2016 Annual Report on Market Issues and Performance Gabe Murtaugh - - PowerPoint PPT Presentation

2016 Annual Report on Market Issues and Performance

Gabe Murtaugh – Senior Analyst, Monitoring and Reporting Department of Market Monitoring California ISO Web Conference May 24, 2017

• Annual report highlights

– Demand and supply conditions – Wholesale market performance – EIM Performance

• Key recommendations

Page 2

Presentation outline

The peak load in 2016 was moderate and did not reach the 1-in-2 year forecast.

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42,000 43,000 44,000 45,000 46,000 47,000 48,000 49,000 50,000 51,000 2012 2013 2014 2015 2016 System peak load (MW) 1-in-10 year peak forecast 1-in-2 year peak forecast Actual peak

In-state hydro-electric generation and snowpack improved from previous recent years.

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5,000 10,000 15,000 20,000 25,000 30,000 35,000 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Annual hydro production (GWh) May 1 Snowpack (% of normal) 2016 59% 2015 3% 2014 18% 2013 17% 2012 39% 2011 190%

Solar generation increased by about 30 percent and continues to be the largest source of renewable generation connected to the ISO.

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5,000 10,000 15,000 20,000 25,000 Solar Wind Geothermal Biogas/Biomass GWh 2013 2014 2015 2016

Solar capacity made up more than 80 percent of total new summer capacity in 2016.

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500 1,000 1,500 2,000 Q1 Q2 Q3 Q4 Megawatts Other Natural gas Solar

Natural gas prices decreased by about 9 percent in 2016.

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$0 $1 $2 $3 $4 $5 $6 $7 Jan Mar May Jul Sep Nov Jan Mar May Jul Sep Nov Jan Mar May Jul Sep Nov Jan Mar May Jul Sep Nov 2013 2014 2015 2016 Gas price ($/MMBtu) Henry Hub PG&E Cityate SoCal Citygate Hub 2016 2015 2014 2013 PG&E Citygate $2.70 $2.99 $4.84 $3.97 SoCal Citygate $2.55 $2.78 $4.67 $3.95

Total market costs were down by about 4 percent after accounting for natural gas and greenhouse gas price changes.

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$0 $1 $2 $3 $4 $5 $6 $7 $0 $10 $20 $30 $40 $50 $60 $70 2012 2013 2014 2015 2016 Average annual gas price ($/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)

Markets continued to perform close to competitive benchmarks.

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$0 $10 $20 $30 $40 $50 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Average price ($/MWh) Competitive baseline ($/MWh) Average load-weighted day-ahead price Average load-weighted 15-minute price Average load-weighted 5-minute price

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Day-ahead prices continued to be higher than real- time prices for much of the year.

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

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Prices followed the net load curve and were higher in the 5-minute market than in the day-ahead market during ramping hours.

5,000 10,000 15,000 20,000 25,000 30,000 35,000 $0 $10 $20 $30 $40 $50 $60 $70 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Average net system load (MW) Price ($/MWh) Day-ahead 15-minute 5-minute Average net load

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Price spikes in the 5-minute market continued to be relatively infrequent in 2016.

0.0% 0.2% 0.4% 0.6% 0.8% 1.0% 1.2% Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2015 2016 Percent of real-time intervals $250 to $500 $501 to $750 $751 to $1000 > $1000

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The frequency of negative prices continued to grow in 2016 and were most frequent in the second quarter.

0% 1% 2% 3% 4% 5% 6% 2012 2013 2014 2015 2016 Percent of 5-minute intervals Below -$145

• $145 to -$50
• $50 to $0

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The profile of when negative prices occur has changed with the net load curve.

0% 2% 4% 6% 8% 10% 12% 14% 16% 18% 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 5-minute intervals 2012 2014 2016

Renewable resources primarily bid into the real-time market at negative prices in 2016.

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• 1,500
• 1,000
• 500

500 1,000 1,500 2,000 2,500 3,000 below -$50

• $50 to -$25
• $25 to $0

$0 to $25 $25 to $50 above $50 Average hourly MW Natural Gas Hydro Geothermal Wind Solar Other

Most natural gas resources provided economic bids in the real-time market.

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75% 49% 36% 24% 15% 9% 5% 1% 0% 20% 40% 60% 80% 100% 2,000 4,000 6,000 8,000 10,000 Percent of economic bids Average hourly MW Not Bid Bid Downward Flexibility

Revenues for a hypothetical combustion turbine were significantly below $177/kW-yr fixed cost estimates.

• DMM updated assumptions in our net-revenue analysis
• Analysis showed that a hypothetical combustion turbine

would have earned net revenues between $5/kW-year and $17/kW-year – The CEC estimates fixed costs at $177/kW-year

• A combined cycle plant would have earned revenues

between $11/KW-year and $22/kW-year – The CEC estimates fixed costs at $166/kW-year

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Historically, ratepayers have received less than half of the value of auctioned off congestion revenue rights. This trend continued in 2016.

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0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% $0 $50 $100 $150 $200 $250 $300 $350 $400 $450 $500 2012 2013 2014 2015 2016 Percent of auctioned payments $ million Auction revenues received by ratepayers Payments to auctioned CRRs Auction revenues as percent of payments Average percent 2012-2016

Regulation requirements and costs increased in 2016 to address variable renewable output.

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$0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $1.20 $0 $10 $20 $30 $40 $50 $60 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2015 2016 Cost per MWh of load served ($/MWh) Total cost ($ million) Regulation down Regulation up Spin Non-spin Mileage Cost per MWh of load

The flexible ramping product replaced the flexible ramping capacity mechinism in November.

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$0.00 $0.02 $0.04 $0.06 $0.08 $0.10 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2015 2016 Payments per MWh load ($/MWh) Total payments ($ million) California ISO PacifiCorp East PacifiCorp West NV Energy Puget Sound Energy Arizona Public Service Payments per MWh of load

Flexible ramping product implementation

Average limits in the energy imbalance market

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Transfers tended to flow into NV energy from the ISO in the midday hours.

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• 500
• 400
• 300
• 200
• 100

100 200 300 400 500 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Imports into NV Energy (MW) PacifiCorp East to NV Energy California ISO to NV Energy Average transfer

Arizona transferred energy in from PacifiCorp East and out to the ISO.

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• 500
• 400
• 300
• 200
• 100

100 200 300 400 500 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Imports to Arizona Public Service (MW) PacifiCorp East to Arizona California ISO to Arizona Average transfer

PacifiCorp West sent transfer energy to Puget during midday hours.

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• 200
• 100

100 200 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Imports into PacifiCorp West (MW) ISO to PacifiCorp West PacifiCorp East to West Puget to PacifiCorp West Average transfer

Key recommendations

• Congestion revenue rights
• Gas prices used for bid caps
• Opportunity cost adders
• Bidding limits for EIM participants

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Impact of 1-day lag in next day gas prices used in day-ahead market.

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60% 80% 100% 120% 140% 0% 5% 10% 15% 20% Percent of traded volume Trade price as percent of next-day index price from prior day

110% 125%

Next-day trade prices available at 8:30 am tend to be very close to next-day average prices.

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60% 80% 100% 120% 140% 0% 15% 30% 45% 60% Percent of traded volume Trade price as percent of average at 8:30 am

110% 125%