Copyright © 2013 The Brattle Group, Inc.

PRESENTED TO

PRESENTED BY

Net CONE for the ISO-NE Demand CurveResponse to Stakeholder Questions

NEPOOL Markets Committee

Sam Newell, BrattleChristopher Ungate, Sargent & Lundy

February 6 , 2014

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Agenda  Reference Technology  Cost of Capital  E&AS Methodology

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Reference Technology Questions▀ What criteria should be considered in selecting the reference

technology? ▀ What are the plant specifications and performance characteristics

for the reference technologies?▀ Does the relatively larger E&AS offset for CC mean greater

uncertainty in Net CONE?▀ Why is DR not considered as a potential reference technology?▀ Have we considered an oil-only unit?

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Framework for Selecting a Reference Technology

  Objective▀ Estimate Net CONE that supports prices just high enough to attract sufficient

new investment to maintain the long-term target reserve margin

  Criteria for selecting the Reference Technology to meet the objective▀ Likely to be economic

− Complies with all environmental regulations− Lowest or near-lowest estimated Net CONE− Demonstrated commercial interest by developers

▀ Can estimate Net CONE accurately− Cost estimates based on established technologies− Low E&AS uncertainty

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Rating the Candidates Against the Criteria

Criteria: 1. Likely economic 2. Estimate accurately

Technology

Meets Environ. Regulations

Recently Built or Proposed

Net CONE Estimate

Accuracy of Capital and FOM Cost Estimates

Accuracy of E&AS Estimate

2x0 LMS100188 MW

Yes Limited $16.28/ kW-mo

Well established technology

Smaller component*

2x0 Frame CT417 MW

Yes Very limited

$7.90/ kW-mo

Well established technology

Smaller component*

2x1 CC715 MW

Yes Yes $8.96/ kW-mo

Well established technology

Larger component, less

certain

*We have not yet fully examined forward reserve market revenues which add uncertainty to CT E&AS estimates

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Aero-Derivative Combustion Turbine

Frame-Type Combustion Turbine

Combined Cycle Gas Turbine

Plant SpecificationsTurbine Model GE LMS100 PA Siemens SGT6-5000F(5) Siemens SGT6-5000F(5)

Configuration 2 x 0 2 x 0 2 x 2 x 1

Cooling System Dry Fin-Fan Intercooler N/A Dry

Power Augmentation Evaporative CoolingNo inlet chillers

Evaporative CoolingNo inlet chillers

Evaporative CoolingNo inlet chillers

Environmental Controls Water Injection NOx ControlInlet Air FiltersSCRCO Catalyst

Dry Low NOx BurnersWater Injection NOx Control (ULSD)Inlet Air FiltersSCRCO Catalyst

Dry Low NOx BurnersWater Injection NOx Control (ULSD)Inlet Air FiltersSCRCO Catalyst

Dual Fuel Capability ULSD ULSD ULSD

Blackstart Capability No No No

On-Site Gas Compression Yes No No

Interconnection 345 kV 345 kV 345 kV

Plot Size (acres) 10 10 20

Location Worcester, MA Worcester, MA Worcester, MA

Reference Technology Plant Specifications

  All candidates can meet environmental requirements in New England

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FERC Order on F Class Frame CT w/ SCR in NYISO

  On January 28, FERC accepted the simple cycle F-class frame CT with Selective Catalytic Reduction (SCR) as “economically viable” and its use as the reference technology for several NYISO capacity zones

▀ “[W]e find the record of evidence presented in support of the frame unit with SCR is adequate in order to find that NYISO reasonably concluded that the F class frame with SCR is a viable technology and able to serve as proxy unit in NYC, LI, and the G-J Locality”

  Several protestors argued that F class frame CT with SCR is not considered “commercially accepted” as there are no proposed units in the queue, however FERC found this argument misplaced as economic viability determinations are a “matter of judgment”

▀ “While protestors argue that ‘market acceptance’ is material to the question of economic viability, we find that NYISO’s method of judging economic viability is a reasonable one. NYISO provided information sufficient to conclude that the F class frame unit with SCR can be practically constructed in each Locality and is economically viable.”

