may 5, 2015 | NEPOOL markets committee

1. may 5, 2015 | NEPOOL markets committee Jonathan Lowell Market development Price Formation When Fast Start Resources Are Committed and Dispatched Fast Start Pricing

2. Goals 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 External Market Monitor’s recommendations • Address shortcomings of current Fast Start Pricing: • 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

3. Fast Start Pricing Design in a Nutshell • RT Dispatch solution • Respects physical limits • Determines DDPs • RT Pricing solution • EcoMin values of committed Fast Start resources relaxed to zero • Amortization of commitment costs • No Load cost amortized over EcoMax • Startup cost amortized over EcoMax during Minimum Run Time • Determines energy and reserve prices • Lost opportunity cost payment when a resource is dispatched to a DDP less than its “economic dispatch point”

4. Additional Information Available! • These documents have been re-posted for the April MC meeting: • Memo: “Fast-Start Pricing Improvements – Revised Edition” • Detailed explanation of Fast Start Pricing logic, rationale and examples • Powerpoints: • March MC meeting - “Fast Start Pricing” presentation • Includes examples from the memo and discussion of Fast Start Pricing design principles • April MC meeting - “Fast Start Pricing” presentation • Includes impact analysis and simulation results

5. Fast start pricing Design & Impact analysis – follow-up discussion Key Concepts and Questions Discussed During the April MC Meeting

6. Key Questions and Follow-up to the April MC • Importance of aligning incentives with dispatch instructions • Reliability, efficiency, incentives and consumer costs • Compensation – Market Prices vs. NCPC • Do we need (more) performance incentives? • What is LOC and why is it necessary? • Recent ISO design initiatives to improve price formation and market efficiency • Related Fast Start Pricing impacts on Day-Ahead and Forward Capacity Markets

7. But First, a Quick Refresher on the Simulated FS Pricing Impacts Presented in April • Annualized RT market results based on 11 month study period • Jan 1, 2014 – Dec 2, 2014

8. Average zonal LMP increases from FS Pricing Minimal price separation across zones, except during tight operating conditions in Jan 2014. *Note: December data includes only two days (12/1/2014 – 12/2/2014)

9. FS Pricing RT NCPC Impacts

10. Importance of Incentives Aligned to Encourage Performance • External Market Monitor’s 2013 Annual Markets Report, p. 95: • “Allowing peaking resources to set prices when marginal would also improve: • Incentives for reliable performance during the relatively tight operating conditions, since fast start units are dispatched primarily when operating reserve margins are smallest during the morning and evening peaks; and • Incentives governing longer-term investment and retirement decisions by participants, since it would provide increased net revenues to generators that are available during tight operating conditions.  This would, in turn, reduce the required net revenues from the capacity market.” • The 2013 AMR also suggests: • “[L]ikely market responses to the higher real-time prices: • Incentives to purchase more in the day-ahead market would increase, which would increase the amount of lower-cost generation committed in the day-ahead market. • Net imports would increase from neighboring control areas, particularly from New York during the morning and evening peak hours.” • These factors improve efficiency by displacing high cost peaking generation with lower cost intermediate resources. This effect is not captured in the ISO’s retrospective impact analysis. • “Performance” is more than simply operating in accordance with a resource’s offered parameters • From a system perspective, resources that become more flexible by increasing ramp rate, or decreasing Min Run or Min Down times, provide better performance that contributes to lower production costs

11. Lost Opportunity Costs • LOC payments are not a new concept • Real-time reserve payments are opportunity costs • Posturing compensation is an opportunity cost payment • The regulation market pays opportunity costs • “Why do we need LOC payments?” • Without LOC payments, a resource operator has a clear financial incentive to deviate from dispatch instructions, or respond slowly. • “Is LOC a double payment?” • No, LOC is not a double payment. • It only provides compensation for net revenue that could have been earned by not following dispatch instructions • It does not pay for fuel not burned • Opportunity cost payments ensure resources are always willing to provide the requested service

12. Recent ISO Efforts to Improve Price Formation • Taken together, ISO’s pricing initiatives do not consistently raise or lower energy prices

13. Day-ahead and fcm market impacts Stakeholder Feedback and Q&A

14. Stakeholder Feedback • “The ISO’s estimated DAM impact of $400m seems too high”: • “Jan-Mar 2014 were highly unusual due and may not be representative of future outcomes” • “How would results change if these months were excluded?” • Simulation of post-12/3/2014 (Hourly Offer Flexibility) outcomes is not feasible in the time available

