ENERGY SECURITY IMPROVEMENTS: MARKET- BASED … · Slide 6: April ESI presentation. ISO-NE PUBLIC 4 Today’s Presentation Agenda • Problem review –Problem 1 –A brief review

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M A Y 7 , 2 0 1 9 | M A R K E T S C O M M I T T E E

Andrew Gillespie4 1 3 . 5 4 0 . 4 0 8 8 | A G I L L E S P I E @ I S O - N E . C O M

Discussion of a market-based solution to improve energy security in the region

ENERGY SECURITY IMPROVEMENTS: MARKET-BASED APPROACHES

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Winter Energy Security Improvements WMPP ID:125

Proposed Effective Date: Mid 2024

• In accordance with FERC’s July 2, 218 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

https://www.iso-ne.com/static-assets/documents/2019/04/a00_iso_discussion_paper_energy_security_improvements.pdf

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Three Conceptual Components

• 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

Slide 6: April ESI presentation

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Today’s Presentation Agenda

• Problem review– Problem 1 – A brief review– Problem 2 – A more detailed look

• Day-Ahead energy call option– Seller’s perspective

• Including some detours to show important concepts (offer price formation, incentives created)

– Buyer’s (ISO) perspective

• Generation Contingency Reserves– Services– Requirements– Clearing and pricing– Examples

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PROBLEM REVIEW• A brief review of Problem No. 1

• A more detailed look at Problem No. 2

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Three Interrelated Energy-Security Related Problems

1. Incentives and Compensation. Market participants whose resources face production uncertainty may have inefficiently low incentives to invest in additional energy supply arrangements, even though such arrangements would be cost-effective from society’s standpoint as a means to reduce reliability risks

2. Operational Uncertainty. There may be insufficient energy available to the power system to withstand an unexpected, extended (multi-hour to multi-day) large generation or supply loss, particularly during cold weather conditions

3. Inefficient Schedules. The power system may experience premature (inefficient) depletion of energy inventories for electric generation, absent a mechanism to coordinate and reward efficient preservation of limited-energy supplies over multiple days



PROBLEM 1. INCENTIVES AND COMPENSATION A brief review

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Problem 1. Incentives and Compensation: Takeaways

• Resources that face production uncertainty may have inefficiently low incentives to invest in additional energy supply arrangements, even though such arrangements would be cost-effective from society’s standpoint and would tend to reduce reliability risk

• Misaligned incentives: The value difference between what society avoids and what generators are paid (with the investment in energy arrangements) results in a divergence between the social and private benefit of the investment

• Energy supply arrangements matter: If the generator does not make energy supply arrangements in advance, then with some probability the real-time price for energy will be higher, or reliability will be worse, than if the generator did make advance supply arrangements

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Resources Facing Production Uncertainty

• Off-line fast-start dispatchable generators (generally, hydro-electric and distillate-fueled combustion turbines and internal-combustion units), which infrequently receive day-ahead energy market schedules

• Higher-cost ‘blocks’ of combined-cycle generators that receive day-ahead schedules below their maximum output (or possibly for a lower-output configuration)

• Higher heat-rate combined-cycle generators that infrequently clear in the day-ahead market

• Long lead-time oil-steam units that infrequently clear in the day-ahead market

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Capability Without a Day-Ahead Schedule

• Day-Ahead headroom is the difference between the sum of day-ahead schedule amounts and the sum of real-time Economic Maximum values for the winter On-Peak hours

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A Case of Misaligned Incentives

• Making supplemental fuel/stored energy arrangements in advance requires an up-front investment (a cost is incurred)– The value that society places on making the supplemental

arrangements is based on the high price it avoids with the investment– The value the generator places on the same arrangement is based on

the lower price it receives in the energy market (with the investment)

• Misaligned incentives: This value difference results in a divergence between the social and private benefit of the investment in supplemental fuel/stored energy arrangements


PROBLEM 2. OPERATIONAL UNCERTAINTYA more detailed look

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Problem 2. Operational Uncertainty

• Imagine a situation when, after the day-ahead market clears, we unexpectedly lose a large (non-gas) generator for an extended duration

– The energy needed to replace the lost generator must come from a generator that did not clear in the day-ahead market

The Problem

• As a consequence of Problem 1, it is not certain that a replacement generator will have adequate fuel/energy supply arrangements (especially if the replacement generator does not routinely clear in the day-ahead market)

• Conceptually, this implies the need for an ‘energy margin’ to address uncertainty

Slide 11: March ESI presentation

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Problem 2. How to Cover the Energy Gap?

