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Project No. 49852, Review of Summer 2019
ERCOT Market Performance
ERCOT’s Review of Summer 2019
ERCOT Public
October 11, 2019
ERCOT Public
Key Observations for Summer 2019
• Early summer was mild, and August was very hot (September was also above
normal).
• There were many days with tight conditions, and an Energy Emergency Alert
(EEA) Level 1 was declared twice.
– Emergency Response Service (ERS) deployments prevented the need for EEA2.
• Peak demand day saw higher Intermittent Renewable Resource (IRR)
production.
– As a result, it was not one of the highest-priced days, and there was no EEA.
• Tightest conditions frequently occurred earlier than time of peak demand.
• Resource performance continues to outpace historical patterns.
• Overall, the market outcomes supported reliability needs.
• Even with significant pricing events, there were no mass transitions.
2
(Board slide 2)
ERCOT Public
Outline
• Summer overall
• Peak week
• Peak day
• EEA days
• Commercial information
3
(Board slide 3, modified)
ERCOT Public
Summer Overall
ERCOT Public
Weather
• June – July 2019 was the coolest since 2007*
• August 2019 was the 2nd hottest on record*
• Overall, June – August 2019 was 21st hottest on record
• Extended period of above normal heat in Texas – but not much
extreme heat (105 or greater)
5
• Comparison to 2018 differed
across the state
– Dallas cooler
– Austin/San Antonio similar
– Houston, South Texas hotter
• More heat along coast
*Based on mean temperature
(Board slide 4)
ERCOT Public
Daily Peak Hour Demands
6
40
45
50
55
60
65
70
75
801 3 5 7 9
11
13
15
17
19
21
23
25
27
29 1 3 5 7 9
11
13
15
17
19
21
23
25
27
29
31 2 4 6 8
10
12
14
16
18
20
22
24
26
28
30
June July August
GW
Higher demands
in August
June was
cool and wet
July was warm
and dry
(Board slide 5)
ERCOT Public
Comparison of Summer Monthly Peak Demand
• A new all-time record for
system demand peak was set
at 74,666 MW on Aug. 12,
2019.
• A new all-time record for
weekend system demand
peak was set at 71,915 MW
on Aug. 11, 2019.
• Monthly peak demands in
June and July 2019 were
lower than 2018.
7
* Data: Hourly integrated peak demand as published in the ERCOT D&E report.
67,6
33
69,5
12
67,8
89
69,1
23
73,4
73
69,9
19
68,1
59
70,8
55
74,6
66
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
June July August
MW
2017 2018 2019
(Board slide 6)
ERCOT Public
Day-Ahead Load Forecast Performance
8
June July August
Average
YTD
MAPE 2019
Average
Monthly
MAPE3.03 2.21 2.15
2.50
Lowest
Daily
MAPE in
Month
0.95 0.64 0.40
Highest
Daily
MAPE in
Month
9.62 4.55 9.00
• Mean Absolute Percent Error (MAPE) for ERCOT Mid-Term Load Forecast
(MTLF) at 14:00 Day-Ahead trended as normal on average.
ERCOT Public
0
2000
4000
6000
8000
10000
12000
14000
16000
6/1
6/3
6/5
6/7
6/9
6/1
1
6/1
3
6/1
5
6/1
7
6/1
9
6/2
1
6/2
3
6/2
5
6/2
7
6/2
9
7/1
7/3
7/5
7/7
7/9
7/1
1
7/1
3
7/1
5
7/1
7
7/1
9
7/2
1
7/2
3
7/2
5
7/2
7
7/2
9
7/3
1
8/2
8/4
8/6
8/8
8/1
0
8/1
2
8/1
4
8/1
6
8/1
8
8/2
0
8/2
2
8/2
4
8/2
6
8/2
8
8/3
0
MW
2018 Wind 2019 Wind
2018 Peak
Day 7/19
2019 Peak
Day 8/12
Wind Output
• ERCOT had approximately 2,400 MWs of additional installed wind capacity
going into summer 2019 compared to 2018.
9
For hour ending 15:00
(Board slide 7)
ERCOT Public
Timing of Peak Load and Peak Net Load (Load-IRR)
10
12:00
13:00
14:00
15:00
16:00
17:00
18:00
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30
June July August
Hour
Max Load Time Max Net Load Time
• During summer 2019, the peak net load frequently occurred prior to peak load.
