July 8-10, 2014 | Markets Committee

1. July 8-10, 2014 | Markets Committee Catherine McDonough cmcdonough@iso-ne.com | 413-535-4027 Implications of the May 30,2014 FERC Order: Discussion Peak Energy Rent (‘PER’) Adjustment Mechanism

2. How FERC Order Impacts PER Adjustment • To comply with the May 30, 2014 FERC Order ER14-1050 , ISO will: • Increase the Reserve Constraint Penalty Factors (RCPFs) on Dec. 3, 2014 • Implement the Pay-for-Performance (‘PFP’) design in the Forward Capacity Market (‘FCM’) beginning with Capacity Commitment Period (‘CCP’) 2018/2019 (CCP9) • Near-term: Higher RCPFs may increase energy and reserve market revenue and the PER Adjustment. Suppliers are concerned that they were not able to factor these changes into bids for the Forward Capacity Auctions (‘FCA’) associated with CCP5-CCP8 ; December 2014-to-May 2018. • Longer-term: The FCMPFP design is expected to markedly improve supplier incentives to perform and may therefore reduce the need for the PER Adjustment to curb supplier incentives to exercise market power in the energy market.

3. Two Different Evaluations Are Required Near-term (CCP5-8): • What should be done to address suppliers’ concern that they cannot retroactively alter bids for FCA5-FCA8 to account for the potentially greater PER Adjustment due to increased RCPFs ? Longer-term (CCP10 and beyond): • Does the FCM Pay-for Performance (‘PFP’) alter the need for the PER Adjustment Mechanism or require changes to the PER Adjustment so that it better aligns with the PFP design?

4. Near-term (CCP5-CCP8): Impacts of Higher RCPFs

5. Reserve Constraint Penalty Factors: Recent History and FERC Order Changes that Lie Ahead • The Reserve Constraint Penalty Factor (‘RCPF’) is the administrative price-cap on reserves • ISO software will re-dispatch the system to provide adequate reserves if possible, until the price of re-dispatch exceeds the RCPF • Recent History of RCPFs • RCPF for 10 minute non-spinning reserves (‘TMNSR’) has remained unchanged at $850/MWh since co-optimized real-time reserves were implemented in 2006 • RCPF for system-wide 30 minute reserves (‘TMOR’) was raised from $100/MWh to $500 /MWh in June 2012 • RCPF for replacement reserves, an additional increment of TMOR, was set at $250/MWh in October 2013 • To comply with the May 30th FERC Order, the RCPFs will be increased on December 3, 2014; • RCPF for 30-minute reserves (TMOR) will increase from $500 to $1,000/MWh • RCPF for 10-minute reserves (TMNSR) will increase from $850 to $1,500/MWh

6. . Estimate of Real Time Impact of Higher RCPFs • Higher RCPFs would have reduced the number of RCPF activations but real time revenues would have been $12.5 million higher on average due to higher RT LMPS (Hub) and reserve prices. • Notes: 1. The RCPF would have set the price of reserves in 109 dispatch intervals between 2011 and July 2013 with the existing RCPFs in place ; this number would have been only 105 if the new RCPFs had been in place. • 2. Does not include the impact on DAEM revenue; the DA LMP will reflect any increase in expected RT LMPs • 3. Revenue impacts for 2013 reflect data through July

7. Higher RCPFs May Increase the PER Adjustment By Increasing the RTLMP • PER Adjustment = 12-month moving average of Monthly PER prior to the obligation month multiplied by Participant’s CSO for obligation month • Monthly PER = sum of Hourly PER Values for the month • Hourly PER = RT LMP – PER Strike Price • PER Strike Price (S) is set daily at a level based on the variable cost of a deemed “proxy unit” that would be dispatched as the system enters a scarcity condition. • Hourly PER also varies over time with scale factor (See Appendix. p29) • PER Adjustment is a deduction from each Participant’s monthly FCM payment

