2019 Q4 Report on Market Issues and Performance...CAISO Public Highlights of Q4 market performance Page 2 • Market prices were low and highly competitive – Wholesale energy cost

CAISO PublicCAISO Public

2019 Q4 Report on Market Issues and Performance

March 5, 2020

Department of Market Monitoring, California ISO

Amelia Blanke, Ph.D., Manager of Monitoring and Reporting

http://www.caiso.com/Documents/2019FourthQuarterReportonMarketIssuesandPerformance.pdf

http://www.caiso.com/market/Pages/MarketMonitoring/AnnualQuarterlyIssuesPerfomanceReports/Default.aspx

http://www.caiso.com/Documents/2019FourthQuarterReportonMarketIssuesandPerformance.pdf

http://www.caiso.com/market/Pages/MarketMonitoring/AnnualQuarterlyIssuesPerfomanceReports/Default.aspx

CAISO Public

Highlights of Q4 market performance

Page 2

• Market prices were low and highly competitive– Wholesale energy cost ($44/MWh)

• Decrease from Q4 2018 ($54/MWh, - 18%)• Increase from Q3 2019 ($39/MWh, +15%)

• Average gas prices up 19% from Q4 2018 • Real-time offset costs in Q4 of $50 million ($100 million for

2019)• Increase in load adjustments by operators• Congestion revenue rights losses to ratepayers fell to $22

million from $29 million in Q4 2018 ($34 million for 2019)

CAISO Public

Western energy imbalance market highlights

• Northwest prices regularly lower than the rest of the system due to limited transfer capability

• Sufficiency test failures drove prices up in Arizona Public Service

• Congestion imbalance offset costs related to base schedules remained low

• Western EIM greenhouse gas prices continued to increase

Page 3

CAISO Public

Special issues covered in Q4 market report

Page 4

• Energy storage and distributed energy resources phase 3• Local market power mitigation enhancements• Gas usage constraints• System market power

CAISO Public

Total Q4 wholesale costs down 18% from Q4 2018, 4% after adjusting for gas and greenhouse gas costs

Page 5

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Q4 Q1 Q2 Q3 Q4

2018 2019

Aver

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Average cost (nominal)Average cost normalized to gas price, including greenhouse gas adjustmentAverage daily gas price, including greenhouse gas adjustments ($/MMBtu)

CAISO Public

Q4 CAISO wholesale costs totaled $2.3 billion or about $44/MWh

Page 6

Q4 2018 Q1 2019 Q2 2019 Q3 2019 Q4 2019

Change Q4 2018-Q4 2019

Day-ahead energy costs 51.46$ 52.23$ 23.97$ 35.94$ 41.35$ (10.11)$ Real-time energy costs (incl. flex ramp) 0.01$ 0.30$ 1.28$ 0.98$ 1.44$ 1.44$ Grid management charge 0.48$ 0.46$ 0.47$ 0.45$ 0.46$ (0.02)$ Bid cost recovery costs 0.48$ 0.56$ 0.50$ 0.72$ 0.47$ (0.01)$ Reliabil ity costs (RMR and CPM) 0.90$ 0.06$ 0.06$ 0.06$ 0.06$ (0.83)$ Average total energy costs 53.32$ 53.60$ 26.28$ 38.15$ 43.78$ (9.54)$

Reserve costs (AS and RUC) 0.53$ 0.94$ 1.15$ 0.46$ 0.49$ (0.05)$ Average total costs of energy and reserve 53.85$ 54.54$ 27.42$ 38.61$ 44.27$ (9.59)$

CAISO Public

Average CAISO gas prices 19% less than Q4 2018

Page 7

$0

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2018 2019

Gas

pric

e ($

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Henry HubPG&E CityateSoCal CitygateEl Paso PermianNW Sumas

Avg Hub Price (Q4) 2018 2019 Henry Hub $3.78 $2.39PG&E Citygate $4.57 $3.27SoCal Citygate $6.14 $4.49NW Sumas $7.78 $3.51El Paso Permian $1.91 $1.36

CAISO Public

Energy prices decreased compared to the same quarter in 2018, increased over Q3 2019Day-ahead and 15-minute prices closely aligned

Page 8

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Day-ahead 15-min 5-min

CAISO Public

Renewable generation increases over Q4 2018 (13%) due to higher hydro (up 36%)

Page 9

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Total Hydro Solar Wind

CAISO Public

Hourly variation in generation by fuel type (Q4 2019),hourly variation driven by solar

Page 10

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Solar Wind Hydro Natural Gas Imports Other

