ISO-NE Offer Review Trigger Price 2013 Update – Draft Results Presented to:

Antitrust/Competition Commercial Damages Environmental Litigation and Regulation Forensic Economics Intellectual Property International Arbitration International Trade Product Liability Regulatory Finance and Accounting Risk Management Securities Tax Utility Regulatory Policy and Ratemaking Valuation Electric Power Financial Institutions Natural Gas Petroleum Pharmaceuticals, Medical Devices, and Biotechnology Telecommunications and Media Transportation

Copyright © 2013 The Brattle Group, Inc. www.brattle.com

ISO-NE Offer Review Trigger Price2013 Update – Draft Results

Presented to:NEPOOL Markets Committee

Presented by:Sam Newell (Brattle) and Chris Ungate (Sargent & Lundy)

August 7, 2013

2

Agenda

Summary

Methodology Updates

ORTP Results

♦ Combined Cycle ORTP

♦ Simple Cycle Gas Turbine ORTP

♦ Onshore Wind ORTP

♦ Demand Response ORTP

♦ Energy Efficiency ORTP

Annual Updates

Appendix

3

Summary

Objectives and Approach

Objectives

♦ Provide Offer Review Trigger Price (ORTP) values for various resource types for use in FCA9

♦ Provide a capital budgeting model and indices that ISO-NE’s IMM can use to update ORTPs for FCA10 and FCA11

Approach

♦ Screen technologies

♦ Build bottom-up cost estimates of capital costs, then estimate the amount a resource would need from the first-year FCA to achieve zero NPV net of all revenue sources over 20 years

♦ Recommend indices for future updates

4

Summary

Recommended ORTP Values

Summary of ORTPs (2018 $)

Notes: 1.Overnight costs, fixed O&M, Gross CONE and revenue offsets are calculated based on installed capacities; Net CONE and ORTP values are calculated based on qualifying capacities.2.Some values, esp. Onshore Wind, may appear high compared to current costs. These values are in 2018$ and include all cost components (e.g. Onshore Wind is $2,823/kW in 2013$ of which $496/kW is due to interconnection.) See later slides for detailed values of each technology for which we developed an ORTP. 3.FOM includes site leasing costs.4.DR categories evaluated at the asset level. Actual resources would be aggregations of at least 100 kW.

Reference Total Plant Installed Qualifying Overnight After-Tax Fixed Gross Revenue Net 2018/19Technology Capital Cost Capacity Capacity Cost WACC O&M CONE Offsets CONE ORTP

($m) (MW) (MW) ($/kW) (%) ($/kW-mo) ($/kW-mo) ($/kW-mo) ($/kW-mo) ($/kW-mo)denominator Installed Installed Installed Installed Qualifying Qualifying

Combustion Turbine $318 192 192 $1,582 7.2% $2.65 $16.10 $2.84 $13.26 $13.26

Combined Cycle $877 730 730 $1,107 7.2% $2.33 $12.58 $3.84 $8.75 $8.75

Onshore Wind $206 60 11 $3,230 7.2% $6.73 $26.51 $24.63 $9.87 $9.87

Energy Efficiency n.a. 1 1 $2,571 7.2% $0.00 $24.40 $25.37 -$0.96 $0.00

Large DR n.a. 0.5 0.5 n.a. 7.2% n.a. $1.15 $0.00 $1.15 $1.15

Mass Market DR n.a. 0.001 0.001 n.a. 7.2% n.a. $7.09 $0.00 $7.09 $7.09

5

Agenda

Summary

Methodology Updates

ORTP Results






Annual Updates

Appendix

6

Methodology

Generation Technology Screening (in 2018 $s)

