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1 Planning Reserve Margin Dan Egolf Senior Manager, Power Supply & Planning.

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Presentation on theme: "1 Planning Reserve Margin Dan Egolf Senior Manager, Power Supply & Planning."— Presentation transcript:

1 1 Planning Reserve Margin Dan Egolf Senior Manager, Power Supply & Planning

2 2 Resource Adequacy Requirements Planning Reserve Margin (PRM): power supply buffer that allows a utility to reliably serve customers Three primary drivers: Dependent on resource portfolio and is utility-specific Industry standard is Loss-Of-Load-Expectation (LOLE) of 1 day in 10 years Resource forced outages Increased demand due to weather Higher than expected load growth

3 3 What is Planning Reserve Margin (PRM)? Extra capacity Not having enough won’t get the job done Having too much is costly Shown in MW or percentage Lots of different ways of measuring it No “one size fits all” solution Are additional resources required? Our study is based on 2012 Load Forecast and information

4 4 So What’s the Problem? A basic assumption is that enough resources exist to meet the load Do we really need PRM? - Load Uncertainty A. Short-term weather-related B. Long-term load growth - Resource Uncertainty A. Generation risk B. Contract risk C. Market risk With perfect knowledge far enough in advance, PRM wouldn’t be needed Every utility’s situation is different

5 5 How do we evaluate PRM? This requires two steps: 1. Measurement Options: - Loss of Load Expectation (LOLE, in days per year) - Loss of Load Hours (LOLH, in hours per year) - Expected Unserved Energy (EUE, in MWh per year) - Loss of Load Probability (LOLP, in %) 2. Methodology Approaches: - Older rule-based - Modern probabilistic Monte Carlo based FBC is using LOLE of 1 day in 10 years, or 0.1 day per year using a Monte Carlo simulation

6 6 Risk Assumptions Load uncertainty - Long-term load uncertainty is covered as part of the load forecast - Short-term weather has a significant impact on loads and the timing of the peak load is particularly risky Generation Risk - Required operating reserves are part of PRM - Unit Forced Outage Rate (FOR) based on historical data or reasonable assumptions Contract Risk: PPA assumed to have no risk Market Risk (Short-Term) - Market access of 150 MW is assumed - Transmission Forced Outage Rate of 0.74%

7 7 Results: LOLE in the Base Case YearJanFebMarAprMayJunJulAugSepOctNovDecAnnual Winter PRM % 20140.000 0.0020.000 0.0010.0020.0040.000 0.0020.0050.01627% 20150.0020.0000.0150.000 0.0010.000 0.0060.02426% 20160.0020.0000.0010.000 0.002 0.000 0.0090.01626% 20170.0020.0000.0010.000 0.0010.000 0.0050.00926% 20180.0000.0010.000 0.006 0.0010.000 0.0020.01625% 20190.0020.000 0.0030.0050.0030.000 0.0070.02025% 20200.0010.000 0.001 0.0040.0020.000 0.0060.01525% 20250.0000.001 0.0000.0120.0030.000 0.0030.02124% 20300.0000.0020.000 0.0070.0010.000 0.0140.02423% 20330.0010.0020.000 0.0030.0010.000 0.0230.03023% LOLE 0.1 day per year met in all years PRM is about 25%

8 8 Results: Cases for Sensitivity Analysis CaseDescriptionMeet LOLE Target? Load Sensitivity Analysis Case 11-in-10 economic drivers Case 2Industrial self-generating demand of 40 MW Case 3Time of seasonal peaks Resource Sensitivity Analysis Case 4WAX FOR Case 5Double FOR Case 6No WAX surplus taken into account for PRM requirements Case 7No additional capacity planned for gaps expected gaps must be met Market Sensitivity Analysis Case 8Market sizes at the base case FOR Case 9No market access alternative capacity needed Case 10Market FOR at 150 MW

9 9 Next Steps We can present a detailed ½ day technical workshop on PRM if there is interest Our PRM Report will be updated and included as part of the 2016 Long Term Electric Resource Plan Questions?

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