744
Quartile 1
$44,242
Quartile 2:
$32,630
Quartile 3:
$27,128
Comments
This graph does not represent a performance measure. It is
used for analysis.
Calculation
used
DF70.2 / ST100.1
Page18
2014 T&D: Statistics
PERCENT OF DISTRIBUTION CIRCUITS REMOTELY OPERATED
Comment
s
Calculation
used
ST110.1
Page19
2014 T&D: Statistics
PERCENT OF SWITCHES OUTSIDE THE SUBSTATION REMOTELY
OPERATED
Comment
s
Calculation
used
ST110.2
Page20
We ask for several measures of System Activity
21
2014 T&D: System Activity
SUBSTATION MVA ADDED
Distribution
Transmission
Calculation used
SA40.4A / ST100.1 * 100 , SA40.6A / ST100.1 * 100 ,
SA45.4A / ST100.1 * 100 , SA45.6A / ST100.1 * 100
Page22
Financial –
Overview of the Cost Model
Working with an adjusted FERC model
23
T&D Substation Cost Profile
2013YE
2012YE
Mean
Q1
Q2
Q3
# of
Bars
Mean
Q1
Q2
Q3
# of
Bars
Substation O&M per Customer
Distribution Substation O&M per
Customer
Substation O&M per Installed MVA
Transmission Substations O&M per
MVA
Distribution Substations O&M per
MVA
$13.47
$7.94
$13.47
$14.64
15
$16.56
$8.42
$11.75
$15.05
17
$8.40
$3.78
$5.99
$13.75
14
$7.07
$3.39
$6.19
$11.00
17
$492
$267
$353
$483
12
$544
$308
$543
$802
14
$442
$205
$326
$614
11
$489
$217
$436
$681
12
$516
$235
$345
$501
10
$1,419
$274
$502
$703
14
Substation O&M per Total Assets
1.23%
0.87%
1.18%
1.47%
16
1.23%
0.94%
1.17%
1.40%
17
Transmission Substations per Asset
0.91%
0.57%
0.95%
1.08%
13
1.13%
0.76%
1.07%
1.16%
15
Distribution Substations per Asset
1.45%
0.74%
1.29%
2.24%
14
1.36%
0.76%
1.13%
1.83%
17
7.24% 10.45% 5.59%
3.82%
13
5.44%
6.41%
4.25%
2.63%
15
5.07%
5.19%
3.24%
11
3.93%
5.13%
3.38%
2.19%
14
8.23% 13.04% 5.27%
4.13%
12
6.38%
7.17%
5.26%
3.19%
14
O&M Cost
Investment Rate
Substation Capital Spending less New
Subs per Asset [Activity Based]
Distribution Substations
Replacement Rate
Transmission Substations
Replacement Rate
5.55%
24
Financial –
Overview of the Cost Model
Working with an adjusted FERC model
and the
Activity-Based Cost Model
25
Activity-Based Cost Model
2014 Guidelines
The activity-based cost model breaks the expenditures into capital and
O&M, and then splits them into the activities shown on the process model
introduced above. The following 3 pages provide more details of the
individual activities for Transmission, Substations, and Distribution.
Activity-Based
Costs
Transmission
Lines
Transmission
Subs
Distribution Subs
Transmission Line Capital
• Serve New
• Expand
• Sustain
• Other
• CIAC
T&D Substation Capital
• Serve New
• Expand
• Sustain
• Other
• CIAC
Transmission Line O&M
• Sustain the Network
• Operate the Network
T&D Substation O&M
• Sustain the Network
• Operate the Network
• Other
Distribution Lines
Distribution Line Capital
• Serve New
• Expand
• Sustain
• Other
• CIAC
Distribution Line O&M
• Sustain
• Other
26
Activity Based Costs - Substations
2014 Guidelines
While capital expenditures are split among several different processes from the
overall process model, O&M expenses are almost entirely associated with
sustaining the network.
T&D Substation Capital
• Serve New: New Substations and
new substation capacity to serve
specific new customer requests
• Expand: Capacity Additions to meet
generic load growth
• Sustain: Repair/replace-in-kind
• Sustain: system improvement
(reliability/efficiency, system
hardening, physical security)
• Sustain: Service Restoration
• Sustain: Mobile/Spare Transformer
Purchases
• Other
• CIAC
T&D Substation O&M
• Inspection & Maintenance
• Service Restoration
• Distribution Operations
Center
• Engineering/Design O&M
(Planning studies,
standards, mapping)
• Other
27
2014 T&D: T&D Substation Financials
T&D SUBSTATION CAPITAL SPENDING PER ASSET [FERC]
Mean Quartile
Mean
10.0 %
Quartile 1
7.5 %
Quartile 2:
4.9 %
Quartile 3:
4.7 %
#28 reported all costs as
transmission – total is
correct but components
will be excluded from TSub slides.
Calculation used
DF10.5 / ( DF70.2 + TF65.2 ) * 100 , TF10.5 / ( DF70.2 +
TF65.2 ) * 100
Page
2
2014 T&D: Dist Substation Financials
DISTRIBUTION SUBSTATION O&M & CAPITAL SPENDING PER
ASSET [FERC]
Mean Quartile
Mean
5.9 %
Quartile 1
3.7 %
Quartile 2:
4.7 %
Quartile 3:
7.4 %
Comments
Some companies are distribution only or transmission only,
only a few are T&D combined.
#24 reported very little
O&M expense
Calculation used
DF30.5 / DF70.2 * 100 , DF10.5 / DF70.2 *
100
Page29
Distribution Substation
Financial –
Overview of the Cost Model
Working with an adjusted FERC model
30
2014 T&D: Dist Substation Financials
DISTRIBUTION SUBSTATION CAPITAL SPENDING PER ASSET
[ACTIVITY- BASED] [V.14]
Mean Quartile
Mean
6.28 %
Quartile 1
7.84 %
Quartile 2:
5.56 %
Quartile 3:
4.92 %
Comment
s
Calculation used
DF55.1 / DF70.2 * 100 , DF55.2 / DF70.2 * 100 , DF55.3 /
DF70.2 * 100 , DF55.4 / DF70.2 * 100 , DF55.5 / DF70.2 * 100
, DF55.6 / DF70.2 * 100 , DF55.7 / DF70.2 * 100
Page31
2014 T&D: Dist Substation Financials
DISTRIBUTION SUBSTATION CAPITAL SPENDING EX SERVE NEW,
EXPAND PER ASSET [ACTIVITY-BASED] [V.14]
Mean Quartile
Mean
3.40 %
Quartile 1
4.51 %
Quartile 2:
2.88 %
Quartile 3:
2.24 %
Comment
s
Calculation used
1 / ( DF55.1 - DF55.1 ) , 1 / ( DF55.2 - DF55.2 ) , DF55.3 /
DF70.2 *
100 , DF55.4 / DF70.2 * 100 , DF55.5 / DF70.2 * 100 , DF55.6 /
DF70.2 * 100 , DF55.7 / DF70.2 * 100
Page32
2014 T&D: Dist Substation Financials
DISTRIBUTION SUBSTATION CAPITAL SPENDING PER
CUSTOMER [ACTIVITY-BASED] [V.14]
Mean Quartile
Mean
$32.75
Quartile 1
$38.89
Quartile 2:
$33.47
Quartile 3:
$26.37
Comment
s
Calculation used
DF55.1 / (ST5_T&D Dist End Use Customers) , DF55.2 /
(ST5_T&D Dist End Use Customers) , DF55.3 / (ST5_T&D Dist
End Use Customers) , DF55.4 / (ST5_T&D Dist End Use
Customers) , DF55.5 / (ST5_T&D Dist End Use Customers) ,
DF55.6 / (ST5_T&D Dist End Use Customers) , DF55.7 /
(ST5_T&D Dist End Use Customers)
Page33
2014 T&D: Dist Substation Financials
DISTRIBUTION SUBSTATION CAPITAL SPENDING EX SERVE NEW
PER DEPRECIATION EXPENSE [ACTIVITY- BASED] [V.14]
Mean Quartile
0%
200%
400%
600%
Mean
$248.71
Quartile 1
$331.12
Quartile 2:
$190.57
Quartile 3:
$161.50
Comment
s
Calculation used
1 / ( DF55.1 - DF55.1 ) , DF55.2 /
DF80.2 * 100 , DF55.3 / DF80.2 *
100 , DF55.4 / DF80.2 * 100 ,