♦ We developed ORTPs for CTs, CCGTs, and Onshore Wind

♦ Offshore Wind, Solar PV, and Biomass have too high a Net CONE to use any ORTP other than the auction starting price

per kW ofInstalled Capacity

per kW ofQualifyingCapacity

Component Units CCGT CT OnshoreWind

OffshoreWind

Solar PV Biomass

AssumptionsPlant Size MW 730 192 60 400 20 50Overnight Costs (2013$) $/kW $953 $1,370 $2,823 $5,000 $2,750 $6,107Overnight Costs (2018$) $/kW $1,108 $1,583 $3,230 $5,588 $3,074 $7,143Installed Costs (2018$) $/kW $1,202 $1,651 $3,441 $6,035 $3,320 $8,084FOM $/kW-yr $28 $32 $81 $85 $32 $250Capacity Factor % n.a. n.a. 31% 37% 13% 50%Avg Elec Price $/MWh n.a. n.a. $59 $60 $65 n.a.REC $/MWh n.a. n.a. $50 $50 $50 $15PTC $/MWh n.a. n.a. $26 n.a. n.a. $26ATWACC (real) % 4.8% 4.8% 4.8% 4.8% 4.8% 4.8%Tax Rate % 40% 40% 41% 40% 40% 41%Qualified Capacity % 100% 100% 19% 26% 25% 100%

CalculationsGross CONE $/kW-mo $13 $16 $27 $35 $18 $72

Capital Costs $/kW-mo $13 $18 $38 $66 $36 $89FOM $/kW-mo $2 $3 $7 $7 $3 $21Dep Tax Shield $/kW-mo -$3 -$5 -$13 -$18 -$10 -$29Tax Credit $/kW-mo $0 $0 -$6 -$19 -$10 -$9

Revenue Offsets $/kW-mo $4 $3 $25 $30 $11 $8Energy Margin $/kW-mo $4 $3 $13 $16 $6 $3RECs $/kW-mo $0 $0 $11 $13 $5 $6

Net CONE $/kW-mo $9 $13 $10 $22 $29 $63

ORTP $/kW-mo $9 $13 $10 $22 $29 $63

7

Methodology

Cost of Capital

♦ We estimated the after-tax weighted-average cost of capital (ATWACC) based on market data for merchant generation companies

♦ There are only two public merchant generation companies• Estimated ATWACC for NRG is 6.9%, reflecting substantial hedging

• Estimated ATWACC for Calpine is 7.5%, reflecting greater merchant exposure

• Contrary to earlier presentations, no risk-free adjustment was needed since rates have increased over the past 2 months

♦ We have chosen to use the average ATWACC of NRG and Calpine due to our consideration of their portfolios relative to tariff requirements (assume PPA on only non-capacity revenues)

♦ The value-weighted average of these two data points is 7.2%

8

Methodology

Net Energy and Ancillary Service Revenue Offsets

Estimated 1st year E&AS margins using historical net revenues for like units in 2010-12 adjusted to 2018/2019 based on 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 = 2013 Market Heat Rate * (2018 Henry Hub + 2013 Algonquin City Gates Adder)

♦ This is a proxy for a PPA-supported 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 after the FCA price floor disappears; nor does it fully account for the growing discount one would expect for forward prices relative to expected spot prices for longer forward periods (as with any pro-cyclic commodities)

0

5

10

15

20

25

30

35

40

45

50

0

20

40

60

80

100

120

Aug-13 Aug-14 Aug-15 Aug-16 Aug-17 Aug-18 Aug-19

Gas

Pric

e ($

/MM

Btu)

Elec

tric

ity P

rice

($/M

Wh)

Mass HubOn Peak

Alongquin City Gates

Henry Hub

Projected Mass Hub On Peak prices for estimating energy revenues

Average Projected E&AS MarginProjected Gas and Electricity Prices

Year CC CT Onshore Wind

($/kW-mo) ($/kW-mo) ($/kW-mo)

2010 3.30 2.46 10.972011 3.15 2.34 9.942012 2.92 2.01 7.49

2013 3.33 2.46 12.312014 3.20 2.34 11.002015 3.33 2.44 11.482016 3.44 2.51 11.842017 3.58 2.62 12.332018 3.78 2.78 13.00

