2016 economic studies – part ii natural gas system

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D E C E M B E R 1 4 , 2 0 1 6 | W E S T B O R O U G H , M A

Mark Babula System Planning – Resource Adequacy

Planning Advisory Committee Meeting Agenda Item 6.0 (Revised-05/18/17)

2016 Economic Studies – Part II Natural Gas System Capacity & Energy Analysis – Methodology & Assumptions

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Table of Contents

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• Goals and Today’s Objectives • Metrics • Methodology to Quantify Unserved Capacity and Energy

- Capacity Analysis Process Flow - Energy Analysis Process Flow

• The Reason to Model Six Natural Gas Topologies • Natural Gas Capacity Analysis • Natural Gas Energy Analysis • Next Steps & Schedule • Q & A • Appendix 1 – Definition of Terms and Equations • Appendix 2 – Gas-Fired Generation by Pipeline & LNG/LDC • Appendix 3 – Maps of Northeastern Natural Gas Pipelines and Regional

LNG Import Terminals

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Conversion Rates

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• Natural gas is measured by volume or heating value. The standard measure of heating value in the English system of units is millions of British thermal units or “MMBtu.” Dekatherms (Dth) are also a standard unit of measurement within the natural gas industry. One million Btus equals one Dekatherm (1 MMBtu = 1 Dth).

• The standard measure of gas volume in the English system of units is standard cubic feet or “scf.” The “s” for standard is typically omitted in expressing gas volume in cubic feet. Therefore “scf” is typically short formed to “cf.” Because the heating value of natural gas is not uniform across production areas, there is no one fixed conversion rate between gas volume and heating value. Pipeline gas in North America usually has a heating value reasonably close to 1,000 Btu/cf. Therefore, for discussion purposes, one thousand cubic feet (Mcf) is roughly equivalent to one million Btu (MMBtu).

1 Mcf ≈ 1 MMBtu = 1 Dth 1 Bcf = 1,000 MMcf ≈ 106MMBtu = 106 Dth

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NATURAL GAS SYSTEM CAPACITY AND ENERGY ANALYSIS – METHODOLOGY & ASSUMPTIONS Natural Gas System Capacity and Energy Analysis

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Goals: Identify the natural gas system’s capability to meet the installed capacity and energy requirements of natural gas-fired generation in the various Scenarios within the 2016 Economic Studies And Today’s Objectives: Review the methodology and assumptions used for the natural gas system capacity and energy analysis

2016 Economic Study (NEPOOL Scenario Analysis) Natural Gas System Capacity and Energy Analysis

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METRICS Natural Gas System Capacity and Energy Analysis

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Metrics Assumptions

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• Local (Gas) Distribution Company (LDC) natural gas demand – Met by firm supply and firm pipeline transportation, augmented by

satellite LNG and propane-air facilities – Prohibited by their state Tariffs to sell their gas to power generators

• Power generation natural gas demand – Met through non-firm (interruptible) supply and pipeline contracts – Subordinate entitlements compared to gas LDCs

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Two Metrics

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• Using the 2016 Economic Study results quantify the following two metrics for both the constrained and unconstrained electric transmission cases: 1. Natural gas pipeline capacity analysis to meet 2016 Economic Study, installed gas-fired capacity requirements

– Identify served and unserved gas-fired capacity amounts

2. Natural gas pipeline energy analysis to meet 2016 Economic Study power generation (fuel) requirements

– Power generation gas demands by individual pipeline and integrated gas-system

– Served and unserved gas-fired energy amounts – Frequency of unserved energy amounts


METHODOLOGY TO QUANTIFY UNSERVED CAPACITY AND ENERGY Natural Gas System Capacity and Energy Analysis

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Unserved Generation - Background

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• If total New England gas demand, from both gas utilities and power generation, is greater than the capacity of the future gas-grid, there will be unserved gas-fired generation

• For this analysis, unserved gas-fired generation results in the electric system operating at higher costs due to the need for mitigation measures to ensure system reliability. It is not synonymous with curtailment of firm electric service

• All gas to electrical equivalents are calculated at an assumed future, average fleet heat-rate of 7,000 Btu/kWhr


CAPACITY ANALYSIS PROCESS FLOW Natural Gas System Capacity and Energy Analysis

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Capacity Analysis Process Flow

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For winter & summer: • Identify installed gas-fired capacity

• Determine future gas-system capacity under six gas topology cases - Subtract future, firm gas LDC demands from gas-system capacity - Determine gas-system capacity surplus/deficiency and convert into an electrical

capacity equivalent

• Compare minimum and maximum installed capacity against electrical capacity equivalent under six gas topology cases

