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 $120 $10 Average cost (nominal) Average cost normalized to 2009 gas price A t li d t 2009 i Avg. daily gas price ($/MMBtu) ($/MMBtu) $100 $8 /MWh) $80 $80 age gas price ( annual cost ($ $6 $60 $4 $4 Average a Annual Avera $40 $2 $20 $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. 30,000 105% oad les to actual lo 28,000 103% MW) 26 000 26,000 101% 101% Total load (M ahead schedul 24,000 99% Ratio of day ‐ a Day ‐ ahead scheduled Load 22,000 97% Day ‐ ahead forecasted load Actual Load Ratio of day ‐ ahead shedules to actual load y 20,000 95% 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 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. $70 Day ‐ ahead competitive baseline price Average day ‐ ahead price $60 Average real ‐ time price $ $50 rice ($/MWh) $40 $30 $30 Average pr $20 $10 $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. $1.00 2.5% Ancillary service cost per MWh of load y p st ) rved ($/MWh) ale energy co Ancillary service cost as percent of energy costs $0.80 2.0% age of wholesa Wh of load ser $0.60 1.5% $0.40 $0 40 1 0% 1.0% Cost per MW as a percenta $0.20 0.5% Cost $0.00 0.0% 2006 2007 2008 2009 2010 Slide 5

Hour-ahead market prices were significantly lower than real- time prices – creating revenue imbalances that must be ti i ti i b l th t t b allocated to load serving entities. $60 $ Day ‐ ahead Hour ‐ ahead Real ‐ time $50 $ $40 Price ($/MWh) $30 P $ $20 $10 $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 Day ahead Hour ahead Hour ‐ ahead Real time Real ‐ time $45 $40 MWh) $35 PG&E price ($/M $30 $30 $25 $20 $15 $ P $10 $5 $0 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 $200 Net revenues (NP15) Net revenues (SP15) $180 Levelized fixed cost target $160 $140 $140 $/kW ‐ year $120 $100 $ $80 $60 $40 $20 $0 2005 2006 2007 2008 2009 2010 Slide 8

Generation additions continue to outweigh retirements. 15,000 New generation Retirements 13,000 W) rements (MW Net yearly total Cumulative net total 11,000 9,000 additions/reti 7,000 5,000 3,000 Capacity a 1,000 ‐ 1,000 ‐ 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