Market Issues and Performance Eric Hildebrandt, Ph.D. Director, - PowerPoint PPT Presentation

Briefing on 2009 Annual Report on Market Issues and Performance Eric Hildebrandt, Ph.D. Director, Department of Market Monitoring Board of Governors Meeting General Session May 17-18, 2010

Total wholesale costs have decreased primarily due to drop in gas prices – but the new market design also lowered costs. $120 $10 Average Cost - Nominal ($/MWh) Average Cost - Normalized to 2009 Gas Price ($/MWh) Avg. Daily Gas Price ($/MMBtu) Averge Annual Gas Price ($/MMBtu) $100 $8 Average Annual Cost ($/MWh) $80 $6 $60 $4 $40 $2 $20 $0 $0 2005 2006 2007 2008 2009 Slide 2

Load and generation scheduled in day-ahead market has been very high – but not too high. 32,000 104% Ratio of day-ahead schedules to actual load 103% 29,000 102% Total load (MW) 101% 26,000 100% 99% Day-ahead scheduled Load 23,000 98% Day-ahead forecasted load Actual Load 97% Ratio of day-ahead shedules to actual load 20,000 96% 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Hour of Day Slide 3

Day-ahead and real-time prices have been about equal to a perfectly competitive baseline. $60 $50 $40 $/MWh $30 $20 $10 $0 APR MAY JUN JUL AUG SEP OCT NOV DEC Day-Ahead Competitive Baseline All Real-Time Prices Actual Day-Ahead Prices Slide 4

Ancillary service costs have decreased due to co-optimization. $1.00 2.5% Ancillary service cost per MWh of load Cost per MWh of Load Served ($/MWh) Cost as a Percentage of Wholesale Ancillary service cost as % of energy $0.80 2.0% Energy Cost $0.60 1.5% $0.40 1.0% $0.20 0.5% $0.00 0.0% 2005 2006 2007 2008 2009 Slide 5

Bid cost recovery uplift payments were relatively low and compared favorably with other ISOs. Real-time energy $ .81 (2%) Day-ahead energy Ancillary services $35.57 (93%) $ .39 (1%) Bid cost recovery $.29 (<1%) Reliability (RMR and ICPM), $.25 (<1%) Grid management charge, $.78 (2%) Slide 6

The number of units impacted by local market power mitigation procedures has been relatively low. 4 Units subject to mitigation Units with bids changed by mitigation 3.5 Units with potential increase in dispatch due to mitigation Average number of units per hour 3 2.5 2 1.5 1 0.5 0 Apr May Jun Jul Aug Sep Oct Nov Dec Day-ahead market Slide 7

When bids are lowered due to mitigation, the market impact has usually been relatively low. 90 Potential increase in dispatch due to mitigtion 80 70 (average MW per hour) 60 50 40 30 Increase in day-ahead 20 market dispatch due to mitigation. 10 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 Trade Hour Slide 8

Month ahead resource adequacy capacity showings exceeded system and local requirements. Demand response programs Other Imports Generating units within ISO 70,000 Monthly Resource Adequacy Capacity (MW) Total RA Requirements 60,000 50,000 40,000 30,000 20,000 10,000 0 May June July Aug Sept Slide 9

About 91% of resource adequacy capacity was available in the day-ahead market during very high load hours. 50,000 45,000 40,000 35,000 Megawatts 30,000 25,000 20,000 15,000 10,000 5,000 0 Apr May Jun Jul Aug Sep Oct Nov Dec IFM bids and schedules RUC bids and schedules Resource adequacy capacity Slide 10

Over 2,400 MW of new generation capacity was added in 2009, including 86 MW of renewables. 15,000 New generation Capacity additions/retirements (MW) 13,000 Retirements 11,000 Net yearly total 9,000 Cumulative net total 7,000 5,000 3,000 1,000 -1,000 -3,000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 (Planned) Slide 11

Estimated net revenues earned by a hypothetical new combined cycle unit from the ISO spot market dropped significantly. Slide 12

The drop in gas prices accounts for most of the decrease in net revenues of new gas-fired generation. $120 System marginal cost at $8.80/mmBtu Bid price at marginal cost ($/MWh) System marginal cost at $3.90/mmBtu $8.80/mmBtu $100 $80 $60 $3.90/mmBtu $40 11,000 10,000 9,000 8,000 Btu/kWh Btu/kWh 7,000 $20 Btu/kWh 6,000 Btu/kWh Btu/kWh Btu/kWh $0 Market clearing quantity (MW) Slide 13

Recommendations: Market power mitigation  Continuation of CPUC policies encouraging high level of forward energy contracting.  Maintain current local market power provisions in 2010, while developing refinements:  Complete review of modifications previously proposed by DMM in convergence bidding design process.  Consider how to “relax” test for competitiveness of constraints once tool allowing more dynamic testing is completed.  Improve processes to ensure proper implementation of all aspects for local market power mitigation procedures. Slide 14

Recommendations: Market design issues  Develop capability to monitor proxy demand resource program taking effect in 2010 and adjust program as needed.  Work with CPUC to develop requirements for proxy demand resources developed by non-utility demand service providers to provide resource adequacy capacity.  Continue to work with CPUC to refine resource adequacy capacity counting criteria and performance standards for cogeneration, wind and solar resources. Slide 15