• Problem 1 precipitates Problem 2: There may be insufficient energy available to the power system to withstand an unexpected, extended (multi-hour to multi-day) large generation or supply loss, particularly during cold weather conditions

• This leads us to focus to the resources and capabilities that Problem 1 may adversely impact the most in practice: Those we rely upon to cover an ‘energy gap’ when the system’s conditions during the operating day significantly differ from the ISO’s day-before operating plan and the outcomes of the day-ahead market

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Covering the Energy Gap

In practice, the ISO relies upon much of the generation fleet’s capabilities, above and beyond their day-ahead energy schedules, to fill such energy gaps

Three operational categories:

A. Operating Reserves for Fast-Start/Fast-Ramping Generation Contingency Response

B. Replacement Energy

C. Load-Balance Reserves

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A. Operating Reserves

• Energy from resources that infrequently receive day-ahead energy market schedules, but on which the ISO relies for real-time operating reserves, including both off-line generation and ‘upper blocks’ of on-line (spinning) generation

• However, the ISO does not plan for these resources to sustain their energy production indefinitely after a contingency – the ISO can rely on many of these resources for only a limited amount of time (e.g., a few hours or less)

• After that point, the replacement energy to cover the energy gap must come from other resources that likewise did not receive a day-ahead energy market schedule (or a day-ahead schedule below the resource’s maximum output)

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B. Replacement Energy

• Energy needed if a day-ahead cleared resource is unable to perform for an extended (multi-hour or multi-day) duration

• As noted in the prior slide, at some point the energy to cover the energy gap must come from other resources (i.e., not the operating reserve energy resources) that also did not receive a day-ahead energy market schedule

• When this occurs, the ISO must dispatch online resources above their day-ahead schedules, or supplementally commit offline resources without day-ahead schedules, to supply sufficient energy to cover the energy gap through the balance of the day (and possibly the following day)

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C. Load-Balance Reserves

• Energy to supply the load-balance ‘gap’ when the total day-ahead cleared generation is less than the ISO’s load forecast, in one or more hours, during the next (operating) day

• This is in addition to, and distinct from, ensuring that the system is prepared to handle uncertainty (e.g., supply loss contingencies) addressed with operating reserve energy and replacement energy resources

• Today, the energy to cover the load-balance gap is supplied through the dispatch and post-market commitment of other resources operating above, or that did not receive, a day-ahead market schedule

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Problem 2. Operational UncertaintyImplications

• Quantity. Depending on the day, there may be up to approximately 4-6 GW of resources in categories A, B, and C, for which Problem 1 is a concern

• Not a fixed set of resources. The most cost-effective set of resources to meet these needs can and does vary daily

• The ‘Margin’ for Uncertainty. In prior stakeholder discussions, the ISO has stressed at a high-level the need for a ‘margin’ to address operational uncertainties in an increasingly energy-limited system


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Quantities

The total power and energy the ISO relies upon to satisfy these three operational purposes varies from day to day

• Operating reserves. Total hourly operating reserves for contingency response are typically in the range of 2-to-2.5 GW, and are based on the projected size of the largest and next-largest source-loss contingencies each day

• Replacement energy. This is more complex, as it depends on the scheduled energy profile of the system’s largest contingency over the course of the day

• Load-balance energy. Varies from day to day, but this energy gap can amount to many hundreds of MWh (per hour) and occasionally over a GWh in some hours

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Not a Fixed Set of Resources

• The most cost-effective set of resources (e.g., see slide 9) to meet the operational needs in categories A, B, and C can and does vary daily

• It depends on the day-ahead cleared generation pattern, the cleared and forecast demand profile over the course of the day, available resources’ lead-times and capabilities, weather and intermittent-resource energy production (actual and forecast), constraints on natural-gas pipelines supplying electric generation, etc.

• Bottom-line: There isn’t a specific resource ‘type’ or technology at issue


PROBLEM 2. OPERATIONAL UNCERTAINTYRoot causes and takeaways

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Problem 2. Operational UncertaintyRoot Causes and Takeaways

• The resources that the system relies upon for the three operational purposes discussed above are also those expected to be most adversely affected by Problem 1

• This, in turn, precipitates Problem 2: there may be insufficient energy available to withstand an unexpected, extended (multi-hour to multi-day) large generation or supply loss– In the past there was an implicit assumption that there would be sufficient

additional energy to cover any ‘energy gap’

• These resource capabilities are not compensated in the day-ahead market today

• While it may be a cost-effective means to reduce reliability risks if these resources invested in additional energy supply arrangements, the current market construct provides inefficiently low incentives to do so

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Why Are These Issues ‘Problems’ Now?

• New England’s power system is evolving into an ever-more energy-limited system– Pipeline constraints, retiring generators with ample fuel storage, and

growing ‘just-in-time’ generation from renewable technologies

• The decision to make (or not make) advance fuel/energy supply arrangements matters more in an increasingly energy-limited power system– In the past, if a unit wasn’t able to operate (for fuel or any other reason),

there was sufficient energy to dispatch up another resource in its place– The presumption that there will be sufficient energy may not be valid in an

increasingly energy-limited system– If too many generators cannot operate the system may face:

• Operating a much more expensive generator further up the supply stack, or• Scarcity prices, if there is a real-time deficiency in the system’s energy plus

reserves requirement



A DAY-AHEAD ENERGY CALL OPTION

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Design Objectives for a Market-Based Solution

1. Risk Reduction. Minimize the heightened risk of unserved electricity demand during New England’s cold winter conditions by solving Problems 1, 2, and 3

