Review of Reliability
Performance Data
Texas Reliability Entity, Inc.
Introduction
● This purpose of the presentation is to review
the performance data for the ERCOT region.



Overview of the reliability areas of interest
Review of key metrics for each area
Review of key observations
● Data is collected under Section 800, 1000 or
1600 of the NERC Rules of Procedure, not
under Section 400 (compliance and
enforcement).
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Texas RE Review of Reliability Performance
Texas RE Assessment of Reliability Performance report
for 2013 planned for publication April 2014 will provide:
● High-level 2013 data;
● Associated historical data;
● Analysis of 2013 and other historical data as indicators of current
state of ERCOT region;
● Observations that help connect the state of the region today to
the future; and
● Recommendations, where possible, for addressing threats to
reliability and gaps in data and analysis process.
●
●
2012 Texas RE Assessment of Reliability Performance (May 2013):
http://www.texasre.org/CPDL/2012%20Texas%20RE%20State%20of%20Reliability%20Report.pdf
NERC 2013 State of Reliability Report (May 2013):
http://www.nerc.com/pa/RAPA/PA/Performance%20Analysis%20DL/2013_SOR_May%2015.pdf
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NERC Reliability Impact Steering Committee’s
2013 Risks and Challenges
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Reliability Areas with Associated Data
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Event Analysis
Transmission Reliability Analysis (TADS)
Generation Reliability Analysis (GADS)
Protection System Misoperations
Frequency Control
Primary Frequency Response
Demand Response
Infrastructure Protection
Ancillary Service and Other Performance Trends
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Event Analysis – Key Observations 2011-2013
● Eighty-nine (89) reportable events
 80 events classified as Category 0 or Category 1 (little or
minimal follow-up per Events Analysis Program)
 304 event reports received
 94 lessons learned received
● Weather (37%), Equipment Failure (34%), and
Relaying Issues (9%) are the main causes
● 14 events in 2011-2013 involved multiple generator
trips
● Generation trips > 450 MW average 18 per quarter
 Boiler system (25 events), steam turbine/generator (21
events), external to plant (13 events), and balance of plant
(49 events) are the major causes.
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Event Analysis – Summary Data
Events
2011-2013 Event Cause
Total Events
Cat 4 & 5
Cat 3
Cat 2
Cat 1
Cat 0
Human error
0%
Generator Trips >450MW
30
Equipment Failure
30
37%
34%
Natural Disaster/Foreign
Interference
Relaying Issues
25
25
IT/Network Failures
Sabotage
21
20
Cyber Security
20
18
0%
4%
Unknown
1%
6%
15
15
9%
9%
Weather
12
10
10
7
6
5
5
5
5
4
3
3
3
2
0
Weather (37%),
Equipment Failure
(34%), and Relaying
Issues (9%) are the
main causes of events
0
2011 1st 2011 2nd 2011 3rd 2011 4th 2012 1st 2012 2nd 2012 3rd 2012 4th 2013 1st 2013 2nd 2013 3rd 2013 4th
Qtr
Qtr
Qtr
Qtr
Qtr
Qtr
Qtr
Qtr
Qtr
Qtr
Qtr
Qtr
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Event Analysis – Summary Data
OE-417 Reportable Disturbances
Total Customer Impact
# Reportable Events
DCS EVENTS
DCS Events
5
DCS Events > MSSC
4
700,000
7
600,000
6
500,000
5
400,000
4
300,000
3
200,000
2
100,000
1
3
2
1
0
2008
2009
2010
2011
2012
7
EEA 2
0
2009
2010
2011
2012
2013
• NERC metrics ALR6-2, ALR6-3,
ALR2-5 and ALR2-5
• Average three DCS events per year
since 2008
• Average four OE-417 reportable
outage events per year with average
customer impact of 490,000 per year
EEA EVENTS
EEA 1
0
2013
EEA 3
6
5
4
3
2
1
0
2008
2009
2010
2011
2012
2013
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Transmission Reliability – Key Observations
● 842 automatic outages and 2343 planned outages of 345kV lines
reported in Transmission Data Availability System (TADS) for 2010-2013
 Overall average circuit availability remained above 98.5%.
