Planning Reserve Margin (PRM)

Transcription

1 Planning Reserve Margin (PRM) Nguyen Pham Planning Specialist, Power Supply & Planning

2 Overview A more detailed version of the PRM presentation given in July 2015 Q & A on the PRM report based on 2012 Load Forecast and information Feedback for updated PRM report as an Appendix in the 2016 Long Term Electric Resource Plan 2

3 What is Planning Reserve Margin? Capacity buffer that allows a utility to reliably serve customers Shown in MW or percentage PRM = Dependable Resource Capacity Expected Peak (MW) PRM = (Dependable Resource Capacity Expected Peak)/Expected Peak (%) PRM for neighboring utilities 3

4 What is Planning Reserve Margin (PRM)? Is PRM the same as Operating Reserves (OR)? No, PRM covers OR OR is defined by NERC as capability above firm system demand required to provide for regulation, load forecasting error, equipment forced and scheduled outages, and local area protection. It consists of spinning and non-spinning reserves. OR = Contingency Reserve + Regulating Reserve Contingency Reserve: For control under contingencies, e.g. forced outages Regulating Reserve: For control under normal conditions Is PRM the same as Planning Margin (PM)? No, PRM = PM + OR 4

5 What is Planning Reserve Margin? Trap #1: Not all % are the same My PRM is 17%... Do you mean PRM or PM? Is that inclusive of OR? Is that PRM or CRM (Capacity Reserve Margin) CRM = (Dependable Resource Capacity Expected Peak)/ Dependable Resource Capacity What is your timing? Winter, summer, or a specific month? 5

6 What is Planning Reserve Margin? Trap #2: What are the dependable capacity resources? My PRM is 17%... Do you count nameplate capacity or capacity available at the time of peak? How about market imports? PRM Avista 24% incl. OR 15% excl. OR BC Hydro Idaho Power NorthWestern Energy 14% 10% PRM by Suppliers Pacific Corp Portland General Electric Puget Sound Energy 13% 12% 15.7% OR Included? Market Included? Yes and No Yes Yes N/A Yes Yes No Yes No Yes Yes (100%) Yes No Yes 6

7 Why PRM? For resource adequacy requirements Resource adequacy means the provision of generating resources to meet projected load Reliability means the ability to deliver the resources to the loads, such that the overall power grid remains stable (Resource Adequacy and Reliability Analysis, EPA 2014) Three primary drivers: 7

8 Why PRM? A basic assumption is that enough resources exist to meet the expected load Do we really need PRM? Load Uncertainty Short-term weather-related Long-term load growth Resource Uncertainty Generation risk Contract risk Market risk With perfect knowledge far enough in advance, PRM wouldn t be needed Every utility s situation is different 8

9 Why PRM? Trap #3: My PRM is super high, so there is no need to invest any more on the infrastructure to keep the lights on Probably not on generation, but don t forget about T&D Trap #4: My PRM is super high, so I don t need any energy resources No, PRM is all about capacity, not energy Might be a problem with limited hydro storage in the PNW Some investigating steps from NERC to address the energy issues Trap #5: I have a lot of intermittent renewable resources, so I don t need to care about PRM Intermittent renewable resources are for energy requirements It s dependable capacity that matters for PRM 9

10 How to determine PRM? Dependent on resource portfolio and is utility-specific Not having enough won t get the job done Having too much is costly No one size fits all solution Are additional resources required? Need some metric(s) to base on 10

11 How to determine PRM? Metric 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 %) Methodology Approaches: Older rule-based Modern probabilistic Monte Carlo based Industry standard is Loss-Of-Load-Expectation (LOLE) of 1 day in 10 years Expected number of days in a year that generation capacity fails to meet load =

12 How to determine PRM? Trap #6: Mixing LOLE (days/year) and LOLP (%) Trap #7: Converting LOLH (hours/year) to LOLE (days/year) Trap #8: Equaling EUE (MWh/year) to LOLE (days/year) Trap #9: I have two generators at 99% reliability, each has the capacity equal to the peak demand, so there will never be a shortage Your system reliability is not 100%: 1-(1-0.99)*(1-0.99) = 99.99% Trap #10: I want 100% adequacy, or at least 99% Did you discuss with BCUC about the potential rate increase? Trap #11: What % for PRM should I target for resource adequacy? The target should be LOLE, not PRM % 15% PRM with FOR 1% can do the job, 30% PRM with FOR 10% may not 12

13 How does FBC determine PRM? Monte-Carlo simulation approach with the industry standard target LOLE of 1 day in 10 years (or 0.1 day/year for annual analysis) Generate random events and collect the statistics Base case for expected operational conditions Sensitivity cases for operational conditions deviating from the base case Key take-away: The current system, given the capacity resources acquired to meet the expected gaps and the market access of 150 MW at only transmission forced outage rate, is able to meet the LOLE target of 1 day in 10 years without having to acquire further resources for the PRM purposes. 13

14 How does FBC determine PRM? Base Assumptions 1. The peak forecast is the expected forecast with the winter and summer peaks to occur in December and July respectively; 2. The FBC s own and contracted generators FORs are assumed as per column 3 in Appendix B, Table B-2; 3. WAX s expected FOR for is 0.5% and after 2019 is 0.25%; 4. Forced outages last for less than one day and an outage on one day does not influence if the following day will have an outage as well; 5. Market access is 150MW and the transmission FOR is 0.74%; 6. Capacity to meet expected gaps is firm at FOR 5% and planned in advance as in Appendix B, Table B-5; and 7. WAX surplus capacity for unit-contingent sales is not available to meet system requirements while the remaining hourly WAX surplus capacity is. 14

15 Percent of Monthly Peak How does FBC determine PRM? Peak Demand 2012 After-DSM and other savings load forecast Daily peaks derived from the forecast monthly peaks and the monthly shapes 120.0% 100.0% 80.0% 60.0% 40.0% 20.0% 0.0% July December 15

16 How does FBC determine PRM? Resources Forced outage rates: From detailed Operations Centre s reports Owner Plant Unit Forced or Maintenance Derated -Minor / Planned from / Unplanned to time Derated Capacity Energy lossreason for derating Year Month (M / F) (Y) (M / P / U) Day Hour Min Day Hour Min o.o.s. MW Remaining MW.h FBC 2 1 M Y U Trashrack SNL FBC 2 1 M U Trashrack cleaning FBC 2 1 M U Trashrack cleaning FBC 2 1 M P Annual Inspection FBC 2 1 M P Tailrace slot repairs - Dual outage # FBC 2 1 F U Governor problems due to shutdown of other old units FBC 2 1 F U Oil Leak FBC 2 1 M P Annual maintenance Summary % P2U1 Minor Planned Forced Forced Unplanned Total Time (hr) Occurrence Time Rate 0.00% 2.31% 0.11% 0.08% 2.41% Occurrence longer than 1 day Rate of occurrence longer than 1 day #DIV/0! 88% 17% 33% 57% Occurrence less than 1 hr Rate of occurrence less than 1 hr #DIV/0! 0% 17% 33% 7% 16

17 How does FBC determine PRM Resources 17

18 How does FBC determine PRM Base Results 18

19 How does FBC determine PRM Sensitivity 19

20 What s next? Stakeholders feedback, especially on: Is it OK to adopt the LOLE target of 1 day in 10 years? Is it OK to adopt the Monte-Carlo simulation approach? Is that OK to use market imports for PRM purposes? Are there any sensitivity cases missing? FBC Update the PRM report with the updated load forecast and resource data Consider stakeholders feedback 20