8. Higher RCPFs May Increase the PER Adjustment By Increasing the RTLMP: Example • Assume • RTLMP > PER strike price in one hour of the 12-month period • PER strike price is $600 on that day • Offer price of marginal generator $400/MWh, No Transmission Congestion • Current RCPFs: If price of TMOR is set at the RCPF of $500 • RTLMP is $900 in that hour: $400/MWh marginal energy offer +$500/MWh RCPF • Hourly PER = $900 - $600 = $300/MWh • Monthly PER rate (based upon 12 month moving average) = $300 x (1/12) + 0 x (11/12) = $25/ MW-mo • Revised RCPFs: If price of TMOR is set at the RCPF of $1,000 • RTLMP is $1,400 in that hour: $400/MWh marginal energy offer +$1000 /MWh RCPF • Hourly PER = $1,400 - $600 = $800/MWh • Monthly PER rate = $800 x (1/12) + $0 x (11/12) = $67/MW-mo • PER Adjustment rate increases by $42/MW-month in this example

9. Impact on PER Adjustment May Cause Higher RCPFs to Transfer Revenue from Suppliers to Load • Higher RCPFs increase energy market revenue through higher DA LMPs, RT LMPs and RT reserve prices. Higher RCPFS also increase the PER Adjustment deduction • Any impact of higher RCPFs on the PER Adjustment is likely to more than offset the aggregate impact of higher RCPFs on energy and reserve market revenue • Most supply clears in the Day Ahead Energy Market (‘DAEM’) at the DALMP • PER Adjustment is based on the RTLMP and each Participant’s CSO • RTLMP > DALMP in vast majority of hours that the Hourly PER is positive • So, the increase in RCPFs may result in a net transfer of money from suppliers to load (capacity buyers) • Suppliers will not be able to reflect the PER Adjustment associated with the increase in RCPFs in their FCM offers until FCA9 (CCP 2018/2019) and beyond

10. Potential Actions to Address Impact of Higher RCPFs on the PER Adjustment • Do Nothing • Even if the suppliers had factored higher RCPFs into their bid prices, the FCA clearing prices may not have been higher • FCA price was supported at administrative floor FCA3-to-FCA-7 except for NEMA/Boston where the FCA -7 price was administratively capped • FCA-8 price was administratively capped • Raise the PER Strike Price to reduce the expected PER Adjustment • ISO tweaked the method used to calculate the PER Strike Price in the middle of the first FCA commitment period (12/2010) sharply reducing the PER Adjustment. • Hourly PER was zero between December 2010 and January 2013 (See following slides) • Other Suggestions

11. Existing PER Adjustment:Historical View of Key Components

12. Existing PER Adjustment : Historical View of Monthly PER and Moving Average of Monthly PER

13. Summary and Next Steps • FERC Order on FCM PFP has implications for the PER Adjustment for periods in which FCAs have already cleared • RCPFs will be increased on December 3, 2014 independent of any action taken to modify PER Adjustment rules for CCP5 • FCA9 will be run under the current PER Adjustment Rules

14. Longer-term (CCP10 and Beyond): Implications of FCM PFP design on PER Adjustment

15. Discussion Questions • To what extent does the FCM Pay-For-Performance change a supplier’s potential incentive to exercise market power in the energy market? • Scarcity conditions • Non-scarcity conditions • Local versus system scarcity conditions • To what extent does the PER Adjustment have other consequences that should be considered in addition to its potential effects on market power (in the energy market)? • If the PER adjustment remains a worthwhile means to curb the incentive to exercise market power once the FCM PFP is implemented, what changes to the PER Adjustment should be considered?

16. Appendix Background Materials Presented at Previous Meetings

17. PER Adjustment and FCM Design (Pre-FCA9)

18. Forward Capacity Market (‘FCM’) Design Objectives • Reliability • Make sure sufficient capacity is available to meet the generation adequacy standard • Financial • Allow new resources to compete with existing resources to serve load • Replace the missing scarcity rents with a smooth revenue stream available to recover fixed costs • Reduce incentive for generators to exercise market power in the energy market • Protect consumers from high energy prices

19. Fundamental Elements of the FCM • FCM establishes a price that the ISO will pay suppliers for an obligation that is both physical and financial. • Physical: Suppliers are required to bid their capacity supply obligation (‘CSO’) into the DA and RT Energy Markets and to build capacity required to deliver on those obligations during scarcity conditions • Financial: gives ISO the right to collect the (positive) difference between the market clearing LMP and a pre-defined strike price. • Peak Energy Rent (PER) Adjustment Mechanism • PER Adjustment is an integral part of what the ISO purchases from generators in the FCM

20. PER Adjustment and Market Power

21. PER Adjustment: Primary Rationale Today • Main rationale for the PER Adjustment Mechanism is to curb supplier incentives to exercise market power in the energy market. • Market Power (MP) is the ability to profitably alter prices away from competitive levels. • Market power in the energy market is exercised by withholding generation and/or offering generation at a high price (>VC). • Exercise of market power can cause an unnecessary dispatch of more expensive resources (inefficiency) and a price increase that transfers wealth from consumers to suppliers. • Example: Assume Supplier A owns two relatively inexpensive generating units and Supplier B owns an expensive unit.