 Lightning, Contamination, and Unknown represented 73% of momentary outages.
 Lightning, Failed Substation Equipment, and Human Error represented 50% of
sustained outages.
 “Unknown” represents 20% of momentary outages. More accurate cause coding
will help future analysis.
 “Failed AC Substation Equipment” represented 21% of sustained outage events
and 25% of outage duration. “Failed AC Circuit Equipment” represented 7% of
sustained outage events vs. 39% of outage duration. Sharing of lessons learned
may reduce these events.
● Dependent Mode and Common Mode outages merit deeper review
 Represented 8.1% of momentary outage events, 33.2% of sustained outage
events and 49.1% of sustained outage duration for 2010-2013 combined
● Initial review of voltage control performance in progress
● Annual TADS summary is shared with OWG
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ERCOT Region TADS Data for 2011-2013
Outage Information
Automatic
Non-Automatic
Voltage Class
Metric
AC Transmission Outages Failed Protection System
Equipment
AC Transmission Outages Human Error
AC Transmission Outages Failed AC Substation
Equipment
AC Transmission Outages Failed AC Circuit Equipment
AC Transmission Outages Lightning
AC Transmission Outages Contamination
AC Transmission Outages Foreign Interference
Total
Element Availability
Percentage (APC)
Transmission System
Unavailability
2011
Duration
Count
(hrs)
279
1908.6
787
46712.4
2012
Duration
Count
(hrs)
230
682.6
516
36295.1
2011
2012
2013 (thru Q3)
300-399 kV
300-399 kV
300-399 kV
Outages/Number of circuits
2013 (thru Q3)
Duration
Count
(hrs)
139
1396.8
467
39832.6
2011
2012
2013 (thru Q3)
300-399 kV
300-399 kV
300-399 kV
Outages/100 mi/year
0.0305
0.0262
0.0204
0.0926
0.0804
0.0602
0.0677
0.0426
0.0175
0.2057
0.1307
0.0516
0.1320
0.0589
0.0204
0.4011
0.1809
0.0602
0.0508
0.0458
0.0087
0.1543
0.1407
0.0258
0.2067
0.2055
0.1309
0.6376
0.6333
0.3872
0.1667
0.1011
0.1018
0.5142
0.3116
0.3011
0.0567
0.0620
0.0029
0.1748
0.1910
0.0086
0.9300
0.7504
0.4112
2.8694
2.3121
1.1960
98.0625
98.6192
98.6287
1.9375
1.3808
10
1.3713
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Transmission Availability – ALR Metrics
Comparison of ERCOT to NERC metrics for Adequate Level of Reliability (ALR) measurements for 300-399 kV
2010
Metric
Definition
ERCOT
Metric
NERC
Metric
2011
ERCOT
NERC
Metric
Metric
ALR611
Automatic Outages
Initiated by Failed
Protection
Equipment
4.95%
6.26%
3.05%
5.55%
2.62%
5.19%
2.04%
3.43%
ALR612
Automatic Outages
Initiated by Human
Error
Automatic Outages
Initiated by Failed
AC Substation
Equipment
1.41%
6.57%
6.77%
6.87%
4.26%
6.55%
1.75%
3.78%
8.13%
5.59%
13.2%
8.14%
5.89%
6.19%
2.04%
2.66%
ALR614
Automatic Outages
Initiated by Failed
AC Circuit
Equipment
2.83%
5.89%
5.08%
5.37%
4.58%
5.01%
0.87%
1.89%
ALR615
Element Availability
Percentage
98.64%
98.41%
98.06%
97.86%
98.62%
97.89%
98.63%
98.94%
ALR613
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2012
ERCOT
NERC
Metric
Metric
2013 (thru Q3)
ERCOT
NERC
Metric
Metric
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Transmission Limits – IROL Exceedances
Count
60
Duration > 30mins
20mins < Duration ≤ 30mins
10Secs < Duration ≤ 10mins
Cumulative Minutes
10mins < Duration ≤ 20mins
250
229.13
50
40
West-North Exceedance for 11 minutes (Limit
reduced due to unsolved contingencies.
