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march 11, 2015 | NEPOOL markets committee

march 11, 2015 | NEPOOL markets committee. Jonathan Lowell. Principal analyst | market development. Improving Price Formation When Fast Start Resources Are Committed and Dispatched. Fast Start Pricing. Today’s Presentation. Quick Review of Key Fast Start Pricing Concepts

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march 11, 2015 | NEPOOL markets committee

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  1. march 11, 2015 | NEPOOL markets committee Jonathan Lowell Principal analyst | market development Improving Price Formation When Fast Start Resources Are Committed and Dispatched Fast Start Pricing

  2. Today’s Presentation • Quick Review of Key Fast Start Pricing Concepts • Deep-dive into Lost Opportunity Cost • Detailed Walk-through of several examples • Example 1 – Illustration of the Four FS Pricing Design Changes • Example 2 – A “not economically useful” Fast Start Will Not Set Price • Example 3 – Illustration of Reserve Pricing during Fast Start Pricing • Additional information and detailed examples are provided in an expanded memo accompanying this presentation: • “Fast Start Pricing Improvements – Revised Edition” • Presentation of the results of a simulation of 2014 using Fast Start Pricing was originally planned for March MC meeting, but due to software issues has been rescheduled for the April meeting.

  3. Quick Review - Objectives of the Fast Start Pricing Design • Improve price formation by reflecting the cost of fast-start deployments through transparent market price signals. • Improve performance incentives for all resources during tight system conditions when reliability risk is heightened. • Address shortcomings of the current Fast Start Pricing methodology • Shortcoming #1 - Fast Start assets are generally unable to set price after the first dispatch interval, even though committed and dispatched economically • Shortcoming #2 - Relaxing EcoMin values in the dispatch solution distorts the system energy balance

  4. Quick Review – Fast Start Pricing Design • “Lumpiness” is the Primary Source of Fast Start Pricing Problems • No pricing solution will fully satisfy the three pricing design principles: • Efficiency • Transparency • Simplicity • The new design has four components: • Unit dispatch solution will respect FS offer minimum MW in all intervals • EcoMin values for any committed Fast Start assets are “relaxed” to 0 MW in the pricing solution • Fast-Start commitment cost amortization in the pricing solution • Startup Fee amortized over EcoMax during Min Run Time • No Load Fee amortized over EcoMax during and after Min Run Time • Compensation for Lost Opportunity Costs (LOC)

  5. Lost opportunity costs

  6. Why Are LOC Payments Necessary? • LOC payment ensures willingness to follow real-time dispatch instructions, by eliminating financial incentives to deviate from instructions. • All assets receive DDPs from the dispatch solution. While honoring resource offer parameters, these DDPs: • minimize total production cost • respect reliability constraints • maintaining the system energy balance • Dispatch DDPs are consistent with each asset’s economic offer • Note that exceptions may occur for specific reliability needs (e.g. posturing) • However, prices that result from Fast Start Pricing may create opportunities for some assets to increase profit by increasing output above the dispatch DDP. • The LOC payment solves this problem.

  7. How Does LOC Occur – A Graphical Example • Assumptions • Demand = 430 MW • FS offer, adjusted for amortized startup cost = $30/MWH + ($400 / 50 MW/hour) = $38/MWH

  8. LOC Illustration - Dispatch Solution

  9. LOC Illustration – Pricing Solution

  10. LOC Illustration – Non-FS Unit DDP is Held Back Relative to the Pricing Solution

  11. Example 1 Illustrating the Four Fast Start Pricing Design Changes

  12. Example 1 - Assumptions • Two units, already committed for the interval: FS and non-FS • Demand = 430 MW • Example study period is 1 hour

  13. Example 1 – FS Unit Amortization of Commitment Costs Within the MRT Period Amortized Cost = $150/(50 MW×0.5 hr) + ($100/h)/50MW = $8/MWh No Load Cost Startup Cost

  14. Example 1 – FS Unit Amortization of Commitment Costs After the MRT Period Amortized Cost = $0/MWH + ($100/h)/50MW = $2/MWh No Load Cost Startup Cost

  15. Example 1 – Dispatch & Pricing Solution Note that MW output levels from the Pricing Solution are not used for dispatch and are not telemetered to assets.