DF55.5 / DF80.2 * 100 , DF55.6 /
DF80.2 * 100 , DF55.7 / DF80.2 *
100
Page34
2014 T&D: Dist Substation Financials
OTHER ACTIVITY BASED COSTS: DISTRIBUTION SUBSTATION
CAPITAL SPENDING
Calculation
used
DF56.1
ID
31
33
23
38
24
21
30
27
32
Response
Capital Tools, R&D, Premise Equipment, Facilities
not applicable
NA
Environmental/Legislative/Regulatory Environmental/Legislative/Regulatory
Not applicable
Customer Orders, General Plant, Normal Ops, and Meters/Xfmrs
N/A
Environmental
Not applicable
Page35
2014 T&D: Dist Substation Financials
DISTRIBUTION SUBSTATION O&M EXPENSE PER ASSETS
[ACTIVITY-BASED] [V.14]
Mean Quartile
Mean
1.42 %
Quartile 1
0.74 %
Quartile 2:
1.11 %
Quartile 3:
2.13 %
Comment
s
#34 reported high service
restoration costs
#34, 40 high other
Calculation used
DF65.1 / DF70.2 * 100 , DF65.2 / DF70.2 * 100 , DF65.3 /
DF70.2 * 100 , DF65.4 / DF70.2 * 100 , DF65.5 / DF70.2 * 100
Page36
2014 T&D: Dist Substation Financials
DISTRIBUTION SUBSTATION O&M EXPENSE PER CUSTOMER
[ACTIVITY- BASED] [V.14]
Mean Quartile
Mean
$8.02
Quartile 1
$3.77
Quartile 2:
$5.05
Quartile 3:
$12.06
Comment
s
Calculation used
DF65.1 / (ST5_T&D Dist End Use Customers) , DF65.2 /
(ST5_T&D Dist End Use Customers) , DF65.3 / (ST5_T&D Dist
End Use Customers) , DF65.4 / (ST5_T&D Dist End Use
Customers) , DF65.5 / (ST5_T&D Dist End Use Customers)
Page37
2014 T&D: Dist Substation Financials
OTHER ACTIVITY BASED COSTS: DISTRIBUTION SUBSTATION
O&M
Calculation
used
DF66.1
ID
31
33
23
38
24
21
30
27
34
32
Response
Training and R&D
not applicable
VM including mowing and landscape.
na
Not applicable
O&M associated with New Customers and Construction
N/A
Administration, Landscape Maint, Order Material, Inspections, Rodent Proofing
Substation training & staff
Not applicable
Page38
2014 T&D: Dist Substation Financials
CWIP AS A % OF CAPITAL EXPENDITURES - DISTRIBUTION
SUBSTATION
Mean Quartile
Mean
118.9 %
Quartile 1
31.9 %
Quartile 2:
55.7 %
Quartile 3:
135.8 %
Comment
s
Calculation used
DF85.2 / DF10.5 * 100
Page39
2014 T&D: Dist Substation Financials
FERC VS ACTIVITY SPENDING: DISTRIBUTION SUBSTATION
O&M PER ASSET [V.14]
Comment
s
#22, 24,25 did not report
activity cost
Calculation used
DF30.5 / DF70.2 * 100 , (DF65_ABC Dist Sub O&M v.14) /
DF70.2 * 100
Page40
2014 T&D: Dist Substation Financials
FERC VS ACTIVITY SPENDING: DISTRIBUTION SUBSTATION
CAPITAL PER ASSET [V.14]
Comment
s
Calculation used
DF10.5 / DF70.2 * 100 , (DF55_Dist Subs Cap ABC v.14) /
DF70.2 * 100
Page41
2014 T&D: Dist Substation Financials
DEPRECIATION EXPENSE AS A PERCENT OF ASSETS:
DISTRIBUTION SUBSTATIONS
Mean Quartile
Mean
Quartile 1
Quartile 2:
Quartile 3:
Comment
s
Calculation used
DF80.2 / DF70.2 * 100
Page
4
2.20 %
1.81 %
2.25 %
2.55 %
Distribution Substation: Capital Spending
2013 saw an increased spending level…
2010YE
Q2
5.5%
2011YE
Q2
4.5%
2012YE
Q2
4.24%
2013YE
Q2
5.56%
Less Serve New:
Subtotal: Sustain & Cap
Adds
Less Capacity Adds
1.9%
0.8%
2.07%
0.37%
3.6%
3.7%
2.17%
5.19%
1.4%
1.6%
0.08%
2.31%
Subtotal: Sustain
2.2%
2.1%
2.09%
2.88%
Total Capital
43
43
Panels exclude D-only companies
Transmission sub Financial –
Overview of the Cost Model
44
2014 T&D: Trans Substation Financials
TRANSMISSION SUBSTATION O&M & CAPITAL SPENDING PER
ASSET [FERC]
Mean Quartile
Mean
7.0 %
Quartile 1
5.8 %
Quartile 2:
6.6 %
Quartile 3:
8.7 %
Comments
Some companies are distribution only or transmission only,
only a few are T&D combined.
Calculation used
TF30.5 / TF65.2 * 100 , TF10.5 / TF65.2 *
100
Page45
2014 T&D: Trans Substation Financials
TRANSMISSION SUBSTATION CAPITAL SPENDING PER ASSET
[ACTIVITY-BASED] [V.14]
Mean Quartile
Mean
7.41 %
Quartile 1
11.50 %
Quartile 2:
5.60 %
Quartile 3:
3.83 %
Comment
s
Calculation used
TF50.1 / TF65.2 * 100 , TF50.2 / TF65.2 * 100 , TF50.3 / TF65.2
* 100 , TF50.1 / TF65.2 * 100 , TF50.5 / TF65.2 * 100 , TF50.4 /
TF65.2
* 100 , TF50.6 / TF65.2 * 100
Page46
2014 T&D: Trans Substation Financials
TRANSMISSION SUBSTATION CAPITAL SPENDING EX SERVE
NEW, EXPAND PER ASSET [ACTIVITY- BASED] [V.14]
Mean Quartile
Mean
2.80 %
Quartile 1
4.12 %
Quartile 2:
2.37 %
Quartile 3:
1.19 %
Comment
s
Calculation used
1 / ( TF50.1 - TF50.1 ) , 1 / ( TF50.2 - TF50.2 ) , TF50.3 / TF65.2 *
100 , TF50.1 / TF65.2 * 100 , TF50.5 / TF65.2 * 100 , TF50.4 /
TF65.2
* 100 , TF50.6 / TF65.2 * 100
Page47
2014 T&D: Trans Substation Financials
OTHER ACTIVITY BASED COSTS: TRANSMISSION SUBSTATIONS
CAPITAL SPENDING
Calculation
used
TF51.1
ID
31
33
23
38
24
21
30
27
32
Response
Capital Tools, R&D, Premise Equipment, Facilities
not applicable
NA
Environmental/Legislative/Regulatory
not applicable
n/a
N/A
Substation security
Not applicable
Page48
2014 T&D: Trans Substation Financials
TRANSMISSION SUBSTATION O&M EXPENSE PER ASSETS
[ACTIVITY-BASED] [V.14]
Mean Quartile
Mean
0.90 %
Quartile 1
0.57 %
Quartile 2:
0.96 %
Quartile 3:
1.06 %
Comment
s
#40 has high sub
operations expense
Calculation used
TF60.1 / TF65.2 * 100 , TF60.2 / TF65.2 * 100 , TF60.1 /
TF65.2 * 100 , TF60.1 / TF65.2 * 100 , TF60.3 / TF65.2 * 100
Page49
2014 T&D: Trans Substation Financials
CWIP AS A % OF CAPITAL EXPENDITURES - TRANSMISSION
SUBSTATION
Mean Quartile
Mean
80.1 %
Quartile 1
25.2 %
Quartile 2:
48.5 %
Quartile 3:
115.4 %
Comment
s
Calculation used
TF80.2 / TF10.5 * 100
Page50
2014 T&D: Trans Substation Financials
FERC VS ACTIVITY SPENDING: TRANSMISSION SUBSTATION
O&M PER ASSET [V.14]
Comment
s
#25,359,37 Did not report
T-Sub Activity O&M
#21 Activity >>FERC
Calculation used
TF30.5 / TF65.2 * 100 , (TF60_ABC Trans Sub O&M v.14) /
TF65.2 * 100
Page51
2014 T&D: Trans Substation Financials
FERC VS ACTIVITY SPENDING: TRANSMISSION SUBSTATION
CAPITAL PER ASSET [V.14]
Comment
s
#25,37 did not report
activity
Calculation used
TF10.5 / TF65.2 * 100 , (TF50_ABC Trans Subs Cap v14) /
TF65.2 * 100
2014 T&D: Trans Substation Financials
DEPRECIATION EXPENSE AS A PERCENT OF ASSETS:
TRANSMISSION SUBSTATION
Mean Quartile
Mean
2.01 %
Quartile 1
1.90 %
Quartile 2:
2.06 %
Quartile 3:
2.21 %
Comment
s
Calculation used
TF75.2 / TF65.2 * 100
Page53
Transmission Substations: Capital Spending
2013 saw a slightly reduced level of transmission substation overall
spending, but an increase in sustain activity.