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Tariff Requirements in NYISO and PJM

  NYISO: Market Administration and Control Area Services Tariff, Section 5.14▀ The periodic review shall assess…the current localized levelized embedded cost of a

peaking plant in each NYCA Locality, the Rest of State, and any New Capacity Zone, to meet minimum capacity requirements.

▀ For purposes of this periodic review, a peaking unit is defined as the unit with technology that results in the lowest fixed costs and highest variable costs among all other units’ technology that are economically viable, and a peaking plant is defined as the number of units (whether one or more) that constitute the scale identified in the periodic review.

  PJM: OATT Attachment DD – Reliability Pricing Model▀ “Reference Resource” shall mean a combustion turbine generating station,

configured with two General Electric Frame 7FA turbines with inlet air cooling to 50 degrees, Selective Catalytic Reduction technology in CONE Areas 1, 2, 3, and 4, dual fuel capability, and a heat rate of 10.096 MMbtu/MWh.

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Reference Technology Plant Performance

Aero-Derivative Combustion Turbine

Frame-Type Combustion Turbine

Combined Cycle Gas Turbine

Plant PerformancesNet Plant Power Rating 1, 2 Base Load: Base Load: Max Load (w/ Duct Firing):

188 MW at 90 °F, 49.6% RH 417 MW at 90 °F, 49.6% RH 715 MW at 90 °F, 49.6% RH

Net Plant Heat Rate (HHV) 1, 2 Base Load: Base Load: Max Load (w/ Duct Firing):9,260 btu/kWh at 90 °F, 49.6% RH 10,806 btu/kWh at 90 °F, 49.6% RH 7,543 btu/kWh at 90 °F, 49.6% RH

Potential-to-Emit (lb/hr) 3

NOx Base Load: Base Load: Max Load (w/ Duct Firing):7.9 lb/hr at 90 °F, 49.6% RH 20.3 lb/hr at 90 °F, 49.6% RH 19.5 lb/hr at 90 °F, 49.6% RH

CO Base Load: Base Load: Max Load (w/ Duct Firing):19.3 lb/hr at 90 °F, 49.6% RH 9.9 lb/hr at 90 °F, 49.6% RH 13.7 lb/hr at 90 °F, 49.6% RH

Ramp Rate 50 MW/Min 30 MW/Min 30 MW/Min (CT)MW from 0-10 min 100% Load ~70% Load ~70% Load4

MW from 0-30 min 100% Load 100% Load 100% Load4

Minimum Up Time 5 1 hr 1 hr 4 hr

Minimum Down Time 6 1 hr 1 hr 4 hr

Forced Outage Rate 2.0% 2.0% 2.5% Notes:1. Net plant power rating and net heat rate are provided for average degraded conditions and firing natural gas.2. Duct firing rate is a constant 470 mmBtu/hr (HHV) to the duct burner, per HRSG.3. Emissions are based on firing 100% natural gas at 100% load with environmental controls listed; they do not include start-up/shut down events.4. Conservatively based only on CT portion; some contribution could be expected from steam turbine, particularly on hot starts.5. There are no physical constraints on minimum up time, but typically set as shown to prevent excessive cycling, which increases O&M cost. 6. There are minor physical constraints on minimum down time such as normal permissive sequencing and purge requirements, but typically set as shown to prevent excessive cycling.

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Most Recent and Proposed Builds

  CCs are the dominant technology recently installed and proposed

  Very few frame CTs

  ISO-NE queue has 1,048 MW of CCs and 415 MW CTs (all LMS100s)

Source: Ventyx Energy Velocity Generating Unit Capacity Dataset

Installed Since 2000 (MW) ISO-NE NYISO PJM U.S.

Combined Cycle 4,692 4,757 18,797 150,501Simple Cycle

Aeroderivative Turbine 618 904 1,188 13,778Frame-Type Turbine 74 0 8,359 29,806

Installed Since 2009 (MW) ISO-NE NYISO PJM U.S.

