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January 8, 2018| Markets committee

January 8, 2018| Markets committee. Chris Geissler. 413.535.4367 | Cgeissler@iso-ne.com. Details of ISO’s Interim Winter Energy Security Proposal. INTERIM COMPENSATION TREATMENT. Winter Energy Security: Interim Treatment. WMPP ID: 133. Proposed Effective Date: CCP 14.

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January 8, 2018| Markets committee

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  1. January 8, 2018| Markets committee Chris Geissler 413.535.4367 | Cgeissler@iso-ne.com Details of ISO’s Interim Winter Energy Security Proposal INTERIM COMPENSATION TREATMENT

  2. Winter Energy Security: Interim Treatment WMPP ID: 133 Proposed Effective Date: CCP 14 Industry and policy trends are changing the makeup of New England’s power system ISO is developing a market-based approach to address energy security as part of its response to FERC’s July 2nd Order, but that design will not be filed before retirement bids are due for FCA 14 (March 2019) ISO committed to addressing impacts of retaining resources for fuel security and, therefore, the ISO is proposing an interim compensation treatment to provide similar compensation to similarly situated resources and to reduce the likelihood of uneconomic retirement bids from resources that provide winter energy security This interim compensation treatment will be in place for CCPs 14 and 15 Today, the ISO will discuss proposal details, including the maximum duration, forward and spot settlement rates, and Tariff language

  3. Background: Design objectives Objectives introduced at November MC Objective A: Provide similar compensation for similar service Objective B: Reduce the likelihood that an (otherwise economic) resource seeks to retire because it is not fully compensated for its winter energy security attributes in the wholesale markets Objective C: Simple, transparent, and can be implemented in time for CCP 14 (2023-2024) Objective D: Satisfies standard market design principles

  4. Background: Five core design components Trigger conditions: Indicate when pipeline gas availability may be low, and system conditions tight Maximum duration: Caps the total inventoried energy that is compensated Forward settlement rate: Per MWh payment rate for inventoried energy sold forward for entire winter season Spot settlement rate: Per MWh payment rate for inventoried energy maintained during each trigger condition Two settlement structure: Standard settlement pays/charges participants for deviations between their forward and spot positions at the spot settlement rate

  5. Background: Updated stakeholder schedule • Earlier presentations indicated that the ISO would ask participants for a vote at the February MC • Stakeholders raised concerns that this did not provide sufficient time to assess the proposal, and develop alternatives/amendments • ISO is shifting its requested MC vote to March, allowing the proposal to be discussed at an additional MC meeting • Participants Committee vote would be later in March, after the MC, and the ISO will file the proposal with FERC shortly thereafter • Filing would still occur before the close of the retirement de-list bid window in late March

  6. Proposed program parameters

  7. Proposed core design elements • In its December presentation, the ISO outlined several proposed program parameters, and also highlighted outstanding design elements that it was continuing to assess, including: • Trigger condition criteria • Inventoried energy measurement time • Maximum duration • Forward and spot settlement rates • Program eligibility and estimated program costs • Next: Discuss ISO’s proposal for each of these design elements

  8. Trigger condition criteria • As discussed at the December MC, a day will be a trigger condition if it meets the following conditions • Condition 1: Occurs in December, January, or February • Condition 2: Average of the high and low temperatures measured on that day at Bradley Airport (Windsor Locks/Hartford, CT) is less than or equal to 17 degrees • This corresponds to a heating degree day (base-65) of 48 or more degrees • Do not propose to limit trigger conditions to weekdays, but if such a limitation was included, would expect fewer trigger conditions • Would not impact forward settlement rate, which is based on incremental cost of signing LNG contract • Increases the spot rate because resources expect fewer conditions

  9. Additional data on historic trigger conditions At the December MC, the ISO presented historic data indicating that previous winters would have produced approximately 10 trigger conditions, on average In response to stakeholder requests for more granular data on historic trigger conditions, the ISO posted daily average temperatures at Bradley Airport since 2001 Available at https://www.iso-ne.com/static-assets/documents/2018/12/a00_trigger_condition_temperatures_interim_compensation_treatment.xlsx