2018/2019 3.84 2.84 13.35

9

Methodology

REC Revenue Offsets

1st year REC Revenues have been estimated using the most forward-looking prices available in New England

♦ REC forwards for 2018/2019 are not available ♦ The furthest forward RECs are 2016 MA Class I RECs currently

priced at $47/MWh (source: SNL)♦ We escalated the 2016 REC forward value to $50/MWh (2018$)

10

Methodology

Five Year Lock-In

New resources may take the 5-year price lock-in option♦ If they do, five years of non-capacity revenues could be

considered in estimating their competitive capacity offer

♦ However, if future revenues stay constant in real terms (nominally increasing at the rate of inflation), Net CONE would be unaffected by the lock-in

♦ We adopt this assumption for simplicity, lacking readily-available data sources to project energy margins in 2019-2024

11

Methodology

Performance Incentives

♦ Given the preliminary nature of the PI proposal, we did not include performance incentives in the formulation of the ORTPs

♦ PI could be included in asset specific reviews

12

Agenda

Summary

Methodology Updates

ORTP Results






Annual Updates

Appendix

13

Combined Cycle ORTP

CC Technical Specifications

♦ Recent and planned new CCs are typically 500-700 MW in a 2x1 configuration

♦ Duct firing is common on CCs in New England to increase summer output

• New England CCs with duct firing include Kleen, Mystic, and Fore River

• We assumed duct firing expands capacity by 15%

♦ Other features include dry cooling, dual-fuel, and SCR

♦ Hampden County was chosen due to proximity to high voltage transmission and gas pipelines

Unit SpecificationsCombined Cycle Gas

Turbine

Turbine Model Siemens SGT6-5000F(5)Primary Fuel Natural GasConfiguration 2 x 2 x 1Net Plant Capacity (MW) 730

without Duct Firing (MW) 631Cooling System DryPower Augmentation Evaporative Cooling

No inlet chillersNet Heat Rate (Btu/kWh,HHV) 7,526

without Duct Firing (Btu/kWh, HHV) 7,204Capacity Factor ---Qualified Capacity 100%Environmental Controls Dry Low NOx Burners

Inlet Air FiltersSCRCO Catalyst

Dual Fuel Capability ULSDBlackstart Capability NoOn-Site Gas Compression NoInterconnection 345 kVPlot Size (acres) 20Location Hampden County, MA

14

Combined Cycle ORTP

CC Capital Costs

Capital Costs2013 Overnight

Costs2013 Overnight

Costs2018 Overnight

Costs(2013 $) (2013 $/kW) (2018 $/kW)

EPC CostsEquipment

Gas Turbines $90,000,000 $123 $141Boiler / HRSG / SCR $43,000,000 $59 $67Condenser $26,900,000 $37 $42Steam Turbines $36,000,000 $49 $56Wind Turbines $0 $0 $0Other Equipment $50,093,000 $69 $78

Construction Labor $154,140,000 $211 $254Other Labor $36,833,000 $50 $61Materials $33,198,000 $46 $52Sales Tax $17,449,000 $24 $27EPC Contractor Fee $58,514,000 $80 $93EPC Contingency $54,613,000 $75 $87

Total EPC Costs $600,740,000 $823 $959

Non-EPC CostsOwner's Costs (Services) $42,052,000 $58 $67Electrical Interconnection $16,000,000 $22 $25Gas Interconnection $3,600,000 $5 $6Emission Reduction Credits $0 $0 $0Land $0 $0 $0Working Capital and Inventories $13,507,000 $19 $20Owner's Contingency $6,013,000 $8 $9Financing Fees $13,638,000 $19 $22

Total Non-EPC Costs $94,810,000 $130 $149

Overnight Capital Costs ($) $695,550,000 $953 $1,107

15

Combined Cycle ORTP

CC Revenue Offsets

Projected E&AS margins were estimated using historical margins for New England CCs with similar characteristics, adjusted based on forward prices