Combined Cycle 622 1,452 2,530 29,119Simple Cycle

Aeroderivative Turbine 331 462 604 5,976Frame-Type Turbine 0 0 160 3,724

In Development (MW) ISO-NE NYISO PJM U.S.

Combined Cycle 1,331 7,696 23,334 76,848Simple Cycle

Aeroderivative Turbine 0 264 208 1,313Frame-Type Turbine 0 0 0 1,986

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Accuracy of E&AS Revenue Offset  Good demand curve performance depends on

estimating an administrative Net CONE that equals the Net CONE developers need

  The EAS offsets is one of the most uncertain components, and the degree of uncertainty varies by technology

  One indication of relative uncertainty is the higher variability of CCs’ historical revenues

  Another indication is that our CC E&AS revenue estimate is quite sensitive to small changes in the assumptions in our method (see next slide)

Sources:• NYISO State of the Market Annual Report• PJM State of the Market• ISO-NE Confidential Revenue Data

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Sensitivity of E&AS Revenue Offset  To capture the most recent market conditions and futures prices, we updated

the E&AS revenue estimates with ISO-NE data through September 2013

  The change in timeframe of historic revenues has a significant impact on CC E&AS but a limited impact on the CTs E&AS

▀ CC E&AS increased by $1.46/kW-mo to $5.67/kW-mo▀ Frame CT E&AS decreased by $0.04/kW-mo to $2.08/kW-mo▀ LMS100 E&AS decreased by $0.05/kW-mo to $2.88/kW-mo

  If we use just the past 12 months of revenue data, the CC E&AS revenue increases an additional $2.01/kW-mo resulting in a Net CONE that is $1.59/kW-mo lower than the Frame CT

E&AS Margin Net CONECC LMS100 Frame CT CC-Frame CT CC - Frame CT

Time Period Analyzed $/kW-mo $/kW-mo $/kW-mo $/kW-mo $/kW-mo

[1] Jan 2010 to Dec 2012 (Jan Mtg) 4.21 2.93 2.12 1.28 2.56[2] Oct 2010 to Sept 2013 5.67 2.88 2.08 2.79 1.05[3] Oct 2012 to Sept 2013 7.68 2.25 1.63 5.43 -1.59

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Forward Reserve Market Revenues (for CTs)

  Recent changes in the Forward Reserve Market add uncertainty to the E&AS revenues for the CT technologies

▀ In 2012 ISO-NE increased its system-wide 10-minute operating reserve requirements, effective Summer 2013

▀ The change increased the corresponding FRM requirements and caused FRM system-wide prices to increase from less than $1/kW-mo in 2011 & 2012 to greater than $3/kW-mo beginning with the Summer 2013 FRM auction

▀ ISO-NE introduced a more stringent penalty structure

  Going forward, FRM revenues will apply similarly to the LMS100 and Frame CT if they are able to meet similar capacity levels in 10 and 30 min while meeting environmental restrictions

  While we are still estimating the impact of FRM revenues on the CT E&AS revenues, the following items will be considered

1. How representative current prices are of future prices2. How deep is the market and how sensitive will prices be to new capacity additions3. How much capacity can a CT offer in the FRM4. How much do the FRM revenues impact the energy and real-time reserve revenues

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Units Not Considered as Reference Technology

  Demand Response▀ Demand response capacity resource costs are asset-specific with a wide-

range of costs of new entry, creating a supply curve of DR assets▀ There is no reasonable way to identify the single type of DR asset that

would be expected to clear the FCM to meet the ISO-NE reserve margin objectives over the long term

▀ Capacity prices need to reflect the cost of capacity, not the price where the highest-cost DR asset that clears the market was willing not to “buy”

  Oil-Only Units▀ Net savings of an oil-only unit would be small, if not negative▀ Likely complications for permitting▀ No oil-only units have been or are under consideration in New England,

even if some have been burning only oil lately

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Cost of Capital Question▀ How does the NYISO DCR cost of capital value compare to the

ATWACC for the ISO-NE proposed demand curve?

