2019 Annual Report on Market Issues and Performance · CAISO Public Total CAISO wholesale costs...
Transcript of 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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as p
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MBt
u)
Aver
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 ($41/MWh)
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2015 2016 2017 2018 2019Change '18-'19
Day-ahead energy costs 34.23$ 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
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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
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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
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
hour
ly lo
ad (M
W)
Hour
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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Annu
al h
ydro
pro
duct
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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age
net s
yste
m lo
ad (M
W)
Pric
e ($
/MW
h)
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
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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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Pric
e ($
/MW
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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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rice
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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.
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CAISO Public
Congestion on transfer constraints from EIM areas into CAISO resulted in lower prices in Northwest EIM areas.
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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($/MWh)
CAISO Public
Day-ahead congestion had lower impact on prices in 2019
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Impa
ct to
pric
es ($
/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 $131 million in 2018.
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$ m
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.
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CAISO Public
Real-time imbalance offset costs decreased by 23% to $103 million.
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Imba
lanc
e of
fset
cha
rge
($ m
illio
n)
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 $40 million in 2018 (after accounting for uplift allocation).
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l net
reve
nues
($ m
illion
)
Virtual supply net revenueVirtual demand net revenueTotal net revenues paid
CAISO Public
Ancillary service costs decreased to $149 million, but remained at about 1.7% of wholesale energy costs.
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2.0%
2.5%
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Cos
t as
a pe
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ene
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Cos
t per
MW
h of
load
ser
ved
($/M
Wh)
Cost per MWh of load
Cost as a percent of energy cost
CAISO Public
Bid cost recovery payments in the CAISO decreased to $123 million or about 1.4 % of total energy costs.
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2018 2019
Tota
l cos
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ion)
Day-ahead
Residual unit commitment
Real-time
Total cost ($ 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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Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
2018 2019
Exce
ptio
nal d
ispa
tch
ener
gy a
s pe
rcen
t of
load
Aver
age
hour
ly e
xcep
tiona
l dis
patc
h en
ergy
(MW
)
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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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.
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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
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CAISO Public
Monthly flexible ramping payments by area
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-$0.2$0.0$0.2$0.4$0.6$0.8$1.0$1.2$1.4$1.6$1.8$2.0$2.2
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rM
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Mar Ap
rM
ay Jun
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2018 2019
Tota
l pay
men
ts ($
milli
on)
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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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
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0255075
100125150175200225250275300
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
2016 2017 2018 2019
Num
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f hou
rs R
SI le
ss th
an o
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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.
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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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Aver
age
bid
capa
city
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)
Hours
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
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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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city
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CAISO Public
Withdrawals from ISO market participation Additions to ISO market
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n ca
paci
ty (M
W)
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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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Aver
age
hour
ly s
ched
ule
(MW
)
Hour
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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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 $38/kW-year.
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$/kW
-yea
r
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 $22/kW-year.
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$/kW
-yea
r
Net energy market revenuesISO's soft offer cap price
Going forward fixed costsEstimated levelized fixed cost target