June 10-12, 2019| Markets committee

1. June 10-12, 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

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: • May ESI presentation • April ESI presentation

3. Today’s Presentation Agenda • Day-ahead energy call options: Fundamentals, obligations, offers, and mechanics • Day-Ahead Ancillary Services • Generation Contingency Reserves (GCR) • Energy Imbalance Reserves (EIR)Including an answer to the ‘virtuals’ question • A preview of Replacement Energy Reserves (RER) 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. Items for Future Meeting Discussion Continued on next slide Design aspects the ISO is preparing for future meetings: • The seasonal forward and multi-day ahead market (M-DAM): • The ISO has previously noted that the seasonal forward component would be taken up in a separate track • The ISO is reviewing the stakeholder suggestion to develop the M-DAM sequentially (i.e., separately from the October filing scope) • Jurisdictional questions regarding energy call options • The ISO is reviewing this, but does not believe there is an issue

5. Items for Future Meeting DiscussionContinued • Mitigation • Other ISO/RTO day-ahead markets have varying day-ahead ancillary service offer mitigation practices; some have (market-wide) offer caps only, and cap-levels vary • In general, market power in day-ahead ancillary services is likely to be tempered by the fact that energy call option offers are (indirectly) competing with all energy supply offers via co-optimization • 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)

6. Overview and energy market basics

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 * 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. Energy Market mechanics A high-level review of the energy market, from day-ahead to real-time

12. Day-Ahead Energy Market: Current Practice * See slides 59-60 of April ESI presentation Generally speaking: • Each day for each unit, Market Participants submit hourly energy offers into the Day-Ahead Energy Market, up to the unit’s Economic Maximum • A unit with a cleared day-ahead energy offer in a given hour then has a day-ahead energy ‘schedule’ for that hour • This day-ahead energy schedule amount (MWh) is settled in two parts; day-ahead award and close-out of day-ahead position* • A unit’s day-ahead hourly energy offers remain in effect in real-time, and may adjusted for use in real-time (often called ‘re-offers’) • Energy delivered in real-time is settled at the real-time LMP*

13. Day-Ahead Energy Market: Current Perspectives • From a participant’s perspective: The day-ahead market is a financial market, for forward sales/purchases of real-time delivered energy • From the ISO’s perspective: The day-ahead market’s energy supply awards are the basis for (most of) the ISO’s next-day operating plan requirements for the region’s power system • With the proposed new day-ahead ancillary services: • The day-ahead market will remain a financial market, with both forward transactions for real-time energy and option transactions for real-time energy • The day-ahead market awards will cover – “in market” – more of the ISO’s next-day operating plan requirements (the load forecast, various reserve capabilities, etc.) • Meeting these requirements via “in market” awards improves resources’ incentives to arrange energy supplies facing uncertainty

14. Real-Time Energy Market • After the Day-Ahead Market is cleared the ISO may commit additional units in the Reserve Adequacy Analysis (RAA) based on the energy forecast for the next day (e.g., if day-ahead cleared physical generation is less than the forecast) • Throughout the operating day the ISO may re-run the RAA and commit additional units, if needed • For more information see Manual 11 Market Operations

15. day-ahead energy call option

16. Day-Ahead Energy Call Option • In this section we will review the day-ahead energy call option fundamentals: • Mechanics • Quantities procured • Obligation • Offer price formulation • Strike price determination • Settlement

17. Parameters of Day-Ahead Energy Call Option

18. Day-ahead energy Option Mechanics

19. Product (Energy Call Option) Seller’s Perspective • Product: An hourly energy call option construct, awarded to units that submit and clear an option offer in the day-ahead energy market • Hourly awards (in MWh) • Hourly clearing prices ($/MWh) • One (hourly) offer price ($/MWh) • A resource may have a different offer price for each hour of each day • More on different costs in the Offer Price Formulation section below (slide 43) • A maximum amount offered (MWh) • This would limit the total DA option award to the resource • This may be zero, the resource’s maximum eligible capability, or something in between • In exchange for payment at the option clearing price for the hour, the resource will be subject to an option ‘close-out’ settlement for that corresponding hour

