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

Presentation outline • Annual report highlights – Demand and supply conditions – Wholesale market performance – EIM Performance • Key recommendations Page 2

The peak load in 2016 was moderate and did not reach the 1-in-2 year forecast. 51,000 50,000 49,000 System peak load (MW) 48,000 47,000 46,000 45,000 1-in-10 year peak forecast 44,000 1-in-2 year peak forecast Actual peak 43,000 42,000 2012 2013 2014 2015 2016 Page 3

In-state hydro-electric generation and snowpack improved from previous recent years. 35,000 May 1 Snowpack (% of normal) 2016 59% 30,000 Annual hydro production (GWh) 2015 3% 2014 18% 25,000 2013 17% 2012 39% 2011 190% 20,000 15,000 10,000 5,000 0 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Page 4

Solar generation increased by about 30 percent and continues to be the largest source of renewable generation connected to the ISO. 25,000 2013 2014 2015 2016 20,000 15,000 GWh 10,000 5,000 0 Solar Wind Geothermal Biogas/Biomass Page 5

Solar capacity made up more than 80 percent of total new summer capacity in 2016. 2,000 Other Natural gas Solar 1,500 Megawatts 1,000 500 0 Q1 Q2 Q3 Q4 Page 6

Natural gas prices decreased by about 9 percent in 2016. $7 Henry Hub $6 PG&E Cityate SoCal Citygate $5 Gas price ($/MMBtu) $4 $3 $2 Hub 2016 2015 2014 2013 $1 PG&E Citygate $2.70 $2.99 $4.84 $3.97 SoCal Citygate $2.55 $2.78 $4.67 $3.95 $0 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 Page 7

Total market costs were down by about 4 percent after accounting for natural gas and greenhouse gas price changes. $70 $7 Average cost (nominal) Average cost normalized to gas price, including greenhouse gas adjustment $60 $6 Average annual gas price ($/MMBtu) Average daily gas price, including greenhouse gas adjustments ($/MMBtu) Average annual cost ($/MWh) $50 $5 $40 $4 $30 $3 $20 $2 $10 $1 $0 $0 2012 2013 2014 2015 2016 Page 8

Markets continued to perform close to competitive benchmarks. $50 Competitive baseline ($/MWh) Average load-weighted day-ahead price Average load-weighted 15-minute price Average load-weighted 5-minute price $40 Average price ($/MWh) $30 $20 $10 $0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Page 9

Day-ahead prices continued to be higher than real- time prices for much of the year. $45 Day-ahead 15-Minute 5-Minute $40 $35 Price ($/MWh) $30 $25 $20 $15 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2015 2016 Page 10

Prices followed the net load curve and were higher in the 5-minute market than in the day-ahead market during ramping hours. $70 35,000 Day-ahead 15-minute 5-minute Average net load $60 30,000 Average net system load (MW) $50 25,000 Price ($/MWh) $40 20,000 $30 15,000 $20 10,000 $10 5,000 $0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Page 11

Price spikes in the 5-minute market continued to be relatively infrequent in 2016. 1.2% $250 to $500 $501 to $750 $751 to $1000 > $1000 1.0% Percent of real-time intervals 0.8% 0.6% 0.4% 0.2% 0.0% Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2015 2016 Page 12

The frequency of negative prices continued to grow in 2016 and were most frequent in the second quarter. 6% Below -$145 -$145 to -$50 -$50 to $0 5% Percent of 5-minute intervals 4% 3% 2% 1% 0% 2012 2013 2014 2015 2016 Page 13

The profile of when negative prices occur has changed with the net load curve. 18% 2012 2014 2016 16% 14% Percent of 5-minute intervals 12% 10% 8% 6% 4% 2% 0% 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Page 14

Renewable resources primarily bid into the real-time market at negative prices in 2016. 3,000 Natural Gas Hydro Geothermal Wind Solar Other 2,500 2,000 Average hourly MW 1,500 1,000 500 0 -500 -1,000 -1,500 below -$50 -$50 to -$25 -$25 to $0 $0 to $25 $25 to $50 above $50 Page 15

Most natural gas resources provided economic bids in the real-time market. 10,000 100% Not Bid Bid Downward Flexibility 8,000 80% 75% Percent of economic bids Average hourly MW 6,000 60% 49% 36% 4,000 40% 24% 15% 2,000 20% 9% 5% 1% 0 0% Page 16

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 Page 17

Historically, ratepayers have received less than half of the value of auctioned off congestion revenue rights. This trend continued in 2016. $500 100% Auction revenues received by ratepayers $450 90% Payments to auctioned CRRs $400 80% Percent of auctioned payments Auction revenues as percent of payments $350 70% Average percent 2012-2016 $ million $300 60% $250 50% $200 40% $150 30% $100 20% $50 10% $0 0% 2012 2013 2014 2015 2016 Page 18

Regulation requirements and costs increased in 2016 to address variable renewable output. $60 $1.20 Regulation down Regulation up Spin Cost per MWh of load served ($/MWh) Non-spin Mileage Cost per MWh of load $50 $1.00 Total cost ($ million) $40 $0.80 $30 $0.60 $20 $0.40 $10 $0.20 $0 $0.00 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2015 2016 Page 19

The flexible ramping product replaced the flexible ramping capacity mechinism in November. $2.50 $0.10 California ISO PacifiCorp East Payments per MWh load ($/MWh) PacifiCorp West NV Energy Total payments ($ million) Puget Sound Energy Arizona Public Service $2.00 $0.08 Payments per MWh of load Flexible ramping product implementation $1.50 $0.06 $1.00 $0.04 $0.50 $0.02 $0.00 $0.00 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 Page 20

Average limits in the energy imbalance market Page 21

Transfers tended to flow into NV energy from the ISO in the midday hours. 500 PacifiCorp East to NV Energy California ISO to NV Energy 400 Average transfer Imports into NV Energy (MW) 300 200 100 0 -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 Page 22

Arizona transferred energy in from PacifiCorp East and out to the ISO. 500 PacifiCorp East to Arizona California ISO to Arizona Imports to Arizona Public Service (MW) 400 Average transfer 300 200 100 0 -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 Page 23

PacifiCorp West sent transfer energy to Puget during midday hours. 200 ISO to PacifiCorp West PacifiCorp East to West Imports into PacifiCorp West (MW) Puget to PacifiCorp West Average transfer 100 0 -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 Page 24

Key recommendations • Congestion revenue rights • Gas prices used for bid caps • Opportunity cost adders • Bidding limits for EIM participants Page 25

Impact of 1-day lag in next day gas prices used in day-ahead market. 20% 125% 110% Percent of traded volume 15% 10% 5% 0% 60% 80% 100% 120% 140% Trade price as percent of next-day index price from prior day Page 26

Next-day trade prices available at 8:30 am tend to be very close to next-day average prices. 60% 110% 125% Percent of traded volume 45% 30% 15% 0% 60% 80% 100% 120% 140% Trade price as percent of average at 8:30 am Page 27