July 8 -10, 2019| Markets committee

1. July 8 -10, 2019| Markets committee Andrew Gillespie 413.540.4088 | agillespie@iso-ne.com Discussion of a market-based solution to improve energy security in the region ENERGY SECURITY IMPROVEMENTS: MARKET-BASED APPROACHES Ben Ewing 413.535.4361 | bewing@iso-ne.com

2. Winter Energy Security Improvements WMPP ID: 125 Proposed Effective Date: Mid 2024 In accordance with FERC’s July 2, 2018 order in EL18-182-000, the ISO must develop and file improvements to its market design to better address regional fuel security, and file by October 15, 2019 Key Projects – Energy-Security Improvements • Discussion paper 2019-04-09 and 2019-04-10 MC A00 ISO Discussion Paper on Energy Security Improvements – Version 1 Prior Energy-Security Improvement presentations: • June ESI presentation • May ESI presentation • April ESI presentation

3. Today’s Presentation Agenda • New Day-Ahead Ancillary Services • Energy Imbalance Reserve (EIR) • Reliability standards related to day-ahead ancillary services • Replacement Energy Reserve (RER) • Option Specifications • Updates on mechanics-type questions • Cost allocation methodology (and some interesting notes & observations) • Multiple Day-Ahead Market (MDAM) • An update on ISO’s perspective to phase-in the MDAM • Mechanics and participation • Clearing and settlement • A comparison of the MDAM to opportunity cost bidding in a single day-ahead market Notes: • ‘Stakeholder questions’ embedded in this presentation are paraphrased questions asked during previous presentations • The use of the term ‘unit’ throughout is meant generically (a.k.a., resource, asset, etc.)

4. Mitigation • The ISO is continuing to assess appropriate approaches to mitigation: • Extent of option pivotal suppliers during tight operating days • Appropriate basis for market-wide offer caps (if any) • Detailed mitigation-related rules will be part of the ISO's efforts in 2020, subject to FERC approval of the core ESI design filing in October

5. Stakeholder Question • Some units can have different fixed costs to provide different ancillary service capabilities. What is the ISO’s thinking on that? • This would require different option offers for different ancillary services. • Instead of two offers per hour, a separate option offer and energy offer, there’d be (potentially) six offers per hour (one for energy and one option offer for each ancillary service requirement). • The ISO has carefully considered this suggestion. This approach would not fundamentally change the core design concepts. • However, given the complexity associated with adding this type of flexibility into the design at this point in time, this aspect might be better addressed as part of the ISO's efforts in 2020, subject to FERC approval of the core ESI design filing in October.

6. Overview & design objectives and principles

7. Three Conceptual Components Slide 6: April ESI presentation • Multi-day ahead market. Expand the current one-day-ahead market into a multi-day ahead market, optimizing energy (including stored fuel energy) over a multi-day timeframe and producing multi-day clearing prices for market participants’ energy obligations • New ancillary services in the day-ahead market. Create several new, voluntary ancillary services in the day-ahead market that provide, and compensate for, the flexibility of energy ‘on demand’ to manage uncertainties each operating day • Seasonal forward market. Conduct a voluntary, competitive forward auction that provides asset owners with both the incentive, and necessary compensation, to invest in supplemental supply arrangements for the coming winter

8. Design Objectives for a Market-Based Solution Slide 46: April ESI presentation • Risk Reduction. Minimize the heightened risk of unserved electricity demand during New England’s cold winter conditions by solving Problems 1, 2, and 3 • Cost Effectiveness. Efficiently use the region’s existing assets and infrastructure to achieve this risk reduction in the most cost-effective way possible • Innovation. Provide clear incentives for all capable resources, including new resources and technologies that can reduce this risk effectively over the long term

9. Design Principles for a Market-Based Solution Slide 47: April ESI presentation • Product definitions should be specific, simple, and uniform. The same well-defined product or service should be rewarded, regardless of the technology used to deliver it • Transparently price the desired service. A resource providing an essential reliability service (for instance, a call on its energy on short notice) should be compensated at a transparent price for that service • Reward outputs, not inputs. Paying for obligations to deliver the output that a reliable system requires creates a level playing field for competitors that deliver energy reliably through cold-weather conditions • Sound forward markets require sound spot markets. Forward-market procurements work well when they settle against a transparent spot price for delivering the same underlying service • Compensate all resources that provide the desired service similarly.