20. Option Mechanics – Submitting Offers • The ISO will specify the option strike price ($/MWh) for each hour before option offers are submitted into the day-ahead market – more on this in the Strike Price Determination section below • Hourly option offers would be submitted at the same time hourly energy offers are submitted • For every hour in the day-ahead market a unit may have both an energy offer and an option offer • Current thinking: Option offers would not be specific to a particular ancillary service requirement - more on this in the Offer Price Formulation section below (slide 43) • When submitting offers it is not necessary to adjust energy offers for any option offer submitted, nor is it necessary to adjust option offers for energy offers submitted; the market clearing engine will determine which (energy or option, if any) to clear from the unit

21. Option Mechanics – Awards • A unit with a cleared option (an option ‘award’) in a given hour then has a day-ahead option position for that hour in addition to any energy schedule • Day-ahead energy schedules and option awards would be feasible given the unit’s physical parameters • In a given day, a unit may have an energy schedule in some hours, and an option award in other hours, or some combination if feasible given the unit’s physical parameters • The sum of an energy schedule and option award in the same hour would be greater than or equal to the unit’s Economic Minimum, and less than or equal to the unit’s Economic Maximum • Energy schedule and option award amounts may vary hour-to-hour

22. Option Mechanics – Exercise In real-time: The option award will be 'closed out' at the delivery hour real-time LMP (more on the next slide) During the operating day, the unit will be economically committed for/dispatched during the delivery hour based on its then-prevailing real-time energy supply offer (as occurs today) The unit is not explicitly 'exercised' (dispatched/committed) based on its option award or based on the strike price

23. Option Mechanics – Settlement • Day-ahead clearing price for option award paid to unit • Day-ahead option position is closed-out at delivery hour’s real-time LMP • If the real-time LMP is greater than the strike price the unit will be debited an amount equal to the product of the option quantity and the difference between the real-time LMP and the strike price • The unit is also credited for any real-time energy and real-timereserves supplied at the applicable real-timeprices (5-minute real-timemarket settlements)

24. Stakeholder Questions • Can a Limited Energy Resource be limited in its cleared energy schedule and option awards (to a daily MWh limit)? • The ISO is still assessing this suggestion/question. • When are options procured? Seasonally? Daily? Hourly? • For the short-forward component (2ndbullet on slide 7) the current thinking is these options would be procured in the DA market for each hour of the next operating day, year-round. • Are there any sustainability requirements for these ancillary service awards? • At present the only sustainability requirement is the capability of the unit as reflected in the unit’s day-ahead supply offer information. • For example, an option would not be awarded to a unit that is out of service per its supply offer information.

25. Stakeholder Question • Is there any kind of “pre-qualification” process? For example, demonstration of fuel supply arrangements before being allowed to submit an offer for the new products? • Is there any way to ask for participants to demonstrate they have made the necessary fuel arrangements in order to qualify to participate in this voluntary market? Response: • For the short-forward component (2nd bullet on slide 7) the current thinking is there would not be a ‘pre-qualification’ process or fuel demonstration requirement. • It is not a requirement that a unit have an explicit fixed fuel cost to submit an option offer – more on this in the Offer Price Formulation section below.

26. Quantities procured The total amount of energy call options procured is based on the different ancillary service requirements (i.e., the required amounts for each category)

27. Ancillary Service Requirements Buyer’s Perspective * 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

28. Stakeholder Question * See slides 15-18 of May ESI presentation: Covering the Energy Gap • How are the daily required quantities determined for each category? • In the July Markets Committee presentation we will present materials identifying the various NERC/NPCC/ISO reliability standards and procedures currently used in developing a reliable next-day operating plan (including covering any potential energy gaps).* • The quantities derived from these standards and procedures are formulaic, and while currently incorporated in the next-day operating plan not all categories are formally designated and compensated. • 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.

29. Stakeholder Question * See slide 20 of May ESI presentation: Covering the Energy Gap • How do the pieces (GCR, EIR and RER) fit together? Why are all three needed? • All three are taken into account when developing a reliable next-day operating plan.* • While the ISO considers what reserve units could be used to recover from a large supply contingency, the ISO must also consider what units can be used 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). • In addition, the ISO must also take into account what units might be used to cover the energy gap if/when physical generation scheduled in the day-ahead market is less than the energy demand forecast.