2010YE
Q2
2011YE
Q2
2012YE
Q2
2013YE
Q2
Total Capital
7.0%
7.9%
6.16%
5.74%
Less Serve New
Subtotal: Sustain & Cap
Adds
Less Capacity Adds
1.6%
0.7%
1.12%
0.47%
5.4%
7.2%
5.04%
5.27%
2.9%
3.8%
3.14%
2.16%
Subtotal: Sustain
2.5%
3.4%
1.90%
3.11%
54
54
Substation
Practices and Initiatives
55
AGING ASSETS A PROBLEM FOR ASSET MANAGERS
Aug 11, 2014
T&D World magazine conducted the expansive research, collecting data from June 5-9, 2014, and 685
respondents representing T&D managers and engineers working in construction, maintenance, operations and
engineering. The report looks at all the of the main issues professionals are facing including aging assets,
equipment and technology investments, upgrading capacity vs. lessening susceptibility, power delivery system
redesign plans. Some interesting statistics:
•The majority are investing in diagnostic equipment (66%), while 52% are installing outage management systems.
Far fewer are looking at self-healing circuits (21%).
•A third of respondents (34%) report their utilities are planning to redesign their power delivery systems within the
next two years to accommodate distributed generation, including 16% who plan to do so within the next year.
•Respondent attitudes are divided with regard to whether or not it would make sense for their utilities to support
the development of hybrid microgrids in order to take congestion off the utility grid while meeting local interests in
being more independent: 28% believe this would make sense for their utilities, 35% believe it may, and 37% are
doubtful.
•Just under a third of respondents (29%) expressed a healthy interest in learning more about compliance with
FERC Order 1000, which enables companies to compete against incumbent utilities and bid to deliver turnkey
transmission to meet ISO requested transmission. Another 31% are moderately interested.
56
Potential for Terrorist Attack
The U.S. could suffer a coast-to-coast blackout if saboteurs
knocked out just nine of the country's 55,000 electrictransmission substations on a scorching summer day,
according to a previously unreported federal analysis.
Gunmen attacked transformers at PG&E's Metcalf substation
near San Jose, Calif., last year, putting it out of service for
almost a month. Talia Herman for The Wall Street Journal
57
A Process Model for Managing the Network
Add New
Customers
Expand
Network
Respond to
Emergencies
Operate
Network
Sustain
Network
Project/Portfolio Management
Develop and Approve Asset Plans
Develop Network Strategy
58
Substation Practices/initiatives section
2013 Sections
2014 Proposed by Process
◼ Asset Management – RCM and Life cycle
◼ Asset Management
costing approaches; replacement programs,
◼ Strategy
and problematic equipment
 Substation automation
◼ Planning/Engineering/Design –Changes to
 Mobile spares
standards
◼ Sustain Substations
◼ Substation Automation – Technology and
 Maintenance planning
initiatives underway
 Field maintenance
◼ Job Estimating – Software tools and role of
 Including NERC standards
construction
 Replacement/upgrades
◼ Mobiles/Spares – Deployment of mobiles and
◼ Expand Substations
spare, and optimization techniques
 Planning/Engineering/Design
◼ Field Maintenance Activities – Initiatives
 Job estimating
underway, degree of crew specialization, and
 Field Construction
work management systems
◼ NERC Maintenance Standards – Impact of
NERC standards on substation maintenance
◼ Maintenance – Inspections, impact of deferred
maintenance, initiatives to reduce outages
59
Substation practice Questions
2014 Proposed by Process
◼ Asset Management
◼ Strategy
 Substation automation
 Mobile spares
◼ Sustain Substations
 Maintenance planning
 Field maintenance
 Including NERC standards
 Replacement/upgrades
◼ Expand Substations
 Planning/Engineering/
Design
 Job estimating
 Field Construction
Asset Management (AM)
• Role of the Asset Management organization in decision making
• Key responsibilities of the Substation AM organization
• What keeps you up at night worrying about your system
• Analytic approaches used to predict replacement needs
• Use of concepts embodied in RCM in Subs
• Use of the concepts embodied in 'Life Cycle Costing'
• Use predictive reliability analysis tools on component
failure rates
• Replacement Programs Underway: Power Transformers;
Switch Gear; Circuit Breakers; Relays; Instrument
Transformers; Secondary/Communications
• Classes of equipment that are becoming problematic
• Other Classes of equipment that are becoming
problematic
• Use of dedicated software tools to support substation AM
60
1QC Industry Perspective:
Substations
Situation
• Technology changes
are moving faster in
substations than
elsewhere in T&D
• Regulation changes
have impacted
substation operations
• Workforce aging and
knowledge transfer
are significant issues
• Plan to Build Process
Complication
Question
• NERC maintenance
standards are
imposing additional • What are substation
organizations doing
requirements
to meet the
• Equipment
challenges?
obsolescence is an
issue with new digital
equipment replacing
older components
• Protracted permitting
can create project
delays
• Reliability
requirements
continue to increase
Answer
•Asset Management to
optimize life cycle
costs and reliability
•Strategic Planning
Improving the design
and construction
process
• More sophisticated
maintenance
programs, driven by
analytics around
economics as well as
equipment failure
analysis.
61
Key Success Factors:
Manage assets
Identify risk factors; aging equipment and reduced
maintenance budgets are concerns.
Use Reliability Centered Maintenance (RCM) concepts
Set replacement cycles using condition and failurebased approaches
Strengthen Asset Management Role; can include strategy,
policy, analytics, prioritization, and management
Use predictive analysis tools focusing on component failures
and customer reliability metrics.
62
2014 T&D: Substations
WHAT KEEPS YOU UP AT NIGHT WORRYING ABOUT YOUR SYSTEM
ID
31
28
33
37
38
40
24
Response
Knowledge Transfer and the development of field personnel continues to be a major problem as
the tenured work force leaves.
Safety, theft, our ability to manage the reliability of all the software/firmware/settings associated
with microprocessor control equipment.
Trans bank failures, relay misoperations
Aging infrastructure coupled with limited resources to address
Maintaining a good maintenance program AND meeting O&M targets.
Older equipment (Reliability) and lack of spare parts or vendor support. Electromechanical relays.
27
The increasing age, deteriorating condition, and decreasing reliability of several classes of
equipment in the system - despite continuing efforts at cost effective Condition Based
Maintenance (CBM).
Aging equipment
Substations without internal T- line protection, aging infrastructure, incomplete and inaccurate
asset history and maintenance data
Aging equipment, EHV transformer failure, large customers with single source transformer
359
32
Aging assets and unexpected failures.