  16. Example 1 - Lost Opportunity Cost Credit • LOC during Min Run Time • LMP = $38/MWH • The non-FS unit would maximize profit by operating at 400 MW • Profit at 400 MW = 400 MW x ($38/MWH - $20/MWH) x 0.5 hr = $3600 • As dispatched Profit = 380 MW x ($38/MWH - $20/MWH) x 0.5 hr = $3420 • LOC credit during MRT = $ 3600 - $3420 = $180 • LOC after Min Run Time • LMP = $32/MWH • The non-FS unit would maximize profit by operating at 400 MW • Profit at 400 MW = 400 MW x ($32/MWH - $20/MWH) x 0.5 hr = $2400 • As dispatched Profit = 380 MW x ($32/MWH - $20/MWH) x 0.5 hr = $2280 • LOC credit after MRT = $ 2400 - $ 2280 = $120 • Total LOC credit for the full hour = $180 + $120 = $300

  17. Example 2 Illustrating Startup Amortization Within and After Min Run Time, and Pricing When a Fast Start Asset is not “Economically Useful”

  18. Example 2 - Assumptions • Two units, already committed for the interval: FS and non-FS • Demand = 430 MW for 15 min, then drops to 395 MW • Two study periods: 1st 15 minutes, and 2nd 15 minutes

  19. Example 2 – FS Unit Amortization of Commitment Costs Within the MRT Period • No change from Example 1 assumptions • Applies in both the 1st and 2nd 15 minute study periods Amortized Cost = $150/(50 MW×0.5 hr) + ($100/h)/50MW = $8/MWh No Load Cost Startup Cost

  20. Example 2 – 1st 15 Minutes Dispatch & Pricing • In the first 15 minutes, assumptions are consistent with Example 1, and outcomes are unchanged. • Demand = 430 MW • Dispatch Solution • Non-FS unit quantity 380 MW @ $20/MWH • FS unit quantity 50 MW @ $30/MWH • Pricing Solution (within MRT) • Non-FS unit quantity 400 MW @ $20/MWH • FS unit quantity 30 MW @ $38/MWH • LMP = $38/MWH

  21. Example 2 – 2nd 15 Minutes Dispatch & Pricing • Demand = 395 MW • Dispatch Solution • FS unit quantity 50 MW • Non-FS unit quantity 345 MW • Pricing Solution (still within MRT) • FS unit quantity is 0 MW @ $38/MWH • Non-FS unit quantity is 395 MW @ $20/MWH • LMP = $20/MWH • The FS asset is not dispatched in the pricing solution (0 MW pricing quantity), and is not “economically useful” • Pricing solution would not change if the FS asset was excluded • The FS asset does not set price • The Non-FS unit is the marginal unit and sets the LMP

  22. Example 2 – FS Asset Make-Whole Payment • The FS unit earns net revenues of: 50MW × ($38/MWH – $30/MWH) × 0.25 hr run time + 50MW × ($20/MWH – $30/MWH) × 0.25 hr run time – $150 Startup – ($100 / hr no-load cost × 0.5 hr run time) = $-225 • The FS unit requires a Make-Whole Payment of $225 for the half-hour study period • New FS pricing does not eliminate the need for make-whole payments for FS units, just reduces it.  • FS units may be uneconomic and unneeded (in hindsight) if load changes from expectations when committed.

