Generator Contingency & RAS Modeling

Transcription

1 Generator Contingency & RAS Modeling Revised Straw Proposal March 22, 2017 Perry Servedio Sr. Market Design & Regulatory Policy Developer

2 Agenda Time Topic Presenter 2:00-2:05 Introduction James Bishara 2:05-2:30 Background & objectives Perry Servedio 2:30-4:00 Stakeholder comments & changes to the proposal Perry Servedio Page 2

3 ISO Policy Initiative Stakeholder Process POLICY AND PLAN DEVELOPMENT Issue Paper Straw Proposal Draft Final Proposal Board We are here Page 3

4 BACKGROUND & OBJECTIVES Page 4

5 Brief History April 2016, published issue paper, received stakeholder feedback Conducted cross-functional internal meetings to discover, properly segment, and prioritize root issues in the generator contingency space Pivot the initiative to solve operations and regional transmission planning s highest priority issues from a reliability standpoint November 2016, published revised issue paper and straw proposal, received stakeholder feedback Conducted analyses related to RTCIO and CRR, developed CRR proposal March 2017, published revised straw proposal Page 5

6 Background Generator Contingency & RAS Modeling Generation-loss remedial action schemes can arm large portions of generation within the ISO and have the potential to drop large amounts of generation In certain outage conditions, potential generation loss can cause reliability issues on the system Transmission system security for these types of events is currently managed out-of-market - Potential for production cost savings - Potential to accurately reflect cost of supply in energy prices Page 6

7 Initiative Objectives Generator Contingency & RAS Modeling Initiative objectives: 1. Allow for the benefits of increased transmission capability while protecting the transmission system for generator contingency and RAS events, 2. Appropriately pre-dispatch generation such that all transmission lines will be below emergency ratings if a generator contingency or RAS event were to occur, 3. Appropriately price the contribution to congestion for generators on RAS vs. generators not on RAS. Page 7

8 Issues Ensure transmission line flows remain below emergency ratings Flow on transmission line (MW) Issue to resolve T T+10 Scenario 1 T T+10 Scenario 2 T T+10 Scenario 3 Page 8

9 STAKEHOLDER COMMENTS & CHANGES TO THE PROPOSAL Page 9

10 Stakeholder comments 1. DC Energy, PG&E, Powerex, WPTF, and DMM support; PG&E notes a concern about magnitude of the benefit PG&E notes a potential impact to real-time congestion imbalance offset (RTCIO) - ISO Response: the revised straw proposal covers this 2. SCE and Six Cities are concerned about: Implementation costs -ISO Response: moderate cost to implement Price formation -ISO Response: added a short section to the paper; we ve seen/heard in comments from DMM and MSC that the price formation is correct Market power mitigation -ISO Response: DMM s comments assure that there are no MPM impacts Convergence bidding -ISO Response: Constraints work the same as constraints work today, virtuals will have same impact as they do today. Impacts on CRRs -ISO Response: the revised straw proposal covers this Page 10

11 Overview of changes to the proposal 1. Added background on generator interconnection process as it relates to RAS installations 2. Added discussion on how power systems engineers model for the loss of generation today to show that the proposed enhancements to SCED are aligned with current operating criteria. 3. Added lead-in discussion to the SCED changes to re-iterate that this initiative reserves transmission capacity, not generation capacity. -GCARM CME 4. Added some discussion on why we believe the price formation and resulting economic signals are correct; will ask the MSC to provide their input. - appropriately valuing each generator s contribution to congestion on the system Page 11

12 Overview of changes to the proposal 5. Clarified we will use same outage study process as today to determine which constraints to enforce in the market on a given day. -Stakeholders requested a selection criteria: engineering analysis like today 6. Discussed potential impacts to RTCIO -Actually would have generated a surplus of $148, Propose necessary changes to the CRR market; offer alternate solutions for comment. -Have an optimal solution, plus some minimum viable alternatives -Gen/RAS contingencies have less than 4% impact on limits in the day ahead market in over 84% of the binding hourly DAM constraints Page 12

13 Changes to this proposal RAS implementation decision ISO/PTO planning groups decide to require RAS or transmission installation based on: reliability studies deliverability studies fixed infrastructure cost Decision not based on expected energy market prices Day-ahead market should model the installed system Page 13

14 Changes to this proposal Generation Distribution Factors Engineering studies utilize a generation distribution factor to simulate the system response to loss of generation and observe the change to transmission line flows The proposed enhancements to SCED are aligned with these studies Updated the proposal to only distribute generation to frequency response capable resources better alignment with engineering studies Page 14

15 Changes to this proposal Price formation and economic signals The market should appropriately price each resource s contribution to congestion May result in a RAS resource receiving a higher LMP than non-ras resource at same bus. As shown through example, this is correct Each resource is charged congestion it actually contributes to Page 15