• Identify installed gas-fired capacity surplus(served)/deficiencies(unserved)

REVISED


ENERGY ANALYSIS PROCESS FLOW Natural Gas System Capacity and Energy Analysis

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Energy Analysis Process Flow

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For winter & summer: • Identify gas-fired unit energy (fuel) requirements

• Compile gas-fired energy demands by individual pipeline and integrated gas-system

• Determine future gas-system energy capability under six gas topology cases - Subtract future, firm gas LDC demands from gas-system capacity - Determine gas-system capacity surplus/deficiency and convert into an electrical energy equivalent

• Compare minimum and maximum energy demands against energy equivalent under six gas topology cases

• Identify gas-fired energy surplus(served)/deficiencies(unserved) • Determine the frequency of unserved energy amounts

REVISED


THE REASON TO MODEL SIX NATURAL GAS TOPOLOGIES Natural Gas System Capacity and Energy Analysis

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The Reason to Model Six Natural Gas Topologies

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• The most important variables to determine “unserved generation” is the amount of pipeline capacity and energy available for power generation

• Six gas-system topology cases will be developed to bookend this analysis, to determine the range of pipeline capacity and energy available for power generation – The six gas-system topology cases encompass the various combinations of

capacity/supply options regarding pipelines, LNG supplies, LDC peak-shaving, expansion projects, and LDC demand

REVISED

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Six Building Blocks of the Natural Gas System

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Pipelines

Peak-Shaving

Growth Distrigas

Pipeline Projects

FSRU*

* - Floating Storage & Regasification Unit (FSRU) – Excelerate Energy’s Buoy System

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Six Gas-System Topology Cases

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Gas Infrastructure

Gas Topology Case #1 *

Gas Topology Case #2





Existing Pipelines XXX XXX XXX XXX XXX XXX

Existing LDC Peak Shaving XXX XXX XXX XXX XXX XXX

Pipeline Projects XXX XXX XXX XXX XXX XXX

LDC Peak Shaving Growth

XXX

XXX XXX XXX XXX

Pipeline Growth XXX XXX XXX XXX

Distrigas XXX XXX

FSRU XXX XXX (*) This is the first case in which the gas-system assumptions provide adequate winter capacity to serve all regional LDC core-gas demands in 2025 and 2030.

REVISED

ISO-NE PUBLIC

Total Gas System Capacity under Six Gas-System Topology Cases

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Total Gas System Capacity

Gas Topology Case #1 (Bcf/d)






2025 Winter 5.600 5.674 6.053 6.353 6.453 6.753

2025 Summer 4.747 4.747 5.126 5.426 5.526 5.826

2030 Winter 5.600 5.705 6.224 6.524 6.624 6.924

2030 Summer 4.747 4.747 5.226 5.566 5.666 5.966

NEW SLIDE


NATURAL GAS PIPELINE CAPACITY ANALYSIS Natural Gas System Capacity and Energy Analysis

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IDENTIFY INSTALLED GAS-FIRED CAPACITY Natural Gas System Capacity and Energy Analysis

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2025 Scenarios – Installed Gas-Fired Capacity

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• 2025 Scenarios - Constrained and unconstrained electric transmission system

SCENARIO TOTAL GAS-FIRED CAPACITY (MW)

TOTAL GAS_ONLY CAPACITY (MW)

TOTAL DUAL_FUEL CAPACITY (MW)

2025_S1 & 2025_S1_UN 16,847 9,446 7,401

2025_S2 & 2025_S2_UN 16,190 8,789 7,401

2025_S3 & 2025_S3_UN 16,190 8,789 7,401

2025_S4 & 2025_S4_UN 16,297 8,789 7,508

2025_S5 & 2025_S5_UN 17,335 9,934 7,401

2025_S6 & 2025_S6_UN 16,190 8,789 7,401

Gas-only & dual-fuel capacity totals do not include 1,500 MW of Mystic 8 & 9 on LNG and 16 MW of gas-fired generation located behind the LDC citygates: Totaling 1,516 MW

REVISED

ISO-NE PUBLIC

2030 Scenarios – Installed Gas-Fired Capacity

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• 2030 Scenarios - Constrained and unconstrained electric transmission system

SCENARIO TOTAL GAS-FIRED CAPACITY (MW)

TOTAL GAS_ONLY CAPACITY (MW)

TOTAL DUAL_FUEL CAPACITY (MW)

