review of reliability performance data

Texas Reliability Entity, Inc.

Review of Reliability Performance Data

2

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).

ROS MeetingJanuary 9, 2014

3

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


4

NERC Reliability Impact Steering Committee’s 2013 Risks and Challenges


5

Reliability Areas with Associated Data

● 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


6

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.


7

Event Analysis – Summary Data


0%

34%

4%

9%9%

6%1%

0%

37%

Human error

Equipment Failure

Natural Disaster/ForeignInterferenceRelaying Issues

IT/Network Failures

Sabotage

Cyber Security

Unknown

Weather

2011-2013 Event Cause

Weather (37%), Equipment Failure (34%), and Relaying Issues (9%) are the main causes of events

12

21

18

2

5

3 3

56

43

7

0

5

10

15

20

25

30

0

5

10

15

20

25

30

2011 1stQtr

2011 2ndQtr

2011 3rdQtr

2011 4thQtr

2012 1stQtr

2012 2ndQtr

2012 3rdQtr

2012 4thQtr

2013 1stQtr

2013 2ndQtr

2013 3rdQtr

2013 4thQtr

EventsTotal Events Cat 4 & 5 Cat 3 Cat 2 Cat 1 Cat 0 Generator Trips >450MW

8

Event Analysis – Summary Data


• 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

0

1

2

3

4

5

2008 2009 2010 2011 2012 2013

DCS Events DCS Events > MSSCDCS EVENTS

0

1

2

3

4

5

6

7

2008 2009 2010 2011 2012 2013

EEA 1 EEA 2 EEA 3EEA EVENTS

0

1

2

3

4

5

6

7

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

2009 2010 2011 2012 2013

Total Customer Impact # Reportable EventsOE-417 Reportable Disturbances

9

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


10


ERCOT Region TADS Data for 2011-2013

2011 2012 2013 (thru Q3)

Outage Information CountDuration

(hrs) CountDuration

(hrs) CountDuration

(hrs)

Automatic 279 1908.6 230 682.6 139 1396.8

Non-Automatic 787 46712.4 516 36295.1 467 39832.6

2011 2012 2013 (thru Q3) 2011 20122013 (thru

Q3)Voltage Class 300-399 kV 300-399 kV 300-399 kV 300-399 kV 300-399 kV 300-399 kV

Metric Outages/Number of circuits Outages/100 mi/yearAC Transmission Outages - Failed Protection System

Equipment 0.0305 0.0262 0.0204 0.0926 0.0804 0.0602AC Transmission Outages -

Human Error 0.0677 0.0426 0.0175 0.2057 0.1307 0.0516AC Transmission Outages -

Failed AC Substation Equipment 0.1320 0.0589 0.0204 0.4011 0.1809 0.0602

AC Transmission Outages - Failed AC Circuit

Equipment 0.0508 0.0458 0.0087 0.1543 0.1407 0.0258AC Transmission Outages -

Lightning 0.2067 0.2055 0.1309 0.6376 0.6333 0.3872AC Transmission Outages -

Contamination 0.1667 0.1011 0.1018 0.5142 0.3116 0.3011AC Transmission Outages -

Foreign Interference 0.0567 0.0620 0.0029 0.1748 0.1910 0.0086Total 0.9300 0.7504 0.4112 2.8694 2.3121 1.1960

Element Availability Percentage (APC) 98.0625 98.6192 98.6287

Transmission System Unavailability 1.9375 1.3808 1.3713

11

Transmission Availability – ALR Metrics


2010 2011 2012 2013 (thru Q3)

Metric Definition ERCOTMetric

NERCMetric

ERCOTMetric

NERC Metric

ERCOTMetric

NERCMetric

ERCOTMetric

NERCMetric

ALR6-11

Automatic Outages Initiated by Failed Protection Equipment

4.95% 6.26% 3.05% 5.55% 2.62% 5.19% 2.04% 3.43%

ALR6-12

Automatic Outages Initiated by Human Error

1.41% 6.57% 6.77% 6.87% 4.26% 6.55% 1.75% 3.78%

ALR6-13

Automatic Outages Initiated by Failed AC Substation Equipment

8.13% 5.59% 13.2% 8.14% 5.89% 6.19% 2.04% 2.66%

ALR6-14

Automatic Outages Initiated by Failed AC Circuit Equipment

2.83% 5.89% 5.08% 5.37% 4.58% 5.01% 0.87% 1.89%

ALR6-15

Element Availability Percentage

98.64% 98.41% 98.06%

97.86% 98.62% 97.89% 98.63% 98.94%

Comparison of ERCOT to NERC metrics for Adequate Level of Reliability (ALR) measurements for 300-399 kV