CAISO Public

Average prices continue to follow net load, increasing over Q3 2019 with day-ahead prices over real-time

Page 11

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age

net s

yste

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ad (M

W)

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e ($

/MW

h)

Day-ahead 15-minute 5-minute Average net load

Day-ahead $42/MWh15-min $40/MWh

5-min $36/MWh

CAISO Public

Overall impact of congestion on prices in the day-ahead market continues to be lower in 2019

Page 12

-$9

-$6

-$3

$0

$3

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$9

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

2018 2019

Impa

ct to

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es ($

/MW

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PG&E SCE SDG&E

CAISO Public

Offset costs increase to $50 million, over 2% of wholesale energy cost, primarily congestion offset

Page 13

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Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

2018 2019

Imba

lanc

e of

fset

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rge

($ m

illio

n)

Real-time loss imbalance offset cost

Real-time congestion imbalance offset cost

Real-time energy imbalance offset cost

Total charges ($ millions)2017 2018 2019

Energy $49 $17 $4Congestion $38 $117 $97Loss -$5 -$2 -$0Total $82 $132 $101

CAISO Public

Congestion revenue right auction changes implemented January 2019

• Track 1A:– Significantly reduces the number and pairs of nodes at which

congestion revenue rights can be purchased in the auction. – Designed to limit auction sales to pairs of nodes with physical

generation / load due to potential use as hedges for actual sales and trading of energy.

• Track 1B:– Limits the net payments to CRR holders if payments exceed

congestion charges collected in the day-ahead market on a targeted constraint-by-constraint basis.

Page 14

CAISO Public

Congestion revenue right Q4 losses $22 million, auction revenues and payments to non-load-serving entities

Page 15

0%

30%

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180%

$0

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$120

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

2016 2017 2018 2019

Perc

ent o

f auc

tione

d C

RR

pay

men

ts

Rev

enue

s an

d pa

ymen

ts ($

milli

on)

Auction revenues received by ratepayers

Payments to auctioned CRRs

Auction revenues as a percent of payments

CAISO Public

2019 ratepayer losses fall to $34 million from $131 million in 2018, driven by auction changes and lower congestionhttp://www.caiso.com/Documents/ReportonResultsof2019CongestionRevenueRightsAuction-Jan272020.pdf

Page 16

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2012 2013 2014 2015 2016 2017 2018 2019

$ m

illion

Deficit offsetsRatepayer auction lossesDay-ahead congestion rent

http://www.caiso.com/Documents/ReportonResultsof2019CongestionRevenueRightsAuction-Jan272020.pdf

CAISO Public

Q3 bid cost recovery $27.4 million, down from Q3 ($48 million) and about equal to Q4 2018 ($26.6m)

Page 17

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Bid

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Real-time (Includes EIM) Residual unit commitment Day-ahead

CAISO Public

Ancillary service cost total $23 million, lower than Q3 despite an increase in scarcities

Page 18

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2017 2018 2019

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Tota

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on)

Regulation down Regulation upSpin Non-spinCost per MWh of load

CAISO Public

Convergence bidding revenue totaled $5.5 million in Q4, with most revenue to financial virtual supply

Page 19

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2018 2019

$ m

illion

Virtual supply net revenueVirtual demand net revenueTotal bid cost recovery chargesTotal revenues less charges

CAISO Public

Flexible ramping capacity• Flexible ramping prices were frequently zero • Total uncertainty payments to generators were around $1.5 million,

compared to around $0.6 million in Q3 • Recent ISO and DMM reports highlighted several issues with design

and implementation including:– procurement of capacity from resources not able to meet system

uncertainty because of resource characteristics or congestion – This can reduce the effectiveness of the product to manage net

load volatility and prevent power balance violations • Uncertainty over load and the future availability of resources to meet

that load contributes to operators needing to enter systematic and large imbalance conformance adjustments

Page 20

CAISO Public

Average hourly load adjustment increase despite moderate system conditions (Q4 2018, Q4 2019)

Page 21

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awat

ts

2019 Hour-ahead market 2019 15-minute market

2019 5-minute market 2018 Hour-ahead market

2018 15-minute market 2018 5-minute market

CAISO Public

Average hourly energy from exceptional dispatch was lower than Q4 2018 totaling 0.71% system load

Page 22

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0.6%

0.8%

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0

50

100

150

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250

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

2018 2019

Exce

ptio

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ispa

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s pe

rcen

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load

Aver

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hour

ly e

xcep

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patc

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ergy

(MW

)

In-sequence energy Out-of-sequence energyCommitment energy Percent of load

CAISO Public

Exceptional dispatch cost total $4.4 million

Page 23

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Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

2018 2019

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Out-of sequence costs over price Commitment bid cost recovery costs

CAISO Public

EIM highlights

• May 2019 sufficiency test enhancement decreases failure frequency.