♦ 2010 - 2012 Average E&AS Margin for CCs was $3.13 / kW-mo

♦ 2018/2019 Projected E&AS Margin for CCs is $3.84 / kW-mo

Year CC($/kW-mo)

2010 3.302011 3.152012 2.92

2013 3.332014 3.202015 3.332016 3.442017 3.582018 3.78

2018/2019 3.84

16

Combined Cycle ORTP

CC ORTP Calculation (2018 $s)

Installed Capacity MW 730 Qualified Capacity MW 730 Capital Costs (Installed) $/kW 1,202 ATWACC % 7.2%

Gross CONE $/kW-mo 12.58Levelized Capital Costs $/kW-mo 13.11Fixed O&M $/kW-mo 2.33

Revenue Offsets $/kW-mo 3.84E&AS Margins $/kW-mo 3.84REC Revenue $/kW-mo 0.00

Net CONE $/kW-mo 8.75

ORTP $/kW-mo 8.75

17

Agenda

Summary

Methodology Updates

ORTP Results






Annual Updates

Appendix

18

Simple Cycle Gas Turbine ORTP

CT Technical Specifications

♦ LMS100 is the dominant simple-cycle turbine type being developed today, due to superior heat rate and cost/kw relative to LM6000

♦ 2x0 plant configuration reduces impact of common costs on overall $/kW

♦ LMS100 requires on-site gas compression to raise pressure of delivered gas

♦ Other features include dry cooling, dual-fuel, and SCR

Unit Specifications Combustion Turbine

Turbine Model GE LMS100 PAPrimary Fuel Natural GasConfiguration 2 x 0Net Plant Capacity (MW) 192

without Duct Firing (MW) ---Cooling System DryPower Augmentation Evaporative Cooling

No inlet chillersNet Heat Rate (Btu/kWh,HHV) 9,244

without Duct Firing (Btu/kWh, HHV) ---Capacity Factor ---Qualified Capacity 100%Environmental Controls Water Injection NOx

ControlPulse Inlet Air FiltersSCRCO Catalyst

Dual Fuel Capability ULSDBlackstart Capability NoOn-Site Gas Compression YesInterconnection 345 kVPlot Size (acres) 10Location Hampden County, MA

19


CT Capital Costs


Costs2013 Overnight

Costs2018 Overnight

Costs(2013 $) (2013 $/kW) (2018 $/kW)

EPC CostsEquipment

Gas Turbines $77,500,000 $403 $459Boiler / HRSG / SCR $14,000,000 $73 $83Condenser $0 $0 $0Steam Turbines $0 $0 $0Wind Turbines $0 $0 $0Other Equipment $29,013,000 $151 $172


Total EPC Costs $227,750,000 $1,184 $1,370

Non-EPC CostsOwner's Costs (Services) $15,943,000 $83 $96Electrical Interconnection $4,000,000 $21 $24Gas Interconnection $3,600,000 $19 $21Emission Reduction Credits $0 $0 $0Land $0 $0 $0Working Capital and Inventories $4,806,000 $25 $28Owner's Contingency $2,268,000 $12 $13Financing Fees $5,167,000 $27 $31


Overnight Capital Costs ($) $263,534,000 $1,370 $1,582

20


CT Revenue Offsets

Projected E&AS margins were estimated using historical margins for New England CTs with similar characteristics adjusted based on forward prices

♦ 2010 - 2012 Average E&AS Margin for CT was $2.27 / kW-mo

♦ 2018/2019 Projected E&AS Margin for CT is $2.84 / kW-mo

Year CT($/kW-mo)

2010 2.462011 2.342012 2.01

2013 2.462014 2.342015 2.442016 2.512017 2.622018 2.78

2018/2019 2.84

21


CT ORTP Calculation (2018 $)





ORTP $/kW-mo 13.26

22

Agenda

Summary

Methodology Updates

ORTP Results






Annual Updates

Appendix

23

Onshore Wind ORTP

Onshore Wind Technical Specifications

♦ Assumed siting in Western Maine due to the quality of the wind resources and proximity to transmission

