2019 Annual Report on Market Issues and Performance · CAISO Public Total CAISO wholesale costs...

CAISO PublicCAISO Public

2019 Annual Report on Market Issues and PerformanceJuly 6, 2020

Amelia BlankeManager, Monitoring & ReportingDepartment of Market Monitoring

CAISO Public

Total ISO wholesale costs decreased 17% -- or about 10% increase after accounting for 10% decrease in gas cost

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2015 2016 2017 2018 2019

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as p

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($/M

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u)

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age

annu

al c

ost (

$/M

Wh)

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

CAISO Public

Total CAISO wholesale costs totaled $8.8 billion ($41/MWh)

2015 2016 2017 2018 2019Change '18-'19

Day-ahead energy costs 34.23$ 30.49$ 37.40$ 46.05$ 38.12$ (7.94)$ Real-time energy costs (incl. flex ramp) 0.18$ 0.54$ 0.73$ 0.60$ 1.01$ 0.42$ Grid management charge 0.42$ 0.42$ 0.44$ 0.46$ 0.46$ (0.00)$ Bid cost recovery costs 0.38$ 0.30$ 0.41$ 0.69$ 0.57$ (0.11)$ Reliabil ity costs (RMR and CPM) 0.12$ 0.11$ 0.10$ 0.73$ 0.06$ (0.67)$ Average total energy costs 35.33$ 31.86$ 39.09$ 48.52$ 40.22$ (8.31)$

Reserve costs (AS and RUC) 0.27$ 0.53$ 0.71$ 0.87$ 0.74$ (0.13)$ Average total costs of energy and reserve 35.60$ 32.39$ 39.80$ 49.40$ 40.96$ (8.44)$

CAISO Public

Day-ahead prices were often driven by gas prices

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pric

e ($

/MM

Btu

)

Henry HubPG&E CityateSoCal CitygateEl Paso PermianNW Sumas

Avg Hub Price 2018 2019 Henry Hub $3.16 $2.54PG&E Citygate $3.34 $3.54SoCal Citygate $4.99 $4.13NW Sumas $3.50 $4.57El Paso Permian $1.97 $1.16

CAISO Public

SoCal Citygate gas price spikes were driven by gas supply limitations and potential for high noncompliance charges (OFOs).

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Gas price difference between SoCal Citygate vs. SoCal Border ($/MMBtu)StartingOctober 1, 2017, SoCalGasexperiences additional supply constraints from pipeline outages and maintenance

Starting June 1, 2019, CPUC approved lower penalties for Stage 4 and 5 OFO's for Jun - Sep and a tier structure for Oct - May period.

CAISO Public

Average day-ahead prices ($38/MWh) were slightly higher than 15-minute prices ($37.5/MWh) and 5-minute prices ($37/MWh)

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

2017 2018 2019

Pric

e ($

/MW

h)

Day-ahead 15-Minute 5-Minute

CAISO Public

Peak loads and overall energy loads lower in 2019

Year Annual total energy (GWh)

Average load (MW)

% change Annual peak load (MW)

% change

2017 227,749 26,002 0.0% 50,116 8.4%2018 220,458 25,169 -3.2% 46,427 -7.4%2019 214,955 24,541 -2.5% 44,301 -4.6%

43,00044,00045,00046,00047,00048,00049,00050,00051,00052,000

2015 2016 2017 2018 2019

Syst

em p

eak

load

(MW

)

1-in-10 year peak forecast1-in-2 year peak forecastActual peak

CAISO Public

Average hourly loads continue to decrease due to behind-the-meter solar generation and energy efficiency initiatives, plus lower statewide temperatures in 2019

19,000 20,000 21,000 22,000 23,000 24,000 25,000 26,000 27,000 28,000 29,000 30,000 31,000 32,000

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W)

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2017 2018 2019

CAISO Public

Hydroelectric generation increased to around 14% of supply, compared to 10% in 2018 and 15% in 2017

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ydro

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ion

(GW

h)

April 1 Snowpack (% of normal)

2019 175%2018 58%2017 159%2016 85%2015 5%2014 25%

CAISO Public

Average hourly prices mirror net load, with day-ahead prices lower than real-time in peak hours.