  10. Gas availability during trigger conditions from winter 2017/18 As noted at the December MC, participants asked the extent to which the proposed trigger conditions correspond with tight gas conditions Historic data indicate that during trigger conditions, pipeline gas prices, as measured at Algonquin, are 82 percent higher than their seasonal average over the past five winters In the winter of 2017/18, 14 out of the 15 trigger condition days had gas prices above the seasonal average, with the one exception occurring on December 15th Suggests that trigger conditions generally correspond with days where pipeline gas conditions are tight

  11. Inventoried energy measurement time At the December MC, the ISO indicated that the program will measure inventoried energy after the trigger condition concluded After further consideration and feedback from stakeholders, we propose that this measurement occur between 7am and 8am on the morning after the trigger condition concludes Measurement would occur before morning peak, when inventoried energy may provide more reliability value Relative to overnight measurement, may reduce administrative burden of reporting inventory for resources that measure this value manually

  12. Lag between trigger condition day and inventoried energy measurement As stakeholders have noted, there is a 7-8 hour lag between when the trigger condition concludes and the measurement of inventoried energy Participants will therefore have an incentive to include opportunity cost associated with converting inventoried energy into electric energy up to the time when inventoried energy is measured Do not propose to modify the 24 hour period in which temperature is measured to eliminate this lag (e.g., 8am to 8am), as this would move trigger condition criteria away from standard heating degree day metric

  13. Maximum duration must consider both winter energy security and program costs Recall: The maximum duration represents the cap on how much inventoried energy can be compensated from a given resource Longer maximum durations will tend to procure more inventoried energy, and therefore may provide more winter energy security However, they will also tend to produce higher program costs because they buy more inventoried energy, and the incremental reliability value of inventoried energy is likely to decrease as more is maintained At the December Markets Committee, the ISO indicated that it was evaluating a range of maximum durations between 24 hours and 120 hours

  14. ISO proposes a maximum duration of 72 hours • This maximum duration will strike a balance between improving winter energy security, and limiting program costs • A resource with maximum production of 100 MW can therefore sell up to 7,200 MWh of inventoried energy forward and spot • Or the maximum value it can maintain, if this is less than 7,200 MWh • This inventoried energy may be converted into electric energy in the 72 hours that follow the inventoried energy measurement, or during tight winter periods over the coming days/weeks

  15. Proposed forward rate At the December MC, the ISO presented an indicative forward rate of approximately $100/MWh This indicative rate was calculated by the Analysis Group, which developed a model to estimate a gas resource’s incremental costs associated with purchasing an LNG-based winter peak gas supply contract After further refinements to this model, the final proposed forward rate is slightly lower at $82.49/MWh Next: Analysis Group discusses the methodology and assumptions that produced this final rate

  16. Proposed spot rate • Recall: The spot rate is calculated using the forward rate and expected number of trigger conditions so that participants would expect the same total revenues from selling their inventoried energy forward or spot • See, for example, slide 27 from November MC presentation • Proposed forward rate: $82.49/MWh • Expected number of trigger conditions: 10 (based on historic data) • Proposed spot rate: $8.25/MWh ( = $82.49/MWh / 10 expected trigger conditions)

  17. Eligibility to provide inventoried energy • At the December MC, stakeholders asked several specific questions about whether certain classes of resources are eligible, including: • Imports • Resources that signed cost-of-service agreements • Hydro units with pond storage upstream • The inventoried energy counted from resources that can replenish within the maximum duration window • Next: Review eligibility criteria and discuss the proposed treatment of these resource types

  18. Review: Inventoried energy properties Conditions introduced at December MC To be eligible for compensation, propose that inventoried energy satisfy three conditions Condition 1: Inventoried energy can be converted to electric energy at the ISO’s direction Condition 2: Conversion of this inventoried energy to electric energy reduces the amount of electric energy the resource can produce in the future (before replenishment) Condition 3: Inventoried energy can be measured in MWh and reported daily Inventoried energy may be stored on-site (e.g. oil in a tank), or offsite (e.g. an LNG contract)