10. Categories of New Day-Ahead Ancillary Services Slide 10: June ESI presentation * See slides 15-18 of May ESI presentation: Covering the Energy Gap Procure an energy call option in the Day-Ahead Energy Market (co-optimized with clearing energy schedules) to provide three new ancillary services corresponding to the three operational categories previously discussed* • Generation Contingency Reserves (GCR) – A day-ahead means to assure operating reserve energy • Replacement Energy Reserves (RER) – A day-ahead means to assure replacement energy • Energy Imbalance Reserves (EIR) – A day-ahead means to assure energy to cover the load-balance gap Combined, these provide the ‘margin for uncertainty’ in an increasingly energy-limited system

11. New day-ahead ancillary services In this section we will: Review Energy Imbalance Reserves Using an example, review the reliability standards as the basis for setting each ancillary service’s requirement(s) Discuss Replacement Energy Reserves (clearing and awards)

12. Energy imbalance reserves (EIR) A review and discussion of the example presented in the June presentation Note: Edits to June slides in this presentation are in blue text

13. Energy Imbalance Reserves (EIR) Forecast energy demand frequently (but not always) exceeds the total physical energy supply cleared in the Day-Ahead Energy Market Energy call options will also be awarded to cover the load-balance ‘gap’ when total day-ahead physical energy supply awards are less than the ISO’s forecasted energy demand, in one or more hours, for the next (operating) day These option awards help ensure there is sufficient energy to cover the forecast energy demand each hour of the next operating day

14. EIR Requirement (Amount Demanded) • EIR is meant to cover the load-balance gap in an hour when the total day-ahead cleared physical energy supply schedule amount is less than the ISO’s energy forecast for that hour EIR option awards = forecasted energy – total physical DA energy awards • Where (for discussion purposes): • Physical Energy (PE) is the total physical energy supply award amount • Forecasted Energy (FE) is the forecasted energy requirement, which will incorporate load and wind/solar forecasts(forecast error is part of RER) • Re-writing this (and because this is intended to cover the gap, if there is one): EIR Requirement (MWh) = max (0, FE – PE) = (FE – PE)+

15. Description of Useful Defined (Tariff) Terms Section I–General Terms and Conditions Demand Bid. A request to purchase energy at a specified price that is associated with a physical load. A cleared Demand Bid in the Day-Ahead Energy Market results in scheduled load at the specified Location. Virtual Transactions Decrement Bid (DEC). A bid to purchase energy in the Day-Ahead Energy Market which is not associated with a physical load. (Energy is ‘sold’ back in real-time, at the real-time LMP.) Increment Offer (INC). An offer to sell energy in the Day-Ahead Energy Market which is not associated with a physical supply. (Energy is ‘bought’ back in real-time, at the real-time LMP.)

16. EIR Requirement Determination For cleared day-ahead amounts there is a balance constraint we can use to better specify the various energy clearing amounts • Total cleared supply must equal total cleared demand Cleared supply = cleared demand • We can write this as: PE + INCs = Demand Bids + DECs • And re-order it: PE = Demand Bids + DECs - INCs • And, using this in the EIR requirement equation EIR Requirement = (FE – (Demand Bids + DECs – INCs))+

17. Stakeholder Question • Can the ISO provide more specific formulas that go with the requirements, particularly EIR? • Yes. The next few slides provide a summary of the EIR requirement as described in the “Reliability Standards Supporting Day-Ahead Ancillary Services Requirements” memo. • This requirement is reflected in the EIR data depicted in the Day-Ahead Implied Ancillary Service Requirements - 2018 table included on slide 31 of the June ESI presentation. • EIR awards are determined to satisfy the system’s hourly next-day forecast energy requirement (next slide) • This forecast energy requirement is used in the Reserve Adequacy Analysis (RAA) process today, and will be brought into the Day-Ahead Energy Market clearing process

18. Forecast Energy Requirement Constraint The forecast energy requirement constraint for a given hour (h) is: + + ≥ - Where: • is the total of all DA energy cleared for hour h for all physical generation resources (including active demand response treated as supply) • is the net scheduled interchange of energy for hour h cleared DA (here, imports are positive, exports are negative) • is the energy required for hour h to satisfy the forecast energy requirement • is the ISO’s energy demand (load) forecast for hour h (net of any behind-the-meter energy supply and settlement-only generation not directly visible to the ISO) • is the ISO’s day-before forecast of incremental (or decremental) real-time energy supply from intermittent power resources relative to (i.e., minus) the energy from the same resources that cleared DA for hour h