30. Stakeholder Question • Can the ISO show the data supporting the ‘4-6 GW’ of resources for which Problem 1 is a concern (slide 19 of May ESI presentation)? • Yes. Please see the following slide for a representation of each category for the year 2018.

31. Ancillary Service Requirements - 2018 • GCR: Hourly Total Operating Reserve Requirement used in the initial RAA for the operating day • RER: As an approximation, each day’s avg. hourly largest single source loss (initial RAA) for the operating day • This will be refined as the RER requirements are developed (July MC) • EIR: Hourly difference in physical energy supply cleared in the DAM and scheduled in the RAA (positive values only)

32. Obligation Energy call options do not obligate a unit to provide a specific ancillary service in real-time

33. Energy Call Option Obligation Seller’s Perspective • The ‘product’ is energy call option • The obligation: Hourly day-ahead energy call option awards open after the last (prompt) day-ahead clear will be settled (closed out) against real-time prices • From the supplier’s perspective, the option is on real-timeenergy – not to a specific real-time ancillary service • There is no call option on GCR or call option on EIR, etc.; • Regardless of why the option was awarded to the unit, the same option settlement against the RT LMP applies • Dispatch/commitment during the operating day is (still) based on real-time energy supply offers only • From the buyer’s perspective whether an energy call option is awarded to a unit will depend, in part, on the unit’s physical capabilities and the particular ancillary service requirement(s) those capabilities can satisfy

34. Stakeholder Questions • What is different between the various products?What are the obligations for the different products? • There are no different products, they are all an energy call option. Hence, there are no different obligations, just the option settlement treatment (in particular, the option close-out). • Why are you distinguishing between the products? • The amount of energy call options procured, and from what resources, is based on the different ancillary service requirements (i.e., required amounts for each category). • Thus, the ISO may buy an energy call option from a unit that is GCR capable to meet the GCR requirement – but this does not translate into real-time GCR-type obligation.

35. Stakeholder Questions • If I’m going to provide GCR, I need to be 10 or 30 minute capable. Is there any difference between taking a GCR, EIR or RER obligation? What are the implications of that? • Do the designations and prices matter once you get to real-time operations?Does a GCR award “carry thru” to a real-time reserve designation? Response: • There are no different ‘products’ with different obligations. A unit awarded an energy call option to meet the GCR requirement, for example, is not ‘designated’ as a GCR resource, in day-ahead or in real-time. • There may be different clearing prices paid for energy call options counted toward meeting each specific requirement, due to different aggregate supply (and demand) levels for each requirement.

36. Stakeholder Question • I’d prefer to be awarded the product with the least risk of actually being called to run. Are different products more/less likely to be called in real-time? • There is no ‘carry thru’ of day-ahead option awards or types to the economic commitment/dispatch process during the operating day (i.e., in real-time). • The ‘risk’ does not depend on why the option was awarded to the unit, but rather the settlement implications of selling the energy call option. • The ‘risk’ of actually being called to operate in real-time, if awarded a day-ahead energy option, (still) resides with the unit’s real-time energy supply offers only.

37. Stakeholder Question • Will real-time reserves still be separate products, co-optimized in real-time like today? Do I still get the real-time reserve clearing price (if designated in real-time) if the GCR option was out of the money, or if I didn’t sell a GCR option? • Yes. As previously noted, there are no ‘product’ designations in day-ahead or in real-time. Consequently, real-time unit commitment, dispatch, and real-time reserve designations will continue to function as they do today (i.e., irrespective of any energy call option award). • We expect the reason why a unit was awarded an option will generally translate into how the unit is economically utilized in real-time. • A unit awarded an option to satisfy the GCR requirement would tend to be economically designated for reserves in real-time. • A unit awarded an option to satisfy the EIR requirement would tend to be committed in the RAA process (day-ahead or intra-day) to help meet forecast load. • A unit awarded an option to satisfy the RER requirement would tend to be used to cover any energy gap created when restoring real-time reserves after a contingency, or due to forecast error.

