2017 Annual Report June 14, 2018 Amelia Blanke Manager of Market - - PowerPoint PPT Presentation

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2017 Annual Report June 14, 2018 Amelia Blanke Manager of Market - - PowerPoint PPT Presentation

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2017 Annual Report June 14, 2018 Amelia Blanke Manager of Market Monitoring & Reporting Department of Market Monitoring CAISO Public CAISO Public Total wholesale costs increased 25% -- or 4% increase after accounting for 27% increase in

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CAISO Public CAISO Public

2017 Annual Report

June 14, 2018 Amelia Blanke Manager of Market Monitoring & Reporting Department of Market Monitoring

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CAISO Public

Total wholesale costs increased 25% -- or 4% increase after accounting for 27% increase in gas cost

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$0 $1 $2 $3 $4 $5 $6 $7 $0 $10 $20 $30 $40 $50 $60 $70 2013 2014 2015 2016 2017 Average annual gas price ($/MMBtu) Average annual cost ($/MWh) Average cost (nominal) Average cost normalized to gas price, including greenhouse gas adjustment Average daily gas price, including greenhouse gas adjustments ($/MMBtu)

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CAISO Public

Total wholesale costs by category – excludes costs of meeting resource adequacy requirements.

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2013 2014 2015 2016 2017 Change '16-'17 Day-ahead energy costs 44.14 $ 48.57 $ 34.54 $ 30.70 $ 37.59 $ 6.89 $ Real-time energy costs (incl. flex ramp) 0.57 $ 1.98 $ 0.69 $ 1.03 $ 2.01 $ 0.98 $ Grid management charge 0.80 $ 0.80 $ 0.80 $ 0.81 $ 0.81 $ 0.01 $ Bid cost recovery costs 0.47 $ 0.40 $ 0.39 $ 0.33 $ 0.47 $ 0.14 $ Reliability costs (RMR and CPM) 0.10 $ 0.14 $ 0.12 $ 0.11 $ 0.10 $ (0.01) $ Average total energy costs 46.08 $ 51.89 $ 36.54 $ 32.98 $ 40.99 $ 8.01 $ Reserve costs (AS and RUC) 0.26 $ 0.30 $ 0.27 $ 0.54 $ 0.77 $ 0.24 $ Average total costs of energy and reserve 46.34 $ 52.19 $ 36.81 $ 33.52 $ 41.77 $ 8.25 $

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CAISO Public

Average hourly prices mirror net load

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3,000 6,000 9,000 12,000 15,000 18,000 21,000 24,000 27,000 30,000 33,000 $0 $10 $20 $30 $40 $50 $60 $70 $80 $90 $100 $110 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Average net system load (MW) Price ($/MWh) Day-ahead 15-minute 5-minute Average net load

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CAISO Public

Average quarterly system marginal energy prices increased in Q3 and Q4 due to higher gas prices and tighter supply/demand conditions.

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$15 $20 $25 $30 $35 $40 $45 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2015 2016 2017 Price ($/MWh) Day-ahead 15-Minute 5-Minute

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CAISO Public

Average hourly hydro-electric production by month (2015-2017)

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1,000 2,000 3,000 4,000 5,000 6,000 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec MW 2017 2016 2015

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CAISO Public

Frequency of day-ahead prices near or below $0/MWh increased significantly in 2017 (January – June)

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0% 5% 10% 15% 20% 25% 30% 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Percent of hours

  • $15 to $10
  • $10 to -$5
  • $5 to $0

$0 to $1

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CAISO Public

Higher reliance on gas during months with higher loads and less hydro/renewables.

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5,000 10,000 15,000 20,000 25,000 30,000 35,000 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec MW Other Nuclear Hydroelectric Renewable Import Natural gas

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CAISO Public

About 3,000 MW of gas generation retirements, while most new capacity from solar.

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  • 4,000
  • 3,000
  • 2,000
  • 1,000

1,000 2,000 3,000 4,000 5,000 6,000 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Capacity additions/retirements (MW) Retirements New generation Net yearly total

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CAISO Public

Higher peak loads, but overall energy loads level.

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Year Annual total energy (GWh) Average load (MW) % change Annual peak load (MW) % change 2013 231,800 26,461

  • 1.0%

45,097

  • 3.7%

2014 231,610 26,440

  • 0.1%

45,090 0.0% 2015 231,495 26,426 0.0% 46,519 3.2% 2016 228,794 26,047

  • 1.4%

46,232

  • 0.6%

2017 228,191 26,049 0.0% 50,116 8.4%

42,000 43,000 44,000 45,000 46,000 47,000 48,000 49,000 50,000 51,000 2013 2014 2015 2016 2017 System peak load (MW) 1-in-10 year peak forecast 1-in-2 year peak forecast Actual peak

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CAISO Public

Gas prices are up in later months of year, especially in the south, frequent location of marginal resource

Page 11 $0 $1 $2 $3 $4 $5 $6 $7 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2014 2015 2016 2017 Gas price ($/MMBtu) Henry Hub PG&E Cityate SoCal Citygate Hub 2017 2016 2015 2014 PG&E Citygate $3.24 $2.70 $2.99 $4.84 SoCal Citygate $3.41 $2.55 $2.78 $4.67