19. EIR Requirement • Solving for - the energy required for hour h to satisfy this forecast energy requirement = max{0, - - - } • In implementation, the revised Day-Ahead Energy Market will solve simultaneously for cleared quantities of each term above • Excepting the forecast load and the forecast intermittent power forecast incorporated in , which are exogenous to clearing • The revised Day-Ahead Energy Market will simultaneously also solve to match cleared bid-in demand with cleared energy supply awards, as it does today • The additional physical energy, , to satisfy the forecast energy requirement (if positive)would receive an EIR award in the new, integrated day-ahead energy and ancillary service market

20. Unit Eligible Quantities Unlike GCR capability, a unit’s response time (ramp-up or startup timeframe) for EIR may be considerably longer EIR serves a different purpose. Options awarded to meet the EIR requirement address the load-balance gap Startup-times would not restrict a resource from receiving an EIR award in the day-ahead market, unless it could not start and be released for dispatch by the relevant delivery hour of the next day (given its schedule for the current day)

21. Forecast energy Requirement and energy imbalance reserve pricing A two-step example, with stops for explanations

22. EIR Examples: EIR Clearing and Clearing Prices • In the GCR only example (see May ESI presentation) we saw how option opportunity costs can be ‘inside’ the Day-Ahead LMP • In that example the day-ahead LMP is greater than the expected real-time LMP, which in turn prompted many questions: • Wouldn’t load (i.e., Demand Bids) want to buy less day-ahead? • Wouldn’t virtual supply (i.e., INCs) want to take advantage of this price difference? • To demonstrate EIR clearing and to answer those questions we extend the example in two steps • What we will see is that with the EIR constraints in place together with the GCR constraints, there is no price difference created between the day-ahead and real-time LMPs, and that the payments remain the same

23. Extending the Example with GCR and EIR * Physical Energy: physical energy supply awards First Step • We will add the anticipated reactions • To create the ‘gap’ we will lower the cleared Demand Bid amount to a value less than the forecast load • We will add an INC, offered at the expected real-time LMP • Observations • We will see how payments to Physical Energy* are the same (still $44.95/MWh) • We will see how the LMPs are still different, but in the opposite direction Second Step • We will extend the example further by adding the anticipated reactions to the first step • We will add a DEC, bid at the expected real-time LMP

24. Extending the Example - First Step Extending the example • To create the ‘gap’ we will now assume a lower day-ahead cleared Demand Bid amount of 700 MWh • This is 20 MWh less than the energy demand forecast of 720 MWh • We will add an INC, offered at the expected real-time LMP • In the example we will add an INC, offered at $42/MWh Notes: • For comparison purposes, the GCR-only example has been reformatted on the next slide • On the slide following that, the EIR and GCR constraint example is presented

25. Prior Example (GCR Constraints Only)

26. Example With GCR and EIR ConstraintsFirst Step

27. Day-Ahead Clearing Prices With GCR and EIR Constraints – First Step

28. Day-Ahead LMP Explanation – First Step • The LMP that demand faces for energy is based on marginal cost • Here, the re-dispatch for an additional increment of energy reduces the marginal cost of an additional increment of bid-in energy demand • One more increment of cleared bid-in demand has a ‘redispatch’ cost savings of $2.59/MWh • Each incremental MWh of cleared demand increases the amount of energy cleared by 1 MWh, and reducesthe total EIR options awarded to cover the ‘load-balance gap’ by 1 MWh

29. Forecast Energy Requirement – First StepOpportunity Cost ‘Outside’ the LMP • In order to make Unit F indifferent as to whether it supplies energy or options, it must also be compensated its opportunity cost • Unit F’s total compensation for energy must be $44.95/MWh • However, we cannot incorporate this opportunity cost ‘inside’ the LMP as that would not be the correct marginal cost facing bid-in demand (see prior slide) • We will call this missing opportunity cost the Forecast Energy RequirementPrice (FERP) • Technically, it is the shadow price on the FER constraint • And we must pay the FERP to Physical Energy outside (i.e., in addition to) the LMP