• Net peak load occurred prior to 4 p.m. nearly 2/3 of the days in August.
Time is rounded to nearest 5-minute interval
(Board slide 8)
ERCOT Public
Minimum Wind Generation for June – August
11
• Looking at the minimum wind each day for each hour and taking the average,
the wind output was lower earlier in the afternoon and higher later in the
afternoon when compared to 2018.
0
1000
2000
12 13 14 15 16 17 18
Min
imu
m A
ve
rage
Win
d M
W
HE
Summer-19 Wind Min Summer-18 Wind Min
(Board slide 9)
ERCOT Public
Day-Ahead IRR Forecast Performance
12
June July August
Average
YTD
2019
Wind
Average
Monthly
MAPE4.1 4.1 4.7 4.9
Solar
Average
Monthly
MAPE
6.38 4.94 4.79 6.98
• Mean Absolute Percent Error (MAPE) for ERCOT wind and solar forecast
at 14:30 Day-Ahead trended as normal on average.
*Solar calculations are for all hours where solar production is greater than 5 MW
ERCOT Public
COP Variance - September 2018 vs. 2019
13
For Hour Ending 1700
• Current Operating Plan (COP) – “A
plan by a QSE reflecting anticipated
operating conditions for each of the
Resources that it represents for each
hour in the next seven Operating
Days, including Resource operational
data, Resource Status, and Ancillary
Service Schedule.”
• COP variance shows the difference
between predicted online MWs as
reflected in the COPs and the actual
online MWs for thermal generators.
• The COP variance during the
Operating Day was higher in summer
2019, e.g., September.-18,000
-16,000
-14,000
-12,000
-10,000
-8,000
-6,000
-4,000
-2,000
0
2,000
DA11:00
DA12:00
DA13:00
DA14:00
DA15:00
OD5:00
OD6:00
OD7:00
OD8:00
OD9:00
OD10:00
OD11:00
MW
Hour
Submitted Average COP Variance
Sep-18
Sep-19
COP Variance = COP HSL – SCED HSL for online units and COP HSL – SCED MW for
startup and shutdown units. SCED values are time-weighted for the delivery hour.
ERCOT Public
Number of RUC Instructions Continued to Decrease
14
0
50
100
150
200
250
300
Capacity Congestion#
of H
ou
rs
Primary Driver for the Instruction
2017 to 2019 Effective RUC Resource-Hours
June through August
2017 2018 2019
• Noticeable trend toward self-
commitment during peak
periods.
• June instructions were all
extensions of self-committed
hours when the unit was
needed for congestion.
• August instructions (occurred
on two different days) were
driven by capacity shortage
and longer lead times.
Note: this does not include VDIs
(Board slide 11)
ERCOT Public
Operating Notices Issued in June – August 2019
15
• 8 Operating Condition Notices (OCNs) for reserve capacity shortage
• 25 Advisories due to Physical Responsive Capability (PRC) less than 3,000 MW
• 2 Watches due to PRC less than 2,500 MW
• 2 EEA Level 1 events
• 2 conservation requests during August EEAs
• 1 TCEQ Notice of Enforcement Discretion
– Effective for Operating Days 8/13-8/21
6/0
1
6/0
3
6/0
5
6/0
7
6/0
9
6/1
1
6/1
3
6/1
5
6/1
7
6/1
9
6/2
1
6/2
3
6/2
5
6/2
7
6/2
9
7/0
1
7/0
3
7/0
5
7/0
7
7/0
9
7/1
1
7/1
3
7/1
5
7/1
7
7/1
9
7/2
1
7/2
3
7/2
5
7/2
7
7/2
9
7/3
1
8/0
2
8/0
4
8/0
6
8/0
8
8/1
0
8/1
2
8/1
4
8/1
6
8/1
8
8/2
0
8/2
2
8/2
4
8/2
6
8/2
8
8/3
0
Operating Notices for June - August
Conservation PRC < 2500 OCN PRC < 3000 TCEQ
EEA1 EEA1
(Board slide 10)
ERCOT Public
Operating Notices Issued in September 2019
• 11 OCNs for reserve capacity shortage
• 4 Advisories due to PRC less than 3,000 MW
• 1 voluntary conservation request for Operating Days 9/5 and 9/6
• 2 TCEQ Notices of Enforcement Discretion
– 1 system-wide notice for Operating Days 9/5 and 9/6
– 1 notice for Permian Basin units for Operating Days beginning 9/25
16
9/0
1
9/0
2
9/0
3
9/0
4
9/0
5
9/0
6
9/0
7
9/0
8
9/0
9
9/1
0
9/1
1
9/1
2
9/1
3
9/1
4
9/1
5
9/1
6
9/1
7
9/1
8
9/1
9
9/2
0
9/2
1
9/2
2
9/2
3
9/2
4
9/2
5
9/2
6
9/2
7
9/2
8
9/2
9
9/3
0
Operating Notices in September
Conservation PRC < 2500 OCN PRC < 3000 TCEQ
ERCOT Public
Advisory for PRC < 3,000 MW on July 24, 2019
• Advisories for PRC < 3,000 MW were issued on several days (e.g. July 24).