♦ Analyzed characteristics and costs based on recent projects in other parts of the country

♦ Capacity Factor is based on the wind farms used to develop the capital cost estimates

♦ Qualified Capacity is from ISO-NE analysis of Onshore Wind average summer capacity value and is consistent with Intermittent Resource rules

Unit Specifications On-Shore Wind

Turbine Model GE 1.6-100Primary Fuel WindConfiguration 37 x 1.62 MWNet Plant Capacity (MW) 60Capacity Factor 31%Qualified Capacity 19%Interconnection 115 kVPlot Size (acres) 3,840Location Western ME

24

Onshore Wind ORTP

Onshore Wind Capital Costs


Costs2013 Overnight

Costs2018 Overnight

Costs(2013 $) (2013 $/kW) (2018 $/kW)

EPC CostsEquipment

Gas Turbines $0 $0 $0Boiler / HRSG / SCR $0 $0 $0Condenser $0 $0 $0Steam Turbines $0 $0 $0Wind Turbines $77,922,000 $1,300 $1,482Other Equipment $5,994,000 $100 $114


Total EPC Costs $125,871,000 $2,100 $2,405

Non-EPC CostsOwner's Costs (Services) $8,811,000 $147 $168Electrical Interconnection $27,000,000 $450 $513Gas Interconnection $0 $0 $0Emission Reduction Credits $0 $0 $0Land $0 $0 $0Working Capital and Inventories $1,259,000 $21 $24Owner's Contingency $2,966,000 $49 $56Financing Fees $3,318,000 $55 $63


Overnight Capital Costs ($) $169,225,000 $2,823 $3,230

25

Onshore Wind ORTP

Onshore Wind Revenue Offsets

Projected E&AS margins were estimated using historical margins for five New England wind farms with a weighted capacity factor of 32%

♦ 2010–2012 Average E&AS Margin was $9.47 / kW-mo

♦ 2018/2019 Projected E&AS Margin is $13.35 / kW-mo

♦ 2018/2019 Projected REC price is $50 / MWh

Year Onshore Wind

($/kW-mo)

2010 10.972011 9.942012 7.49

2013 12.312014 11.002015 11.482016 11.842017 12.332018 13.00

2018/2019 13.35

26

Onshore Wind ORTP

Onshore Wind ORTP Calculation (2018 $)

Note: Onshore Wind ORTP is highly sensitive to assumptions♦ Onshore Wind ORTP is very sensitive to REC, capacity factor, capital costs, FOM

and ATWACC

♦ Most sensitive to REC price and capacity factor

♦ Wind ORTP is more sensitive than other technologies due to low Qualified Capacity (19% of Installed Capacity)





ORTP $/kW-mo 9.87

27

Agenda

Summary

Methodology Updates

ORTP Results






Annual Updates

Appendix

28

Demand Response ORTP

DR Asset Specifications

There is a wide range of asset types operating in ISO-NE

We identified “Large C&I” and “Mass Market” asset types as representative of typical DR bidding into FCM

♦ Large C&I• Commercial or industrial customer that is using existing control

technologies to implement load reductions; incremental costs include metering and two-way communication technologies

• 1 – 4 MW of load with 20% demand reduction

♦ Mass Market• Large-scale programs targeting residential or small commercial customers

that control specific end-uses (i.e., air conditioning, water heating, etc.); typically implemented in conjunction with an AMR or “Smart Grid” project

• 1 kW of reduction, based on Automated Meter Reading and Air Conditioning Control (AMR A/C) programs

29


DR Asset Costs

We interviewed several DR aggregators and used public program cost summaries to develop costs for each asset

Cost components and values were identified for an incremental customer being added to an existing DR provider or program administrator

Mass Market Units Values

AssumptionsDemand Reduction kW 1Contract Life years 10ATWACC % 7.2%Total Installation Costs $ $205

Mktg, Sales & Recruitment $ $40Equipment Costs $ $125Initial Customer Incentives $ $40