16 Changes to this proposal Real-time congestion imbalance offset PG&E concerned that the change in commitment between DAM & RTM will result in more transmission reserved in real-time. Our scientists in the Market Quality & Renewable Integration analyzed potential impact: Analyzed from January 2016 through January 2017 Net RTCIO over the study period due to the difference in the commitment pattern between DAM & RTM would have been a $148,341 surplus. Total negative impact to RTCIO over the study period of $44,609. Page 16

17 Changes to this proposal Congestion revenue rights market enhancements If the DAM SCED is changed but the CRR SFT is not changed, we run the risk of exacerbating revenue inadequacy. 1. Proposal offers an optimal solution Directly model the new constraint in the CRR model the same as the market model As it relates to the generator/ras contingency constraints, ensures revenue adequacy 2. Proposal offers an alternate solution Do a historical study to determine the maximum amount of transmission we would have needed to reserve on each constraint per month. Withhold this quantity from the CRR market going forward May be overly conservative May not fully mitigate risk of revenue inadequacy Page 17

18 Changes to this proposal Congestion revenue rights market enhancements Day-ahead market result Page 18

19 Changes to this proposal Congestion revenue rights market enhancements Day-ahead market result DAM collects congestion revenues: 1,500 MW x $ ,414 MW x $ MW x $5 = $7,495 Page 19

20 Changes to this proposal Congestion revenue rights market enhancements CRR market without generator contingencies Page 20

21 Changes to this proposal Congestion revenue rights market enhancements CRR market without generator contingencies CRRs payout: 1,500 MW x $ MW x $ MW x $5 = $10,815 $7,495 in day-ahead market collections minus $10,815 in disbursements equals a $3,320 shortfall CRR balancing account short by $3,320 Page 21

22 Changes to this proposal Congestion revenue rights market enhancements Proposal to enhance CRR market Constraint GFF GDF Page 22

23 Changes to this proposal Congestion revenue rights market enhancements CRR market with generator contingencies Page 23

24 Changes to this proposal Congestion revenue rights market enhancements CRR market with generator contingencies CRRs payout: 1,500 MW x $ ,414 MW x $ MW x $5 = $7,495 $7,495 in day-ahead market collections minus $7,495 in disbursements equals a $0 shortfall CRR balancing account neutral Page 24

25 Changes to this proposal Congestion revenue rights market enhancements Alternative solution Do a historical study on binding generator contingency constraints Withhold transmission capacity from the auction Historical study shows we needed to withhold a maximum of 1,414 MW of transmission -> set limit to 86 MW Page 25

26 Changes to this proposal Congestion revenue rights market enhancements Our scientists in the Market Quality & Renewable Integration group analyzed potential impact: Analyzed binding DAM constraints from January 2016 through January 2017 Modeled largest generator/ras loss on the binding DAM constraints Gen/RAS contingency impacted binding DAM constraints by less than 4% in over 84% of observations. Few observations with over 10% impact Results show that the contingency did not impact constraints all of the time. Different from hour to hour The largest single daily impact to a binding constraint was 35.8% of the line rating on one line Positive percentage represents more transmission needs to be reserved Page 26

27 Changes to this proposal Congestion revenue rights market enhancements Potentially relying on the global scaling factor Currently apply a global scaling factor to all of its enforced internal transmission elements in the congestion revenue rights market model. The global scaling factor applies to all lines at all times. Gen/RAS constraints do not impact all constraints at all times Currently withholds 17.5% of transmission capacity Accounts for potential de-rates that occur due to differences in the outage conditions between the congestion revenue rights market run and the dayahead market run. ISO could consider allowing the global scaling factor to cover the appropriate amount of transmission to withhold from the congestion revenue rights allocation/auction. Page 27

28 RECAP Page 28

29 Recap 1. Added background on generator interconnection process as it relates to RAS installations 2. Added discussion on how power systems engineers model for the loss of generation today to show that the proposed enhancements to SCED are aligned with current operating criteria. 3. Added lead-in discussion to the SCED changes to re-iterate that this initiative reserves transmission capacity, not generation capacity. -GCARM CME 4. Added some discussion on why we believe the price formation and resulting economic signals are correct; will ask the MSC to provide their input. - appropriately valuing each generator s contribution to congestion on the system Page 29

30 Recap 5. Clarified we will use same outage study process as today to determine which constraints to enforce in the market on a given day. -Stakeholders requested a selection criteria: engineering analysis like today 6. Discussed potential impacts to RTCIO -Actually would have generated a surplus of $148, Propose necessary changes to the CRR market; offer alternate solutions for comment. -Have an optimal solution, plus some minimum viable alternatives -Gen/RAS contingencies have less than 4% impact on limits in the day ahead market in over 84% of the binding hourly DAM constraints Page 30

31 QUESTIONS Page 31

32 NEXT STEPS Page 32

33 Next Steps Please submit written comments on the revised straw proposal to by COB April 5, 2017 Materials related to the Generator Contingency and Remedial Action Scheme Modeling initiative are available on the ISO website at: dialactionschememodeling.aspx Page 33