2014/15 Winter Program

1. 2014/15 Winter Program Program Rates, Limits, and Potential Costs Analysis Group May 23, 2014

2. Oil Inventory Program: Program Design • Analysis Group has been asked by ISO-NE to help review possible rates, limits and costs associated with its 2014-15 Winter Program • This presentation provides information relevant to setting the rates for the unused oil inventory and unused contracted LNG (“unused fuel inventory”) program, and provides potential costs for the unused fuel inventory, dual fuel commissioning, and demand response programs. • Factors to consider in setting the Unused Oil Inventory Program rate • Rate is based on an assessment of the costs to hold oil inventory given carrying costs, hedging costs and liquidity risks • Unused Oil Inventory Program Rate would be applied consistently across programs • Assessment of potential costs • Unused Oil Inventory • Unused Contract LNG • Dual Fuel Commissioning Program • Demand Response Program

3. Oil Inventory Program: Establishing the Rate • Generator decisions about the quantity and timing of oil inventory purchases will reflect a number of factors: • The need to meet market obligations – e.g., Capacity Supply Obligations • The potential for infra-marginal supply in energy markets (available inventory provides an energy market supply option) • Expectations regarding ability to replenish oil inventory over various time scales (tomorrow, next week, next month, etc.) • Costs and risks of holding unused oil inventory • The fixed rate for the Unused Oil Inventory Program should be designed to mitigate inventory costs and risks, recognizing asset owners have other incentives for establishing inventory (supply obligations, infra-marginal returns)

4. Oil Inventory Program: Establishing the Rate • Holding Cost estimates: four types of costs and risks are quantified • Carrying Cost – the opportunity cost of dollars invested in securing oil inventory, over the time period that inventory is held • Price Risk– the risk that prices decrease subsequent to purchase of oil inventory • Availability Cost – compensation to cover expected availability charge • Liquidity Risk – the risk that the value of stored oil not used by the end of the winter season can not be easily liquidated • Rate designed as a directional incentive, to mitigate such risks in consideration of these estimates and factors • Need not eliminate 100% of costs/risks for all units – other incentives exist (obligations, inframarginal returns) that are not quantified

5. Elements of Holding Cost: Carrying Cost • Carrying cost reflects the opportunity cost of dollars used to purchase inventory • Appropriate cost of capital reflects multiple factors, and depends on treatment of other risks • Cost of capital will be lower if other actions are taken to mitigate price risk (e.g., purchase of put options) • Cost of capital will vary across market participants based on many factors, including size of balance sheet, ability to access capital markets and other constraints on capital and cash flow • Approach to carrying cost considers program risks • Firms’ WACC used as a proxy for risk free rate plus premiums for other risks (liquidity risk, compliance risk, etc.)

6. Elements of Holding Cost: Price Risk • Price risk reflects the potential decline in value of stored oil not used by the end of the winter season • Several means of accounting for this risk • Risk–adjusted cost of capital • Hedging instruments • Hedging instrument: Price risk can be mitigated financially through purchase of a put option • Put option gives the holder the option to sell the commodity at a pre-determined “strike price” • Consider an option with a strike price equal to the price of purchased oil inventory • If the price declines, sell the commodity at the strike price to avoid the associated loss in value • If the price increases, inventory has appreciated in value • Prices may fall between the beginning and end of winter. Units will seek to hedge this risk. • Standardized futures for fuel oil used to predict December Prices are based on New York DFO and Gulf Coast RFO.

7. Elements of Holding Cost: Price Risk • The option premium for the put option reflects: • A strike price set at the current forward price for delivery in October 2014 • Volatilityset at the current implied volatility for put options • The option premium varies with: • Market expectations of fuel prices at the expiry of the option • The type of fuel: DFO v. RFO • Term of option: 12 months assumed – inventory held until start of next winter season (e.g., inventory can not be resold)

8. Elements of Holding Cost: Availability Charge • Total compensation under the oil inventory program will reflect an Availability Charge Availability Charge = Program Payment x (100% - Availability Metric) • Program participants can be expected to factor in this charge when determining willingness to participate in the program • Expected Availability Charge will reflect a resource’s expectation about its ability to maintain availability during the winter program (less reliable resources would require higher compensation) • For each resource, holding cost is adjusted upward to reflect expected availability: Availability Adjusted Holding Cost = Holding Cost / (100% - Availability Metric) • Availability Metric reflects actual unit unavailability, Dec – Feb 2008 – 2014 • Capped at 8.7% (Historical weighted average oil unit unavailability) • Accounting for expected charge does not account for all of the risk associated with potential unavailability (e.g., unexpected full winter outage)