  23. Example 2 – Non-FS Lost Opportunity Cost • During the first 15 minutes: • At an LMP of $38/MWH, the unit would choose to operate profitably at a quantity of 400 MW, but was dispatched to a 380 MW DDP (400 MW – 380 MW) × ($38/MWH – $20/MWH offer) × .25 hour = $90 LOC • During the second 15 minutes: • The LMP of $20/MWH is equal to the Non-FS offer of $20/MWH (400 MW – 395 MW) × ($20/MWH – $20/MWH offer) × .25 hour = $0 LOC

  24. Example 3 Determining Reserve Prices Under Fast Start Pricing

  25. Example 3 - Assumptions • Three units, already committed for the interval: a FS and two non-FS units • Study period of 1 hour • Demand = 195 MW • Online reserve requirement = 16 MW • Reserve Constraint Penalty Factor = $1000/MWH

  26. Example 3 - Assumptions • The FS asset is block-loaded – provides no reserve when online.

  27. Example 3 – Dispatch Solution • The FS is block loaded at 20 MW • Unit B is the less expensive non-FS, and provides most of the remaining energy and 1 MW of reserve • Unit A provides most of the reserve, because it is the more expensive non-FS unit

  28. Example 3 – Pricing Solution • Unit A, being less expensive than the FS unit, provides additional energy in the pricing solution, when the FS unit’s EcoMin is relaxed. • With EcoMin relaxed, the FS quantity decreases from 20 MW to 11 MW • In this example, reserve designations in the pricing solution do not change. • An additional MWH of energy would be provided by the FS unit at a cost of $150/MWH. Therefore, LMP = $150/MWH. • An additional MW of reserve requires the redispatch of the FS unit and Unit B, at a cost reflecting the relative difference in offer prices. Reserve price is $135/MWH: $150/MWH - $15/MWH = $135/MWH

  29. Example 3 – Reserve Co-optimization Logic • FS pricing preserves the proper pricing relationships between energy and reserves under RT co-optimization • In Example 3, the FS unit sets LMP at $150 / MWH • Unit B is the marginal supplier of reserves (i.e., provides next reserve MW if reqm’t increases by 1 MW). • For dispatch-following incentives in a co-optimized market, all prices must make the marginal reserve supplier (Unit B) indifferent between supplying more energy v. reserves • Therefore, the correct energy-reserve price difference must equal B’s offer cost, which is $15: $150 LMP – $135 RMCP = Unit B’s $15/MWH offer price • Thus the correct co-optimized reserve price must be $135

  30. Example 3 – Lost Opportunity Cost • Given the clearing prices (LMP = $150/MWH and RMCP = $135/MWH) the LOC for each unit is the difference between the maximum feasible profit and the actual profit, but not less than $0.

  31. Example 3 – Pricing Solution Reserve Capability • In the pricing solution, reserve capability is limited to the reserve a FS unit can provide above its original offered EcoMin • In this example, the reserve capability is 0 MW because the unit is block loaded. • If the FS asset had a dispatchable range in the dispatch solution, it would have been able to provide online reserve in the pricing solution between offered EcoMin and EcoMax (subject to ramp rate limitations) • The online reserve designated in the pricing solution must be no greater than the unit’s reserve capability in the dispatch solution

  32. Anticipated Schedule • February MC meeting – conceptual overview • March MC meeting • Design review and detailed examples • April MC meeting • Historical simulation of fast start pricing design impacts • Tariff language review • May MC meeting – request MC vote • June PC meeting – request PC vote • FERC filing – summer 2015 • Implementation - sometime in 2016

  33. Appendix A Fast Start Pricing Presentation at the February 10, 2015 Markets Committee Meeting

  34. February 10, 2015 | NEPOOL markets committee Jonathan Lowell Principal analyst | market development Improving Price Formation When Fast Start Resources Are Committed and Dispatched Fast Start Pricing

  35. Real-Time Price Formation – Reflecting the Cost of Deploying Fast Start Resources • Today, operating characteristics of most fast-start resources prevent them from setting the energy price • RT Fast Start Pricing changes will improve price formation by enabling fast-start resources to set price more frequently and reflecting the cost of fast-start deployments through transparent market price signals. • Fast Start Pricing can improve performance incentives for all resources during tight system conditions when reliability risk is heightened. • ISO-NE’s External Market Monitor recommended Fast Start Pricing improvements in “2013 Assessment of the ISO New England Electricity Markets”, pp. 22 & 87-95. • Stakeholders have identified price formation as a key concern.