Loss of AY autobank or RR autobank 1 until new RR autobank 2 is in service
21
30
Calculation
used
SP10.1
Page
6
2014 T&D: Substations
ANALYTIC APPROACHES USED TO PREDICT REPLACEMENT NEEDS
ID
22
31
28
33
23
37
38
40
21
30
27
359
32
Calculation
used
SP15.1
Response
Condition health assesment in Cascade
Condition/operational monitoring, equipment history, environment issues
MTBF (mean time between failures) is a key metric . Our Sustain Investment Model looks at groups of
assets, anticipated lifetimes, historical performance to determine an evergreen investment program over
multiple decades.
Using cascade we've identified replacement criteria by asset category. We use manufacture
recommendations and industry standards
Failure history, performance, maintenance requirements and grid criticality.
Past failure trending, industry benchmarking and trending, trending of test data
Proprietary models by equipment class to determine replacement order.
Costs, trips per line, age of equipment, availability of spare parts and support. Infrared, test results.
Data from worst performing circuits, track failure rates by equipment types and cause. We are developing
a risk based maintenance strategy to drive replacement needs that will take into consideration
probability of failure (health), consequence of failure (criticality) and life cycle costing considerations.
Transformer criticality spreadsheet that factors in customer base, average loading, emergency ties,
and transformer DGA test results. We take historical hazard/survival rates for each particular asset
classification into consideration when determining overall operational risk to the organization
Power factor testing, DGA, and trends of like equipment.
For long range planning, look at population models and how the age is varying with time. For
individual components, use health index and criticality of the asset.
Mean time between failures, life expectancy, fleet analysis, previous inspection findings (eg wood pole
test/treat reject rates). TRANS - 1) DGA 2) Doble test, megger test, etc. 4) Difficulty in buying
replacement parts 5) Maintenance history
Page
6
2014 T&D: Substations
ANALYTIC APPROACHES USED TO PREDICT REPLACEMENT NEEDS
PSEG
24
Our Computerized Maintenance Management System (CMMS) provides the means for optimizing the
maintenance of our assets through the use of condition - based tools.
• It is a decision support system that assists in making repair/replace/maintain decisions.
•The CBM implementation strategy through CMMS requires the comprehensive integration of data from
multiple systems. These systems include but are not limited to OMSto gather weekly inspection data,
delivery work management (DWMS) to gather diagnostic data collection from field personnel, system and
equipment operational data, equipment test data, and on - line equipment monitoring data.
• This system utilizes available information on equipment health by incorporating it into the maintenance
decision process. Algorithms have been set up to provide ranking systems for all major equipment. The
algorithm factors are based on the data available for each particular asset, and the factor weightings vary
between voltage classes.
•The Action Algorithms provide a score for each asset, with those most in need of review and/or action
scoring the highest. Replacement Algorithms are used to help identify equipment advancing towards
completion of useful life. The algorithms are periodically reviewed and adjusted to keep them on track in
identifying equipment maintenance needs.
2014 T&D: Substations
USE OF CONCEPTS EMBODIED IN 'RELIABILITY CENTERED
MAINTENANCE' IN SUBSTATIONS
ID
22
31
28
Response
Maintenance tempaltes use failure modes to determine appropriate PM taslks
Set frequencies of maintenance, required test performed
We use function, criticality, and condition monitoring to establish our maintenance
programs.
33 we look at equip category failure history by manufacture, age, duty cycle to help predict
future replacement criteria.
23 Targeting worse performers, reviewing failure modes and customer impacts and the risk to
grid on run to failure scenarios.
37 Gone to condition base versus time based maintenance on some assets. Adjusted
maintenance intervals and tasks based on performance. Prioritized spending on
maintenance
38 Monitor critical parameters and replace the worst first. Use equipment condition wherever
possible.
40 Specific reads on inspection triggers
21 Used to determine the proper maintenance strategy for assets. In addition, used to drive
some equipment upgrades and/or reliability improvement projects. We are not heavily
involved in RCM currently.
27 Criticality, impact, failure modes, cost of assets used to determine maintenance cycles
359 For replacement strategy, look at multiple inputs to make decisions, not just one, such as
age
Page
6
USE OF CONCEPTS EMBODIED IN 'RELIABILITY CENTERED
MAINTENANCE' IN SUBSTATIONS
PSEG
24
32
Reliability Centered Maintenance (RCM), or Condition - Based Maintenance (CBM), is a
proactive equipment maintenance capability that uses system health indications to identify
and predict functional failure in advance of the event and provide the ability to take
appropriate preventive action. This approach to maintenance uses data drawn during
operations and/or maintenance intervals to forecast the need for additional or future
maintenance. It extends the concepts of predictive maintenance by using data from
maintenance tests. Ideally condition - based maintenance will allow maintenance personnel
to locate and resolve asset functionality issues before they escalate, minimizing corrective
maintenance costs and system downtime.
TRANS - All major eqipment is routinely maintained on a time based system. Maintenance
intervals are based on a combination of generally accepted industry practice, performance
history, age of equipment, and to some degree the criticality of the equipment. Nonroutine
maintenance is performed as required.
2014 T&D: Substations
USE PREDICTIVE RELIABILITY ANALYSIS
Calculation
used
SP30.1
ID
31
28
33
23
38
40
24
Response
TORT - Transmission operational data
Yes, Asset Health Index (AHI) and Strategic Asset Management (SAM) tools part of the
EPS - M UtiliCase.
no
We track SAIDI, SAIFI, CAIDI as they relate to transmission line,station and feeder
performance. We analyze each incident that we encounter and search for the problem as a
part of our equipment failure reporting in an attempt to identify and share failure modes and
equipment issues that need to be addressed on other infrastructure of the same type.
Key metrics are used to verify effectiveness of improvement projects.
We use SAIFI and SAIDI that helps us to predict and determine reliability issues on our
transmission lines and helps to determine replacement priorities.
Component failure rate information (as available) is used to recommend budgetary needs
for equipment replacements required to maintain system reliability. Specific candidates for
equipment replacement are determed by condition assessment review. Substation design
philosophy includes redundancy and reliability considerations to minimize impact of
21
Substation equipment failures on customer reliability metrics such as SAIFI and CAIDI.
Not sure what you are looking for with this question.
Page
6
2014 T&D: Substations
USE OF DEDICATED SOFTWARE TOOLS TO SUPPORT SUBSTATION ASSET
MANAGEMENT
Calculation
used
SP45.1
ID
22
31
33
23
37
38
40
21
30
27
Response
Cascade
Davies AIS tool for investment prioritization. SAP/BI for asset life cycle analytics.
digital inspections, cascade, 4 years, full inventory, and complete maintenance functionality.
Maximo 7.5 since May 2013. Asset warehouse & maintenance system.
Maximo - last updated in 2009 provides asset tracking and cost analysis
'1) TOA(Transformer Oil Analysis) Delta X Research 16 years
CASCADE - Tracks maintenance tasks results and history of equipment.
Cascade 2 - 1/2 years, Powerbase 6 months
EMPAC (Indus) 1994
We have used Maximo by IBM for 2 years. It holds are maintenance records & is work
manangement
359 Digital Inspections - CASCADE 3.31, Substation and LTN Inventory and Preventative
Maintenance Management.
32 TRANS - MAXIMO used for creating and storing job plans, test data. Automatically
generates work orders for all time based maintenance activities. Any unscheduled
maintenance is planned through MAXIMO and records kept.
Page69
USE OF DEDICATED SOFTWARE TOOLS TO SUPPORT
SUBSTATION ASSET MANAGEMENT
28
1) NERC Audit & Report, in - house, 4 years, Management of work orders, schedule,
compliance. 2) EPS - M (Utili - Case), 5 years, Asset Analytics, Asset Information, Asset
Performance, Algorithms used to provide the 30 years System Investment Management
profile, and Reporting. 3) Asset Health Index (AHI), 10 years, Report provides full of results
data on the condition and estimated remaining life of assets in the BC Hydro transmission
and distribution system (T&D), including substation assets (Stations). 4) Asset Needs and
Risk Register (in -house), 2 years, integrated planning and risk register tool for both long term (20 -30 years) and short - term (2- 10 years) assets/system needs.