9. Elements of Holding Cost: Liquidity Risk • Liquidity risk reflects the risk that excess inventory cannot be sold at the end of the winter period • Treating oil inventory as a financial asset assumes the asset can be sold (liquidated); may not be reasonable for some units due to cost or technical barriers • Several factors potentially affect how liquidity risk affects oil inventory decisions • Cost to resell oil inventory (salvage cost) • Risk of extended holding – that is, what is the risk that inventory is not used to produce energy for an extended period • Liquidity risk and price risk are independent – that is, compensating for liquidity risk will not eliminate the price risk that the fuel oil will have depreciated over the winter months • Liquidity risk can be compensated through a risk premium • A reasonable level for liquidity risk premium would reflect: • The discount for reselling inventory • Interim payments from ISO for holding inventory • Risk premium implied in WACC for merchant generators sufficient to cover liquidity risk

10. Setting Unused Oil Inventory Program Rate • Unused Oil Inventory Program rate is set based on calculation of holding costs for individual units • Individual unit holding costs calculated using • Carrying cost at generator WACC (from FCM Sloped Demand Curve filing) – assumed to include premiums for liquidity and other non-price risks • 12-month put option using existing oil futures price for December 1 and current expectations around volatility • Rate selected to cover holding costs of units sufficient to meet an inventory goal roughly equivalent to the quantity purchased last winter • Result: Rate equal to $18/barrel • Program Costs will depend on oil inventory remaining on March 1 • Estimated based on remaining inventory as of February and March in last winter season • High/low estimates based on 100% remaining, and 25% remaining, respectively

11. Setting Unused Contracted LNG Program Rate • The rate for the Unused Contracted LNG Program is based upon the Unused Oil Inventory Program rate, converted to $/MMBtu • Result: Rate equal to $3/MMBtu • Program Costs will depend on unused contracted volume remaining on February 28 • Estimate based on data on current LNG supply capacity • Estimate under different scenarios of unused contracted LNG remaining match analysis of unused oil inventory program rate

12. Unused Fuel Inventory Program Costs • Maximum Program Costs would occur in the cases where a large amount of oil inventory or unused contracted LNG remains after the winter

13. Dual Fuel Commissioning Program – Testing Costs • Costs of recommissioning dual fuel capability typically fall into three categories: • Tuning and testing of controls, burners and nozzles • Upgrading or testing of water systems • Cleaning and maintenance on tanks • Some of these costs need to be incurred periodically under normal operations (e.g., tank cleaning and maintenance) • Fuel costs associated with testing the unit represent a large portion of expected costs • Cannot rely on performing tests when resource is in-merit (although potentially can schedule to minimize NCPC) • Testing requirements may vary across resources, in particular depending on: • State-level environmental requirements • Whether the resource has maintained its permits

14. Dual Fuel Commissioning Program Costs • Potential program costs estimates reflect several assumptions • 12 units would participate totaling around 3,500MW of winter capacity • NCPC compensation for 20 hours of testing • In practice, hours of testing needed to fully tune the resource could exceed this cap • Resources have the incentive to be efficient, with or without fuel cost recovery • NCPC amount reflects • Forecasted fuel prices • Net of energy market revenues (using historical October-November RTLMPs) • Resource-specific heat rate and capacity (assuming tests must be performed at full capacity) • Resource-specific start-up costs, assuming 3 cold starts per unit on the secondary fuel • Resource-specific no-load costs for the 20 hours of testing on secondary fuel • Maximum program costs are estimated at $12.9 million

15. Demand Response Program – Program Costs • Potential program costs estimates reflect several assumptions • Monthly payment and Energy payment costs assume 100 MW of participation • Monthly payment rate is based on the oil program rate: $1.80/kW-month • Energy payments are assumed at the average payment rate of last year’s program • Energy payments assume 50 hours of dispatch • Demand Response Program costs are estimated at $2.4 million

16. Combined Winter Program Costs • Estimate combines the Unused Oil Inventory, Unused Contracted LNG, and Dual Fuel Commissioning Programs • Dual Fuel Commissioning Program costs assumed constant across scenarios • Demand Response Program costs assumed constant across scenarios

17. Paul HibbardTodd SchatzkiAnalysis Group111 Huntington Avenue, 10th Floor Boston, MA 20199phibbard@analysisgroup.com617-425-8171