Transmission Watch issued)
200
171.38
150
30
West-North Exceedance for 13
minutes due to forced outages
NERC ALR 3-5
IROL/SOL
Exceedance (< 30
minutes)
Region
2011
2012
EI
194
172
WECC
734
927
TRE
103
82
Note: IROL/SOL
violations from 10 sec to
< 30 minutes
100
20
10
0
73.28
64.77
50
45.27
34.4
27.28
7.32
0.48
0
0 0
2011 Q1 2011 Q2 2011 Q3 2011 Q4 2012 Q1 2012 Q2 2012 Q3 2012 Q4 2013 Q1 2013 Q2 2013 Q3
Count of Interconnection Reliability Operation Limit (IROL) exceedances, categorized by duration
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Transmission Limits (Line Binding Constraints)
# Ckts
60
345kV Line Constraint Total Hrs
345kV Lines (# of Ckts That Are Binding Constraints)
138kV Line Constraint Total Hrs
138kV Lines (# of Ckts That Are Binding Constraints)
Hours
300.0
55
50
250.0
45
40
200.0
35
30
150.0
25
20
100.0
15
10
50.0
5
0
0.0
-
Lines represent the total number of lines which are a constraint during the month (i.e. a postcontingency overload > 100%)
Bars represent the total hours during the month that the line constraints occurred
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Transmission Outages – Common/Dependent Mode
Common Mode and Dependent Mode Outage Statistics
Avg AC Circuit Sustained Automatic Outage Mode
Avg AC Circuit Momentary Automatic Outage Mode
3.36%
3.75%
5.64%
0.00%
Single Mode
0.99%
Dependent Mode
Initiating
0.30%
Dependent Mode
Initiating
24.04%
Dependent Mode
Common Mode
Common Mode
Common Mode Initiating
3.26%
66.77%
91.90%
Momentary Outage Modes Comparison
2010
2011
Single Mode
Dependent Mode
Common Mode Initiating
2012
Sustained Outage Modes Comparison
2013
2010
2011
2012
2013
30.0%
8.0%
7.0%
•
•
Dependent Mode outages
(defined as an automatic
outage of an element which
occurred as a result of another
outage)
Common Mode outages
(defined as one or more
automatic outages with the
same initiating cause and
occur nearly simultaneously).
Common Mode & Dependent
Mode Outage Comparison
2010-2013 (Q3)
TRE
NERC
Momentary
Cause
8.1%
15.6%
Sustained
Cause
33.2%
28.9%
Sustained
Duration
49.1%
49.4%
25.0%
6.0%
20.0%
5.0%
15.0%
4.0%
3.0%
10.0%
2.0%
5.0%
1.0%
0.0%
0.0%
Dependent Mode Dependent Mode Common Mode
Initiating
Common Mode
Initiating
Dependent Mode Dependent Mode Common Mode
Initiating
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Common Mode
Initiating
Note: Multi-year average
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Voltage Control (Generation Buses) – Dec 2013
1.06
Voltage Profile Control Point
1.04
1.02
1.00
0.98
0.96
Telemetry flat-lined since 11/25
0.94
-
One-minute PI data from 52 generation buses (138kV and 345kV). Includes both fossil and wind generation.
Boxes represent the 25%/75% percentiles. Leader lines show the min/max voltage during the period.