  19. Provided at December MC What types of resources are eligible for inventoried energy revenues?

  20. Resource eligibility questions from December meeting Are imports eligible for compensation under this program? • No, imports do not meet the first condition: conversion of inventory to electric energy at the ISO’s direction • ISO New England has no authority to commit resources outside of New England • External energy transactions are not tied to specific resources in a neighboring control area; scheduled energy transactions may have no relation to inventoried energy on the other side of the border

  21. Inventory reporting questions from December Can hydro generators with pond storage include upstream reservoirs? • No, only inventory that is available to be converted to electric energy at the time it is measured is eligible for compensation • Consistent with proposed treatment of resources that have arranged for the delivery of fuel that is not yet available Can storage units count inventory from multiple, in-day replenishments? • No, only measured inventory at the time of reporting is eligible for compensation • That is, inventory available that can be converted to electric energy at the time the inventory is reported • Counting ‘potential future’ inventories could create perverse bidding incentives that undermine the program’s design objectives

  22. Estimated direct program costs • At the December MC, the ISO presented indicative program costs for a 72 hour maximum duration of $180 million/year • With the final forward rate of $82.49/MWh, estimate annual program costs of $142 million • Estimates assumed program participation from the Mystic 8 and 9 units • Cost is equal to the product of the forward rate and the 1.72 million MWh of inventoried energy that is assumed to be sold • Assumes all existing resources participate to their maximum potential, and total inventoried energy from LNG is equal to 500,000 MWh (discussed more later)

  23. Examples: Program’s impact on inventory management and opportunity costs

  24. Additional discussion of opportunity costs in energy market offers At the December MC, stakeholders asked several questions about how resources could include the opportunity costs associated with converting inventoried energy into electric energy in their energy market offer price A resource’s opportunity cost depends on its characteristics and expected future market conditions Next: Walk through a series of examples showing this opportunity cost for a range of resource types and market conditions

  25. Overview of examples • Example 1: Opportunity cost for a resource that has ‘excess’ inventoried energy • No matter how frequently it runs, it will have more inventoried energy than its maximum duration at the end of the winter • Example 2: Opportunity cost for a resource with limited inventoried energy when today is a trigger condition • Expects no additional trigger conditions before replenishment • Example 3: Opportunity cost for a resource with limited inventoried energy when today and tomorrow are trigger conditions • Example 4: Participation of storage in energy market and inventoried energy settlement

  26. Example 1: Resource with excess inventoried energy • Resource 1 produces electric energy using inventoried energy • It has significant inventoried energy • If it runs for the remainder of the winter, it would still have more inventoried energy than its cap limit • As a result, converting a MWh of inventoried energy into electric energy now does not reduce its expected inventoried energy payments in the future • This is true whether it expects 0 or 20 trigger conditions for the remainder of the winter • Therefore, resource 1 has no opportunity cost associated with inventoried energy, and should not include such a cost in its energy market offer

  27. Resource 1 benefits from other participants including an opportunity cost • By not including an opportunity cost, resource 1 is more likely to be dispatched than resources with similar marginal costs that have more limited inventoried energy (and higher opportunity costs) • The inclusion of these opportunity costs by other resources will increase resource 1’s energy market revenues • Will generally lead the system to be economically dispatched in a manner that better maintains energy inventories • Resources with limited energy inventories will be displaced by those with large inventories, or do not use inventoried energy • Improves winter energy security

  28. Example 2: Resource with limited inventoried energy Resource 2 has marginal costs of $20/MWh and no opportunity costs besides those associated with forgone inventoried energy payments It produces electric energy using inventoried energy It has less inventoried energy than its cap quantity, meaning each MWh of inventoried energy that it converts to electric energy today reduces its inventoried energy going forward Spot settlement rate is $8.25/MWh

  29. Example 2: Market conditions and timing Today is T0 Resource 2 expects tomorrow (T1) to be a trigger condition Inventoried energy measurement occurs at 8am on the day following the trigger condition (T2) After T1, no expected trigger conditions before end of winter (or scheduled replenishment), for simplicity in this example