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

CAISO Public

Expansion of the western energy imbalance market (EIM) helped improve the overall structure and performance of the real-time market

• One new member joined in April (BANC/SMUD)

• The EIM/CAISO system now accounts for over half of WECC peak load

• Load conformance limiter changes increased frequency of prices at the cap (Feb)

• Sufficiency test changes reduced frequency of test failures (May)

• EIM supply that can be delivered into CA lower due to change in EIM greenhouse gas accounting made in Nov. 2018

CAISO Public

On average, prices in the CAISO are higher than other energy imbalance market balancing areas

Monthly 15-minute market prices

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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

Prices and transfers reflect differences in regional supply conditions and transfer limitations

Hourly 15-minute market prices

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Wh)

PacfiCorp West, Puget Sound Energy and Portland General ElectricPacifiCorp East and Idaho PowerNV EnergyArizona Public ServicePowerexBalancing Authority of Northern CaliforniaPacific Gas and Electric (ISO)

CAISO Public

Net imports into CAISO (excluding EIM) decreased 15% in 2019 due to lower imports from the Northwest.

CAISO Public

Congestion on transfer constraints from EIM areas into CAISO resulted in lower prices in Northwest EIM areas.

BANC* 1% -$0.39 1% -$0.23Arizona Public Service 3% $4.84 4% $4.32NV Energy 5% $2.25 5% $3.45PacifiCorp East 5% -$0.08 5% $0.75Idaho Power 6% -$0.55 6% $0.33PacifiCorp West 26% -$2.33 20% -$2.60Portland General Electric 28% -$2.59 22% -$2.84Puget Sound Energy 31% -$2.21 26% -$2.53Powerex 47% -$2.06 52% -$3.15

15-minute market 5-minute marketCongestion Frequency

Price Impact($/MWh)

Congestion Frequency

Price Impact($/MWh)

CAISO Public

Day-ahead congestion had lower impact on prices in 2019

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2018 2019

Impa

ct to

pric

es ($

/MW

h)

PG&E SCE SDG&E

Congestion revenues totaled 4.3 percent of day-ahead market energy costs, compared to about 6.8 percent in 2018.

CAISO Public

Transmission ratepayers lost over $22 million from auctioned CRRs in 2019, down from $131 million in 2018.

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2012 2013 2014 2015 2016 2017 2018 2019

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illion

Auction revenues received by ratepayersPayments to auctioned CRRsTotal ratepayer losses

CAISO Public

Congestion revenue right auction changes implemented January 2019• Implemented in response to systematic losses from congestion

revenue right auction sales since 2009

• Transmission ratepayer losses are significantly lower due to auction changes and lower congestion. – Day-ahead congestion revenues $354 million in 2019, compared to $628

million in 2018.– Losses from auctioned rights equal 6% of total congestion revenue in

2019, compared to 21% in 2018.

• DMM continues to believe the current auction is unnecessary and could be eliminated– If the CAISO/stakeholders believe a market is necessary for hedging,

replace auction with a market of willing buyers and sellers.

• DMM has recommended consideration of changes to CRR allocation process to load serving entities.

CAISO Public

Real-time imbalance offset costs decreased by 23% to $103 million.

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Imba

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fset

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rge

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illio

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RT loss imbalance offset chargeRT congestion imbalance offset chargeRT imbalance energy offset charge

Total charges ($ millions)2017 2018 2019

Energy $49 $18 $6Congestion $38 $117 $97Loss $-5 -$2 $0Total $82 $133 $103

Most congestion offset costs were due to reductions in constraint limits between day-ahead and real-time markets.

CAISO Public

Convergence bidding profit of $37 million, down from $40 million in 2018 (after accounting for uplift allocation).

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Virtual supply net revenueVirtual demand net revenueTotal net revenues paid

CAISO Public

Ancillary service costs decreased to $149 million, but remained at about 1.7% of wholesale energy costs.