Annual Customer Incentives $/yr $40O&M Costs $/yr $10Software/Communication $/yr $10

Large C&I Units Values

AssumptionsDemand Reduction kW 500Contract Life years 3ATWACC % 7.2%Customer Incentive % 70%Sales Commission % 1%Capacity Clearing Price $/kW-mo 3.15Reconfiguration Clearing Price $/kW-mo 1.30Equipment Costs $ 3,500

30


DR ORTP Calculation (2018 $)

Large C&I Units Values

AssumptionsDemand Reduction kW 500Contract Life years 3ATWACC % 7.2%

Incremental CostsEquipment Costs $/kW-mo 0.20Customer Incentive $/kW-mo 0.91Sales Rep. Commission $/kW-mo 0.03

Total Incremental Costs $/kW-mo 1.15

ORTP $/kW-mo 1.15

Mass Market Units Values

AssumptionsDemand Reduction kW 1Contract Life years 10ATWACC % 7.2%

Incremental CostsInstallation Costs $/kW-mo 2.09Annual Customer Incentives $/kW-mo 3.33O&M Costs $/kW-mo 0.83Software/Communication $/kW-mo 0.83

Total Incremental Costs $/kW-mo 7.09

ORTP $/kW-mo 7.09

31

Agenda

Summary

Methodology Updates

ORTP Results






Annual Updates

Appendix

32

Energy Efficiency ORTP

EE Program Specifications

We calculated costs and benefits for the following state programs, excluding Low Income programs

♦Benefits and costs of all programs are aggregated into a single “resource,” consistent with how states offer into the FCM

♦Program MW sizes are for summer peak conditions and grossed up for line losses

Vermont New Hampshire Maine Connecticut Massachusetts Rhode Island

Residential New Construction

ENERGY STAR Lighting Residential Lighting Residential Consumer Products

Resid'tl. New Constrct. & Renovations

Large Commercial New Construction

Residential Efficient Products

ENERGY STAR Homes Residential Appliances Residential New Construction

Residential Heating and Water Heating

Large Commercial Retrofit

Business New Construction

Home Energy Solutions Business Incentive Program

Home Energy Solutions Multifamily Retrofit Small Business Direct Install

Business Existing Facilities

ENERGY STAR Appliances

Large Customer C&I Lost Opportunity MassSAVE Single Family - Low Income Services

Residential Existing Homes

New Equipment & Construction

C&I Large Retrofit O Power Residential New Construction

Large C&I Retrofit C&I Small Business ENERGY STAR Lighting ENERGY STAR® HVAC

Small Business Energy Solutions

ENERGY STAR Appliances

EnergyWise

C&I New Constrct. & Major Renovations

ENERGY STAR® Lighting

C&I Large Retrofit ENERGY STAR® Appliances

C&I Small Retrofit

33


EE Program Costs and Benefits

EE program costs are computed using the 2012 budget from each state♦ Include customer costs to account for total costs to support energy

savings♦ Assume budgets will be spent during pre-power year

We considered both energy and avoided T&D investment as benefits♦ Avoided energy saving ($/MWh) is calculated based on historical load-

weighted average LMP adjusted by Mass Hub futures prices ♦ Projected load-weighted wholesale price in 2018/19 is $63/MWh♦ Avoided T&D savings is estimated at $36/kW-yr ($41/kW-yr in 2018/19)

based on Connecticut 2013 Conservation and Load Management Plan

34


EE ORTP Calculation (2018 $)

Installed Capacity MW 1 Qualified Capacity MW 1 Capital Costs (Installed) $/kW 2,571 ATWACC % 7.2%Annual Energy Savings MWh 4,212Energy Benefit $/MWh 62.63Avoided T&D Costs $/kW-yr 40.55


Revenue Offsets $/kW-mo 25.37Energy Savings $/kW-mo 21.99T&D Savings $/kW-mo 3.38