  30. Example 2: Opportunity costs and energy market offers • For each MWh of inventoried energy that is converted to electric energy on T1, resource 2 will earn $8.25 less in inventoried energy revenues when it is measured on the morning of T2 • Therefore has opportunity cost of $8.25/MWh that should be added to its energy market offer price for T1 • Should therefore increase its offer to $28.25/MWh • Sum of its marginal costs and opportunity costs associated with forgone inventoried energy payments

  31. Example 2: Observations • Opportunity cost also applies to periods outside the trigger condition on T1, including: • Before the trigger condition in T0 (and T-1, T-2, etc.) all the way back to the previous replenishment or start of the delivery period • After the trigger condition ends, but before the measurement of inventoried energy at 8am in T2 • Opportunity cost no longer applies after the inventory measurement at 8am on T2

  32. Example 3: Market conditions and timing • Similar resource and market conditions to example 2, with one key difference • Resource 3 expects a second trigger condition in T2 that occurs before replenishment • Inventoried energy for this second trigger condition is measured at 8am on T3

  33. Example 3: Opportunity costs and energy market offers • For each MWh of inventoried energy that is converted to electric energy between 8am on T2 and 8am on T3, resource 3 will receive $8.25 less in revenues when inventoried energy is measured on the morning of T3 • Therefore has opportunity cost of $8.25/MWh that should be added to its energy market offer price during this 24 hour window • Should increase its offer to $28.25 on the second “day” • That is, between 8am on T2 and 8am on T3 • Sum of its marginal costs and opportunity costs associated with forgone inventoried energy payments

  34. Example 3: Opportunity costs and energy market offers (con’t) • For each MWh of inventoried energy that is converted to electric energy before 8am on T2, resource 3 will have an opportunity cost of $16.50, equal to its reduction in inventoried energy revenues • Inventoried energy revenue associated with measurement at 8am on T2 is reduced by $8.25 • Inventoried energy revenue associated with measurement at 8am on T3 is reduced by $8.25

  35. Generalizing example 3 • If resource 3 has limited inventoried energy and expects several trigger conditions before replenishment (or the end of the delivery period), its corresponding energy market opportunity cost could be (proportionally) larger • E.g., if it expects five trigger conditions, should increase offer by $41.25/MWh ( = 5 × $8.25/MWh) • The opportunity cost adder for such resources should be equal to the product of the spot rate and the number of trigger conditions expected prior to replenishment • May incent resources to line up replenishments so that they can receive inventoried energy payments while also generating and earning higher energy prices

  36. What is the optimal amount of inventoried energy to hold? At the December MC, stakeholders asked if this program provides incentives for resources to hold sufficient inventoried energy to meet the region’s winter energy security needs For example, inventoried energy beyond the 72 hours compensated under this program may have reliability value heading into (say) a week-long cold spell, such as that experienced last December-January

  37. What is the optimal amount of inventoried energy to hold? (con’t) • Consider case where the region expects an extended cold spell with five consecutive trigger conditions with high energy prices • The resources that earn the greatest revenues • Produce energy during each trigger condition • Maintain at least 72 hours of inventoried energy after each trigger condition • To satisfy both of these conditions, a resource that uses inventoried energy will need to start the cold spell with at least 8 days of inventoried energy • Alternately, could replenish during the cold spell • Optimal starting quantity increases with expected length of cold spell

  38. What happens if there is an extended cold spell early in the winter? • Stakeholders asked about this scenario at the December MC • Leading up to and during cold spell, resources with limited inventoried energy may include significant opportunity cost in their energy market offer price • The inclusion of these opportunity costs will move the economic dispatch toward resources with the following traits : • Produce electric energy without using inventoried energy • Have significant inventoried energy • Can easily and promptly replenish • Helps maintain inventoried energy for tight conditions that may occur later in winter • Provides additional energy market revenue for resources that deliver energy during cold spell

