1. Julia Matevosyan, Resource Adequacy January, 2014 Application of KERMIT in the DOE LTS process

2. 2 Motivation ERCOT’s transmission planning processes so far relied on generation expansion tools (Market Power), production cost simulation tools (PROMOD, UPLAN) and tools for AC analysis (PSS/E, PowerWorld). These tools do not capture intra-hourly production variability of the renewables and ability of the future generation fleet to maintain system frequency at all times. Planning scenarios with high share of renewables may require higher operating reserves to achieve acceptable frequency performance. Consideration of higher operating reserves impacts unit commitment and dispatch. It may also impact generation expansion in a scenario. Need for a new tool that would capture: ̶Renewable power production uncertainty and variability; ̶Relevant ERCOT market and operation processes.

3. 3 Integrating Renewables / KERMIT analysis ERCOT procured KEMA’s Renewable Market Integration Tool (KERMIT), for assessment of operating reserves needed to balance generation portfolios with increasing share of renewables. KERMIT is Simulink/Matlab/Excel based platform. Models generation fleet, load and renewable variability, generation and system frequency control actions (governor response, AGC). Simulates second-by-second system operation, for 24 hour horizon. Provides an assessment of a power system’s ability to achieve adequate balancing and maintain system frequency.

4. 4 Relevant ERCOT Processes and Modules in KERMIT Governor response Regulation (AGC) SCED Unit Commitment Inertia response First few seconds 10-30 seconds 20 seconds to 5 minutes every 5 minutes Every hour KERMIT Modules Separate Module outside of KERMIT

5. 5 Metrics to use for reserve adequacy analysis For planning scenarios, real time operation can be simulated with KERMIT for representative days in a year. The following metrics can be used to assess reserve adequacy of future generation scenario: Sufficiency of available resources to balance renewables and load variability; System frequency second to second; Compliance with NERC’s Control Performance Standard 1, (CPS1 ≥ 100%), If reserve adequacy is not established, higher reserve requirements should be added in production cost simulation and study needs to be re-ran.

6. 6 Scenarios studied in KERMIT as a part of DOE LTS Scenario 3 (S3) – BAU all Tech −18 GW Wind & 2.5 GW Solar −Year 2022 Scenario 8 (S8) Environmental with DR/EE mandates, −50 GW Wind & 1.5 GW Geothermal −Year 2016

7. 7 Results of Reserve Adequacy Study for Planning Scenarios The results from the KERMIT study show: Unit commitment in both scenarios does not have sufficient dispatchable capacity to follow 5-minute to 5-minute net load ramp-ups in spring and autumn months (low load/high wind situations); In both scenarios without additional reserves, NERC Reliability Standard is not fulfilled (CPS1<100%); Hypothetical reserve with 0 start up time and ramping capability of 800MW/5min (S3) and 1300 MW/5min (S8) was added to achieve CPS1 score similar to the current situation; Seldom-occurring high-magnitude net load ramps call for significant increase in deployments of existing quick-start/non-spin reserves. In S8 at low load/high wind conditions, conventional generators are dispatched close to minimum and are not able to follow 5-minute to 5-minute net load ramp-downs. Wind energy curtailment.

8. 8 Results of Reserve Adequacy Study for Planning Scenarios Actual Reserves 2012 Initial KERMIT RunScenario 3Scenario 8 MinMax Spinning/Reg up 240940600 RRS 1400 1050 New 5 min product - - -8001310 Non Spin QS (15 Min Product) - 5 min start, 10 min ramp 47020001650 30 minute product (cold) Total 21104340330041004610

9. 9 Impact of the assumptions Only normal operation was studied with KERMIT for the future scenarios. Scenarios with large amount of renewable (non-synchronous) generation may lead to unacceptably large frequency deviations during generation outages. This may become a limiting factor on share of renewables that can be reliably integrated in the ERCOT system. The study was based on the assumption that ERCOT electricity market design will remain unchanged. More frequent deployment of non-spinning reserves and intra-day unit commitment compared to current situation may call for changes in market design and/or Ancillary Services products.

10. 10 Conclusions ERCOT has recently improved the planning process to include the impact of high renewables on the system. In both studied scenarios the system needs more reserves through a new 5 min AS product or increase in Regulation Reserve requirement. There are a few but highly impactful high magnitude ramps caused by renewables Curtailments will be necessary to maintain system reliability in low load/high wind situations Simulation of generator outages in KERMIT may put additional restrictions on amount of renewables in ERCOT system and will be studied in the future work.

11. 11 Appendix: Planning Process Yes No Future generation mix scenario Production Cost Simulation (PROMOD) Is solution feasible? Transm. violations? Results Transm. upgrades Yes No New sub-process in a Long Term Study

12. 12 Appendix: Unit Commitment -> SCED Module -> KERMIT Load 5-min Wind, 5-min Hourly Gen. Dispatch 5-min Dispatch Wind Curtail. KERMIT (Inertia, Gov. resp. AGC) Load, 1-sec Wind, 1-sec Gen. Outputs Frequency UC SCED Varia- bility Hourly Load Varia- bility Hourly Wind 1 hour resolution 5 minute resolution 1 second resolution

13. 13 Appendix: KERMIT Load (1-sec) AGC Freq. change Conv. Plants Renewables Load RRS  ΔfΔf ΔP Reg ΔfΔf ΔfΔf P BP P Renew PGPG P RRS P Gen P BP Renew. (1-sec) P Load P Renew. SCED (5-min) P BP ΔfΔf Storage ΔfΔf P Storage

14. 14 Appendix: DOE LTS Scenario Examples Economic assessments performed as part of the DOE study suggested increasing proportions of wind generation on the ERCOT system. We needed to assess the adequacy of operational reserves for increasing proportions of wind and solar generation. S3, 2022, 7GW of new wind, 2.5 GW solar S8, 2016, 39 GW of new wind