Net CONE $/kW-mo -0.98

ORTP $/kW-mo 0.00

35

Agenda

Summary

Methodology Updates

ORTP Results






Annual Updates

Appendix

36

Annual Updates

Annual Updates of ORTP Values

ORTPs for FCA10 and FCA11 will be updated in 2014 and 2015 using escalation factors calculated from indices for each line item of capital and fixed O&M cost

♦ Indices specific to each capital cost line item have been selected based on applicability and availability (see below)

♦ E&AS margins and RECs will be updated based on futures prices available at the time

♦ Futures updates will require inserting new values for each index and model will escalate each line item accordingly

Cost Component Index

Gas Turbines BLS - PPI "Turbines and Turbine Generator Sets"Steam Turbines BLS - PPI "Turbines and Turbine Generator Sets"Wind Turbines Bloomberg Wind Turbine Price IndexOther Equipment BLS - PPI "General Purpose Machinery and Equipment"Construction Labor Composite index developed from RS Means labor categoriesOther Labor Composite index developed from BLS job classificationsMaterials BLS - PPI "Materials and Components for Construction"Electric Interconnection BLS-PPI "Electric Power Distribution."Gas Interconnection BLS-PPI "Oil and Gas Field Equipment and Machinery."

37

Agenda

Summary

Methodology Updates

ORTP Results






Annual Updates

Appendix

38

Sensitivity Analysis

Cost of Capital Sensitivities

♦ Limited sensitivity to range of ATWACC values♦ Wind is most sensitive due to its highest capital cost per kW

of qualified capacity

ORTP ($/kW-mo)

NRG Average CalpineATWACC 6.9% 7.0% 7.1% 7.2% 7.3% 7.4% 7.5%

CT $12.88 $13.01 $13.12 $13.26 $13.38 $13.49 $13.65

CC $8.43 $8.55 $8.68 $8.75 $8.85 $8.94 $9.04

Wind $6.47 $7.82 $9.19 $9.87 $10.91 $11.95 $12.99

39

Methodology

Generation Costs

Sargent & Lundy developed bottom-up estimates for capital and fixed O&M costs for selected technologies

Assume a competitive entrant at an unencumbered site♦ No electric transmission line or gas lateral costs (nor network

upgrades, but need direct interconnection costs include breakers and substation expansion)

♦ No site-specific challenges or unusual environmental requirements

♦ Contingencies and owner’s development cost at the lower end of the range Sargent & Lundy has seen

Escalate 2013 installation to a 2018 online year (in 2018 $s)

40

Methodology

CONE Calculations

The Cost of New Entry (“CONE”) is the net revenue a new resource would need in Year 1 to be willing to enter the market, such that the NPV of all cash flows (over 20 years) is zero

A key driver of CONE is whether total net revenues are likely to increase over time (such that lower first year revenues are acceptable) or decrease (such that higher first-year revenues are necessary)

♦ Long-term revenues will be determined by future prices (energy + capacity + other) which, all-in, must equal CONE of future entrants to support investment

♦ Hence, projected cost trends determine revenue trajectories for current entrants

♦ Need to consider different non-capacity net revenues between current and future entrants

Revenue trajectories may vary by technology♦ Assume total revenues for current gas entrants will be approximately constant in real

terms over time because future entrants are likely to enter at a higher CONE (turbine prices have historically increased slightly faster than inflation) but out-compete current entrants slightly on efficiency

♦ We assume total revenues for renewables will also stay approximately constant as future entrants enjoy more efficient technology but must locate at inferior or more remote sites

41

Methodology

Revenue Offsets and Net CONE

First year revenues must equal CONE, with revenues coming from several sources, including capacity, energy and ancillary services margins (EAS), RECs if applicable, and performance incentives (PI)

“Net CONE” is the 1st year revenue a new resource would need specifically from capacity to be willing to enter the market

♦ Net CONE = CONE – 1st Year Non-Capacity Revenue Offsets

♦ ORTP is Net CONE of a competitive entrant for each technology

ISO-NE Offer Review Trigger Price 2013 Update – Draft Results Presented to:

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