  39. Example 4: Participation of storage in selling inventoried energy • At the December MC, stakeholders asked how the inventoried energy measurement time impacts incentives and revenues for storage resources • A storage resource may not have inventoried energy at the end of the trigger condition (midnight), but is likely to charge overnight and have inventoried energy by the next morning • Evaluate measurement time’s impact on revenues in two cases: • Case A: Measure inventoried energy at end of trigger condition (midnight) • Case B: Measure inventoried energy between 7am and 8am on morning after trigger condition (as proposed) • Sum of energy market and inventoried energy revenues are similar in each case

  40. Example 4: Scenario evaluated Day T1 is a trigger condition Storage resource’s inventoried energy measured either at end of T1 (case A), or at 8am on T2 (case B) For simplicity, assume no additional trigger conditions are expected for remainder of winter period Compare storage resource’s total energy market and inventoried energy revenues during T2 in each case when it charges overnight

  41. Example 4: Storage resource assumptions Storage resource can hold 100 MWh of energy No storage losses (more on that later) Consumes energy between 2am and 6am (off-peak hours) Generates energy between 4pm and 8 pm (peak hours) Resource is inframarginalwhen charging and generating

  42. Example 4: Market assumptions Spot settlement rate is $8.25/MWh Opportunity cost of $8.25/MWh is added to the marginal resource’s energy market offer until inventory is measured for the Trigger Condition on T1

  43. Example 4: Market assumptions (con’t) • Energy market price during off-peak hours of T2, when resource is charging, is: • $20/MWh under case A, where the marginal resource does not include an opportunity cost, because measurement of inventoried energy has already occurred • $28.25/MWh under case B, where the marginal resource includes an opportunity cost, because measurement of inventoried energy has not yet occurred • Assume now the energy price during on peak hours of T2, when resource is generating, is $50/MWh • Does not vary between cases because measurement has already occurred in both cases

  44. Example 4: Comparing revenues between cases • Compare revenues on day T2 between cases A and B • Revenue consists of three components • Energy production payments associated from generating electricity during peak hours • Charging costs associated with consuming electric energy during off-peak hours • Inventoried energy revenues based on the energy in storage at the time of the inventoried energy measurement • Total revenues for storage resource in T2 are equal to the sum of these three components

  45. Example 4 Case A: Day T2 storage resource revenue

  46. Example 4 Case B: Day T2 storage resource revenue The total revenues are equivalent in cases A and B

  47. Example 4 takeaways • Measuring inventoried energy the morning after the trigger condition concludes may increase storage resource’s inventoried energy revenues • It is also likely to reduce their energy revenues if the price when they charge reflects an opportunity cost associated with the marginal resource converting inventoried energy to electric energy • Generally provides similar incentives for storage resources to charge as a design that measures inventoried energy immediately following the trigger condition

  48. Generalizing example 4 • This revenue equivalence holds across a range of energy prices, expected number of trigger conditions, etc. • However, if either of two assumptions are relaxed, the revenue equivalence in this example will not hold • Assumption 1: Storage resource is 100 percent efficient • Assumption 2: Full opportunity cost associated with converting inventoried energy into electric energy is incorporated into the energy market price before inventory measurement

  49. Generalizing example 4: Relaxing assumption 1 • If the storage resource is less than 100 percent efficient (e.g. where consuming 100 MWh of energy leads to 75 MWh of inventoried energy), the storage resource earns higher revenues if inventoried energy is measured at midnight • If example 4 assumes 25 percent losses, net revenues are $1,750 if measured at midnight (case A), versus $1,544 if measured the next day (case B) • Assumption 1 is unlikely to hold in practice

  50. Generalizing example 4: Relaxing assumption 2 If the full opportunity cost is not incorporated into the energy market price before inventory measurement, the storage resource will earn higher revenues when inventoried energy is measured at 8am (case B) If no opportunity cost is added to energy market price during off-peak hours of T2, example 4 produces net revenues of $3,000 under case A, and $3,825 under case B Higher revenues under case B appropriately reflect that inventoried energy added to storage unit is assumed not to reduce inventoried energy elsewhere on the system Net effect of relaxing both assumptions is not clear, as they work in opposite directions

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