Annual Report on 2010 Market Issues and p Performance Eric - - PowerPoint PPT Presentation

Annual Report on 2010 Market Issues and p Performance

Eric Hildebrandt Ph D Eric Hildebrandt, Ph.D. Director, Department of Market Monitoring Board of Governors General Session May 18-19, 2011 y ,

Total annual wholesale costs load decreased 7% after accounting for higher gas prices accounting for higher gas prices.

$10 $120 Average cost (nominal) A t li d t 2009 i $8 $80 $100 ($/MMBtu) /MWh) Average cost normalized to 2009 gas price

• Avg. daily gas price ($/MMBtu)

$4 $6 $60 $80 age gas price ( annual cost ($ $2 $4 $20 $40 Annual Avera Average a $0 $0 2006 2007 2008 2009 2010

Slide 2

Load scheduled in day-ahead market continues to be about equal to actual real-time load about equal to actual real-time load.

105% 30,000

• ad

101% 103% 26 000 28,000 les to actual lo MW) 99% 101% 24,000 26,000 ahead schedul Total load (M 97% 22,000 Ratio of day‐a

Day‐ahead scheduled Load Day‐ahead forecasted load Actual Load Ratio of day‐ahead shedules to actual load

95% 20,000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

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Slide 3

Day-ahead market prices were about equal to competitive baseline prices, while average real-time prices were driven higher by occasional price spikes.

$ $60 $70

Day‐ahead competitive baseline price Average day‐ahead price Average real‐time price

$30 $40 $50 rice ($/MWh) $10 $20 $30 Average pr $0

Q2 Q3 Q4 Q1 Q2 Q3 Q4 2009 2010 Slide 4

Ancillary service costs decreased slightly and totaled less than 1 percent of total energy costs.

2.5% $1.00 st ) Ancillary service cost per MWh of load 2.0% $0.80 ale energy co rved ($/MWh) y p Ancillary service cost as percent of energy costs 1 0% 1.5% $0 40 $0.60 age of wholesa Wh of load ser 0.5% 1.0% $0.20 $0.40 as a percenta Cost per MW 0.0% $0.00 2006 2007 2008 2009 2010 Cost

Slide 5

Hour-ahead market prices were significantly lower than real- ti i ti i b l th t t b time prices – creating revenue imbalances that must be allocated to load serving entities.

$ $ $50 $60 Day‐ahead Hour‐ahead Real‐time $ $30 $40 Price ($/MWh) $10 $20 P $0 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2009 2010

Slide 6

This trend has continued in 2011, but prices in these markets have been much closer in recent weeks.

$50 Day ahead Hour ahead Real time $30 $35 $40 $45 MWh) Day‐ahead Hour‐ahead Real‐time $15 $20 $25 $30 PG&E price ($/M $0 $5 $10 $ P Jan Feb Mar Apr May (1‐12)

Slide 7

A significant gap continues to exist between net operating revenues earned by typical new combined cycle units in the revenues earned by typical new combined cycle units in the ISO energy market and the fixed costs of new capacity.

$200 $140 $160 $180 $200 Net revenues (NP15) Net revenues (SP15) Levelized fixed cost target $100 $120 $140 $/kW‐year $40 $60 $80 $ $0 $20 2005 2006 2007 2008 2009 2010

Slide 8

Generation additions continue to outweigh retirements.

13,000 15,000 W) New generation Retirements 9,000 11,000 rements (MW Net yearly total Cumulative net total 3,000 5,000 7,000 additions/reti ‐1,000 1,000 Capacity a ‐3,000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

(Planned)

Slide 9

Recommendations

• Address hour-ahead/real-time price divergence and

resulting energy imbalance costs. g gy

• Enhance model to address issues resulting in occasional

extreme congestion prices -- most notably in San Diego. g p y g

• Enhance existing local market power mitigation

procedures by making more dynamic and targeted at congestion on non-competitive constraints.

Slide 10