• On these days, while PRC was low, there was non-frequency responsive
capacity (which does not contribute to PRC) and offline Quick Start Generating
Resource (QSGR) capacity still available.
17
0
5,000
10,000
15,000
20,000
25,000
Re
se
rve
s (
MW
)
July 24, 2019
RTOLCAP
PRC
ERCOT Public
Online Reserves Above PRC Due to Unfired Combined
Cycle Duct Capacity (NFRC) and Offline Quick Starts
18
0
2,500
5,000
7,500
10,000
12,500
15,000
17,500
On
line
Re
se
rve
s in
Exce
ss o
f P
RC
(M
W)
Online Reserves in Excess of PRC - July 24, 2019
Other
Differences Between MW and BP
Offline Quick Start Resources
Non-Frequency Responsive Capacity
Capacity > 20% of HSL - NFRC
ERCOT Public
Planned Transmission Outages
19
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
Jan Feb Mar Apr May Jun Jul Aug Sep
Count
of
# o
uta
ges a
ctive e
ach d
ay
Comparison 2018 vs. 2019Daily Count of All Transmission Outages
2018 2019
• Restrictions on summer transmission outages were again implemented to avoid planned
transmission outages that could require generation curtailment during high load periods.
• With longer lead time to adjust outage plans to meet the restrictions compared to 2018,
more maintenance and upgrade outages were approved, even during summer.
(Board slide 12)
ERCOT Public
Transmission Outages in Summer 2019
• There are impacts of meeting these restrictions, such as starting
outages very early in the day.
20
160
165
170
175
180
185
190
35
40
45
50
55
60
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Sp
rin
g O
uta
ge
Co
un
t
Su
mm
er
Ou
tag
e C
ou
nt
Hour Ending (HE)
Average Planned Transmission Outages
Summer Spring
Complete outages
before peak hours
during Summer
Outages start later
and are completed
after peak hours
Data only includes Line and Transformer Outages
Note: the y-axis scales are different to show detail
(Board slide 13)
ERCOT Public
Peak Week
ERCOT Public
Temperature Trend at Major Load Centers
• Temperatures at most major load centers between Aug. 12 and Aug. 16
were at or above 90th percentile levels in comparison with what these
regions have experienced in past summers (1950 thru 2019).