12

Transmission Limits – IROL Exceedances


171.38

229.13

0.48

45.27

73.2864.77

7.32

34.4 27.28

0 0 0

50

100

150

200

250

0

10

20

30

40

50

60

2011 Q1 2011 Q2 2011 Q3 2011 Q4 2012 Q1 2012 Q2 2012 Q3 2012 Q4 2013 Q1 2013 Q2 2013 Q3

Duration > 30mins 20mins < Duration ≤ 30mins 10mins < Duration ≤ 20mins

10Secs < Duration ≤ 10mins Cumulative MinutesCount

Count of Interconnection Reliability Operation Limit (IROL) exceedances, categorized by duration

West-North Exceedance for 13 minutes due to forced outages

West-North Exceedance for 11 minutes (Limit reduced due to unsolved contingencies. Transmission Watch issued)

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

13

Transmission Limits (Line Binding Constraints)

- Lines represent the total number of lines which are a constraint during the month (i.e. a post-contingency overload > 100%)

- Bars represent the total hours during the month that the line constraints occurred


0.0

50.0

100.0

150.0

200.0

250.0

300.0

0

5

10

15

20

25

30

35

40

45

50

55

60

345kV Line Constraint Total Hrs 138kV Line Constraint Total Hrs345kV Lines (# of Ckts That Are Binding Constraints) 138kV Lines (# of Ckts That Are Binding Constraints)# Ckts Hours

14

Transmission Outages – Common/Dependent Mode

Common Mode and Dependent Mode Outage Statistics


• 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).

91.90%

0.99%

3.75%3.36%

0.00%

Avg AC Circuit Momentary Automatic Outage Mode

Single Mode

Dependent ModeInitiating

Dependent Mode

Common Mode

Common Mode Initiating

66.77%

3.26%

24.04%

5.64%0.30%

Avg AC Circuit Sustained Automatic Outage Mode

Single Mode


Dependent Mode

Common Mode

Common Mode Initiating

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%

6.0%

7.0%

8.0%


Dependent Mode Common Mode Common ModeInitiating

2010 2011 2012 2013Momentary Outage Modes Comparison

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%


Dependent Mode Common Mode Common ModeInitiating

2010 2011 2012 2013Sustained Outage Modes Comparison

Common Mode & Dependent Mode Outage Comparison2010-2013 (Q3)

TRE NERC

Momentary Cause

8.1% 15.6%

Sustained Cause

33.2% 28.9%

Sustained Duration

49.1% 49.4%

Note: Multi-year average

15

Voltage Control (Generation Buses) – Dec 2013

- 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

profileROS Meeting

January 9, 2014

0.94

0.96

0.98

1.00

1.02

1.04

1.06

Vol

tage

Profi

le C

ontr

ol P

oint

Telemetry flat-lined since 11/25

16

Voltage Control (Transmission Buses) – Dec 2013

- 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.


330.000

335.000

340.000

345.000

350.000

355.000

360.000

365.000

370.000

Bus 1

Bus 2

Bus 3

Bus 4

Bus 5

Bus 6

Bus 7

Bus 8

Bus 9

Bus 1

0Bu

s 11

Bus 1

2Bu

s 13

Bus 1

4Bu

s 15

Bus 1

6Bu

s 17

Bus 1

8Bu

s 19

Bus 2

0Bu

s 21

Bus 2

2Bu

s 23

Bus 2

4Bu

s 25

Bus 2

6Bu

s 27

Bus 2

8Bu

s 29

Bus 3

0Bu

s 31

Bus 3

2Bu

s 33

Bus 3

4Bu

s 35

Bus 3

6Bu

s 37

Bus 3

8Bu

s 39

Bus 4

0Bu

s 41

Bus 4

2Bu

s 43

Bus 4

4Bu

s 45

Bus 4

6Bu

s 47

Bus 4

8Bu

s 49

Bus 5

0Bu

s 51

Bus 5

2Bu

s 53

Bus 5

4Bu

s 55

Bus 5

6Bu

s 57

Bus 5

8Bu

s 59

Bus 6

0Bu

s 61

17

Voltage Control by Weather ZoneOne-minute PI data from one selected generation bus in each weather zone, normalized from seasonal profile

0.96

0.97

0.98

0.99

1

1.01

1.02

1.03

1.04Voltage Control Chart for Coast - 2013

0.96

0.97

0.98

0.99

1

1.01

1.02

1.03

1.04Voltage Control Chart for South - 2013

0.96

0.97

0.98

0.99

1

1.01

1.02

1.03

1.04Voltage Control Chart for North - 2013

0.96

0.97

0.98

0.99

1

1.01

1.02

1.03

1.04Voltage Control Chart for North Central - 2013

18

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

19

Review of ERCOT-Region GADS Data


- 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)