  The cost of capital estimated for the NYISO Demand Curve Reset assumed a higher Return on Equity, which results in an ATWACC that is 0.3% higher than our estimate for the ISO-NE proposed demand curve

ISO-NE Net CONE NYISO DCR

InputsRecommended

InputsSample

CompaniesRecommended

Inputs

Return on Equity 11.9% 11.3% 12.5%Cost of Debt 7.0% 3.4 - 6.8% 7.0%Capital Structure (Debt/Equity) 50/50 --- 50/50

WACC 9.5% --- 9.8%ATWACC 8.0% --- 8.3%

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E&AS Revenue Offset Questions▀ Are forward reserves considered in the E&AS offset?▀ How will the recent winter fuel price volatility be captured?▀ Can you average futures prices over a period of time instead of

using a single day?▀ Can you provide more information on how you estimated the

E&AS offset?▀ What is included in the Ancillary Services?

  The previous slides have answered these questions except for the basic methodology which is outlined in the appendix slides

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Updated Net CONE Estimates  We have estimated Net CONE for three potential reference technologies

  The estimates below are the same as in the January meeting, but with updated E&AS revenues based on most recent market data

  These estimates do not yet include▀ FRM revenues ▀ Refined electrical interconnection costs

Reference Installed Total Plant Overnight After-Tax Capital Fixed Gross Revenue NetTechnology Capacity Capital Cost Cost WACC Costs O&M CONE Offsets CONERest of Pool (MW) ($m) ($/kW) (%) ($/kW-mo) ($/kW-mo) ($/kW-mo) ($/kW-mo) ($/kW-mo)

2x0 LMS100 188 $345 $1,754 8.0% $16.23 $2.93 $19.16 $2.88 $16.282x0 Frame CT 417 $397 $908 8.0% $8.41 $1.57 $9.98 $2.08 $7.902x1 CC 715 $937 $1,196 8.0% $12.13 $2.50 $14.62 $5.67 $8.96

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Appendix Slides

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Historic Net E&AS Revenue Offsets  We estimate 1st year E&AS revenue offsets based on historical revenues for like units

then adjust the revenues forward to 2018/2019 using gas and electricity futures prices

  We calculated historical market revenues by asset with data provided by ISO-NE Markets Analysis and Settlements department for March 2003 to January 2014

▀ We first calculated total revenues for CC and LMS100 based on like-units▀ We then calculated net revenues by subtracting fuel (Ventyx) and variable O&M (S&L) costs▀ Due to limited data availability, we calculated Frame CT net revenues as a percentage of

LMS100 revenues based on the results of a virtual dispatch of the two technologies against historical electricity prices

  Ancillary services include:▀ Net Commitment Period Compensation (NCPC)▀ Regulation▀ Real Time Reserves▀ Blackstart▀ VAR Capacity▀ Forward Reserve Market revenues were not included in our initial analysis but we are

currently examining whether and how much they should be included (see slide 12)

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FCA9 Net E&AS Revenue Offsets  We adjusted historical net revenues for like units to 2018/2019 based on the most recent

30-day average of gas and electricity futures prices▀ 2018/2019 E&AS Margin = Historical E&AS Margin / Historical Electricity Price * 2018/2019

Electricity Price ▀ 2018/2019 MA Hub On Peak Electricity Price = 2014 Market Heat Rate * (2018 Henry Hub + 2014

Algonquin City Gates Adder)▀ This is a proxy for a forward energy price that accounts for the effect of rising gas prices. It does

not account for how market heat rates might increase as generation reserve margins tighten nor does it fully account for the growing discount one would expect for forward prices relative to expected spot prices for longer forward periods.

Projected Gas and Electricity Prices

Year CC CT

2011 $3.74 $2.742012 $2.22 $2.772013 $5.68 $2.52

2014 $6.06 $3.602015 $5.36 $3.322016 $5.41 $3.342017 $5.50 $3.392018 $5.60 $3.45

2018/19 $5.67 $3.48

Projected Future Year E&AS Revenues