2. Cost Effectiveness. Efficiently use the region’s existing assets and infrastructure to achieve this risk reduction in the most cost-effective way possible

3. Innovation. Provide clear incentives for all capable resources, including new resources and technologies that can reduce this risk effectively over the long term


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Design Principles for a Market-Based Solution

1. 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

2. 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

3. 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

4. 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

5. Compensate all resources that provide the desired service similarly.


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Practical Elements, in Simple Terms

1. Compensate the supplier such that it will be willing to incur the fixed costs of arranging energy supplies in advance when that would be cost-effective from the system’s standpoint

2. Tie compensation to financial consequence, so that the suppler will be induced to incur the fixed costs of arranging energy supplies

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Categories of New Day-Ahead Ancillary Services

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 (slide 15)

• 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

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A Map of What’s Ahead

• Product

• Offers and offer parameters

• Clearing process

• Pricing and pricing processes

• Settlement

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Parameters of Day-Ahead Energy Call Option

Seller’s Perspective Buyer’s (ISO) Perspective

Product

There is only the one ‘product’ – the energy call option

Offer Parameters

• Offer price ($/MWh)• Maximum (total) offer amount (MWh)

• Resource maximum eligible amount for various services given resource’s capabilities

Clearing and Pricing Process (to meet GCR, EIR, and RER requirements)

• Different day-ahead clearing prices for options procured to meet each different ancillary service requirement

• Determine least cost solution to satisfy various ancillary service requirements

• Uniformly price options procured to meet each requirement, accounting for marginal costs, shadow prices, opportunity costs, etc.

Settlement

The close-out settlement of the energy call option is the same; it does not depend on why the option was procured, or the price paid for the option


DAY-AHEAD ENERGY CALL OPTION –SELLER’S PERSPECTIVEThis section will go over the parameters important from the seller’s perspective

Seller’s Perspective

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Product (Energy Call Option)

• An hourly energy call option construct, awarded in the day-ahead energy market, to resources that offered the energy call option – Hourly awards (in MWh)– Hourly clearing prices ($/MWh)

• In exchange for this day-ahead (hourly) payment, the resource will be subject to a corresponding option settlement treatment (close out) for the corresponding hour(s)


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Offer Parameters

Current thinking:

Day-ahead Energy Call Option Offer:

• One (hourly) offer price ($/MWh)– A resource may have a different offer price for each hour of each day

• A maximum amount offered (MWh)– This would limit the total option amount cleared/procured from the

resource– This may be zero, the resource’s maximum eligible capability, or

something in between



OFFER PRICE FORMULATION –A SLIGHT DIGRESSIONWe can gain some insight into how to form an option offer price by examining Generator 3’s net revenues in Example 2 of the discussion paper, specifically the case with advance energy supply arrangements

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Offer Price Formulation

• First, we will examine what would have been Generator 3’s minimum option offer price in Example 2 from the ISO’s discussion paper, given the real-time scenarios

• This will provide a framework for thinking about offer price formation; by ‘reverse engineering’ the minimum offer price we can see the relevant offer price components

• From there we can write a general ‘formula’ for developing offer prices for these energy call options, which will be useful when examining settlement examples wherein the resource sells the option but does not take steps to be capable of “covering the call”

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

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

Generator Energy Option Energy Reserve Energy Reserve Energy Reserve

[1] Gen 1 100 0 100 0 100 0 100 0

[2] Gen 2 90 10 70 20 90 10 100 0

[3] Gen 3 0 20 0 30 0 30 10 30

[4] Gen 4 0 0 0 40 0 40 0 40

[5] Totals 190 30 170 90 190 80 210 70

[6] Clearing Price $39 $11 $30 $0 $30 $0 $40 $0

[7]

[8]

[9]

[10]

[11]

$5,233

$7,203 $7,803 $8,453

$7,819

Demand Probability

Expected Total System Production Cost

Scenario Market Payments (incl. DAM)

Expected Total Market Payments

33% 33% 33%

$5,200 $5,900

Day Ahead Real-Time Market Outcomes

Market Awards Low Demand Medium Demand High Demand

Table 3-2. Market Outcomes for Example 2 with Day Ahead E&AS Market, Case A: Generator 3 With Fuel

Scenario Total Production Cost $4,600

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Expected Net Revenue for Example 2 (Table 3-4)(from ISO Discussion Paper on Energy Security Improvements – Version 1)

Generator's Market Settlements Calculation Low Dmd Med Dmd High Dmd Low Dmd Med Dmd High Dmd

[1] Day Ahead Energy DA LMP * Qe_DA -$ -$ -$ -$ -$ -$

[2] Real-Time Energy Close-Out -RT LMP * Qe_DA -$ -$ -$ -$ -$ -$

[3] Day Ahead Option DA OCP * Qo_DA 220$ 220$ 220$ 220$ 220$ 220$

[4] Day Ahead Option Close-Out -max(RT LMP-K, 0)* Qo_DA -$ -$ ($100) -$ -$ ($1,100)