22
69,000
70,000
71,000
72,000
73,000
74,000
75,000
0102030405060708090
100
HE17 HE17 HE17 HE17 HE17
Mon, Aug 12 Tue, Aug 13 Wed, Aug 14 Thu, Aug 15 Fri, Aug 16
Lo
ad
(M
W)
Pe
rce
nti
le
Dallas/Fort Worth Houston Austin
San Antonio Brownsville Midland
Load
ERCOT Public
Difference of Load and Net Load Peak Times
23
14:5015:15
17:40 15:25
15:15
16:40 15:20 16:50
16:2516:25
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
8/12/2019 8/12/2019 8/13/2019 8/14/2019 8/15/2019 8/16/2019
MW
Net Load Load MaxNet MaxLd
EEAEEA
8/12/2019 8/13/2019 8/14/2019 8/15/2019 8/16/2019
ERCOT Public
Daily DC-Tie Schedule for August at Peak Hour
24
816 816
676
766
816 815 816 816 816 816 816 816 816 816
876
816
850
782
816 816 816
598
845816
854
816
669
455
816 816
866
0
100
200
300
400
500
600
700
800
900
1000A
ug-0
1
Au
g-0
2
Au
g-0
3
Au
g-0
4
Au
g-0
5
Au
g-0
6
Au
g-0
7
Au
g-0
8
Au
g-0
9
Au
g-1
0
Au
g-1
1
Au
g-1
2
Au
g-1
3
Au
g-1
4
Au
g-1
5
Au
g-1
6
Au
g-1
7
Au
g-1
8
Au
g-1
9
Au
g-2
0
Au
g-2
1
Au
g-2
2
Au
g-2
3
Au
g-2
4
Au
g-2
5
Au
g-2
6
Au
g-2
7
Au
g-2
8
Au
g-2
9
Au
g-3
0
Au
g-3
1
Additional 60 MW of
emergency energy provided
from CENACE
EEA1 events
ERCOT Public
Load Patterns – 13:00-20:00 on 8/12-8/16
25
8/12 (Peak)
8/13 (EEA)
8/14
8/15 (EEA)
8/16
64000
66000
68000
70000
72000
74000
76000
12 13 14 15 16 17 18 19
MW
Hour
8/12 (Peak) 8/13 (EEA) 8/14 8/15 (EEA) 8/16
(Board slide 25)
ERCOT Public
Preliminary Load Reduction Observations for Peak Week
26
• The information needed to accurately evaluate demand response during 2019 is not
yet available.
– Customer-level data is needed to evaluate the occurrence and load reductions in response to
various factors. Data and results for summer are expected to be available by December 2019.
• Reductions shown below are estimates of the total of all load reduction (including
ERS, 4CP and for high prices), calculated using regression baseline estimates of
ERCOT total load.
– Load reductions are small relative to the total load, so the accuracy of the load reduction
estimates is relatively low.
Date Characteristics Max RT Load
Zone SPP
Estimated HE 17 Load
Reduction
Aug. 12 Actual 4CP Day $6,537 2,500 MW
Aug. 13 EEA1/Near 4CP $9,159 3,100 MW
Aug. 14 - $1,807 200 MW
Aug. 15 EEA1 $9,053 1,800 MW
Aug. 16 Near 4CP $1,583 1,600 MW
(Board slide 26)
ERCOT Public
Aug. 12 – Peak Day
ERCOT Public
Closer Look at Peak Demand Day of Aug. 12
28
0
2
4
6
8
10
12
14
16
18
0
10
20
30
40
50
60
70
80
00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16 17 18 19 20 21 22 23
Win
d O
utp
ut
(GW
)
Po
wer
(GW
)
Delivery Hour
Nuclear Coal Gas Traditional Simple Cycle
Combined Cycle Wind Solar Diesel
Hydro Renewables Total Dispatch Wind Output
ERCOT “Peak” Hours
ERCOT Public
Closer Look at Aug. 12 – Peak Day
29
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
G, H
, a
nd
I (
MW
)
A, B
, C
, D
, E
an
d F
(M
W)
Hour Ending
Hourly Average Demand, Capacity, and Reserves on 8/12/2019
A: Outages B: Quick-Start Resources C: Off-Line
D: Renewable HSL E: Non-renewable HSL F: Load
G: PRC H: Wind I: Solar
PRC = 2300
(Board slide 14)
ERCOT Public
Closer Look at Aug. 12
30
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
MW
Hour Ending
Off-Line Resources and Resources on Outage on 8/12/2019
Outages Off-Line - Not Providing Non-Spin
Off-Line - Providing Non-Spin Quick-Start Resources
(Board slide 15)
ERCOT Public
The Summer 2019 Seasonal Assessment of Resource
Adequacy (SARA) Values vs. Actuals at Peak Demand
31
Source: Final 2019 Summer SARA
*The totals for the Final 2019 Summer SARA column combine multiple rows into a single row in some cases.
(E.g., already in-service Thermal and Hydro Resources with planned Thermal and Hydro Resources).