Data is normalized so that the 1.0 per-unit value represents the control point from the seasonal voltage
profile
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Bus 1
Bus 2
Bus 3
Bus 4
Bus 5
Bus 6
Bus 7
Bus 8
Bus 9
Bus 10
Bus 11
Bus 12
Bus 13
Bus 14
Bus 15
Bus 16
Bus 17
Bus 18
Bus 19
Bus 20
Bus 21
Bus 22
Bus 23
Bus 24
Bus 25
Bus 26
Bus 27
Bus 28
Bus 29
Bus 30
Bus 31
Bus 32
Bus 33
Bus 34
Bus 35
Bus 36
Bus 37
Bus 38
Bus 39
Bus 40
Bus 41
Bus 42
Bus 43
Bus 44
Bus 45
Bus 46
Bus 47
Bus 48
Bus 49
Bus 50
Bus 51
Bus 52
Bus 53
Bus 54
Bus 55
Bus 56
Bus 57
Bus 58
Bus 59
Bus 60
Bus 61
Voltage Control (Transmission Buses) – Dec 2013
370.000
365.000
360.000
355.000
350.000
345.000
340.000
335.000
330.000
One-minute PI data from 61 345kV transmission buses.
Boxes represent the 25%/75% percentiles. Leader lines show the min/max voltage during the period.
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Voltage Control by Weather Zone
One-minute PI data from one selected generation bus in each weather zone, normalized from seasonal profile
Voltage Control Chart for South - 2013
Voltage Control Chart for North - 2013
1.04
1.04
1.03
1.03
1.02
1.02
1.01
1.01
1
1
0.99
0.99
0.98
0.98
0.97
0.97
0.96
0.96
Voltage Control Chart for North Central - 2013
Voltage Control Chart for Coast - 2013
1.04
1.04
1.03
1.03
1.02
1.02
1.01
1.01
1
1
0.99
0.99
0.98
0.98
0.97
0.97
0.96
0.96
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Generation Reliability – Key Observations
● Mandatory GADS reporting for units > 50 MW began
in Jan 2012
● Mandatory GADS reporting for units > 20 MW
(excluding wind) began Jan 2013
● Immediate forced outage and forced de-rate events
were reviewed for common failure modes
● ERCOT-region GADS metrics compare favorably
with NERC fleet-wide metrics in most cases
● Quarterly GADS summary is shared with PDCWG
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Review of ERCOT-Region GADS Data
EFORd
2012
2013 Q1-Q3
12.00%
NERC 2008-2012
Fleet Avg EFORd
Fossil
10.00%
8.00%
9.71
Coal
8.29
Gas
16.63
Lignite
6.00%
Nuclear
3.94
Jet Engine
9.87
Gas Turbine
4.00%
6.99
CC Block
10.49
4.57
2.00%
0.00%
-
EFORd: Equivalent Forced Outage Rate Demand. Measures the probability that a unit will not meet its
demand periods for generating requirements because of forced outages or derates.
ERCOT units only, based on GADS submittal data (no wind, or units under 50 MW in 2012)
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Review of ERCOT-Region GADS Data
Weighted Equivalent
Availability Factor
2012
NERC 2008-2012
Fleet Avg WEAF
2013 (Q1-Q3)
100.00%
Fossil
90.00%
80.00%
70.00%
60.00%
93.78%
93.38%
86.96%
88.90%
92.03%
91.57%
90.73%
86.73%
30.00%
88.10%
84.67%
88.54%
85.19%
84.00%
88.58%
88.67%
88.12%
85.74%
85.25%
82.67%
83.86%
85.52%
81.49%
86.25%
86.10%
84.61%
83.75%
40.00%
86.83%
85.43%
50.00%
82.90
Coal
83.08
Gas
82.82
Lignite
84.80
Nuclear
87.66
Jet Engine
89.14
Gas Turbine
90.15
CC Block
86.63
20.00%
10.00%
0.00%
-
Equivalent Availability Factor: Measures the percentage of net maximum generation that could be provided
after all types of outages are taken into account. Weighted by unit MW capacity.