30. Observations • Wait, the day-ahead LMP is still different! How does EIR fix the apparent price difference problem? • Because now we would anticipate the opposite reaction • Wouldn’t load (i.e., Demand Bids) want to buy moreday-ahead? • Wouldn’t virtual demand(i.e., DECs) want to take advantage of this price difference? Second Step • We will extend the example further by adding the anticipated reactions to the first step, since the expected real-time LMP is still $42/MWh • We will add a DEC, bid at the expected real-time LMP ($42/MWh)

31. Example With GCR and EIR ConstraintsSecond Step

32. Day-Ahead Clearing Prices With GCR and EIR Constraints – Second Step

33. Day-Ahead LMP Explanation – Second Step • The LMP that demand faces for energy is based on marginal cost • Here, because the DEC bid is $42/MWh (think $41.999/MWh) it is marginal and sets the LMP • Note: DEC and Demand Bids are equivalent in terms of clearing Generally speaking (for day-ahead LMPs): • If a physical unit is marginal for energy, the LMP will be based on its energy offer price and EIR (cost) savings • If a virtual bid or offer (DEC or INC) is marginal for energy, the LMP will be based on its (bid or offer) price • A marginal cleared virtual would not produce any EIR cost savings

34. Forecast Energy Requirement – Second StepOpportunity Cost ‘Outside’ the LMP • In order to make Unit F indifferent as to whether it supplies energy or options, it must also be compensated its opportunity cost • Unit F’s total compensation for energy must be $44.95/MWh • Now, observe that the EIR clearing price is equal to Unit F’s option opportunity cost • There may be a clearing price determined, even if no award is made, because the ‘load-balance’ constraint (the forecast energy requirement) has a true cost at the margin • Hence, the Forecast Energy RequirementPrice(FERP) will equal to the EIR clearing price, here and in general • Notice that this was also true in the first step

35. Day Ahead Payment Rates

36. Stakeholder Question • Is it correct to think that resources with an EIR award should expect to be committed to meet the forecast for the next day? • Yes. A unit with an EIR option awarded to meet the day-ahead forecast energy requirement should expect to receive a commitment instruction, which would be consistent with its start-up and notification times. • We are still assessing whether it would be beneficial to economically “re-evaluate” commitment of a unit with an EIR award (but with no energy award) in the day-before or intra-day RAA optimization processes.

37. Stakeholder Question • If a unit has an EIR award and is being evaluated for unit commitment in the RAA, would the RAA still evaluate its startup costs and would real-time uplift be applicable to that commitment? • The RAA will (continue to) consider the unit’s 3-part energy offer, however, precisely how the option payment be addressed in real-time uplift calculations has not (yet) been examined. • Examining uplift will be part of the ISO's efforts in 2020, subject to FERC approval of the core ESI design filing in October. • As a reminder, the intent (here and generally) is to ensure that units always have incentives to follow commitment and dispatch instructions.

38. NERC/NPCC/ISO standards related to day-ahead ancillary service awards The total amount of energy call options procured is based on the different ancillary service requirements (i.e., the required amounts for each category)

39. Ancillary Service Requirements Slide 27: June ESI presentation * See slides 15-18 of May ESI presentation: Covering the Energy Gap • The total amount of energy call options procured will meet each of the day-ahead ancillary service requirements (GCR, EIR, and RER) • In this context, the ‘requirement’ is a quantity and should not be confused with or interpreted to imply any corresponding obligationrequirement • These amounts would be based, at a minimum, on the procedures currently applied by the ISO in developing a reliable next-day operating plan* • Required quantities are not static; they are inherently dynamic and will vary both hourly and day-to-day based on: • The energy demand forecast • The generation cleared for energy in the day-ahead market • The system’s largest anticipated potential single-source energy loss

40. NERC/NPCCC/ISO Reliability Standards A brief summary of the “Reliability Standards Supporting Day-Ahead Ancillary Services Requirements” memo The memo identifies the various NERC/NPCC/ISO reliability standards and procedures currently used in developing a reliable next-day operating plan The quantities derived are formulaic, and while currently incorporated in the next-day operating plan, not all categories are formally designated and compensated As described in the memo, a similar formulaic determination will be the basis for setting the required amount of energy call options for the different day-ahead ancillary service categories (GCR, EIR and RER)

41. Stakeholder Question • How do the pieces (GCR, EIR and RER) fit together? Why are all three needed? • As described in the memo, all three are taken into account when developing a reliable next-day operating plan. • Each requirement requires different (physical) resource capabilities, above DA energy awards, as part of the ISO’s next-day Operating Plan. • While the ISO takes into account the (unloaded) supply capability available to recover from a large supply contingency, the ISO must alsotake into account what additional (unloaded) supply capability is available to fill the energy gap created when the reserve requirement is restored (i.e., what units will provide energy when the activated reserve units are put back into a reserve state). • The example in the memo illustrates this, and we will review that example in the next few slides.