**The outage information in this table was extracted on Sept. 16, 2019.
2019 Actual Peak
Demand (8/12/19)
Final 2019
Summer SARA* Difference
Total Resources, MW 80,098 78,930 1,168
Thermal and Hydro 64,401 65,526 (1,125)
Private Use Networks, Net to Grid 3,203 3,437 (234)
Switchable Generation Resources 2,837 2,726 111
Wind Capacity Contribution 7,447 4,898 2,549
Solar Capacity Contribution 1,394 1,405 (11)
Non-Synchronous Ties 816 938 (122)
Peak Demand, MW 74,666 74,853 (187)
Reserve Capacity, MW 5,432 4,077 1,355
Total Outages, MW 3,972 4,226 (254)
Extreme Outage Scenario 6,891
Capacity Available for Operating
Reserves, MW 1,460 (149) 1,609
**
Largest absolute difference
31(Board slide 16)
ERCOT Public
EEA1 Days
ERCOT Public
Load, Wind, and Outage Differences – 8/12-8/13
33
Outages Shown are non-IRR Outages
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
65,000
66,000
67,000
68,000
69,000
70,000
71,000
72,000
73,000
74,000
75,000
8/12/2019 8/13/2019 8/14/2019 8/15/2019 8/16/2019
Win
d a
nd O
uta
ges (
MW
)
Load (
MW
)
Load Wind Outages
At Time of Lowest Reserves
14:51 15:14 17:47 15:2015:18
(Board slide 17)
ERCOT Public
Closer Look at Aug. 13 – EEA1 Day
34
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
G, H
, a
nd
I (
MW
)
A, B
, C
, D
, E
an
d F
(M
W)
Hour Ending
Hourly Average Demand, Capacity, and Reserves on 8/13/2019
A: Outages B: Quick-Start Resources C: Off-Line
D: Renewable HSL E: Non-renewable HSL F: Load
G: PRC H: Wind I: Solar
PRC = 2300
(Board slide 18)
ERCOT Public
Closer Look at Aug. 13 – EEA1 Day
35
0
2,000
4,000
6,000
8,000
10,000
12,000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
MW
Hour Ending
Off-Line Resources and Resources on Outage on 8/13/2019
Outages Off-Line - Not Providing Non-Spin
Off-Line - Providing Non-Spin Quick-Start Resources
(Board slide 19)
ERCOT Public
Aug. 13 EEA Level 1 Timeline
36
Time Events
05:00 Issued OCN for HE 14 to HE 18
13:50 Issued Advisory for PRC < 3,000 MW
14:46 Sent VDIs to 5 hydro units for HE17
14:55 Issued Watch for PRC < 2,500 MW
15:15 Issued EEA1 for PRC < 2,300 MW
15:16 Issued a public appeal for voluntary energy conservation
15:16 Deployed all 10-min and 30-min ERS (926 MW)
15:56 Recalled 10-min ERS (93 MW)
16:02 Re-deployed 30-min ERS
16:14 Recalled 30-min ERS
17:00 Cancelled EEA1
17:30 Cancelled Watch
18:00 Cancelled Advisory and OCN
ERCOT Public
PRC on Aug. 13 – EEA1 Day
37
• ERCOT declared EEA Level 1 at 15:10 when the PRC was 2,156 MW.
• PRC was under 2,300 MW for 35 minutes.
• EEA Level 1 continued for 1 hour and 50 minutes until deployed resources
were recovered and reserves sustained an upward trend.
PRC=2300
PRC=1750
PRC=1000
45,000
50,000
55,000
60,000
65,000
70,000
75,000
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
0:00 2:00 4:00 6:00 8:00 10:00 12:00 14:00 16:00 18:00
Lo
ad
(M
W)
PR
C (
MW
)
PRC (Load) PRC (Hydro) PRC (Generation) PRC (Wind) PRC (Total) Load (MW)
EEA Level 1
PRC < 2,300 MW
15:10 17:00
Minimum PRC:
2,025 MW @ 15:14
(Board slide 20)
ERCOT Public
Aug. 13 ERS Deployment
38
Deployment Instruction*Recall Instruction*
Start Sustained
Response Period*
• Fleet-wide, ERS deployment exceeded the obligation.
*Refers to ERS-30 only. All MW quantities include both ERS-30 and ERS-10.