24
The CMMS system discussed in SP15 is an internally developed software platform that is
used to integrate data from multiple sources and apply internally generated condition
assessmemnt algorithms to rank all assets in terms of need for maintenance and/or
replacement. The sources include characterisitic and cost information from SAP, loading
and other system condition data maintained in a PI historical data warehouse, weekly
inspection data input from hand - held mobile devices, on- line monitoring devices (such as
gas - in - oil monitors for transformers), and laboratory diagnostic field test databases
maintained by our Test Laboratory.
2014 T&D: Substations
SUBSTATION STANDARDS CHANGED RECENTLY AND WHY
ID Response
31 Meet with user groups to identify required standards needs
28 Planning, Design, and Commissioning standards have changed recently to provide
consistency with third party service providers and alignment with Safety - by - Design
principles.
33 Complete standards revision began in 2013 for update our maintenance practices.
37 Application of substation safety signs to comply with latest version of ANSI/NESC. Relay
standards updated Capacitor Protection guide, Alarm guide, Cyber security guide. Breaker
standard updated to include magnetic actuators (new technology for us) and battery
standard updated per periodic review
40 Relay Maint. and Const. for updated supplements to PRC - 005 of 001b, 002, and 003.
Updated transformer and breaker specifications; Protection System Maintenance Plan
21 Transformers, SF6 Breakers
30 None
Page71
SUBSTATION STANDARDS CHANGED RECENTLY AND WHY
27 We require our 13.8kV switchgear to be arc resistant type 2B rated for increased crew safety
while racking the breakers in and out. We added card readers to PDC buildings and added
building access, building temperature and fire alarms to our SCADA system to better monitor and
control building access and decrease response time in the event of a fire. We automated the
drive - through gate with card reader control at new substations with the open and closed
positions reported to SCADA to monitor and control access to the substation. We also install a
manual locked man gate to be used if the automated gate does not operate. We revised our
transformer specifications to inlcude transformer monitioring equipment from Dynamics Ratings
359 We are in the process of 'overhauling' all of our Standards for Transmission and Substations.
Currently we revised the 230/69 kV entire substation standard and created a manual. The
manual consist of Standard design intent, design criteria, relay design intent, relay and control
acceptable devices and protection requirements, Construction work and bid template and testing
and commissioning requirements. This manual will be a model to be used when doing the 500
and 69/12 kV substations, which we intend to have done by the end of the year. We are also
updating our entire grounding standards for all substations. We have also updated our
equipment specifications to include more industry proven devices that will help move us from
time based maintenance to a condition based maintenance approach. For instance we now
require on - line DGA devices to eliminate employees from taking samples every 6 months on
our transformers. We are also using bushing monitoring devices for our transformers to move
away from Doble testing.
2014 T&D: Substations
IDENTIFY ANY SOFTWARE PRODUCTS USED OR BEING EVALUATED FOR
SUBSTATION JOB ESTIMATING
Calculation
used
SP60.1
ID Response
22 None
31 Internally developed excel spreadsheets
28 We are currently using Excel for estimating and @Risk for Monte- Carlos
analysis. We are also evaluating ???U.S Cost?? and HeavyBid estimating
software for future use.
33 in house estimating program
23 Spreadsheets and in house software tool.
37 Maximo and Business Objects
38 none
40 Maximo & Excel
21 Cascade
30 Excel
27 Microsoft Excel
359 Excel; Bulk Power Estimator (internally developed tool)
32 No Software
Page73
Key Success Factors:
Maintenance programs
Understand and comply with NERC requirements
Conduct regular inspections, and analyze the results to drive maintenance
activity
Review inspection program and maintenance cycles, using advanced
analytic tools
Coordinate maintenance activity with the asset management function, to
get the most from both maintenance and capital replacement .
Use mobile spares to reduce outage durations
74
2014 T&D: Substations
Power Transformers
Switch Gear
Circuit Breakers
Relays
Instrument Transformers
SecondaryCommunications
Other
87%
67%
93%
80%
60%
60%
40%
Calculation used
SP35.1 , SP35.2 , SP35.3 , SP35.4 , SP35.5 , SP35.6 ,
SP35.7
Legends
Power Transformers
♦
Switch Gear
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
Relays
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
Instrument
Transformers
SecondaryCommunication
s
Other
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
Circuit Breakers
♦
♦
♦
♦
♦
♦
♦
Page
7
♦
Partial Table
SUBSTATION REPLACEMENT
SUBSTATION REPLACEMENT PROGRAMS
POWER
TRANSFORMERS
ID#
I nstrument
Transformers
Secondary
Communications
Switch Gear
Circuit Breakers
Relays
Life Cycle
Replacement
24
Program based on
condition
Life Cycle
Replacement
Program based on
condition
Life Cycle
Replacement
Program based on
condition
As needed of
As needed
enhance functionality
As needed
Replace
transformers based
27
upon transformer
index rating
Replacing switch
gear with PDC or
free standing
breaker. (several a
year)
Replace 5 - 10
OCB's each year
Electromechanical
relays are being
replaced.
upon failure
Microwave radios are
being replaced.
Replacing airblast
breakers and
associated
compressor systems.
Dual pressure SF6
and bulk oil breakers
are also being
replaced.
Electromechanical
relays are being
replaced with
microprocessor
based relays.
Proactive
replacement
program.
1. Batteries and
chargers, 2. Tone and
test panels. 3.
Microwave links are
being converted from
analog to digital and
MPLS.
Poor performing
models proactive
Automation/installatio
n of electronic relays
FBS breakers
replacement
continues and
micro - processor
upgrades
Continue SCADA RTU
replacements
OCB, Airblast, high
SF6 leak rate
Electro - mechanical None
At fialure;not supported
by vendor;or as
required to meet project
specs
Driven by capacity
needs and failures
Driven by capacity
needs and failures
Replaced when
End - of - life
28 loading exceeds
replacements.
capacity or on failure.
30
Split winding 50MVA
units proactive
31 Yes
32
Replace on loading
or testing
37
Driven by capacity
needs and failures
Yes - nearly
completed
None
76
Substation
Practices and Initiatives
77
AGING ASSETS A PROBLEM FOR ASSET MANAGERS
Aug 11, 2014
T&D World magazine conducted the expansive research, collecting data from June 5-9, 2014, and 685
respondents representing T&D managers and engineers working in construction, maintenance,
operations and engineering. A majority of T&D professionals reported that their companies are addressing aging
assets (65%), followed by the use of smart meters feeding outage management systems (42%), according to a
new survey sponsored by Burns & McDonnell.
(http://tdworld.com/sitefiles/tdworld.com/files/uploads/2014/08/BurnsMcDonnellSurvey.pdf)
T&D World magazine conducted the expansive research, collecting data from June 5-9, 2014, and 685
respondents representing T&D managers and engineers working in construction, maintenance, operations and
engineering. The report looks at all the of the main issues professionals are facing including aging assets,
equipment and technology investments, upgrading capacity vs. lessening susceptibility, power delivery system
redesign plans. Some interesting statistics:
•The majority are investing in diagnostic equipment (66%), while 52% are installing outage management systems.
Far fewer are looking at self-healing circuits (21%).
•A third of respondents (34%) report their utilities are planning to redesign their power delivery systems within the
next two years to accommodated distributed generation, including 16% who plan to do so within the next year.
•Respondent attitudes are divided with regard to whether or not it would make sense for their utilities to support
the development of hybrid microgrids in order to take congestion off the utility grid while meeting local interests in
being more independent: 28% believe this would make sense for their utilities, 35% believe it may, and 37% are
doubtful.
•Just under a third of respondents (29%) expressed a healthy interest in learning more about compliance with
FERC Order 1000, which enables companies to compete against incumbent utilities and bid to deliver turnkey
transmission to meet ISO requested transmission. Another 31% are moderately interested.
78
Potential for Terrorist Attack
The U.S. could suffer a coast-to-coast blackout if saboteurs
knocked out just nine of the country's 55,000 electrictransmission substations on a scorching summer day,
according to a previously unreported federal analysis.