2030_S1 & 2030_S1_UN 19,770 12,369 7,401

2030_S2 & 2030_S2_UN 15,625 8,224 7,401

2030_S3 & 2030_S3_UN 15,625 8,224 7,401

2030_S4 & 2030_S4_UN 16,297 8,789 7,508

2030_S5 & 2030_S5_UN 20,458 13,057 7,401

2030_S6 & 2030_S6_UN 15,625 8,224 7,401

Gas-only & dual-fuel capacity totals do not include 1,500 MW of Mystic 8 & 9 on LNG and 16 MW of gas-fired generation located behind the LDC citygates: Totaling 1,516 MW

REVISED

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Determining Installed Gas-Fired Capacity

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• Winter & Summer – Gas-fired capacity consists of both installed gas-only and dual-

fuel capacity – Maximum gas-only capacity is 13,057 MW (2030_S5 case) – Maximum dual-fuel capacity is 7,508 MW (S4 case in 2025 & 2030) – Maximum gas-fired capacity is 20,458 MW (2030_S5 case)

– Minimum gas-only capacity is 8,224 MW (S2, S3, S6 cases in 2030) – Minimum dual-fuel capacity is 7,401 MW (S1, S2, S3, S5 and S6 cases in

2025 & 2030) – Minimum gas-fired capacity is 15,625 MW (S2, S3 and S6 cases in 2030)

REVISED


EXISTING PIPELINE CAPACITY Natural Gas System Capacity and Energy Analysis

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Existing Pipeline Capacity

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• Regional pipeline capacities were derived by ICF Consulting – Capacities reflect current shipper’s contracts into, through, and out of

New England – Capacities may not reflect the overall physical capability of each pipeline

• Algonquin Pipeline = 1.782 Bcf/d = 1.440 Bcf/d of New England Contract Capacity plus 0.342 Bcf/d of AIM Project Capacity (10,607 MW/d or 245,571 MWhr)

• Iroquois Pipeline = 0.260 Bcf/d = Connecticut-Only Contracts (1,548 MW/d or 37,143 MWhr)

• M & N Pipeline = 0.833 Bcf/d = Capacity at Westbrook, ME (4,958 MW/d or 119,000 MWhr)

• PNGTS = 0.190 Bcf/d = New England Contracts (1,131 MW/d or 27,143 MWhr) • Tennessee Pipeline = 1.320 Bcf/d = New England Contracts (7,857 MW/d or

188,571 MWhr)


PIPELINE PROJECTS Natural Gas System Capacity and Energy Analysis

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Pipeline Projects

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• ICF’s forecast of near-term gas infrastructure projects that are scheduled to materialize between 2016 ~ 2017/18 are shown below:

These values are in billion cubic feet per or (Bcf/day or Bcf/d)

Pipeline System Existing Capacity Expansions Total

Capacity

Algonquin Gas Transmission (AGT) 1.44 AIM: 0.34 Atlantic Bridge: 0.13 1.91

Iroquois Gas Transmission (IGT) 0.26 0.26

Tennessee Gas Pipeline (TGP) 1.32 Connecticut: 0.07 1.39

Portland Natural Gas Transmission (PNGTS) 0.19 C2C: 0.11 0.30

Maritimes and Northeast Pipeline (M&N) 0.83 0.83

Total In-Bound Contracted Capacity 4.04 0.65 4.69

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Pipeline Projects – cont’d

Project Name

Company Route Planned

In-Service Date

Capacity (Bcf/d)

Status ICF’s

Handicapping

AIM Project Spectra New Jersey to Massachusetts Nov-2016 0.342 Under Construction

Likely Online by Nov-2016

Connecticut Expansion

Tennessee Gas

Wright, NY (Albany County) to Hartford County, CT Nov-2016 0.072 Under

Construction Delayed, but Likely Online by Nov-2017

Atlantic Bridge

Algonquin & M&N

New Jersey to New England and Maritimes Canada Nov-2017 0.133 FERC Filed Likely

Online by Nov-2017

Continent to Coast (C2C)

PNGTS Canada markets via Pittsburg, NH,

to the Maritimes and Northeast Pipeline at Westbrook, ME

Nov-2017 0.110* Announced Likely

New contracts active 2017/18

* The C2C capacity expansion will increase firm contracts on PNGTS from 0.190 Bcf/d to approximately 0.300 Bcf/d; however, historically PNGTS already flows at rates up to 0.300 Bcf/d on a non-firm basis.