ERCOT Public
Load, Wind, and Outage Differences – 8/12-8/15
39
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
65,000
66,000
67,000
68,000
69,000
70,000
71,000
72,000
73,000
74,000
75,000
8/12/2019 8/13/2019 8/14/2019 8/15/2019 8/16/2019
Win
d a
nd O
uta
ges (
MW
)
Load (
MW
)
Load Wind Outages
At time of lowest reserves
15:2014:51 15:14 15:1817:47
Outages shown are non-IRR outages
(Board slide 21)
ERCOT Public
Closer Look at Aug. 15 – EEA1 Day
40
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
G, H
, a
nd
I (
MW
)
A, B
, C
, D
, E
an
d F
(M
W)
Hour Ending
Hourly Average Demand, Capacity, and Reserves on 8/15/2019
A: Outages B: Quick-Start Resources C: Off-Line
D: Renewable HSL E: Non-renewable HSL F: Load
G: PRC H: Wind I: Solar
PRC = 2300
(Board slide 22)
ERCOT Public
Closer Look at Aug. 15
41
0
2,000
4,000
6,000
8,000
10,000
12,000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
MW
Hour Ending
Off-Line Resources and Resources on Outage on 8/15/2019
Outages Off-Line - Not Providing Non-Spin
Off-Line - Providing Non-Spin Quick-Start Resources
(Board slide 23)
ERCOT Public
Aug. 15 EEA Level 1 Timeline
42
Time Events
05:00 Issued OCN for HE 14 to HE 18
13:30 Issued Advisory for PRC < 3,000 MW
15:00 Issued Watch for PRC < 2,500 MW
15:05 Declared EEA1 for PRC < 2,300 MW
15:05 Issued a public appeal for voluntary energy conservation
15:11 Deployed 30-min ERS (833 MW)
15:30 Sent VDI for emergency energy across the Railroad DC-Tie to ERCOT
15:53 Sent VDIs to keep two generators online for HE16 and HE17
16:54 Recalled all 30-min ERS
17:05 Terminated EEA1
17:15 Ended VDI for emergency energy across the Railroad DC-Tie
17:35 Cancelled Watch
18:00 Cancelled Advisory and OCN
ERCOT Public
PRC on Aug. 15 – EEA1 Day
• ERCOT declared EEA Level 1 at 15:05 when the PRC was 2,245 MW.
• PRC was under 2,300 MW for 26 minutes.
• EEA Level 1 continued for 2 hours until deployed resources were recovered
and reserves sustained an upward trend.
43
PRC=2300
PRC=1750
PRC=1000
40,000
45,000
50,000
55,000
60,000
65,000
70,000
75,000
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
0:00 2:00 4:00 6:00 8:00 10:00 12:00 14:00 16:00 18:00
Lo
ad
(M
W)
PR
C (
MW
)
PRC (Load) PRC (Hydro) PRC (Generation) PRC (Wind) PRC (Total) Load (MW)
EEA Level 1
PRC < 2,300 MW
15:05 17:05
Minimum PRC:
2,134 MW @
15:18
(Board slide 24)
ERCOT Public
Aug. 15 ERS Deployment*
44
Deployment Instruction Recall Instruction
Start Sustained
Response Period
*Note: Weather sensitive and non-weather sensitive ERS-30 deployed
• Fleet-wide, ERS deployment exceeded the obligation.
ERCOT Public
Commercial Information
ERCOT Public
Day-Ahead Market (DAM)/Real-Time (RT) Price
Convergence
46
• On average, price convergence was within normal range over the summer.
• Day-to-day, significant volatility was observed.
Daily Average Unweighted Settlement Point Prices at ERCOT 345kV Hub Average
0
200
400
600
800
1000
1200
$/M
Wh
RT Settlement Point Price
DAM Settlement Point Price
ERCOT Public
Load Forecast for Sept. 5 and 6
47
• On both days, demand was lower than forecast due to lower than
expected temperatures.
67
68
69
70
71
72
73
74
75
DAM DRUC Midnight 8 a.m. Noon 4 p.m. Actual
GW
Reference -Peak on 8/12
HE 17 Forecasts vs. Actual
OD 9/5 OD 9/6
ERCOT Public
Record DAM Prices (Closer Look at Sept. 5 and 6)
48
• Day-Ahead Market (DAM) for Operating Day (OD) 9/5 had record prices.
– The RRS price was a result of a $6k offer plus ~$3k opportunity cost of energy.
• The overall increase in prices can be attributed to three things:
– Increase in both bid quantity and bid prices
– Prices in the offer stack increased earlier in the day compared to recent days
– Decrease in Ancillary Service quantities offered into the DAM
• DAM for OD 9/6 saw more RRS quantities offered in, though the energy bid/offer curves were similar
to OD 9/5. Therefore, energy prices were similar for the two days, but the RRS price was lower.