Gunmen attacked transformers at PG&E's Metcalf substation
near San Jose, Calif., last year, putting it out of service for
almost a month. Talia Herman for The Wall Street Journal
79
A Process Model for Managing the Network
Add New
Customers
Expand
Network
Respond to
Emergencies
Operate
Network
Sustain
Network
Project/Portfolio Management
Develop and Approve Asset Plans
Develop Network Strategy
80
Substation Practices/initiatives section
2013 Sections
2014 Proposed by Process
◼ Asset Management – RCM and Life cycle
◼ Asset Management
costing approaches; replacement programs,
◼ Strategy
and problematic equipment
 Substation automation
◼ Planning/Engineering/Design –Changes to
 Mobile spares
standards
◼ Sustain Substations
◼ Substation Automation – Technology and
 Maintenance planning
initiatives underway
 Field maintenance
◼ Job Estimating – Software tools and role of
 Including NERC standards
construction
 Replacement/upgrades
◼ Mobiles/Spares – Deployment of mobiles and
◼ Expand Substations
spare, and optimization techniques
 Planning/Engineering/Design
◼ Field Maintenance Activities – Initiatives
 Job estimating
underway, degree of crew specialization, and
 Field Construction
work management systems
◼ NERC Maintenance Standards – Impact of
NERC standards on substation maintenance
◼ Maintenance – Inspections, impact of deferred
maintenance, initiatives to reduce outages
81
Substation practice Questions
2014 Proposed by Process
◼ Asset Management
◼ Strategy
 Substation automation
 Mobile spares
◼ Sustain Substations
 Maintenance planning
 Field maintenance
 Including NERC standards
 Replacement/upgrades
◼ Expand Substations
 Planning/Engineering/
Design
 Job estimating
 Field Construction
Asset Management (AM)
• Role of the Asset Management organization in decision making
• Key responsibilities of the Substation AM organization
• What keeps you up at night worrying about your system
• Analytic approaches used to predict replacement needs
• Use of concepts embodied in RCM in Subs
• Use of the concepts embodied in 'Life Cycle Costing'
• Use predictive reliability analysis tools on component
failure rates
• Replacement Programs Underway: Power Transformers;
Switch Gear; Circuit Breakers; Relays; Instrument
Transformers; Secondary/Communications
• Classes of equipment that are becoming problematic
• Other Classes of equipment that are becoming
problematic
• Use of dedicated software tools to support substation AM
82
1QC Industry Perspective:
Substations
Situation
• Technology changes
are moving faster in
substations than
elsewhere in T&D
• Regulation changes
have impacted
substation operations
• Workforce aging and
knowledge transfer
are significant issues
• Plan to Build Process
Complication
Question
• NERC maintenance
standards are
imposing additional • What are substation
organizations doing
requirements
to meet the
• Equipment
challenges?
obsolescence is an
issue with new digital
equipment replacing
older components
• Protracted permitting
can create project
delays
• Reliability
requirements
continue to increase
Answer
•Asset Management to
optimize life cycle
costs and reliability
•Strategic Planning
Improving the design
and construction
process
• More sophisticated
maintenance
programs, driven by
analytics around
economics as well as
equipment failure
analysis.
83
Key Success Factors:
Manage assets
Identify risk factors; aging equipment and reduced
maintenance budgets are concerns.
Use Reliability Centered Maintenance (RCM) concepts
Set replacement cycles using condition and failurebased approaches
Strengthen Asset Management Role; can include strategy,
policy, analytics, prioritization, and management
Use predictive analysis tools focusing on component failures
and customer reliability metrics.
84
2014 T&D: Substations
Substa
tion
WHAT KEEPS YOU UP AT NIGHT WORRYING ABOUT YOUR SYSTEM
ID
31
28
33
37
38
40
24
Response
Knowledge Transfer and the development of field personnel continues to be a major problem as
the tenured work force leaves.
Safety, theft, our ability to manage the reliability of all the software/firmware/settings associated
with microprocessor control equipment.
Trans bank failures, relay misoperations
Aging infrastructure coupled with limited resources to address
Maintaining a good maintenance program AND meeting O&M targets.
Older equipment (Reliability) and lack of spare parts or vendor support. Electromechanical relays.
27
The increasing age, deteriorating condition, and decreasing reliability of several classes of
equipment in the system - despite continuing efforts at cost effective Condition Based
Maintenance (CBM).
Aging equipment
Substations without internal T- line protection, aging infrastructure, incomplete and inaccurate
asset history and maintenance data
Aging equipment, EHV transformer failure, large customers with single source transformer
359
32
Aging assets and unexpected failures.
Loss of AY autobank or RR autobank 1 until new RR autobank 2 is in service
21
30
Calculation
used
SP10.1
Page
8
2014 T&D: Substations
ANALYTIC APPROACHES USED TO PREDICT REPLACEMENT NEEDS
ID
22
31
28
33
23
37
38
40
21
30
27
359
32
Response
Condition health assesment in Cascade
Condition/operational monitoring, equipment history, environment issues
MTBF (mean time between failures) is a key metric . Our Sustain Investment Model looks at groups of
assets, anticipated lifetimes, historical performance to determine an evergreen investment program over
multiple decades.
Using cascade we've identified replacement criteria by asset category. We use manufacture
recommendations and industry standards
Failure history, performance, maintenance requirements and grid criticality.
Past failure trending, industry benchmarking and trending, trending of test data
Proprietary models by equipment class to determine replacement order.
Costs, trips per line, age of equipment, availability of spare parts and support. Infrared, test results.
Data from worst performing circuits, track failure rates by equipment types and cause. We are developing
a risk based maintenance strategy to drive replacement needs that will take into consideration
probability of failure (health), consequence of failure (criticality) and life cycle costing considerations.
Transformer criticality spreadsheet that factors in customer base, average loading, emergency ties,
and transformer DGA test results. We take historical hazard/survival rates for each particular asset
classification into consideration when determining overall operational risk to the organization
Power factor testing, DGA, and trends of like equipment.
For long range planning, look at population models and how the age is varying with time. For
individual components, use health index and criticality of the asset.
Mean time between failures, life expectancy, fleet analysis, previous inspection findings (eg wood pole
test/treat reject rates). TRANS - 1) DGA 2) Doble test, megger test, etc. 4) Difficulty in buying
replacement parts 5) Maintenance history
Calculation
used
SP15.1
Page
8
2014 T&D: Substations
ANALYTIC APPROACHES USED TO PREDICT REPLACEMENT NEEDS
PSEG
24
Our Computerized Maintenance Management System (CMMS) provides the means for optimizing the
maintenance of our assets through the use of condition - based tools.
• It is a decision support system that assists in making repair/replace/maintain decisions.
•The CBM implementation strategy through CMMS requires the comprehensive integration of data from
multiple systems. These systems include but are not limited to OMSto gather weekly inspection data,
delivery work management (DWMS) to gather diagnostic data collection from field personnel, system and
equipment operational data, equipment test data, and on - line equipment monitoring data.
• This system utilizes available information on equipment health by incorporating it into the maintenance
decision process. Algorithms have been set up to provide ranking systems for all major equipment. The
algorithm factors are based on the data available for each particular asset, and the factor weightings vary
between voltage classes.
•The Action Algorithms provide a score for each asset, with those most in need of review and/or action
scoring the highest. Replacement Algorithms are used to help identify equipment advancing towards
completion of useful life. The algorithms are periodically reviewed and adjusted to keep them on track in
identifying equipment maintenance needs.
2014 T&D: Substations
USE OF CONCEPTS EMBODIED IN 'RELIABILITY CENTERED
MAINTENANCE' IN SUBSTATIONS
ID
22
31
28
Response
Maintenance tempaltes use failure modes to determine appropriate PM taslks
Set frequencies of maintenance, required test performed
We use function, criticality, and condition monitoring to establish our maintenance
programs.
33 we look at equip category failure history by manufacture, age, duty cycle to help predict
future replacement criteria.