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Cost per MWh of load

Cost as a percent of energy cost

CAISO Public

Bid cost recovery payments in the CAISO decreased to $123 million or about 1.4 % of total energy costs.

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Day-ahead

Residual unit commitment

Real-time

Total cost ($ million) 2018 2019Day-ahead $33 $36 RUC $30 $18Real-time $100 $80Total $162 $133

CAISO Public

Total energy from exceptional dispatches increased in 2019, but still account for a low portion of system load (0.7%).

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

Total exceptional dispatch costs decreased to $29 million from $52 million in 2018

CAISO Public

Load adjustment in hour-ahead scheduling process by grid operators remained high, particularly in ramping hours.

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0100200300400500600700800900

1,0001,1001,200

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awat

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2019 Hour-ahead market2018 Hour-ahead market2017 Hour-ahead market2019 5-minute market2018 5-minute market2017 5-minute market

CAISO Public

Flexible ramping product (FRP)• Product is designed to enhance reliability and market performance

by procuring real-time ramping capacity to help manage variability and uncertainty.

• Flexible ramping product prices were usually zero (since demand constraint was non-binding) or very low.

• Total payments to generators decreased to $6.3 million, down from $7.1 million in 2018 and $25 million in 2017.

• A significant portion of ramping capacity being procured is from resources that are not able to meet system uncertainty because of resource or transmission limits.

• Ineffectiveness of flexible ramping product reflected by increasing need of grid operators to make large manual load adjustments and manual (exceptional) dispatches to increase ramping capacity from gas-fired resources.

CAISO Public

Improvements needed in flexible ramping product• CAISO initiative to enhance flexible ramping product

– Proposing to procure capacity taking transmission limits between balancing areas into account.

– A 2019 ISO initiative allowed demand response resources to register as 15-minute or 60-minute dispatchable, not eligible for flexible ramping.

• DMM continues to recommend also extending the time horizon of uncertainty used to set flexible ramping requirements– Currently product requirements set based on ramping uncertainty between

the 15-minute and the 5-minute market or between 5-minute intervals.– DMM recommends enhancing product to procure ramping capacity based

on potential need over longer time horizon (e.g. 1 to 3 hours) – See presentation on Enhancing the flexible ramping product to better

address net load uncertainty, June 12, 2020. • http://www.caiso.com/Documents/Presentation-Real-

TimeFlexRampProductEnhancements-WesternEIMBodyofStateRegulators-June122020.pdf

http://www.caiso.com/Documents/Presentation-Real-TimeFlexRampProductEnhancements-WesternEIMBodyofStateRegulators-June122020.pdf

CAISO Public

Monthly flexible ramping payments by area

-$0.2$0.0$0.2$0.4$0.6$0.8$1.0$1.2$1.4$1.6$1.8$2.0$2.2

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milli

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California ISO BANC NV EnergyArizona Public Service Idaho Power PacifiCorp EastPacifiCorp West Puget Sound Energy Portland General ElectricPowerex

CAISO Public

The ISO’s energy markets were competitive in 2019

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

Energy prices about equal to competitive baseline prices calculated by DMM

CAISO Public

Day-ahead market was more structurally competitive relative to 2017 and 2018

0255075

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

2016 2017 2018 2019

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SI le

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One pivotal supplier test (RSI1)Two pivotal supplier test (RSI2)Three pivotal supplier test (RSI3)

CAISO Public

Market competitiveness and mitigation• Market for capacity needed to meet local requirements is structurally

uncompetitive in all local areas.

• Mitigation of exceptional dispatches reduced cost by about $8 million– DMM recommending that new “RA Max” exceptional dispatches be

subject to mitigation to strong potential for suppliers to exercise market power

• Opportunity cost adders to reflect gas unit limitations implemented and now included in commitment cost bid caps.

• More than a third of start-up and minimum load bids for gas capacity bids at or close to bid caps.

• CAISO introduced a new default energy bid option to reflect potential opportunity costs of hydro resources.