[5] Real-Time Energy RT LMP * Qe_RT -$ -$ 400$ -$ -$ -$

[6] Real-Time Reserves RT RCP * Qr_RT -$ -$ -$ -$ -$ -$

[7] Total Settlement [1]+[2]+[3]+[4]+[5]+[6] 220$ 220$ 520$ 220$ 220$ (880)$

Generator's Costs

[8] Advance Fuel F (150)$ (150)$ (150)$ -$ -$ -$

[9] Variable Cost MC -$ -$ (400)$ -$ -$ NA

[10] Total Cost [8]+[9] (150)$ (150)$ (550)$ -$ -$ -$

Generator's Expected Profit

[11] Scenario Net Revenue [7]+[10] 70$ 70$ (30)$ 220$ 220$ (880)$

[12] Demand Probability p or (1-p ) 0.333 0.333 0.333 0.333 0.333 0.333

[13] Expected Net Revenue SumProd [11]x[12]

Table 3-4. Generator 3's Expected Net Revenue for Example 2 with Day-Ahead E&AS Market

Advance Fuel

($147)

No Advance Fuel

$37

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Offer Components

Two components to consider:

• Option settlement (close out); for this example let this be shown as:= max(0, LMPRT – K) = (LMPRT – K)+

• Unrecovered costs incurred to cover the option; for this example let this be shown as:

= fixed costs – real-time net revenue= [(F/Qo) – (LMPRT – MC)]

– Fixed costs (F, in $) incurred regardless of whether or not the resource actually operates; to show as a rate ($/MWh) divide by the awarded option amount (Qo, in MWh)

– Real-time net revenue (presuming the fixed costs are incurred); in this example Generator 3 receives no real-time reserve revenue in any scenario, consequently we can show this term as LMPRT – MC

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Offer Prices for Each Given Outcome

• For each of the given three real-time demand scenarios in Example 2, calculate the minimum offer price for Generator 3

Offer ($/MWh) = (LMPRT – K)+ + [(F/Qo) – (LMPRT – MC)]

Real-Time DemandScenario

(LMPRT – K)+ (F/Qoption) (LMPRT – MC)Minimum Offer Price

($/MWh) ($/MWh) ($/MWh) ($/MWh)

Low $0 ($30 - $35 < $0) $7.50 = $150/20MWh $0 (off-line) $7.50

Medium $0 $7.50 $0 (off-line) $7.50

High $5 = $40* - $35 $7.50 $0 (marginal) $12.50

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Generator 3’s Minimum Offer Price Based on Real-Time Expectations

• Given the minimum offer price in each, equally probable, real-time demand scenario, the minimum offer price for Generator 3 is $9.17/MWh

$9.17/MWh = (0.33 x $7.50/MWh) + (0.33 x $7.50/MWh) + (0.33 x $12.50/MWh)

• This is the minimum offer price that will yield an expected net revenue of zero

• Given the expectations about real-time scenarios, this is the lowestprice Generator 3 would reasonably accept

• If it offered $9.17/MWh, its revenue in line [3] in table 3-4 (slide 39) would drop by $37 to $183, and its expected profit (line [13]) would be (approx.) zero – that’s why this is the minimum offer

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Offer Price Formulation - Takeaway

• The option offer price is based on expectations in real-time; the general ‘formula’ can be thought of as:

Offer price = expected option close out settlement + max[0, fixed costs – expected real-time net revenue]

re-writing this:

Offer ($/MWh) = E(LMPRT – K)+ + max [(F/E(Qo)) – E(RT net rev.)]

Where:

• E - ‘expected value of’

• Qo – awarded option amount (MWh)

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Pricing

• Hourly clearing prices ($/MWh)– Prices may be different every hour; how prices are determined is

covered in the next section (Buyer’s Perspective)

• For a given hour, there will be a uniform clearing price for options procured to meet the same ancillary service requirement that hour (e.g., a uniform clearing price for each type of GCR)

• For that same given hour, there may be different clearing prices for other options procured to meet different ancillary service requirements in that same hour (e.g., a different uniform clearing price for EIR and for RER)


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Settlement

• In exchange for this day-ahead (hourly) payment, the resource will be subject to a corresponding option settlement for the corresponding hour(s) (see Appendix)– Before the last day-ahead clear, settlement would be day-ahead

clearing to day-ahead clearing for each hour with the daily re-clearing of M-DAM (settlement analogous to DA/RT energy deviations)

• Hourly day-ahead energy call option awards (open after the last day-ahead clear) will be settled (closed out) against real-time prices

• Settlement close out is a charge, equal to the option amount times the positive difference between the real-time LMP and the strike price

= (max {0, RT LMP – K} x QDA option)



OPTION SETTLEMENT –A SLIGHT DIGRESSIONWe can gain some insight into how these options are expected to incentivize resources to take action to cover sold energy call options by again examining Generator 3’s net revenues, specifically the case without advance fuel

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Generator 3’s Expected Net Revenue in Example 2 Without Advance Fuel

• Compare the expected net revenues for Generator 3 in Table 3-4 (slide 39), specifically, where Generator 3 sells the option but does not incur the fixed costs to cover the option, and consequently cannot operate