15. Additional Qualitative Factors • DA/RT convergence will not be instantaneous. Could require as much as a year for changes in bidding strategy to cause DA/RT average price convergence • This could reduce first-year DAM impact substantially • FCM clearing prices will likely reduce as increased DA revenues effectively reduce net cost for both existing resources and new entry (see next slides) • These impacts could plausibly reduce the DA, RT, and FCM net impacts of Fast Start Pricing to $0-100m

16. FCM Offsetting Impacts • Increases in DA revenue will reduce the energy market “missing money” (the capacity payment required for both new and existing resources) • Decrease in “missing money” impacts the amount paid in FCM in two ways: • Demand Curve impact • Reduces NetCONE and causes the FCM demand curve to “shift” inward • Lowers the price paid at any given quantity level • For example, the cost to acquire NICR is reduced • Supply Offer Price impact • A supplier’s net going forward cost will decrease due to higher energy market net revenue • This means competitive FCA offer prices from existing or new resources (the amount resources need to recover through FCM) go down • With plausible assumptions, the reduction in FCM payments can largely offset the increase in DA & RT energy payments(see next slide)

17. FCM Offsetting Aspects- Example (1/2) • Assume: • An existing fossil fuel resource sets the price in FCM • This is the benchmark unit used to set the FCA9 Dynamic Delist Threshold • This resource’s annual capacity factor is 30% • Consistent with ISO's recent environmental update on regional capacity factors by generation type • Annual FCM procures 34,000 MW • Average RT and DA energy prices go up by $3.10/MWh (see slide 7) • The operating cost of the unit remains unchanged *ISO’s environmental update: http://www.iso-ne.com/static-assets/documents/2015/04/EAG_envtl_update_4-7-2015.pdf

18. FCM Offsetting Aspects- Example (2/2) • With an average increase of $3.10/MWh in RT and DA LMPs, and the assumptions in previous slide, the competitive bid of this unit goes down by $0.68/kW-m: 0.3 (Capacity Factor) ×8760 (hr/yr) × $3.10/MWh × 1 MW= $8,146/MW-yr=$0.68/kW-m • If this unit sets the price, reduction in FCM payment (purchasing a fixed amount of 34 GW) could be ≈ $277m • Actual reduction in FCM payment could be more or less if FCM price is set by a different existing or new unit (with different CF) • In equilibrium, the reduction in FCM payment should fully offset the increase in the energy market payment (over time)

19. Potential Range of Net FS Pricing Impact • The estimated total net impact (DA, RT and FCM markets) of Fast Start Pricing is NOT $400m • This was only a simple, transparent calculation of the DAM impact if DA prices fully converge to RT prices that increase by $3.18/MWH1 on average at the hub • It ignores the impact of higher DA revenues that lower the capacity market price • Jan-Mar 2014 were NOT typical months • Simple assumptions to exclude none, some or all of the extreme months in 2014 results in a range of plausible estimates: • Average RT hub price increases of $1.61/MWH - $3.18/MWH • RTM Impacts of $16-19m • Annualized DAM market impacts of $200-400m • FCM cost reductions of $200-400m Note 1: The $3.18/MWH average hub price increase and the $3.10/MWH average RT energy component increase are different metrics from the same retrospective simulation.

20. Longer Term Qualitative Factors • New investment will respond to expected changes in price patterns • Greater onpeak/offpeak price spread may encourage • New storage-based resources • Greater demand response (regardless of Supreme Court decision on Price Responsive Demand) during periods when FS Pricing occurs • Fuel supply infrastructure (to ensure resources can run during tight operating conditions) • External Market Monitor - 2013 Annual Markets Report (p.95): “Allowing peaking resources to set prices when marginal would also improve …incentives governing longer-term investment and retirement decisions by participants, since it would provide increased net revenues to generators that are available during tight operating conditions.  This would, in turn, reduce the required net revenues from the capacity market.”

21. additional background information

22. Fast Start Fleet Characteristics

23. Fast Start Fleet Characteristics • Fast Start Fleet Size • 122 units treated as FS by software during our study period • Combined EcoMax of ~5400 MW • Average dispatchable range: 15 MW per unit • Fuel mix (as measured by EcoMax) • 49% hydro • 51% fossil (primarily combustion turbines and ICUs) • 26% can burn NG as either primary or secondary fuel.

24. Next steps

25. Anticipated Schedule • February MC meeting – conceptual overview • March MC meeting • Lost Opportunity Cost discussion • Detailed Examples • April MC meeting • Historical simulation of fast start pricing design impacts • May MC meeting • Review Fast Start Pricing design and impacts • Tariff language review • June MC meeting – request MC vote • June PC meeting – request PC vote • FERC filing – summer 2015 • Implementation - sometime in 2016