• February load conformance limiter enhancement impacts prices Arizona Public Service and NV Energy

• During peak system load hours, prices in the Northwest region (PacifiCorp West, Puget Sound Energy, Portland General Electric, and Powerex) were low relative to other EIM areas due to limited transmission capacity.

• Congestion imbalance deficits related to base schedule changes remained very low

Page 24

CAISO Public

Prices in NV Energy and APS driven up by power balance constraint violations following resource sufficiency test failures in some months (15 minute market)

Page 25

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Pric

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Arizona Public ServiceBalancing Authority of Northern CaliforniaNV EnergyPacifiCorp East and Idaho PowerPacifiCorp West, Puget Sound Energy, and Portland General ElectricPowerexPacific Gas and Electric (ISO)

CAISO Public

Recent EIM price trends continue in Q4 – with lower prices in north and higher prices in south of CAISO/EIM footprint during peak net load hours

Page 26

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1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Aver

age

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ly p

rice

($/M

Wh)

PacfiCorp West, Puget Sound Energy and Portland General Electric

PacifiCorp East and Idaho Power

NV Energy

Arizona Public Service

Powerex

Balancing Authority of Northern California

Pacific Gas and Electric (ISO)

CAISO Public

Frequency of upward failed sufficiency tests falls following May 2019 change

Page 27

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5%

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20%

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30%


2018 2019

Perc

ent o

f int

erva

ls

California ISO PacifiCorp EastPacifiCorp West NV EnergyPuget Sound Energy Arizona Public ServicePortland General Electric PowerexIdaho Power BANC

CAISO Public

Q4 frequency of load conformance limiter in the 5-minute market, prices set at penalty more often after February policy change

Page 28

0.0%0.1%0.2%0.3%0.4%0.5%0.6%0.7%0.8%0.9%1.0%

Exce

ss

Shor

t

Exce

ss

Shor

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Exce

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Shor

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Shor

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Shor

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Exce

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Shor

t

Exce

ss

Shor

t

CaliforniaISO

PacifiCorpEast

PacifiCorpWest

NV Energy PugetSoundEnergy

ArizonaPublic

Service

PortlandGeneralElectric

IdahoPower

BANC

Perc

ent o

f int

erva

ls

Neither limiter triggersOnly previous limiter triggersOnly current (enhanced) limiter triggersBoth limiters trigger

CAISO Public

Average 15-minute market energy imbalance market limits

Page 29

CAISO Public

Congestion between an EIM area and the ISO causes price separation

Page 30

Congested toward ISO

Congested from ISO

Congested toward ISO

Congested from ISO

BANC 0% 0% 0% 0%Arizona Public Service 0% 2% 0% 1%PacifiCorp East 2% 0% 1% 1%Idaho Power 2% 3% 1% 4%NV Energy 1% 0% 1% 0%PacifiCorp West 26% 4% 13% 5%Portland General Electric 26% 4% 13% 5%Puget Sound Energy 26% 12% 13% 15%Powerex 28% 16% 16% 27%

15-minute market 5-minute market

CAISO Public

California ISO - average hourly 15-minute market transfer

Page 31

-1,200-1,000

-800-600-400-200

0200400600800

1,0001,2001,4001,6001,8002,0002,2002,4002,600

Aver

age

trans

fer (

MW

)

California ISO ↔ NV EnergyCalifornia ISO ↔ Arizona Public ServiceCalifornia ISO ↔ PacifiCorp WestCalifornia ISO ↔ Portland GECalifornia ISO ↔ PowerexCalifornia ISO ↔ BANCCalifornia ISO net transfer

Impo

rts in

to

Cal

iforn

ia IS

OEx

ports

from

C

alifo

rnia

ISO

Hour 1 to 24(Q4-2018)

Hour 1 to 24(Q1-2019)

Hour 1 to 24(Q2-2019)

Hour 1 to 24(Q3-2019)

Hour 1 to 24(Q4-2019)

CAISO Public

Impact of congestion on 15-minute prices

Page 32

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$12

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

2018 2019

Impa

ct to

pric

es ($

/MW

h)

PG&E SCE SDGE BANC NEVP AZPS PACE IPCO PACW PGE PSEI PWRX

CAISO Public

Estimated 15-minute market EIM internal constraint congestion imbalances ($ million)