  36. ISO-NE’s Existing Fast Start Pricing - Background • ISO-NE’s existing fast-start pricing logic was designed 15 years ago to work within the software/hardware limitations that existed at the time • Current fast start pricing is neither transparent nor efficient • In practice, fast-start units, even when deployed in economic merit order, often do not set RT LMP • Fast starts generally operate few hours during which inframarginal rents provide an opportunity to recover commitment costs • Must rely on NCPC payments to recoup commitment costs • External Market Monitor: “In 2013, 60 percent of the fast-start capacity that was started in the real-time market did not recoup its offer.” (EMM Assessment, p. 22).

  37. Today’s Presentation • Summary of current Fast Start Pricing and the existing shortcomings to be addressed • High-level description of proposed Fast Start Pricing design • How does it work? • How does it address the existing shortcomings • Additional information and detailed examples are provided in the accompanying memo: • “Fast Start Pricing Improvements”

  38. Future Presentations • Additional discussion of Fast Start pricing details • Examples • Quantitative estimates of FS Pricing impacts, based on simulations applying the new methodology to a year of historical data • RT LMPs and RT reserve prices • Lost Opportunity Cost payments • RT NCPC (for Fast Start assets, and total system) • Planned for the March MC meeting • Discussion of tariff changes • Planned for April-May MC meetings.

  39. ISO-NE’s Current FS Pricing Methodology • In the first 5-minute dispatch interval when a Fast Start is dispatched: • The Fast Start’s EcoMin is “relaxed” to zero • Amortized Startup and No Load costs are added to energy offer price • Fast-starts frequently set price during this initial 5-min interval • In subsequent dispatch intervals • EcoMin is not relaxed to zero (offered EcoMin used for dispatch) • Commitment costs are not added to the energy offer price • Fast-starts generally do not set price after their first dispatch interval, even when they are: • Economically committed and dispatched; and • Highest-priced resource operating at the time

  40. Shortcomings of Current FS Pricing • Shortcoming #1 - Fast Start assets are generally unable to set price after the first dispatch interval, even though committed and dispatched economically • Costs of deploying Fast Starts are not reflected in RT LMPs, even when deployed efficiently to meet demand • “Side payments” (NCPC) required to recover full cost of deployment • Shortcoming #2 - Relaxing EcoMin values in the dispatch solution distorts the system energy balance • Leads to inefficiencies in system dispatch (during first interval) • The distortions must be managed by regulation reserves at potentially higher cost than a balanced energy dispatch.

  41. Pricing is Intimately Related to Real-Time Commitment & Dispatch • Commitment – determine resources to commit (start) and de-commit (shut-down) • Dispatch – determine the “Desired Dispatch Point” (DDP) for each asset • Pricing – determine market prices for energy and reserves

  42. “Lumpiness” is the Primary Source of Fast Start Pricing Problems • “Lumpiness” – caused by minimum output levels and commitment costs • Many Fast Start assets are “block loaded”: EcoMin = EcoMax • Most others have EcoMin close to EcoMax (‘almost’ block loaded) • There is no perfect solution for lumpy problems – no pricing solution will fully satisfy three pricing design principles: • Efficiency • Transparency • Simplicity • Any solution reflects compromises • ISO’s proposal is better than itscurrent practice on these three elements.

