dmm 2017 q2 report highlights - california iso€¦ · -$200-$100 $0 $100 $200 $300 $400 $500 $600...
TRANSCRIPT
-
DMM 2017 Q2 Report Highlights
Kyle Westendorf
Market Monitoring Analyst
Department of Market Monitoring
California ISO
October 3, 2017
-
Discussion outline
Page 2
• ISO market results
– Prices
– Outcomes in June
– Other highlights
• EIM market results
• Special Issues
– Real-time market power mitigation enhancements
– Market power mitigation differences in the day-ahead
market
-
Market Performance
Page 3
-
Prices increased during the quarter as a result of
seasonally higher loads.
Page 4
$0
$10
$20
$30
$40
$50
Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun
2016 2017
Pri
ce
($
/MW
h)
Day-ahead 15-Minute 5-Minute
Average monthly prices – system marginal energy price
-
Average 15-minute market prices were higher than
day-ahead prices in the peak net load ramping hours.
Page 5
0
3,000
6,000
9,000
12,000
15,000
18,000
21,000
24,000
27,000
30,000
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Ave
rag
e n
et
sys
tem
lo
ad
(M
W)
Pri
ce
($
/MW
h)
Day-ahead 15-minute 5-minute Average net load
Average hourly system marginal energy price
-
The frequency of price spikes in the 15-
minute market increased during the quarter.
Page 6
0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun
2016 2017
Pe
rce
nt
of
15
-min
ute
in
terv
als
$250 to $500 $500 to $750 $750 to $1000 $1000 to LMP
Frequency of high 15-minute prices by month
-
The frequency of high 5-minute market
prices larger than $750/MWh increased.
Page 7
Frequency of high 5-minute prices larger than $750/MWh by month
0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun
2016 2017
Perc
en
t o
f 5
-min
ute
in
terv
als
$750 to $1000 $1000 to LMP
-
The market economically dispatched generation
down rather than relax the power balance
constraint or curtail self-scheduled generation.
Page 8
0%
2%
4%
6%
8%
10%
12%
14%
16%
18%
20%
22%
Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun
2016 2017
Pe
rce
nt
of
5-m
inu
te in
terv
als
Below -$145 -$145 to -$50 -$50 to $0
Frequency of negative 5-minute prices by month
-
The day-ahead market system marginal energy
price reached over $600/MWh on June 21.
Page 9
$0
$100
$200
$300
$400
$500
$600
$700
2010 2011 2012 2013 2014 2015 2016 2017
Pri
ce
($
/MW
h)
Day-ahead market system marginal energy price
Highest monthly day-ahead market system marginal energy price (2010 to June 2017)
-
On June 21, there was a downward shift of supply
bids in the day-ahead market.
Page 10
-$200
-$100
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
$1,000
0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000
Bid
pri
ce
($
/MW
h)
Cumulative incremental MW
June 18 June 19 June 20 June 21
Comparison of incremental supply bids between June 18 and June 21, 2017 (Hour 20)
-
Generation bid in below $100/MWh decreased by
around 800 MW.
Page 11
-$200
-$100
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
$1,000
20,000 21,000 22,000 23,000 24,000 25,000 26,000 27,000 28,000 29,000 30,000 31,000
Bid
pri
ce
($
/MW
h)
Cumulative incremental generation MW
June 18 June 19 June 20 June 21
Comparison of incremental generation bids between June 18 and June 21, 2017
-
Virtual supply bid in below $100/MWh decreased
by around 1,100 MW.
Page 12
-$200
-$100
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
$1,000
0 1,000 2,000 3,000 4,000 5,000
Bid
pri
ce
($
/MW
h)
Cumulative virtual supply MW
June 18 June 19 June 20 June 21
Comparison of virtual supply bids between June 18 and June 21, 2017
-
Intertie imports offered decreased significantly
from June 18 to June 19 and remained relatively
low during the other days.
Page 13
-$200
-$100
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
$1,000
0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000
Bid
pri
ce
($
/MW
h)
Cumulative import MW
June 18 June 19 June 20 June 21
Comparison of import bids between June 18 and June 21, 2017
-
On June 21, there was an upward shift in load,
export, and virtual demand bids in the day-ahead
market.
Page 14
Comparison of load, export, and virtual demand bids between June 18 and June 21, 2017
-$200
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
$1,600
$1,800
$2,000
$2,200
$2,400
0 10,000 20,000 30,000 40,000 50,000 60,000
Bid
pri
ce
($
/MW
h)
Cumulative MW
June 18 June 19 June 20 June 21
-
Operating reserve requirements began being
increased during midday hours on June 14.