ERCOT units only, based on GADS submittal data (no wind, or units under 50 MW in 2012)
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Review of GADS Forced Outage Data
Major System
Number of
Immediate Forced Outage events
2012 and 2013 (thru Q3)
Total Duration (hrs)
Avg Duration per Event
(hrs)
Boiler System
419
17823.8
42.5
Nuclear Reactor
1
226.9
226.9
Balance of Plant
658
23671.4
36.0
Steam Turbine/Generator
641
52916.9
82.6
Gas Turbine/ Jet Engine/Expander
1011
40525.7
40.1
Heat Recovery Steam
Generator/Other Combined Cycle
91
4047.3
44.5
Pollution Control Equipment
50
1068.9
21.4
External
135
3115.5
23.1
Regulatory, Safety, Environmental
12
9081.3
756.8
Personnel/Procedure Errors
83
562.4
6.8
Balance of Plant
Forced Outage Events
3.1%
5.0%
Steam Turbine/Generator
0.4%
6.7%
0.8%
1.9%
3.4%
24.5%
Balance of Plant
Forced Outage Duration
2.3%
0.4%
Steam Turbine/Generator
17.5%
3.0%
Gas Turbine/ Jet
Engine/Expander
Gas Turbine/ Jet
Engine/Expander
Heat Recovery Steam
Generator/Other Combined
Cycle
Pollution Control Equipment
Heat Recovery Steam
Generator/Other Combined
Cycle
Pollution Control Equipment
External
External
30.0%
37.7%
23.9%
Regulatory, Safety,
Environmental
39.2%
Personnel/Procedure Errors
Regulatory, Safety,
Environmental
Personnel/Procedure Errors
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Protection System Misoperations – Key Observations
● Relatively flat trend in overall misoperation rate since Jan 2011
 2011 overall rate of 8.85% compared to 2012 overall rate of 9.99%
and 2013 rate (thru Q3) of 8.31%
 Slight upward trend in 345kV rate of 9.01% in 2011 compared to
2012 345kV rate of 11.34% and 2013 rate (thru Q3) of 12.30%
● Incorrect settings/logic (43%), Relay failure (21%), and
Communications failure (10%) are the main causes. This is
similar to NERC-wide trend.
 Relay failures evenly split between electromechanical and
microprocessor-based relay systems
● Transmission lines (62%), Transformers (12%), and Generators
(10%) are the main facilities affected by misoperations
 83% of generator misoperations occur with no system fault
● 52% of misoperations attributable to “human” performance
● Quarterly misoperation summaries are shared with SPWG
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ERCOT Region Protection System Misoperations
% Misoperation Rate
Overall
345kV
138kV
18.0%
NERC 2013 Q1/Q2
Misoperation Rates
Region
Q1
Q2
16.0%
FRCC
12.8%
13%
14.0%
MRO
12.6%
11%
NPCC
7.2%
7%
16.9%
17%
8.9%
9%
SPP
14.3%
13%
TRE
8.9%
8%
12.0%
RFC
10.0%
SERC
8.0%
Note: NERC
misoperation rates do
not include Failure to
Reclose.
6.0%
4.0%
2.0%
0.0%
2011 Q1 2011 Q2 2011 Q3 2011 Q4 2012 Q1 2012 Q2 2012 Q3 2012 Q4 2013 Q1 2013 Q2 2013 Q3
-
Lines show percentage of protection system operations that are misoperations, including Failure to Reclose
Percent Misoperation Rate is normalized based on number of system events
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ERCOT Region “Human Error” Misoperation Reports
Protection System Misoperations - Human Error %
70.00%
60.00%
50.00%
40.00%
30.00%
20.00%
10.00%
0.00%
2011 Q1 2011 Q2 2011 Q3 2011 Q4 2012 Q1 2012 Q2 2012 Q3 2012 Q4 2013 Q1 2013 Q2 2013 Q3 2013 Q4
-
Percentage of Protection System Misoperations due to human factors, i.e. settings errors, wiring errors,
design errors, etc.