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Pipeline Projects – cont’d

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• Algonquin Pipeline = 1.912 Bcf/d = 1.440 Bcf/d of New England Contract Capacity plus 0.342 Bcf/d of AIM Project Capacity plus 0.130 Bcf/d of Atlantic Bridge Project Capacity (electric equivalent of 11,381 MW/d or 273,143 MWhr)

• Iroquois Pipeline = 0.260 Bcf/d = Connecticut-Only Contracts (1,548 MW/d or 37,143 MWhr)

• Tennessee Pipeline = 1.392 Bcf/d = 1.32 New England Contracts plus 0.072 Bcf/d CT Expansion Project Capacity (8,286 MW/d or 198,857 MWhr)

• PNGTS = 0.300 Bcf/d = 0.190 New England Contracts plus 0.110 Bcf/d of the C2C Expansion Project (1,786 MW/d or 42,857 MWhr)

• M & N Pipeline* = 0.833 Bcf/d = Capacity at Westbrook, ME. (4,958 MW/d or 119,000 MWhr)

(*) – ISO assumed that only pipelines that could directly connect with Marcellus/Utica gas supplies were expanded to 2025 and 2030.

REORDERED & REVISED SLIDE


FUTURE PIPELINE CAPACITY Natural Gas System Capacity and Energy Analysis

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Future Pipeline Capacity Expansion Assumptions

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• ISO-NE used growth rates of regional LDC demands to “expand” the pipeline (contract) capacity into/thru New England

• ICF’s LDC demand growth between 2018 and 2025 is ~ 9.80% – 2018 pipelines were expanded to 4.826 Bcf/day by 2025

• ICF’s LDC demand growth between 2025 and 2030 is ~ 3.31% – 2025 pipelines were expanded to 4.966 Bcf/day by 2030

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Future Pipeline Capacity - cont’d

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• Future pipeline capacity

Future Pipeline Capacity

Pipe Capacity 2018/19 2025 2030 UNITS

AGT Capacity 1.912 2.099 2.169 Bcf/d

IGTS Capacity 0.260 0.285 0.295 Bcf/d

TGP Capacity 1.392 1.528 1.579 Bcf/d

PNGTS Capacity 0.300 0.329 0.340 Bcf/d

M&N Capacity 0.833 0.833 0.833 Bcf/d

Total Pipes Capacity Winter 4.697 5.074 5.216 Bcf/d

Total Pipes Capacity Summer 4.697 5.074 5.216 Bcf/d

REVISED


EXISTING LDC PEAK SHAVING CAPACITY Natural Gas System Capacity and Energy Analysis

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Existing LDC Peak Shaving Capacity Assumptions

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• The Northeast Gas Association’s – 2016 Statistical Guide shows • LDC peak shaving vaporization equals 1.40 Bcf/d • 43 regional satellite tanks (LNG & propane-air) located in five states • Total LDC’s peak shaving storage capacity equals 16.0 Bcf

• ISO-NE assumes all propane air (0.121 Bcf/d) will be phased out by the year 2025 • Leaving only LNG-based vaporization at ~1.279 Bcf/day

• ISO-NE assumes LNG peak shaving has a delivery rate of ~66% • Resulting in a LDC peak-day contribution of ~0.853 Bcf/d.

REVISED


FUTURE LDC PEAK SHAVING CAPACITY Natural Gas System Capacity and Energy Analysis

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Future LDC Peak Shaving Capacity Assumptions

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• ICF’s LDC demand growth between 2018 and 2025 is ~ 9.80% – 2018 LDC peak shaving capacity is expanded to 0.937 Bcf/day by 2025

• ICF’s LDC demand growth between 2025 and 2030 is ~ 3.31% – 2025 LDC peak shaving capacity is expanded to 0.966 Bcf/day by 2030

• ISO-NE assumes the LDC’s peak shaving capacity is unavailable during spring, summer, and fall

REVISED


LNG SUPPLIES Natural Gas System Capacity and Energy Analysis

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Canaport LNG Import Terminal

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• Canaport LNG terminal is located in Saint John, NB (est. 2009)

• Storage capability is ~10.0 Bcf

• Maximum send out capacity of ~1.19 Bcf/d into the Brunswick pipeline

• ISO-NE assumes ~1.19 Bcf/d of Canaport supply into the M&N Pipeline at St. Stephen, New Brunswick

– M&N Winter Capacity at Westbrook, ME = ~0.833 Bcf/d (1.19 – 0.250 Bcf/d Maritimes Winter Demand)