15. 15 Appendix: Scenario 3 (BAU All Tech with New Wind profiles) DescriptionUnits201620192022202520282032 CC AddsMW 1,600 2,000 CT AddsMW 1,190 1,700 1,360 1,700 Coal AddsMW Nuclear AddsMW CAES AddsMW Geothermal AddsMW Gravity Power AddsMW Solar AddsMW 1,500 1,000 2,000 1,000 2,500 Wind AddsMW 300 1,886 4,782 2,291 3,818 3,778 Annual Capacity AdditionsMW 1,490 4,986 8,972 5,991 6,178 9,978 Cumulative Capacity AdditionsMW 1,490 6,476 15,448 21,439 27,617 37,595 RetirementsMW - - - - - - Residential Demand ResponseMW - - - - - - Industrial Demand ResponseMW - - - - - - Reserve Margin%0.00(0.80)(2.37)(1.95)(4.00)(4.35) Coincident PeakMW 80,104 83,588 88,083 90,677 94,827 100,744 Average LMP$/MWh 50.52 57.87 63.02 70.03 77.12 87.99 Natural Gas Price$/mmbtu 4.64 5.23 6.13 6.97 7.88 9.18 Average Market Heat RateMMbtu/MWh 10.89 11.07 10.28 10.05 9.79 9.58 Natural Gas Generation% 44.0 44.1 40.9 39.9 38.7 38.5 Coal Generation% 35.2 33.3 32.0 30.9 29.8 28.2 Wind Generation% 9.5 10.8 14.5 16.2 18.7 20.3 Solar Generation% - 0.7 2.0 2.8 3.1 3.9 Scarcity HoursHRS 15 18 21 28 30 37 Unserved EnergyGWhs 20.4 29.4 31.6 48.3 57.1 87.9 SO2Tons 356,096 355,301 356,347 356,442 357,140 357,409 CO2(k) Tons 246,956 250,747 248,318 249,700 251,057 255,536 NOxTons 276,450 276,541 273,803 273,774 274,846 273,963

16. 16 Appendix: Scenario 8 (Environmental Base) DescriptionUnits201620192022202520282032 CC AddsMW - - - - - - CT AddsMW - - - - 680 2,210 Coal AddsMW - - - - - - Nuclear AddsMW - - - - - - CAES AddsMW - - - - - - Geothermal AddsMW 1,500 600 - - - Gravity Power AddsMW - - - - - - Solar AddsMW - - 15,500 500 1,500 Wind AddsMW 38,901 8,768 5,260 8,167 3,523 5,845 Annual Capacity AdditionsMW 40,401 10,268 21,360 8,667 4,703 9,555 Cumulative Capacity AdditionsMW 40,401 50,669 72,029 80,696 85,399 94,954 RetirementsMW - 6,938 14,303 - - - Residential Demand ResponseMW - - - - - Industrial Demand ResponseMW - - 500 Reserve Margin% 5.07 (5.10) (16.05) (16.95) (18.91) (19.86) Administrative UnitsMW - - 25,500 - - 6,970 Coincident PeakMW 80,104 83,588 88,083 90,677 94,827 100,744 Average LMP$/MWh 69.48 72.19 90.05 86.22 95.96 101.85 Natural Gas Price$/mmbtu 9.55 10.01 10.74 11.72 12.70 13.70 Average Market Heat RateMMbtu/MWh 7.28 7.21 8.38 7.36 7.56 7.43 Natural Gas Generation% 19.7 18.3 24.0 22.2 22.7 23.2 Coal Generation% 23.2 19.7 6.3 5.8 5.6 5.3 Wind Generation% 45.1 50.8 50.2 55.0 55.4 55.6 Solar Generation% - - 6.8 6.7 6.9 Scarcity HoursHRS - 4.0 26.0 19.0 15.0 14.0 Unserved EnergyGWhs - 2.0 46.4 35.4 22.1 33.2 SO2Tons 217,810 192,720 23,108 23,003 21,436 21,696 CO2(k) Tons 148,543 135,939 86,273 83,035 86,014 90,442 NOxTons 171,238 156,730 83,051 80,534 83,277 86,848

17. 17 Appendix, new wind projects in S8 (2016) ZoneMW NORTH 13 260 NORTH CE 766 WEST 5 490 SOUTH CE 200 SOUTH 17 809 Austin 601 Dallas 776 Total38 900

18. 18 Appendix, new wind projects in S3 (2022) ZoneMW NORTH 4792 NORTH CE 205 WEST 1 971 Total 6 968 Wind (7 GW) Solar (2.5 GW) Gas (17.9 GW)

19. 19 Studied scenarios, S3 and S8 S3, 2022 (18 GW wind & 2.5 GW solar) Renewable Production, MW Renewable contrib. of load, % Load, MW Date, Time Max renew. hour 14 20029%48 40004/08, 11 am Min load hour 9 70033%29 50010/28, 2 am Max renew. contrib. hour 14 15538%37 60004/08 4am S8, 2016 (50 GW wind & 1.5 GW geoth.) Renewable Production, MW Renewable contrib. of load, % Load, MW Date, Time Max renew. hour 29 20041%71 8008/2, 3 pm Min load hour 9 70029%33 00010/15, 5 am Max renew. contrib. hour 24 60072%34 00003/22, 2am

20. 20 Appendix: Integrating Renewables / KERMIT Study May 21, 2013

21. 21 Appendix: Integrating Renewables / KERMIT Study May 21, 2013

22. 22 Appendix: Results of Reserve Adequacy Study for a Planning Scenario May 21, 2013