• In the high real-time demand scenario the real-time LMP is instead $90 and consequently, the option close out is a charge of $1,100 [($90 - $35) x 20MWh] and Generator 3’s net revenue is minus $880

Continued on next slide

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Generator 3’s Expected Net Revenue in Example 2 Without Advance Fuel - continued

• Even though the net revenue in both the low and medium demand scenarios is a positive $220, given that each scenario is equally probable, the expected net revenue for selling the energy call option and not incurring the fixed costs is a minus $147, compared to the positive $37 when the fixed costs are incurred

• Hence, the incentive to actually incur the fixed costs is to avoid the expected loss of $147 and realize the expected gain of $37 (a difference of $184)

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Offer Prices for Other Cases

• For cases where the offer is based only on the expected option settlement close out term

Offer ($/MWh) = (LMPRT – K)+

Real-Time DemandScenario

(LMPRT – K)+ (F/Qoption) (LMPRT – MC)Minimum Offer Price

($/MWh) ($/MWh) ($/MWh) ($/MWh)

Low $0 $0

Medium $0 $0

High $55 = $90* - $35 $55

*RT LMP is set by Generator 4; Table 3-3 of ISO Discussion Paper on Energy Security Improvements – Version 1

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Offer Prices for Other Cases - Takeaways

• Given the minimum offer price in each, equally probable, real-time demand scenario, the minimum offer price is $18.33/MWh

$18.33/MWh = (0.33 x $0/MWh) + (0.33 x $0/MWh) + (0.33 x $55/MWh)

• This is the minimum offer price that will yield an expected net revenue of zero– Notice! This is greater than Generator 3’s minimum offer, $9.17/MWh

• However, in order to clear an offer from a resource in one of these other cases (and displace Generator 3), the offer must be priced lower than $9.17/MWh– Which effectively means selling the option at an expected loss!


DAY-AHEAD ENERGY CALL OPTION –BUYER’S (ISO) PERSPECTIVEThis section will go over the parameters important from the buyer’s (ISO’s) perspective

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Buyer’s Perspective

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Offer Parameters:Maximum Eligible Capability

• The co-optimized day-ahead clearing will determine a resource’s maximum eligible capability based on it’s time-related parameters (e.g., generator ramp or startup times)

• Knowing the resource’s maximum eligible capability to supply each of the ancillary services is relevant to determining whether, and/or to what degree, an option from the resource can be used to satisfy the various ancillary service requirements

• A resource will not be awarded an option amount that is greater than its maximum eligible capability, or maximum offered amount (if lower)


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Clearing and Awards: Concepts

Current thinking:

• The energy call option ‘product’ is simply that, an energy call option

• From the supplier’s perspective:– It would not be specific to an ancillary service category or product– There would be no GCR energy call option distinguishable from an EIR

energy call option– Regardless of why the option is cleared the same energy call option

settlement terms would apply– Dispatch/commitment during the operating day is based on standing

energy offers at the time

• From the buyer’s perspective:– Whether an energy call option is cleared will depend, in part, on the

resource’s ancillary service capability and the particular requirement(s) those capabilities can satisfy



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Clearing and Awards: Concepts- continued

• To meet each requirement (GCR, EIR, and RER amounts, in MWh), day-ahead energy call options will be procured from resources capable of providing the particular service that would count towards meeting the specific requirement– For example, procuring an energy call option from a resource that can

provide operating reserves may be counted towards meeting the GCR requirements

• Current thinking: Resource capabilities are not offer parameters– The capability of the resource will determine how much of an offered

energy call option, if cleared, could be counted towards meeting each particular requirement



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Clearing and Awards: Concepts- continued

• The day-ahead procurement of energy call options to meet the different requirements (GCR types, EIR, and RER) may result in different clearing prices paid to call options procured to satisfy each– For example, an energy call option procured to meet a GCR

requirement may have a different clearing price than a call option procured to meet the EIR requirement

• Regardless of why the option is cleared, or the price paid for the option, the same energy call option settlement terms would apply


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Clearing:Ancillary Service Requirements

• Current thinking: Quantities procured for each day-ahead ancillary service product (GCR, EIR, and RER) 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 day-to-day based on:– The demand forecast– The generation cleared for energy in the day-ahead market– The system’s largest anticipated potential single-source energy loss

• More on this as we discuss each specific A/S category; today we will discuss GCR


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Clearing Process

• Procurement of these ancillary services would be co-optimized (i.e., simultaneously cleared) with all participants’ energy supply and demand awards in the multi-day ahead market

• This ensures that the clearing prices for energy and each ancillary service incorporate the (respective marginal) suppliers’ opportunity costs of not receiving an award for a different day-ahead product

• It also means that, whenever these inter-product opportunity costs are non-zero (as determined in the clearing process), the day-ahead LMPs for energy will incorporate the clearing prices for the ancillary services



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Pricing Process

• The market clearing optimization would compensate both energy and ancillary service awards at uniform, transparent, product-specific market prices

