dmm 2017 q2 report highlights - california iso · on june 21, there was an upward shift in load,...

DMM 2017 Q2 Report Highlights

Kyle Westendorf

Market Monitoring Analyst

Department of Market Monitoring

California ISO

October 3, 2017

Discussion outline

• 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

Prices increased during the quarter as a result of

seasonally higher loads.

$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.

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.

0.0%

0.2%

0.4%

0.6%

0.8%

1.0%


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.

Frequency of high 5-minute prices larger than $750/MWh by month

0.0%

0.2%

0.4%

0.6%

0.8%

1.0%


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.

0%

2%

4%

6%

8%

10%

12%

14%

16%

18%

20%

22%


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.

$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.

-$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.

-$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


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.

-$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


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.

-$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


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.

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


Operating reserve requirements began being

increased during midday hours on June 14.

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.

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.

$0

$2

$4

$6

$8

$10

$12

$14


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.

-$4

-$2

$0

$2

$4

$6

$8

$10

$12


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.

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

Prices in PacifiCorp West and Puget Sound

Energy were lower as a result of congestion.

$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.

Frequency of upward failed sufficiency test by month

0%

10%

20%

30%

40%

50%

60%


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.

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

The ISO implemented market power mitigation

enhancements in the 5-minute market on May 2.

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.

$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.

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

dmm 2017 q2 report highlights - california iso · on june 21, there was an upward shift in load,...

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