23 Targeting worse performers, reviewing failure modes and customer impacts and the risk to
grid on run to failure scenarios.
37 Gone to condition base versus time based maintenance on some assets. Adjusted
maintenance intervals and tasks based on performance. Prioritized spending on
maintenance
38 Monitor critical parameters and replace the worst first. Use equipment condition wherever
possible.
40 Specific reads on inspection triggers
21 Used to determine the proper maintenance strategy for assets. In addition, used to drive
some equipment upgrades and/or reliability improvement projects. We are not heavily
involved in RCM currently.
27 Criticality, impact, failure modes, cost of assets used to determine maintenance cycles
359 For replacement strategy, look at multiple inputs to make decisions, not just one, such as
age
Page
8
USE OF CONCEPTS EMBODIED IN 'RELIABILITY CENTERED
MAINTENANCE' IN SUBSTATIONS
PSEG
24
32
Reliability Centered Maintenance (RCM), or Condition - Based Maintenance (CBM), is a
proactive equipment maintenance capability that uses system health indications to identify
and predict functional failure in advance of the event and provide the ability to take
appropriate preventive action. This approach to maintenance uses data drawn during
operations and/or maintenance intervals to forecast the need for additional or future
maintenance. It extends the concepts of predictive maintenance by using data from
maintenance tests. Ideally condition - based maintenance will allow maintenance personnel
to locate and resolve asset functionality issues before they escalate, minimizing corrective
maintenance costs and system downtime.
TRANS - All major eqipment is routinely maintained on a time based system. Maintenance
intervals are based on a combination of generally accepted industry practice, performance
history, age of equipment, and to some degree the criticality of the equipment. Nonroutine
maintenance is performed as required.
2014 T&D: Substations
USE PREDICTIVE RELIABILITY ANALYSIS
Calculation
used
SP30.1
ID
31
28
33
23
38
40
24
Response
TORT - Transmission operational data
Yes, Asset Health Index (AHI) and Strategic Asset Management (SAM) tools part of the
EPS - M UtiliCase.
no
We track SAIDI, SAIFI, CAIDI as they relate to transmission line,station and feeder
performance. We analyze each incident that we encounter and search for the problem as a
part of our equipment failure reporting in an attempt to identify and share failure modes and
equipment issues that need to be addressed on other infrastructure of the same type.
Key metrics are used to verify effectiveness of improvement projects.
We use SAIFI and SAIDI that helps us to predict and determine reliability issues on our
transmission lines and helps to determine replacement priorities.
Component failure rate information (as available) is used to recommend budgetary needs
for equipment replacements required to maintain system reliability. Specific candidates for
equipment replacement are determed by condition assessment review. Substation design
philosophy includes redundancy and reliability considerations to minimize impact of
21
Substation equipment failures on customer reliability metrics such as SAIFI and CAIDI.
Not sure what you are looking for with this question.
Page
9
2014 T&D: Substations
Substa
MOVE UP
tion
REPLACEMENT PROGRAMS UNDERWAY: SUBSTATIONS
Comments
Total Respondents
Power Transformers
15
86.67%
Switch Gear
66.67%
Circuit Breakers
93.33%
Calculation used
SP35.1 , SP35.2 , SP35.3 , SP35.4 , SP35.5 , SP35.6 ,
Relays
SP35.7
Instrument Transformers
Legends
SecondaryCommunications
Power Transformers
Switch Gear
Other
Circuit Breakers
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
Relays
♦
♦
♦
♦
♦
Instrument
Transformers
SecondaryCommunication
s
Other
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
80%
60%
60%
♦
♦
40%
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
Page
9
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
♦
2014 T&D: Substations
USE OF DEDICATED SOFTWARE TOOLS TO SUPPORT SUBSTATION ASSET
MANAGEMENT
Calculation
used
SP45.1
ID
22
31
33
23
37
38
40
21
30
27
Response
Cascade
Davies AIS tool for investment prioritization. SAP/BI for asset life cycle analytics.
digital inspections, cascade, 4 years, full inventory, and complete maintenance functionality.
Maximo 7.5 since May 2013. Asset warehouse & maintenance system.
Maximo - last updated in 2009 provides asset tracking and cost analysis
'1) TOA(Transformer Oil Analysis) Delta X Research 16 years
CASCADE - Tracks maintenance tasks results and history of equipment.
Cascade 2 - 1/2 years, Powerbase 6 months
EMPAC (Indus) 1994
We have used Maximo by IBM for 2 years. It holds are maintenance records & is work
manangement
359 Digital Inspections - CASCADE 3.31, Substation and LTN Inventory and Preventative
Maintenance Management.
32 TRANS - MAXIMO used for creating and storing job plans, test data. Automatically
generates work orders for all time based maintenance activities. Any unscheduled
maintenance is planned through MAXIMO and records kept.
Page92
USE OF DEDICATED SOFTWARE TOOLS TO SUPPORT
SUBSTATION ASSET MANAGEMENT
28
1) NERC Audit & Report, in - house, 4 years, Management of work orders, schedule,
compliance. 2) EPS - M (Utili - Case), 5 years, Asset Analytics, Asset Information, Asset
Performance, Algorithms used to provide the 30 years System Investment Management
profile, and Reporting. 3) Asset Health Index (AHI), 10 years, Report provides full of results
data on the condition and estimated remaining life of assets in the BC Hydro transmission
and distribution system (T&D), including substation assets (Stations). 4) Asset Needs and
Risk Register (in -house), 2 years, integrated planning and risk register tool for both long term (20 -30 years) and short - term (2- 10 years) assets/system needs.
24
The CMMS system discussed in SP15 is an internally developed software platform that is
used to integrate data from multiple sources and apply internally generated condition
assessmemnt algorithms to rank all assets in terms of need for maintenance and/or
replacement. The sources include characterisitic and cost information from SAP, loading
and other system condition data maintained in a PI historical data warehouse, weekly
inspection data input from hand - held mobile devices, on- line monitoring devices (such as
gas - in - oil monitors for transformers), and laboratory diagnostic field test databases
maintained by our Test Laboratory.
2014 T&D: Substations
SUBSTATION STANDARDS CHANGED RECENTLY AND WHY
ID Response
31 Meet with user groups to identify required standards needs
28 Planning, Design, and Commissioning standards have changed recently to provide
consistency with third party service providers and alignment with Safety - by - Design
principles.
33 Complete standards revision began in 2013 for update our maintenance practices.
37 Application of substation safety signs to comply with latest version of ANSI/NESC. Relay
standards updated Capacitor Protection guide, Alarm guide, Cyber security guide. Breaker
standard updated to include magnetic actuators (new technology for us) and battery
standard updated per periodic review
40 Relay Maint. and Const. for updated supplements to PRC - 005 of 001b, 002, and 003.
Updated transformer and breaker specifications; Protection System Maintenance Plan
21 Transformers, SF6 Breakers
30 None
Page94
SUBSTATION STANDARDS CHANGED RECENTLY AND WHY
27 We require our 13.8kV switchgear to be arc resistant type 2B rated for increased crew safety
while racking the breakers in and out. We added card readers to PDC buildings and added
building access, building temperature and fire alarms to our SCADA system to better monitor and
control building access and decrease response time in the event of a fire. We automated the
drive - through gate with card reader control at new substations with the open and closed
positions reported to SCADA to monitor and control access to the substation. We also install a
manual locked man gate to be used if the automated gate does not operate. We revised our
transformer specifications to inlcude transformer monitioring equipment from Dynamics Ratings
359 We are in the process of 'overhauling' all of our Standards for Transmission and Substations.
Currently we revised the 230/69 kV entire substation standard and created a manual. The
manual consist of Standard design intent, design criteria, relay design intent, relay and control
acceptable devices and protection requirements, Construction work and bid template and testing
and commissioning requirements. This manual will be a model to be used when doing the 500
and 69/12 kV substations, which we intend to have done by the end of the year. We are also
updating our entire grounding standards for all substations. We have also updated our
equipment specifications to include more industry proven devices that will help move us from
time based maintenance to a condition based maintenance approach. For instance we now
require on - line DGA devices to eliminate employees from taking samples every 6 months on
our transformers. We are also using bushing monitoring devices for our transformers to move
away from Doble testing.
