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.

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$0 $2 $4 $6 $8 $10 $0 $20 $40 $60 $80 $100 $120 2005 2006 2007 2008 2009 Averge Annual Gas Price ($/MMBtu) Average Annual Cost ($/MWh) Average Cost - Nominal ($/MWh) Average Cost - Normalized to 2009 Gas Price ($/MWh)

• Avg. Daily Gas Price ($/MMBtu)

Load and generation scheduled in day-ahead market has been very high – but not too high.

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96% 97% 98% 99% 100% 101% 102% 103% 104% 20,000 23,000 26,000 29,000 32,000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Ratio of day-ahead schedules to actual load Total load (MW) Hour of Day

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

Day-ahead and real-time prices have been about equal to a perfectly competitive baseline.

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$0 $10 $20 $30 $40 $50 $60 APR MAY JUN JUL AUG SEP OCT NOV DEC $/MWh Day-Ahead Competitive Baseline All Real-Time Prices Actual Day-Ahead Prices

Ancillary service costs have decreased due to co-optimization.

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0.0% 0.5% 1.0% 1.5% 2.0% 2.5% $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 2005 2006 2007 2008 2009

Cost as a Percentage of Wholesale Energy Cost

Cost per MWh of Load Served ($/MWh)

Ancillary service cost per MWh of load Ancillary service cost as % of energy

Bid cost recovery uplift payments were relatively low and compared favorably with other ISOs.

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Day-ahead energy $35.57 (93%) Real-time energy $ .81 (2%) Ancillary services $ .39 (1%) Bid cost recovery $.29 (<1%) Reliability (RMR and ICPM), $.25 (<1%) Grid management charge, $.78 (2%)

The number of units impacted by local market power mitigation procedures has been relatively low.

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Day-ahead market

0.5 1 1.5 2 2.5 3 3.5 4 Apr May Jun Jul Aug Sep Oct Nov Dec

Average number of units per hour

Units subject to mitigation Units with bids changed by mitigation Units with potential increase in dispatch due to mitigation

When bids are lowered due to mitigation, the market impact has usually been relatively low.

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10 20 30 40 50 60 70 80 90 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Potential increase in dispatch due to mitigtion (average MW per hour) Trade Hour

Increase in day-ahead market dispatch due to mitigation.

Month ahead resource adequacy capacity showings exceeded system and local requirements.

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10,000 20,000 30,000 40,000 50,000 60,000 70,000 May June July Aug Sept Monthly Resource Adequacy Capacity (MW)

Demand response programs Other Imports Generating units within ISO Total RA Requirements

About 91% of resource adequacy capacity was available in the day-ahead market during very high load hours.

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5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000 Apr May Jun Jul Aug Sep Oct Nov Dec Megawatts

IFM bids and schedules RUC bids and schedules Resource adequacy capacity

Over 2,400 MW of new generation capacity was added in 2009, including 86 MW of renewables.

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• 3,000
• 1,000

1,000 3,000 5,000 7,000 9,000 11,000 13,000 15,000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Capacity additions/retirements (MW) New generation Retirements Net yearly total Cumulative net total

(Planned)

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

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The drop in gas prices accounts for most of the decrease in net revenues of new gas-fired generation.

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$0 $20 $40 $60 $80 $100 $120

Bid price at marginal cost ($/MWh) Market clearing quantity (MW)

System marginal cost at $8.80/mmBtu System marginal cost at $3.90/mmBtu $8.80/mmBtu $3.90/mmBtu

6,000

Btu/kWh

7,000

Btu/kWh

8,000 Btu/kWh 9,000

Btu/kWh

10,000

Btu/kWh

11,000

Btu/kWh

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
• nce tool allowing more dynamic testing is completed.
• Improve processes to ensure proper implementation of all

aspects for local market power mitigation procedures.

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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.

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