22. Competitive Market Outcome So $/MWh Competitive Supply Curve So with two of many suppliers labeled separately as A and B In this competitive market, Supplier A’s units and Supplier B’s unit would be dispatched. The market clearing price is Pe B Pe A2 Do A1 MW

23. Market Outcome w/ exercise of Market Power $/MWh So A2 Suppose that Supplier A offers its Unit 2 at high price (>MC) Supply Stack would change so that Supplier A’s 2nd unit now sets the market clearing market clearing price at P* and boosts profit P* B Pe Do A1 MW

24. PER Adjustment: Primary Rationale Today (continued) • PER Adjustment Mechanism reduces the potential gain from this type of strategic bidding behavior • With the PER Adjustment, any generator with a CSO must remit (LMP-S)* CSO when LMP>S • This reduces the incremental profit that a supplier expects to earn from withholding output or bidding high (above S) in attempt to drive LMP above competitive levels. • Suppliers recover the cost of the PER Adjustment in their FCM bids

25. PER Adjustment: Primary Rationale Today (continued) A Numerical Example PER Adjustment Eliminates Incentive to Exercise Market Power

26. PER Adjustment: Primary Rationale Today (continued) • Better than a bid cap at deterring market power because it applies to the entire CSO even when the generator is not running. • Supplier has much less of an incentive to extend a unit maintenance outage or fake a forced outage to raise or maintain LMP > S • Difficult to determine that a maintenance outage has been extended beyond a reasonable period • Physical withholding is equivalent to a supplier offering to supply power at an infinite price (> bid cap)

27. PER Adjustment Primary Rationale Today (continued) • Attenuates suppliers’ incentive to overstate available capacity since the deduction is tied to the entire CSO • Creates a strong incentive for generators to produce more during system operating deficiencies • Without the PER adjustment, suppliers may find it in their economic interest to not bring additional capacity on line immediately when a large unit trips offline and the LMP spikes. (depends on the infra marginal units that it owns) • With the PER Adjustment, once the LMP >S, every additional dollar the energy price rises will lower a generator’s profit unless it responds by making additional supplies available.

28. PER Adjustment: Details

29. Existing PER Adjustment Mechanism: Details • Hourly PER = (RTLMP-S)* Scale Factor*Availability Factor • RTLMP: for each Load Zone associated with particular capacity zone • S: variable cost of marginal generating proxy unit (22,000 BTU/kWh) * daily cost of gas or oil whichever is higher • Scale factor: creates lower weighting for hours when load is low relative to forecasted peak • Calculated as the actual hourly integrated load divided by the summer 50/50 predicted peak forecast • Availability Factor: marginal proxy unit = 0.95 • Monthly PER = Sum of Hourly PER values for the month. • Average Monthly PER = 12 month moving average of Monthly PER values prior to the obligation month.

30. Existing PER Adjustment Mechanism Details (continued) • PER Adjustment = Average Monthly PER * PER CSO • PER CSO = minimum [CSO, (CSO – Self Supply Obligation)] • Monthly PER Adjustment is capped at the FCA Payment adjusted to account for obligations acquired or shed for the same commitment period after the FCA • PER CAP = FCA Payment + [(ARA CSO+MRA CSO+IBTCSO) *FCA Clearing Price*)] • FCA payment is payment received for activity in the Forward Capacity Auction • [ARA CSO +MRA CSO +IBT CSO] are obligations acquired or shed • FCA clearing price * is adjusted for price collar (This price is used as a proxy price to prevent opportunities to manipulate the PER CAP such as could be done with a bilateral at zero contract price) • ARA is annual reconfiguration auction, MRA is the monthly reconfiguration auction and IBT is internal bilateral transactions

31. PER Adjustment Details: Key Observations

32. PER Adjustment: Observations • Reduces incentive to exercise market power in the real time energy market • Adds an extra step and risk to FCM bidding; FCM clearing prices will be higher than otherwise • Does not distort DA/RT energy market bidding strategies

33. Existing PER Adjustment Mechanism: Observation # 1 • Reduces the incentive for suppliers to exercise market power in the real time energy market. • Important because the risk of suppliers exercising market power is greatest in the real time energy market • Virtual trading and priced demand bids significantly reduce the ability of suppliers to exercise market power in the day ahead energy market.

