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Lessons Learned from Energy Imbalance Market Benefit Study

Lessons Learned from Energy Imbalance Market Benefit Study. WECC TASMWG Webinar December 5, 2011. Arne Olson, Partner Jack Moore, Sr. Consultant. Project Goals and Approach.

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Lessons Learned from Energy Imbalance Market Benefit Study

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  1. Lessons Learned from Energy Imbalance Market Benefit Study WECC TASMWG Webinar December 5, 2011 Arne Olson, Partner Jack Moore, Sr. Consultant

  2. Project Goals and Approach • Overall Goal:Estimate the societal benefits of implementing an EIM throughout the West (excluding CAISO and AESO) • Approach:Calculate Production Cost Savings • GridView production simulation runs for each case • Identified $141MM in EIM Benefits for 2020; $50MM for 2009 Societal Benefit of EIM West-wide production cost without EIM West-wide production cost with EIM - = (Benchmark Case) (EIM Case)

  3. Methodology Summary • Greatest modeling focus on potential changes under EIM compared to status quo (Benchmark Case): • Benchmark Case includes “hurdle rates” intended to represent economic and non-economic barriers to trade across WECC interfaces; hurdle rates are removed for EIM Case • Benchmark Case has higher requirements for flexibility reserves needed to accommodate output of variable generation • EIM Case has EIM-wide procurement of flexibility reserves

  4. 1. Setting Hurdle Rates • “Hurdle Rates” are price adders, in $/MWh, that production simulation models use to inhibit trade between zones • EIM analysis set hurdle rates to reflect many real-life impediments to trade • Point-to-point transmission rates across interfaces • Pancaked losses • Inefficiencies due to illiquid markets • Need to use resources to serve native load • “Benchmarked” hurdle rates such that 2006 simulation results in flows across key interfaces that are similar to actual 2006 path flows • Start with OATT rate schedules & losses • Adjust as feasible to improve simulation of historical flows • Try to reduce all other (non-hurdle rate) simulation differences from historical year before adjusting hurdle rates

  5. Zones in Benchmark Case and Monitored Paths Used for Hurdle Rate Calibration (Shown with Phase 2 zone map) Zone 1 Zone 2 Northwest-BC (P3) MT-Northwest (P8) ID-Northwest (P14) Bridger West (P19) MT-ID(P18) Path C(P20) Tot 3 (P36) IPPDC(P27) COI (P66) PDCI (P65) Tot 2B (P34) Tot 2A(P31) Tot 2C (P35) No. NM(P48) West of River (P46) EOR (P49) So. NM(P47)

  6. Seasonal Benchmarking:Average Path Transfers during HLH Phase 2 Simulation 2006 Historical Flows Phase 1 Simulation

  7. 2. Modified conventional reserve requirement assumptions • Reserve needs in Gridview must be met with committed units, so are more closely the equivalent to needs for regulation & spinning contingency reserves. • For Phase 2: reserve need set at 4% (~1% for reg + 3% for spin) • Assumes sufficient capacity available from hydro units & CTs not requiring day ahead commitment to cover the 2-3% non-spin needs • Unloaded Hydro Capacity in TEPPC & final E3 analysis provided reserves equal to monthly capacity max minus hourly output *Note: Generator ramp rate constraints enforced in all cases for reserve needs. Simulation holds regulation and contingency reserves requirements even in dispatch.

  8. 2. Conventional Reserve Procurement Areas used Zone 1 Zone 2 Area 1 Area 2 Area 3 Area 4 Area 5 Area 6 13 Benchmark Case & EIM Case:Conventional reserve procurement split between Zone and Area level • Fixed portion of conventional reserves procured from resources physically located in Zone (1 of 24) • Can procure remaining portion of requirement from resources physically located within the broader Procurement Area (1 of 7) Area 7 *Note: Simultaneous implementation of reserve requirements at multiple levels of geographic aggregation required development of Gridview software customization

  9. 3. Implementing NREL Flexibility Reserve Requirements • E3 treated conventional reserves separately, so Jack King calculated flexibility reserve requirements specific for accommodating wind & solar (excluded load-related requirements) • “Supplemental” category ignored: Assumed fast ramping gas & hydro could provide without needing to force day-ahead commitment of extra generation

  10. Flexibility Reserves: Benchmark Case vs. EIM • NREL provided hourly flexibility reserve needs • To address hour-ahead uncertainty and variability of resources & loads • Reflects wind & solar diversity across EIM footprint • Average of 45% reduction vs. Benchmark case Average Hourly Reserve needs for Zones in EIM Footprint (*Excludes CAISO + AESO)

  11. Flexibility Reserves: Benchmark Case vs. EIM • NREL provided hourly flexibility reserve needs • To address hour-ahead uncertainty and variability of resources & loads • Reflects wind & solar diversity across EIM footprint • Average of 45% reduction vs. Benchmark case Average Hourly Reserve needs for Zones in EIM Footprint (*Excludes CAISO + AESO)

  12. Lessons & Potential Areas for additional TEPPC modeling • Implementation of Flexibility Reserves • Consider whether to include non-spin requirement • Treat conventional reserve requirements separately from flex (layered) vs. use integrated NREL calculation • Test assumed reserves quantities provided by hydro facilities • Also could consider hurdle rate update • Use tariff + losses only vs. benchmark to incorporate lack of information & other impediments to trade that happen in status quo

  13. Thank You! Energy and Environmental Economics, Inc. (E3)101 Montgomery Street, Suite 1600San Francisco, CA 94104Tel 415-391-5100Web http://www.ethree.com Arne Olson, Partner (arne@ethree.com)Jack Moore, Sr. Consultant (jack@ethree.com)

  14. Appendix

  15. Hurdle Rates Used for Phase 2 Study Benchmark Case Hurdle Rates (2010 $/MWh) Difference from Tariff Rate + Losses Benchmark Case Hurdle Rates (2010 $/MWh) Difference from Tariff Rate + Losses Note: In EIM Case, hurdle rates shown in blue text above are applied during unit commitment but set to zero during dispatch. Rates in gold text (related to a zone not participating in the EIM) are maintained during both unit commitment and dispatch.

  16. Hurdle Rates Used for Phase 2 Study (continued) Additional Hurdle Rates (continued from previous slide) Benchmark Case Hurdle Rates (2010 $/MWh) Difference from Tariff Rate + Losses • Phase 2 calibrated bidirectional hurdle rates for 64 different interfaces (vs. 25 in Phase 1) • For new interfaces for Phase 2 (esp. in NW and AZ) stayed close to OATT tariff rates unless flow results available to indicate otherwise • In calibration, added $2-8 premium to tariff rates to reduce certain flows: • N-S flows on East side • MT/ID into NW • CA imports • For PACE->CA, used large hurdle rate to make flows resemble 2006 actual when IPP gen is offline Note: In EIM Case, hurdle rates shown in blue text above are applied during unit commitment but set to zero during dispatch.

  17. Conventional Reserve Requirements - Zone vs. Area • Determined shares based on aggregation of feedback from discussions with EDTTRS members • Hoover Dam is important component Southwest & CA regions reserve procurement • E3 allocated Hoover reserve flexibility between zones (CAISO, LADWP, NEVP, SRP, APS, WALC) based on reserve procurement rights & ownership share information • Each zone’s allocated Hoover share counts as “within zone“ generation for reserve fulfillment

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