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CAISO Public

Frequency of positive 15-minute price spikes (ISO LAP areas)

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0.0% 0.2% 0.4% 0.6% 0.8% 1.0% 1.2% Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2016 2017 Percent of 15-minute intervals $250 to $500 $500 to $750 $750 to $1000 > $1000

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CAISO Public

Frequency of under-supply power balance constraint infeasibilities (15-minute market)

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0.0% 0.1% 0.2% 0.3% 0.4% 0.5% Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2016 2017 Percent of 15-minute intervals Corrected or invalid infeasibility Load bias limiter resolved infeasibility Valid under-supply infeasibility (shortage)

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CAISO Public

Load adjustment by grid operators increased significantly.

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  • 300
  • 200
  • 100

100 200 300 400 500 600 700 800 900 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Megawatts

2017 Hour-ahead market 2017 15-minute market 2017 5-minute market 2016 Hour-ahead market 2016 15-minute market 2016 5-minute market

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CAISO Public

Real-time imbalance offset costs increased ~50%.

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  • $20
  • $10

$0 $10 $20 $30 $40 $50 $60 $70 $80 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2016 2017 Total cost ($ million) Real-time loss imbalance offset cost Real-time congestion imbalance offset cost Real-time imbalance energy offset cost

Total cost ($ millions) 2016 2017 Energy

  • $3 $46

Congestion $50 $38 Loss $6

  • $5

Total $53 $79

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CAISO Public

Ancillary service costs increased due to higher requirements and tight supply conditions.

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0.0% 0.5% 1.0% 1.5% 2.0% 2.5% $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 2012 2013 2014 2015 2016 2017 Cost as a percentage of wholesale energy cost Cost per MWh of load served ($/MWh) Ancillary service cost per MWh of load Ancillary service cost as percent of energy cost

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CAISO Public

Bid cost recovery payments increased 42% compared to 27% increase in energy cost.

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$0 $10 $20 $30 $40 $50 $60 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2016 2017 Total cost ($ million) Day-ahead Residual unit commitment Real-time

Total cost ($ million) 2016 2017 Day-ahead $13 $14 RUC $10 $13 Real-time $52 $81 Total $76 $108

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CAISO Public

Total above-market costs due to exceptional dispatch increased 92 percent to $20.6 million in 2017

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0.0% 0.0% 0.0% 0.1% 0.1% 0.1% 0.1% 0.1% 0.2% 20 40 60 80 100 120 140 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2016 2017 Exceptional dispatch energy as percent of load Average hourly exceptional dispatch energy (MW) In-sequence energy Out-of-sequence energy Commitment energy Percent of load

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CAISO Public

Congestion raised prices in southern portion of system.

  • San Diego Gas and Electric:

– Increased day-ahead prices by $0.90/MWh (2.5%) – Increased real-time prices by about $1.50/MWh (4%)

  • Southern California Edison:

– Increased day-ahead prices by $0.40/MWh (1.2%) – Increased real-time prices by about $1.10/MWh (3%)

  • Pacific Gas and Electric :

– Decreased day-ahead prices by $0.60/MWh (2%) – Increased 15-minute prices by about $0.30/MWh (0.8%)

  • Intertie congestion impact increased, particularly for interties

connecting the ISO to the Pacific Northwest

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CAISO Public

Transmission ratepayers lost over $100 million from auctioned CRRs in 2017 (>$730 million since 2009)

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$0 $50 $100 $150 $200 $250 $300 $350 $400 2012 2013 2014 2015 2016 2017 $ million Auction revenues received by ratepayers Payments to auctioned CRRs Total ratepayer losses

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CAISO Public

Energy imbalance market expansion improved performance of real-time market.

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Congested toward ISO Congested from ISO NV Energy 2% 2% Arizona Public Service 5% 2% PacifiCorp East 10% 1% PacifiCorp West 45% 13% Puget Sound Energy 46% 15% Portland General Electric* 59% 16%

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CAISO Public

Hourly 15-minute market prices (January – December)

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$0 $10 $20 $30 $40 $50 $60 $70 $80 $90 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Average hourly price ($/MWh) PacifiCorp West and Puget Sound Energy PacifiCorp East NV Energy and Arizona Public Service Southern California Edison

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CAISO Public

Monthly flexible ramping payments by balancing area

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$0.00 $0.04 $0.08 $0.12 $0.16 $0.20 $0.24 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2016 2017 Payments per MWh load ($/MWh) Total payments ($ million) California ISO PacifiCorp East PacifiCorp West NV Energy Puget Sound Energy Arizona Public Service Portland General Electric Payments per MWh of load

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CAISO Public

Flexible ramping constraint requirements were miscalculated, resulting in lower procurement and lower prices in many intervals.

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  • 600
  • 400
  • 200

200 400 600 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 System-level uncertainty requirement (MW) Implemented uncertainty Corrected uncertainty Thresholds

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CAISO Public

Estimated net revenue of hypothetical combined cycle unit increased significantly.