34. Existing PER Adjustment: Observation #2 • Adds an extra step and risk to FCM bidding • Suppliers recover their going forward fixed costs (FC) through : Infra marginal Energy Rents (IMR) + Peak Energy Rents (PER) + Capacity Payments (CP) • Without a PER Adjustment, • Suppliers Minimum FCM Offer = FC – E(IMR) –E(PER) +RP • E() indicates expectation • RP: risk premium associated with forecasting E(IMR) and E(PER) • Minimum FCM Offer is “ the missing money” needed to recover going forward fixed costs • Peaking units don’t expect to receive any IMR so their • Minimum FCM Offer = FC – E(PER) + RP

35. Existing PER Adjustment: Observation #2 (continued) • Example: • Assume that the fixed cost (FC) of peaking unit is $8 /kW-m and the expected PER is $2/ kW-m • With no PER Adjustment, the unit’s FCM offer = $8 - $2 + $1 (RP) =$7 • FCM bidding would be simpler if the PER Adjustment deducted the actual peak energy rents earned during the commitment period. • Suppliers would not have to forecast peak energy rents and could simply bid their fixed costs • FCM Offer for peaking unit in example above would be FC=$8

36. Existing PER Adjustment: Observation #2 • But the PER Adjustment is NOT designed to net off the peak energy rents that generators actually earn during the commitment period; • Instead, the PER Adjustment Mechanism nets off a portion of the peak energy rents that generators would hypothetically earn if their entire PER CSO cleared in the real time energy market • Suppliers must raise their FCM offers (i.e. delist bid) to account for the expected value of the existing PER Adjustment • Minimum FCM Offer = FC – E(PER) + E(PER ADJ) + RP • Even suppliers who expect to clear their entire CSO in the real time market only must markup their FCM bids to account for the expected PER Adjustment because the PER Adjustment will differ from expected real time peak energy rents by the scale factor which varies hourly

37. Suppliers Recover the Expected Cost of the PER Adjustment in FCM Bids in Current FCM Design

38. Existing PER Adjustment: Observation #2 (continued) • Key Points: • The existing PER Adjustment has the same effect on the minimum FCM bid regardless of whether a supplier expects to clear in the DA or RT energy market • If the PER Adjustment were eliminated, FCM bids would be reduced by the expected PER Adjustment

39. Existing PER Adjustment: Observation # 2 (continued) • Estimating the value of expected PER Adjustment • Suppliers can use the same forecast of hourly real time peak energy rents (RTLMP-S) required to forecast the peak energy revenue required to construct their FCM bid. (Slide 27) • No need to consider DA/RT bidding strategy since the PER Adjustment depends only on the supplier’s CSO–not on the megawatts they expect to actually clear in real time market. • Practical complication is the scale factor

40. Existing PER Adjustment Mechanism: Observation #3 • Does not distort DA/RT energy market bidding strategies • PER Adjustment is based on the supplier’s CSO and not on the megawatts that a supplier clears in real time. • A competitive supplier cannot change the PER Adjustment by bidding more or less in the DA or RT energy market • Key Point: Existing PER Adjustment has no impact on the profitability of clearing DA versus RT.

41. Existing PER Adjustment Mechanism: Observation #3 • Example : Assume • Supplier has one unit with MC = $50/MWh and CSO= 300 MW • PER Strike price is $120/MWh • DALMP =$100 • RTLMP =$150 • Case 1 : Clears DA w/ PER Adjustment • Case 2 : Clears RT w/ PER Adjustment • Case 3 : Clears DA w/ No PER Adjustment • Case 4 : Clears RT w/ No PER Adjustment • Table on slide 42 shows calculation of total variable profit for each case • Table on slide 43 shows that the relative profit of clearing DA or RT is not impacted by the existing PER Adjustment

42. Existing PER Adjustment Mechanism:Observation #3 (continued)

43. Existing PER Adjustment Mechanism:Observation #3 (continued) Existing PER Adjustment Does Not Change the Profitability of Clearing in DA versus Clearing in Real Time