Page 33

Balancing Authority Area 2016 2017 2018 2019 Q1 Q2 Q3 Q4

Arizona Public Service $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0BANC $0.0 $0.0 $0.0 $0.0 $0.0Powerex $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0California ISO -$51.1 -$26.2 -$70.4 -$92.3 -$17.9 -$18.4 -$14.0 -$42.0Idaho Power Company $0.0 $0.0 $0.0 $0.0 $0.0 $0.0NV Energy -$0.3 -$0.8 -$0.3 -$0.4 -$0.3 -$0.1 $0.0 $0.0PacifiCorp - East -$4.0 -$18.1 -$2.0 $0.7 $0.8 $0.0 $0.1 -$0.3PacifiCorp - West $0.0 $0.0 -$0.1 $0.0 $0.0 $0.0 $0.0 $0.0Portland General Electric $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0Puget Sound Energy $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0 $0.0

2019 QuarterlyAnnual

CAISO Public

Western EIM greenhouse gas prices increased as the deemed delivered resources shifted from lower to higher greenhouse gas emissions after November 2018 change

Page 34

-200-10001002003004005006007008009001,0001,100

-$2-$1$0$1$2$3$4$5$6$7$8$9

$10$11

Jan

Feb

Mar Ap

rM

ay Jun Jul

Aug

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Nov De

cJa

nFe

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ar Apr

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c

2018 2019

Hour

ly a

vera

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W)

Wei

ghte

d av

erag

e pr

ice

($/M

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15-minute quantity

5-minute quantity (incremental)

15-minute price

5-minute price

CAISO Public

Energy storage and distributed energy resources phase 3 implementation had little market impact

• Implemented November 13• Added new demand response dispatch options (hourly

and 15-minute) • Removed single load-serving entity aggregation

requirement– Expected to increase registration of aggregations

>1MW• Little use of either new option

Page 35

CAISO Public

Local market power mitigation enhancements

• Implemented November 13, 2019• Eliminated carryover mitigation in both real-time markets• Added a new default energy bid option (hydro DEB//0• Proposal to allow an EIM entity balancing authority area

to limit dispatch of incremental net exports when mitigation is triggered due to import congestion was rejected by FERC

Page 36

CAISO Public

Elimination of carryover mitigation reduced rates of mitigation in the ISO and EIM

Page 37

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2018 2019

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Average potential increase in dispatch due to mitigation

Average MW with bids changed by mitigation

Average MW subject to mitigation but bids not changed by mitigation

CAISO Public

Average incremental energy mitigated in 15-minute real-time market (ISO)

Page 38

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CAISO Public

Average incremental energy mitigated in 5-minute real-time market (ISO)

Page 39

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Average incremental energy mitigated in 15-minute real-time market (EIM)

Page 40

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CAISO Public

Most resources not yet using new hydro default energy bid option (November 1 and December 31)

Page 41

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14,000

Before After Before After

CAISO EIM

Hydr

o ge

nera

tion

(MW

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Negotiated DEBVariable cost DEBHydro DEBLMP Option DEB

CAISO Public

Gas usage constraints

• Enforced in the SoCal Gas region, but bound infrequently

• DMM recommends using D+2 projected gas burn or net load to shape gas burn limitations– Shaping based on D+2 gas burn may be better than

net load• Doing so would allow gas to be used during ramping

hours when gas units are needed most

Page 42

CAISO Public

Predicted gas burn (D+2) may be superior to net load for gas limitation nomogram shape

Page 43

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urn

(mm

cfh)

Trade Hour

Gas burn without nomogram enforcedDA limit using gross loadTwo-day ahead market run (D+2)

CAISO Public

SDG&E gas nomogram binding status in day-ahead and real-time market (Nov 9, 2019)

Page 44

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Day-ahead Limit Day-ahead Cleared15-minute Limit 15-minute Cleared5-minute Limit 5-minute Cleared

CAISO Public

The price-cost markup averaged $0.71/MWh or just under 2 percent for 2019

Page 45

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Aver

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Average load-weighted day-ahead priceAverage load-weighted base case priceCompetitive scenario - gas at min(bid,DEB)

CAISO Public

System market power• Market power has had a very limited effect on system market

prices even during hours when the ISO system was structurally uncompetitive

• However, DMM has expressed concern that market conditions may evolve in a way that will increase the potential for system-level market power

• DMM supports the ISO’s initiative as a an incremental improvement

• Continues to recommend other market design changes:– Increasing supply availability of RA imports– Ensure that import bids over $1,000/MWh are subject to ex ante cost

verification– Avoid setting penalty prices at $2,000/MWh except when needed

Page 46