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$0 $20 $40 $60 $80 $100 $120 $140 $160 $180 $200 2016 2017 $/kW-year Net revenues (NP15) Net revenues (SP15) CEC's levelized fixed cost target ISO's soft offer cap price

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CAISO Public

Average hourly resource adequacy capacity and load (210 highest load hours)

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20 40 60 80 100 120 20,000 35,000 50,000 65,000 80,000 June July Aug Sep Number of hours (Load > 40,100 MW) Megawatts 210 highest load hours Resource adequacy capacity Resource adequacy capacity with demand response Average hourly load

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CAISO Public

Peak load and forecast exceed RA requirement on peak days

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20,000 30,000 40,000 50,000 60,000 28 29 30 31 1 2 3 4 5 6 August September MW Resource adequacy capacity Day-ahead bids and schedules Actual peak load Peak day-ahead load forecast Monthly system RA requirement

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CAISO Public

System residual supply index calculation for day- ahead market (2017)

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0.7 0.8 0.9 1.0 1.1 1.2 1.3 1.4 1.5 50 100 150 200 250 300 350 400 450 500 Residual supply index for system energy Hours Single pivotal supplier test (RSI1) 2017 Two pivotal supplier test (RSI2) 2017 Three pivotal supplier test (RSI3) 2017

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CAISO Public

Average number of units mitigated in day-ahead market

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10 20 30 40 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2016 2017 Average number of units per hour Units subject to mitigation (average per hour) Units with bids changed by mitigation Units with potential increase in dispatch due to mitigation

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CAISO Public

Recommendations

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CAISO Public

Congestion revenue rights (CRRs)

  • Continue allocating CRRs to load-serving entities who

pay for the transmission system through the transmission access charge (TAC)

  • Stop auctioning off additional CRRs that are backed

financially by transmission ratepayers through the congestion revenue balancing account

  • Recommend that the ISO move swiftly to replace the

current CRR auction with a voluntary market for financial contracts based on bids from willing buyers and sellers

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CAISO Public

Commitment cost and default energy bid enhancements (CCDEBE)

  • DMM supports overall goal, but proposal has gaps:

– Economic withholding – Inter-temporal constraints and gaming – Manual dispatch and intervention by grid operators

  • Reasonableness thresholds

– Recommend updating based on same day gas market conditions, rather than static approach based

  • n next-day gas trading.

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CAISO Public

Aliso Canyon gas measures

  • More improvements needed in gas use nomograms

– Day ahead? – Adjustment of use limits in real-time

  • Gas cost scalars

– Do not appear effective at reflecting actual gas prices and modifying merit order of units. – Should be replaced by ability to update gas prices during operating day based on actual gas market conditions.

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CAISO Public

Next-day SoCal Citygate trade prices compared to updated next-day average price (Jan – Dec)

Page 34 40% 60% 80% 100% 120% 140% 160% 0% 10% 20% 30% 40% 50% Percent of traded volume Trade price as percent of average at 8:30 a.m.

110% 125%

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CAISO Public

Minimum load capacity bid level of gas resources in real-time market.

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0% 20% 40% 60% 80% 100% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2017 Percent SoCalGas minimum load capacity Bid does not use scalar Bid uses scalar, not near cap Bid uses scalar, at or near cap

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CAISO Public

System Market Power

DMM has recommended that the ISO begin to consider various actions that might be taken to reduce the likelihood of conditions in which system market power may exist and to mitigate the impacts of system market power … 2017

  • Tight system conditions in real-time
  • Day-ahead market showed signs of being less competitive

– Not structurally competitive in some hours; record high prices 2018

  • Conditions likely to allow for additional potential for system market power

– lower hydro – less gas generation (~800 MW compared to summer 2017) – more generation controlled by net sellers (>3,750 MW) 2019

  • Conditions exacerbated by FERC Order 831 compliance and ISO

proposals to increase bid caps

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CAISO Public

Manual dispatch of imports: limit use and improve logging

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1,000 2,000 3,000 4,000 5,000 6,000 7,000 3rd 19th 7th 20th 22nd 1st 28th 29th 1st 2nd 5th 11th May June July August September Megawatts HE16 HE17 HE18 HE19 HE20 HE21 HE22

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CAISO Public

Reliability must-run/capacity procurement mechanism

  • Prohibition on RMR Condition 2 capacity being offered in the CAISO’s

energy market under most conditions must be removed

  • RMR resources on Condition 1 and Condition 2 must be subject to the

same must-offer requirement that units are subject to under the resource adequacy program and capacity procurement mechanism

  • RMR compensation must be modified to be more consistent with CPM
  • Support comprehensive effort to replace or combine backstop capacity

procurement (CPM and RMR).

  • Recommend resources with market power be compensated based on going

forward fixed costs plus a reasonable contribution to sunk fixed costs.

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CAISO Public

Resource adequacy

  • Structural changes creating need for significant changes:

– Intermittent resources, OTC retirements, CCAs

  • Setting requirements sufficiently high to ensure both

reliability and reduce likelihood of non-competitive

  • utcomes
  • Resource adequacy imports

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