2014 T&D: Substations
IDENTIFY ANY SOFTWARE PRODUCTS USED OR BEING EVALUATED FOR
SUBSTATION JOB ESTIMATING
Calculation
used
SP60.1
ID Response
22 None
31 Internally developed excel spreadsheets
28 We are currently using Excel for estimating and @Risk for Monte- Carlos
analysis. We are also evaluating ???U.S Cost?? and HeavyBid estimating
software for future use.
33 in house estimating program
23 Spreadsheets and in house software tool.
37 Maximo and Business Objects
38 none
40 Maximo & Excel
21 Cascade
30 Excel
27 Microsoft Excel
359 Excel; Bulk Power Estimator (internally developed tool)
32 No Software
Page96
NEW
Substation Automation
Substation Automation Initiatives
ID#
RTU Replacement
LTU position indicators
Automation of station voltage
regulators (to provide volt/var
optimization) and feedback
monitoring.
Installing standard tap
changer control systems
compatible with volt/var
optimization schemes.
Replacing of the old 500kV stations
fault recorders with new DFRs.
Electromechanical relays are
being replaced with
microprocessor based
relaying that provides
enhanced functionalities.
A multiyear plan is continuing
to replace older units and
31 replace with units that will
communicate with micro processor relays
Smart Grid installations
continue which incorporates
transformer monitoring
Process beginning on Auto
LTC's to install transmitter
module to inhibit LTC ranges
on auto's near generation.
We have a proactive plan to replace
and/or install a specific number each
year at key substations
Relay protection upgrade
projects continue to meet
current ERCOT/NERC relay
requirements
32 TRANS - None
TRANS - Transformers are
monitored.
TRANS -Yes
TRANS - In all switchyards
TRANS - Replacement
schedule is included in 20
year plan
Multiyear SIRIUS Program to
37 replace Siemens 44550
RTU??s
Pilot Breaker Monitoring
program
Integrated Digital Fault Recorders
MICROPROCESSOR PROTECTIVE
Facility Monitoring
CONTROL
Systems
RELAYING Other
SYSTEMS
On-line monitoring
Replacement of old RTUs with
new 61850 compatible logic
28
control devices (between 10 20 devices per year).
Video feeds and equipment
monitoring cameras to provide
N/A
remote video monitoring
system.
TRANS - All control houses
are monitored to varing
degrees
Implementation of Distributed
Disturbance Monitoring System in
accordance with PRC - 002 DME
requirements. Also implementing
Bitronics meters to replace aging
Qualitrol (Hathaway) DFR??s
97
NEW
Substation Replacement
SUBSTATION REPLACEMENT PROGRAMS
POWER
TRANSFORMERS
ID#
I nstrument
Transformers
Secondary
Communications
Switch Gear
Circuit Breakers
Relays
Life Cycle
Replacement
24
Program based on
condition
Life Cycle
Replacement
Program based on
condition
Life Cycle
Replacement
Program based on
condition
As needed of
As needed
enhance functionality
As needed
Replace
transformers based
27
upon transformer
index rating
Replacing switch
gear with PDC or
free standing
breaker. (several a
year)
Replace 5 - 10
OCB's each year
Electromechanical
relays are being
replaced.
upon failure
Microwave radios are
being replaced.
Replacing airblast
breakers and
associated
compressor systems.
Dual pressure SF6
and bulk oil breakers
are also being
replaced.
Electromechanical
relays are being
replaced with
microprocessor
based relays.
Proactive
replacement
program.
1. Batteries and
chargers, 2. Tone and
test panels. 3.
Microwave links are
being converted from
analog to digital and
MPLS.
Poor performing
models proactive
Automation/installatio
n of electronic relays
FBS breakers
replacement
continues and
micro - processor
upgrades
Continue SCADA RTU
replacements
OCB, Airblast, high
SF6 leak rate
Electro - mechanical None
At fialure;not supported
by vendor;or as
required to meet project
specs
Driven by capacity
needs and failures
Driven by capacity
needs and failures
Replaced when
End - of - life
28 loading exceeds
replacements.
capacity or on failure.
30
Split winding 50MVA
units proactive
31 Yes
32
Replace on loading
or testing
37
Driven by capacity
needs and failures
Yes - nearly
completed
None
98
Thank you for your Input and Participation!
Your Presenters
Dave Canon
[email protected]
817-980-7909
Debi McLain Cook
[email protected]
760-272-7277
Ken Buckstaff
[email protected]
310-922-0783
Dave Carter
[email protected]
414-881-8641
Tim. Szybalski
[email protected]
301-535-0590
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 | Follow our updates on LinkedIn
Satellite Offices
Corporate Offices
California
400 Continental Blvd. Suite 600
El Segundo, CA 90245
(310) 426-2790
Maryland
New York | Texas | Washington | Wisconsin
3 Bethesda Metro Center Suite
700
Bethesda, MD 20814
(301) 961-1505
99
Substation practice Questions
2014 Proposed by Process
◼ Asset Management
◼ Strategy
 Substation automation
 Mobile spares
◼ Sustain Substations
 Maintenance planning
 Field maintenance
 Including NERC standards
 Replacement/upgrades
◼ Expand Substations
 Planning/Engineering/
Design
 Job estimating
 Field Construction
Strategy - Mobile Spares
•Role of spares/mobiles in overall strategy
•Decision support tools used for optimality of mobile/spares inventory
Sustain Substations
•Number of different facilities out of which field personnel work
•Most important initiative underway to improve Sub maintenance practices
•Changed maintenance cycle times for major pieces of equipment and why
•Changes in the degree of specialization of field work force
•WMS Vendor and year of implementation or last major upgrade: Substation
•Regular inspections performed at Substations
•Inspections added at Substations in the last year
•Maintenance deferred or reduced that have NOT caused problems
•Maintenance deferred or reduced that has caused problems
•Actions undertaken to reduce the occurrence of outage causes: Failed
Protection System Equipment; Failed AC Substation Equipment
Expand Substations
Planning/Engineering/Design
•Substation standards changed recently and why
•Substation automation initiatives: RTU replacement; On -line monitoring; LTC
position indicators; Integrated digital fault recorder systems; Microprocessor
protective control relaying systems; Equipment/facility monitoring systems;
Other
•Software products used /evaluated for substation job estimating
•Involving construction in developing job estimates
•Estimate Accuracy -- % of projects completed within +/ - noted %
•Average "Actual as a % of Estimate”
100
Key Success Factors:
strategic planning
Develop Substation Automation Strategy; includes RTU
replacement, on-line monitoring, microprocessor relaying
system; digital fault locating
Assure NERC Compliance; including substation
maintenance documentation
Update Standards; multiple standards, including
mitigation of copper theft
101
Key Success Factors:
Maintenance programs
Understand and comply with NERC requirements
Conduct regular inspections, and analyze the results to drive maintenance
activity
Review inspection program and maintenance cycles, using advanced
analytic tools
Coordinate maintenance activity with the asset management function, to
get the most from both maintenance and capital replacement .
Use mobile spares to reduce outage durations
102
Key Success Factors:
design and construction
Use multiple tools for estimating process
Involve construction in job estimating
Set and monitor estimating accuracy
Use Work Management Systems for scheduling jobs (SAP
and Maximo are most used)
Review Specialization of Field Workforce
103
Thank you for your Input and Participation!
Your Presenters
Dave Canon
[email protected]
817-980-7909
Debi McLain Cook
[email protected]
760-272-7277
Ken Buckstaff
[email protected]
310-922-0783
Dave Carter
[email protected]
414-881-8641
Tim. Szybalski
[email protected]
301-535-0590
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 | Follow our updates on LinkedIn
Satellite Offices
Corporate Offices
California
400 Continental Blvd. Suite 600
El Segundo, CA 90245
(310) 426-2790
Maryland
New York | Texas | Washington | Wisconsin
3 Bethesda Metro Center Suite
700
Bethesda, MD 20814
(301) 961-1505
104