  43. Four Related Changes are Proposed to Address the Identified Existing Shortcomings • Unit dispatch solution will respect FS offer minimum MW in all intervals • Means: The dispatch solution honors all offered values and parameters • (differs from current treatment in first dispatch interval) • Ensures the dispatch instruction is feasible for the FS unit • Directly solves Existing Shortcoming #2 • EcoMin values for Fast Start assets are “relaxed” to 0 MW in the pricing solution that calculates RT prices for any committed FS unit • Makes committed FS units more likely to set LMP • Specifically: Will enable a Fast Start to set its LMP whenever it is • Committed by the ISO (i.e., starting up or while running thereafter), and • “Economically useful” for meeting demand in the least-cost dispatch • “Economically useful” = Total system costs would be strictly greater absent the FS unit (requiring a higher cost unit to be dispatched instead) • Directly addresses Existing Shortcoming #1 (along with Change 3, next).

  44. Four Related Changes, Continued • Fast-Start commitment cost amortization in the pricing solution • Two minor modifications from current amortization rules for FS units • Start-Up Fee amortized over EcoMax and Min Run Time (MRT) • Added to incremental energy offer price until the Fast Start’s MRT has expired • Change from current amortization over 1 hour: some FS units have MRT < 1 hour. • No Load Fee amortized over EcoMax & included in energy offer price • Same treatment as current practice during first dispatch interval • Added to incremental energy offer price until the Fast Start is de-committed 4.Compensation for Lost Opportunity Costs (LOC) • In some circumstances, one (or a few) generators may be “postured” down below their economic dispatch point to maintain the system energy balance • Occurs when a Fast-Start sets price above the offer price of another unit that must be dispatched down ‘against’ price, but Fast-Start is at its minimum. • Necessary to ensure willingness to follow dispatch instructions ‘down’ against price (aka, being postured down).

  45. When Does Fast Start Pricing Apply? • Fast Start Pricing methodology is applied in any dispatch interval in which a Rapid Response Pricing Asset (RRPA) is committed • Keep in mind, dispatch is performed with a 15 minute lookahead • FS Pricing will therefore reflect the assets committed for the upcoming interval at time T+15. • Uncommitted assets do not factor into FS Pricing • What is a Rapid Response Pricing Asset? Generators and DARDs that have the same characteristics as currently required for Fast Start Generators: • dispatchable within the hour through electronic dispatch • minimum run time <= 60 minutes • cold Notification Time plus cold Start-Up Time <= 30 minutes • available for dispatch and manned or remote dispatch capability • receive & acknowledge start-up/shut-down instructions electronically • satisfied any minimum down time constraint

  46. Lost Opportunity Cost (LOC) Calculation • To provide real-time dispatch-following incentives, LOC is calculated for every 5 minute interval, using 5-min energy output and 5-min RT LMPs: LOC = Max Feasible Profit – Actual Profit, but not less than $0 • Few MW will incur a LOC, in general • Affects, at most, MW equal to the EcoMin of the “relaxed” RRPA that sets price • Hourly “rolled-up” LOC credits are included in NCPC credit calculations as additional revenue • “Profits” consider both energy and reserves • “Max Feasible Profit” considers only feasible outcomes, as constrained by ramp rates, EcoMin, EcoMax, etc. Does not consider offline scenarios. • Any LOC not used to offset other NCPC credits would be allocated as RT posturing costs are allocated • RTLO (excluding postured pumps)

  47. Lost Opportunity Cost Credit Eligibility • Who is eligible? • Assets that are committed in the associated dispatch solution • Self-scheduled/self-committed assets, unless otherwise excluded • LOC is $0 for ineligible assets • Who is not eligible? • Non-dispatchable and Settlement Only assets • Demand Response assets, at this time. • Will be evaluated as part of PRD Full Implementation • DNE Dispatchable Generators • These assets are not dispatched to a DDP (not ‘postured’) • Assets postured for other reasons (limited energy) during the interval • The Posturing NCPC credit already covers lost opportunity costs • Assets providing regulation during the interval • Regulation compensation already includes opportunity costs

  48. Anticipated Schedule • February MC meeting – conceptual overview • March - April MC meetings • Design discussion • Examples • Historical simulation of fast start pricing design impacts • Tariff language review • May MC meeting – request MC vote • June PC meeting – request PC vote • FERC filing – summer 2015 • Implementation - sometime in 2016

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