• The clearing prices of these day-ahead ancillary services would vary over time (i.e., as we envision it presently, each hour day-ahead), as supply and demand dictate

• Importantly, the clearing prices of each day-ahead product would account for the inter-product opportunity cost– Clearing prices would reflect both the marginal offer price and the

suppliers’ opportunity costs of not providing energy or any other ancillary service product for the same delivery hour




GENERATION CONTINGENCY RESERVES (GCR)A mid-level summary of current thinking

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GCR Ancillary Services

Three different GCR ancillary service capabilities are procured via the day-ahead clearing of energy call options (in MWh)

• GCR Ten-Minute Spinning Reserve (GCR TMSR)– The capability of a resource to either produce (additional) energy or

(further) reduce energy consumption within ten minutes, relative to the resource’s (hourly) day-ahead energy schedule (provided the resource is committed day-ahead)

• GCR Ten-Minute Non-Spinning Reserve (GCR TMNSR)– The capability of a resource to either produce energy or reduce energy

consumption within ten minutes (provided the resource is not committed day-ahead)

• GCR Thirty-Minute Operating Reserve (GCR TMOR)– The capability of a resource to either produce energy or reduce energy

consumption within thirty minutes, relative to the resource’s (hourly) day-ahead energy schedule

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GCR Requirements

The different GCR ancillary services will be procured day-ahead to satisfy the following GCR requirements (in MWh)

• GCR Ten-Minute Spinning Reserve Requirement – Satisfied by GCR Ten-Minute Spinning Reserve (GCR TMSR) capability

only

• GCR Ten-Minute Reserve Requirement– Satisfied by GCR Ten-Minute Spinning Reserve (GCR TMSR) or

GCR Ten-Minute Non-Spinning Reserve (GCR TMNSR) capability

• GCR Minimum Total Reserve Requirement– Satisfied by GCR Ten-Minute Spinning Reserve (GCR TMSR), or

GCR Ten-Minute Non-Spinning Reserve (GCR TMNSR), or GCR Thirty-Minute Operating Reserve (GCR TMOR) capability

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GCR Eligible Quantities

• The ISO will determine each resource’s eligible GCR capabilities (e.g., GCR TMSR capability) consistent with current real-time operating reserve eligibility and designation rules and practices

• For example:– Claim10 and Claim30 values for off-line units– Ramp rates (over 10 and 30 minutes) for on-line units

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GCR Clearing

• The day-ahead clearing process will co-optimize (i.e., simultaneously clear) energy and energy call options– Energy call options will clear based, in part, on the resource’s ability to

provide the GCR ancillary service(s) necessary to meet the GCR requirement(s)

• The day-ahead clearing process will produce hourly uniform (system) clearing prices for each GCR ancillary service– GCR TMSR– GCR TMNSR– GCR TMOR

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GCR Pricing (and Awards)

• GCR clearing prices for each service will be based on the shadow price of the relevant constraint(s) – Prices reflect marginal cost of each requirement (including

opportunity costs)– Prices will be capped by a corresponding Reserve Constraint Penalty

Factor (likely to be the same as those used in real-time)

• Hourly energy call options for GCR ancillary services (GCR TMSR, etc.) may be awarded to a resource for all 24 hours of the day

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GCR Compensation

• Cleared energy call options will be compensated based on the GCR ancillary service capability of the resource (i.e., how the option, or portion of the option, counts towards satisfying each GCR requirement)

• Energy call options awarded to resources based on the resource’s capability are paid:– For GCR ten-minute spinning capability; the GCR TMSR clearing price– For GCR ten-minute non-spinning capability; the GCR TMNSR clearing

price– For GCR thirty-minute capability; the GCR TMOR clearing price


DAY-AHEAD CLEARING & PRICING EXAMPLESThe following examples are intended to show at a high-level the basis for day-ahead option clearing prices for GCR services, and the impact on day-ahead energy clearing prices

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Day-Ahead Clearing & Pricing Examples

• The first example shows how option opportunity costs (options procured for GCR services) are incorporated in the energy clearing price– For this and the second example we can interpret ‘GCR services’

generically; the intent here is to observe the inter-product opportunity cost impacts

– For brevity, in these examples we will use the term ‘Reserve Clearing Price’ (RCP) to denote the option clearing price(s)

• The second example shows how energy opportunity costs are incorporated in the option (a.k.a., reserve) clearing price

• The third example shows how reserve prices can ‘cascade’

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First ExampleOffer Assumptions and Clearing Results

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First Example - Supply Curves

Price

Qty450 500 550 600

$10

$35

$42

D

E

F

650 700 750 800 850 900

LMP = $44.95

DEnergy = 720MWh DReserve = 190MWh

Unit F Reserve OC impacts LMP$42.00 + $2.95 = $44.95

$44

$45

$43

G

I

50 100 150 200

RCP = $5.54

F

H

$2.5

$5.0

$5.5

$6.0

Unit F Reserve Opportunity Cost

$5.54 - $2.59 = $2.95

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First Example - Observations