– M&N Summer Capacity at Westbrook, ME = ~0.833 Bcf/d (1.19 – 0.150 Bcf/d Maritimes Summer Demand)

REVISED

ISO-NE PUBLIC

Distrigas LNG Import Terminal

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• Distrigas LNG Terminal is located in Everett, MA (est. 1971)

• Storage capability is ~3.4 Bcf

• Maximum send out capacity of ~0.750 Bcf/d into: ~ 0.150 Bcf/d into the Algonquin Pipeline (HP) ~ 0.150 Bcf/d into the Tennessee Pipeline (MP) ~ 0.135 Bcf/d into National Grid LDC (LP) ~ 1 million gallons/day (100 MMcf/d) if Liquids via Trucking ~ 0.300 Bcf/d into Mystic #8 and #9

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Floating Storage & Regasification Units (FSRU)

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• Excelerate Energy’s FSRU buoy-system located off Gloucester, MA (est. 2008)

• Storage capability is based on FSRU tanker size

• Maximum sustainable send-out capacity of ~0.400 Bcf/d into Spectra’s Hubline system

• Excelerate has operated during the last two winters

REVISED


MISCELLANEOUS GAS ASSUMPTIONS Natural Gas System Capacity and Energy Analysis

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Loss of North Atlantic Offshore Production

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• Potential loss of regional natural gas supplies must also be accounted for in the overall supply/demand balance: – ISO-NE assumes the loss of all North-Atlantic offshore natural gas

production at Sable Island’s Offshore Energy Project and Deep Panuke. • During winter 2015/16

– SOEP production averaged ~140 MMcf/d – Deep Panuke production averaged ~82 MMcf/d.

– By 2025, all offshore supply is assumed to be retired and their transportation capacity on the M&N pipeline is picked up by Canaport.

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Maritime’s Natural Gas Demands

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• By 2025, ISO-NE assumes that Canaport will have to supply all Maritimes gas demands (core & power sector) due to loss of North-Atlantic offshore production

• Maritime’s winter gas demands of ~0.250 Bcf/day

• Maritime’s summer gas demands of ~0.150 Bcf/d


NEW ENGLAND GAS LDC DEMANDS Natural Gas System Capacity and Energy Analysis

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New England Gas LDC Demands

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• ICF Consulting supplied the forecast of New England’s gas utility demands from 2016 through 2030 – The gas utility sector includes all residential, commercial, industrial, and

transportation end-users.

• Regional gas utility demands total 23 gas companies & includes: – Annual demand, in billions of cubic feet (Bcf/yr) per year. – Peak winter day (design-day) demand in 1,000 Dth per day (Dth/d). – Peak summer day demand in 1,000 Dth per day (Dth/d).

• ICF forecasts aggregate* gas utility demands to total: – 5.378 Bcf/d in winter 2025 peak design-day (Jan) – 5.556 Bcf/d in winter 2030 peak design-day (Jan) – 0.861 Bcf/d in summer 2025 peak day (Jul) – 0.914 Bcf/d in summer 2030 peak day (Jul) * Does not include the gas demands for the Vermont Gas System which is isolated from the interconnected gas system within the other five New England states.

REVISED

ISO-NE PUBLIC

New England Gas LDC Demands – cont’d

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LDC Demands 2018 2025 2030 Units

Winter Design-Day LDC Demand (January)

4.898 5.378 5.556 Bcf/d

Summer Peak-Day LDC Demand (July)

0.696 0.861 0.914 Bcf/d

REVISED

ISO-NE PUBLIC

New England Monthly Peak-Day Gas LDC Demands

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Aggregate LDC Loads Aggregate LDC Loads

New England System 2025 Monthly Peak-Day Demand

2030 Monthly Peak-Day Demand

January 5,378,000 5,556,000

February 5,039,602 5,155,032

March 4,867,894 4,998,462

April 2,310,792 2,383,257

May 1,380,072 1,429,969

June 1,004,428 1,046,514

July 861,400 913,572

August 867,953 922,088

September 977,673 1,016,696

October 1,368,194 1,418,886

November 2,067,631 2,141,426

December 3,600,838 3,721,111

REVISED

ISO-NE PUBLIC

New England LDC Gas Demands – Miscellaneous Assumptions

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• Peak gas utility and peak power generation gas demands may or may not be coincident.

• New England’s gas utility demands were assumed to occur: – January – Winter peak design-day demands could occur anytime within

this winter month – July – Summer peak day demands could occur anytime within this

summer month – These assumptions use a seasonal peak load exposure approach,

similar to those used within the ISO-NE’s Operable Capacity Analyses publications.