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Frequency Control and Primary Frequency
Response – Key Observations
● Frequency profile has narrowed slightly since start of nodal
market. However, it has also shifted higher (to approximately
60.015 Hz), in part due to impact of governor response from wind
generators for high frequencies.
● For 2012, time error corrections averaged 9.4 per month (or an
average of one (1) second of per day), always for slow time error.
For 2013, time error corrections averaged 1.8 each month with
zero corrections from July thru November.
● Long term trends for primary frequency response show
improvement.
● Some issues with non-frequency responsive units providing
Responsive Reserve Service.
● Regulation exhaustion rates have shown improvement since
implementation of SCR773.
● NERC recalculated the BAL-003-1 frequency response obligation
from 286 MW per 0.1 Hz to 412 MW per 0.1 Hz.
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Frequency Control
% Outside 30 mHZ Epsilon-1
CPS-1
25.0%
175.00
170.00
20.0%
165.00
NERC CPS1
Performance
Eastern-2010
130
Eastern-2011
128
Eastern-2012
130
Western-2010
165
Western-2011
155
Western-2012
147
ERCOT-2010
150
ERCOT-2011
148
ERCOT-2012
160
ERCOT-2013
YTD
166
160.00
15.0%
155.00
150.00
10.0%
145.00
140.00
5.0%
135.00
130.00
0.0%
Jan-11
Feb-11
Mar-11
Apr-11
May-11
Jun-11
Jul-11
Aug-11
Sep-11
Oct-11
Nov-11
Dec-11
Jan-12
Feb-12
Mar-12
Apr-12
May-12
Jun-12
Jul-12
Aug-12
Sep-12
Oct-12
Nov-12
Dec-12
Jan-13
Feb-13
Mar-13
Apr-13
May-13
Jun-13
Jul-13
Aug-13
Sep-13
Oct-13
Nov-13
Dec-13
125.00
-
Bars represent % of time that frequency is outside 30 mHz Epsilon-1 (ε1) value which is used
calculation of CPS 1 for the ERCOT region per BAL-001 (i.e. < 59.97 Hz or > 60.03 Hz)
Based on one-minute PI data
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Primary Frequency Response Performance
1200
ERCOT REGION PRIMARY FREQUENCY RESPONSE (MW per 0.1 Hz at B-point)
Gen Unit Trips > 450 MW
1100
1000
900
800
Primary Frequency
Response provided by
generating units during loss
of generation events is
showing an improving trend
since summer 2012.
ERCOT target is 420 MW
per 0.1 Hz (green line).
NERC minimum is 286 MW
per 0.1 Hz (red line) per
BAL-003-1 for 2013 (Will
change to 412 MW per 0.1
Hz for 2014)
700
600
500
400
300
•
200
100
•
0
2011 Q1 2011 Q2 2011 Q3 2011 Q4 2012 Q1 2012 Q2 2012 Q3 2012 Q4 2013 Q1 2013 Q2 2013 Q3 2013 Q4
27
Leader lines show
min/max for the quarter.
Boxes indicate 25%/75%
quartiles.
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Demand Response, Infrastructure Protection, and
Ancillary Service Performance – Observations
● Demand Response
 Reported demand response capacity increased by 25% since
January 2013, to ~ 6000 MW as of Sept 2013
● Infrastructure Protection
 Texas RE monitors reports from the System Security Response
Group (SSRG)
 Since Jan 2011, reports of copper theft and substation intrusion have
averaged 12 per month, with a maximum of 28 in one month
● Ancillary Service/Other Performance issues
 Some failure of entities to maintain adequate capacity to cover
ancillary service obligations
 Some generators not current with required reactive tests
 Some generators not current with required governor tests
 Some entities repeatedly fall short of TAC-approved telemetry
availability level
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Questions?
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January 9, 2014