CAISO Public

On high load days, resource adequacy resources bid in enough capacity to meet average hourly loadAverage hourly bids by fuel type and RAAIM category (days with 210 highest load hours)

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city

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Nuclear Bio OtherGeothermal Solar - exempt Wind - exemptHydro Hydro - exempt Natural GasNatural Gas - exempt Imports Imports - exempt

CAISO Public

In the real-time market, less than 80 percent of system resource adequacy capacity was bid or self-scheduled during high load hours

MW% of total

RA Cap.MW

% of total RA Cap.

MW% of total

RA Cap.MW

% of total RA Cap.

Must-Offer:

Gas-fired generators 19,499 18,497 95% 18,497 95% 14,977 77% 14,376 74%

Other generators 1,490 1,402 94% 1,402 94% 1,402 94% 1,342 90%

Subtotal 20,989 19,899 95% 19,899 95% 16,379 78% 15,718 75%

Other:

Imports 4,704 4,669 99% 4,440 94% 4,078 87% 3,289 70%

Use-limited gas units 6,708 6,479 97% 6,386 95% 6,395 95% 5,961 89%

Hydro generators 6,551 6,278 96% 5,800 89% 6,265 96% 5,711 87%

Nuclear generators 2,872 2,857 99% 2,856 99% 2,857 99% 2,756 96%

Solar generators 4,176 4,164 100% 2,896 69% 4,145 99% 2,799 67%

Wind generators 1,704 1,698 100% 1,082 63% 1,698 100% 1,057 62%

Qualifying facil ities 1,078 1,062 98% 880 82% 948 88% 803 75%

Other non-dispatchable 686 664 97% 483 70% 582 85% 509 74%

Subtotal 28,479 27,871 98% 24,823 87% 26,968 95% 22,885 80%

Total 49,468 47,770 97% 44,722 90% 43,347 88% 38,603 78%

Bids and self-schedules

Real-time market

Resource type

Total resource adequacy capacity (MW)

Adjusted foroutages

Bids and self-schedules

Day-ahead market

Adjusted foroutages/availability

Average system resource adequacy capacity and availability by fuel type (210 highest load hours)

CAISO Public

Gas capacity retiring is being largely replaced with renewables (mainly solar)

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Capa

city

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Gas Coal Geothermal Biogas and BiomassNuclear Hydro Solar WindDemand response Other

CAISO Public

Withdrawals from ISO market participation Additions to ISO market

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< Summer2016

< Summer2017

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< Summer2020*

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paci

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Natural Gas Other

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500

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<Summer2016

<Summer2017

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<Summer2019

<Summer2020*

Capa

city

add

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W)

Solar Natural Gas Battery Wind Other

CAISO Public

Capacity from battery storage resources remained unchanged at 136 MWAverage hourly schedules for battery resources

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020406080

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Energy (Charging) Energy (Discharging) Reg DownReg Up Spin Reserves Flex Down

CAISO Public

Average day-ahead hourly bids for battery resources compared to nodal resource prices (Q3 2018 – 2019)

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2018 Q3 2018 Q4 2019 Q1 2019 Q2 2019 Q3 2019 Q4

Avg bid to charge ($/MWh) Avg bid to discharge ($/MWh) Avg nodal price

$/M

Wh

CAISO Public

Estimated net revenue of hypothetical combined cycle unit in NP15 and SP15 was about $38/kW-year.

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2016 2017 2018 2019

$/kW

-yea

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Net energy market revenuesISO's soft offer cap price

Going forward fixed costsEstimated levelized fixed cost target

CAISO Public

Estimated net revenues of hypothetical combustion turbine dropped to about $22/kW-year.

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NP15 SP15 NP15 SP15 NP15 SP15 NP15 SP15

2016 2017 2018 2019

$/kW

-yea

r

Net energy market revenuesISO's soft offer cap price

Going forward fixed costsEstimated levelized fixed cost target

2019 Annual Report on Market Issues and Performance · CAISO Public Total CAISO wholesale costs...

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