Page 15
500
1,000
1,500
2,000
2,500
3,000
3,500
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Ho
url
y a
vera
ge r
ese
rve r
eq
uir
em
en
t (M
W)
Actual day-ahead requirement (with adjustments)
Estimated day-ahead requirement (no adjustments)
25 percent of real-time solar forecast
Hourly average operating reserve requirements (June 14 – June 30)
-
Resource adequacy capacity showings and
availability fell below peak day-ahead load
forecasts and actual load.
Page 16
June daily peak load, resource adequacy capacity, and system requirement
20,000
30,000
40,000
50,000
60,000
16 17 18 19 20 21 22 23 24 25 26 27 28 29 30
June
MW
Resource adequacy capacity Day-ahead bids and schedules
Actual peak load Peak day-ahead load forecast
June 2017 System RA Requirement
-
Estimated bid cost recovery payments for the
quarter totaled about $28 million.
Page 17
$0
$2
$4
$6
$8
$10
$12
$14
Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun
2016 2017
Bid
co
st
rec
ove
ry p
aym
en
ts (
$ m
illi
on
) Real-time Residual unit commitment Day-ahead
Monthly bid cost recovery payments
-
Virtual supply was not profitable overall for the quarter
for the second time since its implementation in 2011.
Page 18
-$4
-$2
$0
$2
$4
$6
$8
$10
$12
Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun
2016 2017
$ m
illi
on
Virtual supply net revenue
Virtual demand net revenue
Total bid cost recovery charges
Total revenues less charges
Convergence bidding revenues and bid cost recovery charges
-
Auction revenues continued to be less than payments
made to congestion revenue rights holders.
Page 19
Auction revenues and payments to non-load serving entities
0%
20%
40%
60%
80%
100%
120%
140%
$0
$10
$20
$30
$40
$50
$60
$70
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2
2015 2016 2017
Pe
rce
nt
of
au
cti
on
ed
CR
R p
aym
en
ts
Re
ve
nu
es
an
d p
aym
en
ts (
$ m
illi
on
)
Auction revenues received by ratepayers
Payments to auctioned CRRs
Auction revenues as a percent of payments
-
Energy Imbalance Market
Page 20
-
Prices in PacifiCorp West and Puget Sound
Energy were lower as a result of congestion.
Page 21
$0
$10
$20
$30
$40
$50
$60
$70
$80
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Ave
rag
e h
ou
rly p
ric
e (
$/M
Wh
)
PacifiCorp East, NV Energy, and Arizona Public Service
PacifiCorp West and Puget Sound Energy
Southern California Edison
Pacific Gas and Electric
Hourly 5-minute market prices (April – June)
-
EIM balancing areas continued to fail the upward
and downward sufficiency test.
Page 22
Frequency of upward failed sufficiency test by month
0%
10%
20%
30%
40%
50%
60%
Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun
2016 2017
Pe
rce
nt
of
ho
urs
PacifiCorp East PacifiCorp West NV Energy
Puget Sound Energy Arizona Public Service
-
EIM balancing areas continued to fail the upward
and downward sufficiency test.
Page 23
0%
10%
20%
30%
40%
50%
60%
Nov Dec Jan Feb Mar Apr May Jun
2016 2017
Pe
rce
nt
of
ho
urs
California ISO PacifiCorp East PacifiCorp West
NV Energy Puget Sound Energy Arizona Public Service
Frequency of downward failed sufficiency test by month
-
Special Issues
Page 24
-
The ISO implemented market power mitigation
enhancements in the 5-minute market on May 2.
Page 25
Accurately
predicted
Over
predicted
Under
predicted
June 2016 - May 1 2017 72% 13% 14%
May 2 - July 31 2017 84% 14% 2%
Comparison of 5-minute market power mitigation systems on flow based constraints
Comparison of 5-minute market power mitigation systems on EIM transfer constraints
Accurately
predicted Over predicted
Under
predicted
Jun 2016-May 1 2017 29% 30% 41%
May 2 2017-July 31 2017 56% 35% 8%
-
Prices increased following market power mitigation
in the day-ahead market on June 21.
Page 26
$0
$100
$200
$300
$400
$500
$600
$700
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Pri
ce
($
/MW
h)
Pre-mitigation Post-mitigation
Comparison of day-ahead market system marginal energy prices on June 21, 2017
-
Energy revenues were almost $25 million greater in
the binding market run than in the market power
mitigation run.
Page 27
Total incremental bid cost differences on June 21, hour ending 20
-$200
-$100
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
$1,000
0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000
Price
($
/MW
h)
Quantity (MW)
Post-mitigation incremental bid cost difference
Pre-mitigation incremental bid cost
June 21