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
$/M
Wh
HE
OD 9/5/2019 – DAM System Lambda and AS MCPCs
SystemLambda REGUP REGDN RRS NSPIN
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24HE
OD 9/6/2019 – DAM System Lambda and AS MCPCs
SystemLambda REGUP REGDN RRS NSPIN
ERCOT Public
Day-Ahead and Real-Time (RT) Market Congestion Rent
49
$0
$20
$40
$60
Acro
ss Z
on
e
Housto
n
No
rth
So
uth
We
st
Acro
ss Z
on
e
Ho
usto
n
No
rth
So
uth
We
st
Acro
ss Z
on
e
Ho
usto
n
No
rth
So
uth
We
st
June July August
Co
ng
estio
n R
en
t ($
in
Mill
ion
s)
Summer 2019 Congestion Rent by Zone
Real-Time DAM
• In summer 2018 there was
significant congestion, as
well as CRR underfunding in
July and higher RT Revenue
Neutrality Allocation (RENA)
overall.
• Summer 2019:
– No CRR underfunding
– RENA down to ~$5M from
~$50M last summer
– 2019 RT congestion rent
totaled approx. $180M; for
2018, it was $350M
(Board slide 27)
ERCOT Public
Congestion Revenue Rights (CRRs) Cost vs. Value
50
0
20
40
60
80
100
120
140
160
180
200
Jun Jul Aug Jun Jul Aug Jun Jul Aug
2017 2018 2019
$ M
illio
ns
Cost Value
(Board slide 28)
ERCOT Public
Net Allocation to Load Increased in August Due to
Higher Ancillary Service Costs
51
(100)
(50)
-
50
100
150
200
250
300
June July August June July August June July August
2017 2018 2019
$ M
illio
ns
Ancillary Service Balancing Account Payout to Load CRR Auction Distribution
ERCOT Administrative Fee ERS Settlement Real-Time Ancillary Service Imbalance
Real-Time Revenue Neutrality Other Settlements Total Allocation to Load
(Board slide 29)
ERCOT Public
Collateral
52
• In July, Total Potential Exposure (TPE) and collateral calls increased due to significantly high
Forward Adjustment Factors, which are driven by Intercontinental Exchange (ICE) North Hub prices.
• In September, the increase in TPE and collateral calls was driven more by the increase in ERCOT
Real-Time and Day-Ahead prices.
ERCOT Public
Other Summer Observations
53
• Despite record prices, there were no mass
transitions.
– There was only one default of a Market Participant
(MP) with no load or generation (occurred in
September).
– On one occasion in September, ERCOT was
required to short-pay the market due to a MP’s
failure to pay an invoice. ERCOT drew from the
MP’s available financial security, refunded MPs and
no default occurred.
• The Credit Work Group is evaluating this event and
re-examining surety bonds as financial security.
• Switchable generation coordination agreements
enabled effective communications during EEAs.
• Distributed generation increased net output by an
estimated 150-200 MW during Aug. 12-16 peaks.
(Board slide 30)
ERCOT Public
Future Opportunities
• Filed NOGRR to clearly allow operators to deploy smaller amounts
of RRS at a time.
• Use event data to inform a review of ERS assumptions used for the
reliability deployment price adder, such as the 10-hour recall period.
• Continue to focus on Real-Time Co-optimization, while assessing
whether any improvements can be made to the existing processes
in the interim.
– RTC would have increased reliability and economic efficiency by:
• Improving the ability of SCED to dispatch NFRC ahead of frequency
responsive capacity to maintain higher levels of PRC and reduce the
duration of the two EEA1 events on Aug. 13 and 15.
• Allowing more efficient dispatch of lower-cost capacity that was reserved
behind the High Ancillary Service Limit (HASL) and procurement of AS from
higher-generating cost capacity during tight conditions.
• Reducing the number of ramp-constrained dispatch conditions.
54
ERCOT Public
Future Opportunities
• Consider changes to OCN issuance procedures.
• Discuss switchable generation scenarios and possible market
rule changes.
• Continue to work with gas generators and gas companies on
coordinated communication processes.
• Work with fossil fuel generators on gathering appropriate
emission limitation data to assist in enforcement discretion
requests.
• Complete summer demand response study by December
2019.
55
