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2014/15 Winter ProgramProgram Rates, Limits, and Potential Costs

Analysis GroupMay 23, 2014

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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

Oil Inventory Program: Program Design

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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)

Oil Inventory Program: Establishing the Rate

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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

Oil Inventory Program: Establishing the Rate

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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.)

Elements of Holding Cost: Carrying Cost

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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

Elements of Holding Cost: Price Risk

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.

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The option premium for the put option reflects:

• A strike price set at the current forward price for delivery in October 2014

• Volatility set at the current implied volatility for put options

Elements of Holding Cost: Price Risk

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)

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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)

Elements of Holding Cost: Availability Charge

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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

Elements of Holding Cost: Liquidity Risk

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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

Setting Unused Oil Inventory Program Rate

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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

Setting Unused Contracted LNG Program Rate

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Maximum Program Costs would occur in the cases where a large amount of oil inventory or unused contracted LNG remains after the winter

Unused Fuel Inventory Program Costs

Expected Oil Inventory as of

December 1, 2014 (mil bbl)1

Unused Oil Program

Rate ($/bbl)

Maximum Unused

Contracted LNG

(mil MMBtu)2

LNG Equivalent of Unused

Oil Program Rate

($/MMBtu)3

3.54 $18 6.10 $3

Percentage of Expected Unused Oil

Inventory and Unused Contracted

LNG Remaining4

Expected Unused Oil

Program Cost ($ mil)

Expected Unused

Contracted LNG Program

Cost ($ mil)

Combined Unused Fuel

Inventory Program Costs

($ mil)

100% $63.8 $18.8 $82.675.1% $47.9 $14.2 $62.046.4% $29.6 $8.8 $38.425.0% $15.9 $4.7 $20.7

Notes:

[2] Assumed based on 2 day maximum contract volumes.[3] LNG Program Rates are based on the $18/bbl oil program rate. Conversion is done using oil heat content values from EIA data.

[1] Expected Oil Inventory is the quantity of oil approved for payments under the 2013-2014 Winter Program.

[4] 75.1% is the percentage of system-wide December 2013 oil inventory remaining as of March 2014 (after some inventory refills). 46.4% is the percentage of system-wide December 2013 oil inventory remaining as of February 2014, the month of smallest system inventory during winter 2013-2014.

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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

Dual Fuel Commissioning Program – Testing Costs

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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

Dual Fuel Commissioning Program Costs

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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

Demand Response Program – Program Costs

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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

Percentage of Expected Unused

Oil Inventory and Unused

Contracted LNG Remaining

Combined Unused Fuel

Inventory Program Costs

($ mil)

Dual Fuel Commissioning

Program Costs

($ mil)

Demand Response

Program Costs

($ mil)

Total Inventory, Dual

Fuel, and Demand

Response Program

Costs ($ mil)

100% $82.6 $12.9 $2.4 $97.875.1% $62.0 $12.9 $2.4 $77.246.4% $38.4 $12.9 $2.4 $53.625.0% $20.7 $12.9 $2.4 $35.9

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