38. Offer Price Formulation

39. Offer Components Seller’s Perspective Two components to consider: • Option close-out = max(0, LMPRT – K) = (LMPRT – K)+ • Unrecovered ‘fixed’ costs incurred to cover the option = fixed costs – real-time net revenue In this section we will: • Review the relevant components of the option offer price • Using an example, clarify understandings regarding: • The ‘fixed’ cost component • The option strike price and the unit’s marginal cost

40. Option Close-Out Option close-out = max(0, LMPRT – K) = (LMPRT – K)+ • This settlement treatment does not imply that a unit’s real-time energy offer price should be based on, or set equal to, the strike price • In this section we will demonstrate that it is unnecessary to alter a unit’s real-time energy offer price if the unit has been awarded a day-ahead energy call option • Ideally, the strike price (K) should be set equal to the expected real-time energy price – more on this in the Strike Price Determination section below

41. Unrecovered Fixed Costs * ISO Discussion Paper on Energy Security Improvements: pages 12-13 Unrecovered costs incurred to cover the option= fixed costs – real-time net revenue Fixed costs are distinct from production (i.e., marginal) costs “These assumptions are intended to capture the practical realities that there are fixed costs of acquiring energy supplies in advance of an operating day, in addition to the (marginal) cost of using the fuel itself.”* “For example, consider the $40 fixed cost as the retainer (per MWh) for an intraday-notice gas supply contract with an LNG terminal, and the $70/MWh cost as the incremental cost of calling for gas in order to run the next day if the generator is dispatched. Or, more broadly, consider the up-front cost as the generator’s fixed cost to pre-arrange oil transportation service that would enable prompt replenishment of oil inventories, without which a generator would be out of fuel and not be able to run at all (for the relevant operating day).”*

42. Stakeholder Question • How are you thinking about that fixed-cost number? A lot of those fixed cost are daily, monthly, seasonal. How do we impute, or otherwise account for, them hourly? • Fixed costs as presented here for discussing the short-forward component of the overall design (2ndbullet on slide 7) are presumed amortized over the day-ahead option MWh associated with the incurred expense.

43. Stakeholder Question • Some units can have different fixed costs to provide different ancillary service capabilities. What is the ISO’s thinking on that? • The ISO is still considering this suggestion/comment. • 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). • This approach may make participation and clearing more complicated.

44. Offer Price Formulation - Generalization • The option offer price is based on a Market Participant’s expectations regarding real-time energy prices, and a general ‘formula’ can be thought of as: Offer = (LMPRT – K)+ + max[0, (fixed costs – real-time net revenue)] • In this context, “fixed costs” should be viewed as the total cost a unit incurs to be able to “cover the call” option position, less the marginal costs of production (that it avoids if it does not operate in real-time) • Marginal costs are reflected in the real-time energy offer price (generally), and the “real-time net revenue” term above

45. Stakeholder Concerns • Concerns that all the units that participate in this program will have lower real-time energy offers (i.e., they will offer lower than their marginal cost in real-time because they’ve arranged for actual fuel in advance) • Concerns about scenarios having to ‘buy out’ when LMP is above strike and unit isn’t economic to run in real-time, wasn’t dispatched/committed, etc. Response: • To clear up any misperceptions we will revisit Example 2 and examine (1) the incentive to continue to base real-time energy offers on marginal costs, and (2) how the potential ‘buy-out’ cost can be factored into a competitive option offer price.

46. Return to Example 2 In the next few slides we will develop a payoff diagram for Gen 3 showing: • The payoff at various real-time LMPs • The incentive to actually incur the fixed costs necessary to be able to “cover” the call option position • Why a unit would (generally): • Not want to change its real-time energy offer from its marginal cost to the strike price • Not want to self-schedule when the real-time LMP exceeds the strike price

47. Assumptions for Example 2(from ISO Discussion Paper on Energy Security Improvements – Version 1)

48. Real-Time Demand Scenarios Real-Time Price Distribution • Rather than develop a full price distribution for demonstration purposes, a simplifying assumption was made for Example 2 - there are only three discrete, equally probable, ‘expected’ real-time scenarios Consequently: • The expected LMPRT in Example 2 is $33.33/MWh, if Gen 3 has fuel • Hence, the strike price is set equal to $35/MWh (roughly the expected LMP, close enough for purposes of Example 2)

49. Market Outcomes for Example 2 Generator 3 With Fuel(from ISO Discussion Paper on Energy Security Improvements – Version 1)

50. Example 2 Real-Time Scenarios The following three discrete outcomes were examined previously for Gen 3 A payoff diagram will help visualize these outcomes (they will be points on the diagram)