NERC 2008-2012 Fleet Avg EFORd

Fossil 9.71

Coal 8.29

Gas 16.63

Lignite 6.99

Nuclear 3.94

Jet Engine 9.87

Gas Turbine 10.49

CC Block 4.57

0.00%

2.00%

4.00%

6.00%

8.00%

10.00%

12.00%2012 2013 Q1-Q3EFORd

20

Review of ERCOT-Region GADS Data


- 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)

NERC 2008-2012 Fleet Avg WEAF

Fossil 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

85

.43

%

83

.75

%

86

.10

%

81

.49

%

83

.86

%

85

.25

%

88

.12

%

88

.58

%

85

.19

%

84

.67

%

86

.73

%

91

.57

%

88

.90

%

93

.38

%

86

.83

%

84

.61

%

86

.25

%

85

.52

%

82

.67

%

85

.74

%

88

.67

%

84

.00

%

88

.54

%

88

.10

%

90

.73

%

92

.03

%

86

.96

%

93

.78

%

0.00%

10.00%

20.00%

30.00%

40.00%

50.00%

60.00%

70.00%

80.00%

90.00%

100.00%

2012 2013 (Q1-Q3)Weighted Equivalent Availability Factor

21

Review of GADS Forced Outage Data


Major System Number ofImmediate 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

24.5%

23.9%37.7%

3.4%1.9%

5.0%0.4%

3.1%

Balance of Plant

Steam Turbine/Generator

Gas Turbine/ JetEngine/Expander

Heat Recovery SteamGenerator/Other CombinedCyclePollution Control Equipment

External

Regulatory, Safety,Environmental

Personnel/Procedure Errors

Forced Outage Events

17.5%

39.2%

30.0%

3.0%

0.8% 2.3%6.7%

0.4%

Balance of Plant

Steam Turbine/Generator

Gas Turbine/ JetEngine/Expander

Heat Recovery SteamGenerator/Other CombinedCyclePollution Control Equipment

External

Regulatory, Safety,Environmental

Personnel/Procedure Errors

Forced Outage Duration

22

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


23

ERCOT Region Protection System Misoperations


- 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

NERC 2013 Q1/Q2 Misoperation Rates

Region Q1 Q2

FRCC 12.8% 13%

MRO 12.6% 11%

NPCC 7.2% 7%

RFC 16.9% 17%

SERC 8.9% 9%

SPP 14.3% 13%

TRE 8.9% 8%

Note: NERC misoperation rates do not include Failure to Reclose.

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

14.0%

16.0%

18.0%

2011 Q1 2011 Q2 2011 Q3 2011 Q4 2012 Q1 2012 Q2 2012 Q3 2012 Q4 2013 Q1 2013 Q2 2013 Q3

Overall 345kV 138kV% Misoperation Rate

24

ERCOT Region “Human Error” Misoperation Reports


0.00%

10.00%

20.00%

30.00%

40.00%

50.00%

60.00%

70.00%

2011 Q1 2011 Q2 2011 Q3 2011 Q4 2012 Q1 2012 Q2 2012 Q3 2012 Q4 2013 Q1 2013 Q2 2013 Q3 2013 Q4

Protection System Misoperations - Human Error %

- Percentage of Protection System Misoperations due to human factors, i.e. settings errors, wiring errors, design errors, etc.

25

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.

26

Frequency Control


- 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

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

125.00

130.00

135.00

140.00

145.00

150.00

155.00

160.00

165.00

170.00

175.00

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

Jan-

11Fe

b-11

Mar

-11

Apr-

11M

ay-1

1Ju

n-11

Jul-1

1Au

g-11

Sep-

11O

ct-1

1N

ov-1

1D

ec-1

1Ja

n-12

Feb-

12M

ar-1

2Ap

r-12

May

-12

Jun-

12Ju

l-12

Aug-

12Se

p-12

Oct

-12

Nov

-12

Dec

-12

Jan-

13Fe

b-13

Mar

-13

Apr-

13M

ay-1

3Ju

n-13

Jul-1

3Au

g-13

Sep-

13O

ct-1

3N

ov-1

3D

ec-1

3

% Outside 30 mHZ Epsilon-1 CPS-1

27

Primary Frequency Response Performance


0

100

200

300

400

500

600

700

800

900

1000

1100

1200

2011 Q1 2011 Q2 2011 Q3 2011 Q4 2012 Q1 2012 Q2 2012 Q3 2012 Q4 2013 Q1 2013 Q2 2013 Q3 2013 Q4

ERCOT REGION PRIMARY FREQUENCY RESPONSE (MW per 0.1 Hz at B-point)Gen Unit Trips > 450 MW

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)

•Leader lines show min/max for the quarter.•Boxes indicate 25%/75% quartiles.

28

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

Questions?


review of reliability performance data

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