• The Reserve Clearing Price (RCP) is set by Unit H’s offer price of $5.54/MWh

• What is the incremental cost of energy?– The next increment of energy would be supplied by Unit F– However, Unit F is also providing reserves with the full balance of its potential output – Thus, to provide one more MWh of energy from Unit F the amount of reserves from

Unit F would be reduced by one MWh– Consequently, one additional MWh of reserves is required and would come from Unit H

But notice:– Unit F is more profitable providing reserves instead of energy– Unit F’s profit for providing reserves is the difference between the Reserve Clearing

Price and Unit F’s ancillary service cost (i.e., reserve offer price, $2.59); this difference ($2.95) is Unit F’s reserve opportunity cost

– In order to make Unit F indifferent as to whether it supplies energy or reserves, this reserve opportunity cost is incorporated into the LMP; this outcome is similar to that occurring in real-time when real-time operating reserve prices are positive

• The incremental cost of energy is therefore $44.95/MWh– In this example since the marginal energy offer ($42) is also from Unit F, the LMP is the

sum of its energy offer and its reserve opportunity cost ($42 + $2.95)– Note: It may not always be the case that a unit with reserve opportunity costs is also the

marginal energy unit

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Second ExampleNew Offer Assumptions and Clearing Results

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Second Example - Supply Curves

Price

Qty450 500 550 600

$10

$35

$42

D

E

F

G

I

50 100

650 700

150 200

750 800 850 900

LMP = $42.00

RCP = $8.59

DEnergy = 720MWh DReserve = 190MWh

E

H

Unit E Energy Opportunity Cost

$42.00 - $36.00 = $6.00

Unit E Energy OC impacts RCP

$2.59 + $6.00 = $8.59

$44

$45

$43

$2.5

$5.0

$5.5

$6.0

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Second Example - Observations

• Unit F is marginal for energy, and sets the LMP at its energy offer price of $42/MWh

• Unit E (not Unit H or Unit I) is marginal for reserves!– If the reserve requirement ↑ by one MWh, least-cost solution is to

shift 1MWh of energy from Unit E to Unit F; at a cost of $6.00/MWh– Then Unit E can be awarded another unit of reserves, with an offer

price of $2.59/MWh– The total cost of redispatch for reserves: $6.00 + $2.59 = $8.59/MWh– This is lower cost than awarding 1MWh to Unit I, offered at

$9.07/MWh

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Third ExampleNew Offer Assumptions and Clearing Results

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Third Example - Supply Curves

Price

Qty550 600 650 700

$35

E

F

750 800 850 900 950 1000

LMP = $42.00

DEnergy = 720MWh Req10-Min = 250MWh

$42

G

I

50 100 150 200

DA RCP10 = $8.59

E

H

$2.5

$5.0

$5.5

$6.0

G

50

DA RCP30 = $5.05

1050

ReqTotal = 320MWh

$5.0

$3.5

DA 10-min SHADOW PRICE = $3.54

Marginal Offer (Unit E)= $2.59+ Unit E energy OC = $6.00- Unit G TMOR = $5.05 Shadow Price = $3.54

Additional MWh from Unit E satisfies both 10-min and

total requirement RCP10 = $3.54 + $5.05

Unit E Energy Opportunity Cost

$42.00 - $36.00 = $6.00

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Third Example - Observations

• The LMP is set by Unit F; $42/MWh

• The 30-minute RCP is set by Unit G; $5.05/MWh

• Unit E is marginal for 10-minute reserves– If the 10-minute reserve requirement ↑ by one MWh, least-cost

solution includes shifting 1MWh of energy from capacity-constrained Unit E to Unit F; at a cost of $6.00/MWh

– Then Unit E can be awarded another unit of 10-minute reserves, with an offer price of $2.59/MWh

– This reduces the amount of 30-minute reserves by 1MWh to meet the total reserve requirement (from Unit G, saving $5.05/MWh)

– AND, because the additional 1MWh of 10-minute reserve counts toward meeting the total requirement, the clearing price for 10-minute reserves is the sum of the 10-min and 30-min shadow prices

– Thus, the total cost of redispatch for 10-minute reserves is $8.59/MWh


TODAY’S DISCUSSION TAKEAWAYS

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Takeaways from Today’s Discussion

• Problem 1 precipitates Problem 2: there may be insufficient energy available to the power system to withstand an unexpected, extended (multi-hour to multi-day) large generation or supply loss, particularly during cold weather conditions

Why this is a problem now

• Primarily it is because energy supply arrangements matter

• If the generator does not make arrangements for fuel in advance, then with some probability the real-time price for energy will be higher, or reliability will be worse, than if the generator did make advance fuel/supply arrangements

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Takeaways from Today’s Discussion - Continued

Key Properties of New Ancillary Services as ‘energy on call’ options

• We reviewed how the market clearing optimization would compensate both energy and ancillary service awards at uniform, transparent, product-specific market prices and how this approach satisfied the design principles

• We reviewed how these new ancillary services would be settled, noting in particular:– How the day-ahead settlement is expected to change behavior (i.e.,

how this creates an incentive to make fuel arrangements in advance)