42. Day-Ahead Ancillary Service Requirements As described in the memo: • The day-ahead requirements for TMR, TMSR and TMOR (i.e., GCR) would be the same as formulated currently based on the anticipated first and second largest contingencies in each hour of the next-day • Two types of RER are needed in order to meet restoration timeframes: • 90-min RER. This requirement would equal one-half of the second largest contingency • 240-min RER. This requirement would equal one-half of the third largest contingency

43. Graphic of Key Timeline Concepts

44. Example: Initial Conditions • For demonstration purposes, assume that pre-contingency the system has exactly the required amount of reserves Meaning, • There is only 1,600 MW of Ten-Minute Reserve capability (also called Contingency Reserve) • There is only 700 MW of Thirty-Minute Reserve capability • No other unloaded capability is available (i.e., can provide energy) within 30 minutes or less

45. Contingency Recovery and Restoration Timeline

46. Time Window: First 15 Minutes(a.k.a. Contingency Event Recovery Period) • Contingency Event occurs (first largest contingency, Resource A trips) • This creates a 1,600 MW energy gap • For demonstration purposes we will assume the load does not change over the time span depicted • All 1,600 MW of Ten-Minute Reserve are ‘activated’ (red line in diagram) within 15 minutes • Ten-Minute Reserve is now depleted (0 MW remain) • Ten-Minute Reserve must be restored within 90 minutes following the Contingency Event Recovery Period • However, the new requirement is 1,400 MW as Resource B is now the most severe single contingency (i.e., the new 1st contingency, post the Contingency Event depicted)

47. Time Window: 15 Minutes to 30 Minutes • All 700 MW of Thirty-Minute Reserve are ‘activated’ (green line in diagram) • The energy from these resources will allow 700 MW of the activated Ten-Minute Reserve to be backed down (creating 700 MW of Ten-Minute Reserve) • Thirty-Minute Reserve is now depleted (0 MW remain) • However, the requirement is now 650 MW as Resource C is now the second most severe single contingency (i.e., 2nd contingency, post the Contingency Event depicted)

48. Time Window: 30 Minutes to 105 Minutes • Without additional action, the Ten-Minute Reserve requirement is still deficient 700 MW • Ten-Minute Reserve must be restored within 90 minutes following the Contingency Event Recovery Period • An additional 700 MW of (replacement) energy is provided by unloaded capability available within 90 minutes (blue line in diagram) • The energy from these resources will allow an additional 700 MW of the 900 MW remaining ‘activated’ Ten Minute Reserve to be backed down, creating a total 1,400 MW of Ten-Minute Reserve – as required • The additional energy amount needed within 90 minutes (one half of Resource B) is the basis for the 90-min RER requirement for Operating Reserve restoration purposes

49. Time Window: 105 Minutes to 255 Minutes • Without additional action, the Thirty-Minute Reserve requirement is still deficient 650 MW • The Thirty-Minute Reserve requirement is to be restored within 240 minutes from the end of the Contingency Event Recovery Period • An additional 650 MW of (replacement) energy is provided by unloaded capability available within 240 minutes (brown line in diagram) • The energy from these resources will allow 650 MW of the still ‘activated’ Thirty-Minute Reserve to be backed down (i.e., restored) • The additional energy amount needed within 240 minutes (one half of Resource C) is the basis for the 240-min RER requirement for Operating Reserve restoration purposes

50. Stakeholder Question • Will Market Participants know the requirements before bidding each day? Will it be like the Forward Reserve Market (FRM) where the requirement is known before auction? • Unlike the FRM requirements which are fixed for the auction, the requirements for the new ancillary services are formulaic. • So while the requirement ‘formulas’ are known, the precise amounts each day/hour will depend on how the day-ahead market is cleared. • This is true for TMR, TMSR, and TMOR on a day-ahead basis today. • The ISO presently posts the values for the operating reserve requirements through ISO Express and other materials for the operating day (e.g., the Morning Report). Similarly, we expect to post the day-ahead requirements although precisely how may be determined as part of the ISO's efforts in 2020, subject to FERC approval of the core ESI design filing in October.