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Takeaways from Today’s Discussion

• The new ancillary service call option construct provides stronger incentives to make energy supply arrangements

• The option premium (paid to the generator) makes it profitable on an expected basis for the generator to make advanced energy arrangements, and

• The option premium (i.e., the clearing price of the option) is based not only on the LMP the generator expects to receive when it has energy, but also on the LMP society expects to avoid if it makes the investment in advanced energy supply arrangements

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NEXT STEPS

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Stakeholder Schedule*

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Stakeholder Committee and Date Scheduled Project Milestone

Markets CommitteeMarch 5-6, 2019

Update on ISO conceptual design considerations, stakeholder proposals

Markets CommitteeApril 9-10, 2019 and April 23, 2019

Initial review of discussion paper;Continued discussion of the problem(s) being solvedContinued discussion of stakeholder proposals

Markets CommitteeMay 7-8, 2019

Continued discussion of ISO proposalDiscussion of the impact analysis’ production cost model

Markets CommitteeJune 11-12, 2019

Continued discussion of ISO and stakeholder proposals; Updates of discussion paper as warranted

Markets CommitteeJuly 9-10, 2019

Initial review of impact analysis’ results;Initial discussion of seasonal forward component

Markets CommitteeAugust 13-15, 2019

Draft ISO Tariff language and draft ISO impact analysis report;Continued discussion of the ISO proposal

Markets CommitteeSeptember 18-19, 2019

Final review of proposed Tariff language (ISO proposal and proposed stakeholder amendment(s));Vote on ISO proposed Tariff language and submitted stakeholder amendments

Participants CommitteeOctober 4, 2019

Vote on ISO proposed Tariff language and submitted stakeholder amendments

*Additional MC meetings to be established for the June – September period


APPENDIX

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Market Outcomes for Example 2 Generator 3 Without Fuel(from ISO Discussion Paper on Energy Security Improvements – Version 1)

Generator Energy Option Energy Reserve Energy Reserve Energy Reserve

[1] Gen 1 100 0 100 0 100 0 100 0

[2] Gen 2 90 10 70 20 90 10 100 0

[3] Gen 3 0 20 0 30 0 30 0 0

[4] Gen 4 0 0 0 40 0 40 10 40

[5] Totals 190 30 170 90 190 80 210 40

[6] Clearing Price $39 $11 $30 $0 $30 $0 $90 $0

[7]

[8]

[9]

[10]

[11]

Table 3-3. Market Outcomes for Example 2 with Day Ahead E&AS Market, Case B: Generator 3 Without Fuel

$5,400

$7,203 $7,803 $7,953

$4,600 $5,200 $6,400

33% 33% 33%

Scenario Total Production Cost

Demand Probability

Expected Total System Production Cost

Scenario Market Payments (incl. DAM)

Expected Total Market Payments

Market Awards Low Demand Medium Demand High Demand

$7,653

Day Ahead Real-Time Market Outcomes


ENERGY OPTION SETTLEMENTS From the April ESI presentation to the Markets Committee

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Energy Option Settlements: Components

A call option involves three elements:

• The option price (V)

• The strike price (K)– This is a pre-defined value, set by the ISO before sellers specify their

offer prices

• The price of the underlying product– In this context it is the real-time LMP during the delivery hour

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Energy Option Settlements: Mechanics

Like day-ahead energy, a call option would involve both a day-ahead and a real-time settlement

• The day-ahead settlement is a payment to the seller at the option clearing price (V) for each MWh of the option sold

• The real-time settlement is based on what the seller delivers in real-time, and has two parts. – The first part is a charge for each MWh of the option sold, equal to the

real-time LMP minus the strike price (K), if that difference is positive= (– max{0, RT LMP – K})

– The second part is a credit at the real-time LMP for the energy the resource actually produces

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Where:

• V is the new ancillary service clearing price ($/MWh)

• QDA option is the new ancillary service quantity (MWh)

• K is the strike price ($/MWh)

• RT RCP is the real-time reserve clearing price ($/MWh)

• QRT reserves is the real-time reserve designation (MWh)

Summary of Settlement Rules

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Settlement Rules: Formulas

Energy settlement (no change)

= (DA LMP × QDA energy) - (RT LMP x QDA energy) + (RT LMP × QRT energy)

Which can be re-written:

= (DA LMP × QDA energy) + RT LMP x (QRT energy - QDA energy)

New ancillary services settlement (new, with no day-ahead position)

= (V × QDA option) - (max {0, RT LMP – K} x QDA option) + (RT LMP × QRT energy)

Combining these (new ancillary services with a day-ahead position)

= (DA LMP × QDA energy) - (RT LMP x QDA energy)

+ (V × QDA option) - (max {0, RT LMP – K} x QDA option)

+ (RT LMP × QRT energy)

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a.k.a. “deviations”

Documents

ENERGY SECURITY IMPROVEMENTS: MARKET- BASED … · Slide 6: April ESI presentation. ISO-NE PUBLIC 4 Today’s Presentation Agenda • Problem review –Problem 1 –A brief review