REVISED


DETERMINE GAS-SYSTEM CAPACITY SURPLUS/DEFICIENCY AND CONVERT TO ELECTRICAL EQUIVALENT Natural Gas System Capacity and Energy Analysis

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How Much Capacity and Energy Can 1 Billion Cubic Feet/Day (Bcf/d) of Natural Gas Fuel?

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• Assume a future, average fleet heat-rate of 7,000 Btu/kWhr

• Determine the 24 hour Capacity (MW) and Energy (MWhr) equivalent of 1.0 Bcf/d of natural gas:

((1.0 Bcf/day) / 24 hr /day) / 7,000 Btu/kWhr

((1.0 X 1012 Btu/day) / 24 hr/day) / 7,000 Btu/kWhr

41,667 X 106 Btu X 1 kWhr hr 7,000 Btu

41,667 X 106 = 41,667 X 103 kW 7,000 7

= 5,952,429 kW or 5,952 MW (Capacity) 5,952 MW * 24 hr = 142,858 MWhr (Energy)

REVISED


COMPARE MINIMUM AND MAXIMUM INSTALLED CAPACITY AGAINST ELECTRICAL EQUIVALENT Natural Gas System Capacity and Energy Analysis

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ISO-NE PUBLIC

Compare Minimum and Maximum Installed Gas-Fired Capacity

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• Winter & Summer – Gas-fired capacity consists of both installed gas-only and dual-

fuel capacity – Maximum gas-only capacity is 13,057 MW (2030_S5 case) – Maximum dual-fuel capacity is 7,508 MW (S4 case in 2025 & 2030) – Maximum gas-fired capacity is 20,458 MW (2030_S5 case)

– Minimum gas-only capacity is 8,224 MW (S2, S3, S6 cases in 2030) – Minimum dual-fuel capacity is 7,401 MW (S1, S2, S3, S5 and S6 cases in

2025 & 2030) – Minimum gas-fired capacity is 15,625 MW (S2, S3 and S6 cases in 2030)

REVISED

ISO-NE PUBLIC

Minimum/Maximum Amounts of Gas-System Capacity – Gas Topology Cases #1 / #6

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• Gas Topology Case #1 - Minimum amount of gas-system capacity available for power generation - Reflects Existing Gas Pipelines, Existing LDC Peak-Shaving & Pipeline

Projects

• Gas Topology Case #6 - Maximum amount of gas-system capacity available for power generation - Reflects Existing Pipelines, Existing LDC Peak-Shaving, Pipeline Expansion

Projects, LDC Peak-Shaving Growth, Pipeline Growth, Distrigas & FSRU

REVISED


IDENTIFY GAS-FIRED CAPACITY SURPLUS (SERVED) / DEFICIENCIES (UNSERVED) Natural Gas System Capacity and Energy Analysis

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ISO-NE PUBLIC

Compare Minimum/Maximum Installed Capacity Against Electrical Capacity Equivalent and Quantify Gas-Fired Capacity Surplus/Deficiencies – Sample Calculation

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2025 2030 Units Winter Gas-System Capacity 5.678 5.719 Bcf/day Winter LDC Demands 5.378 5.556 Bcf/day Winter Surplus 0.300 0.163 Bcf/day Electrical Equivalent 1,786 969 MW/day Minimum Gas-Only Capacity 8,789 8,789 MW Minimum Gas-Only Margin -7,003 -7,820 MW Maximum Gas-Only Capacity 13,623 13,623 MW Maximum Gas-Only Margin -11,837 -12,654 MW ------------------------------------------------------------------------------------------------------------------ Summer Gas-System Capacity 4.547 4.547 Bcf/day Summer LDC Demands 0.769 0.813 Bcf/day Summer Surplus 3.778 3.734 Bcf/day Electrical Equivalent 22,488 22,226 MW/day Minimum Gas-Capable Capacity 17,706 17,706 MW Minimum Gas-Capable Margin 4,782 4,520 MW Maximum Gas-Capable Capacity 22,540 22,540 MW Maximum Gas-Capable Margin -52 -314 MW

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Conduct the Natural Gas Pipeline Capacity Analysis

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• Run all 20 Scenarios through all Six Gas Topology Cases to determine the amounts of unserved gas-fired capacity

• The results & findings for all Gas Topology Cases, Case #1 through Case #6, will be presented


NATURAL GAS PIPELINE ENERGY ANALYSIS Natural Gas System Capacity and Energy Analysis

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2025 AND 2030 POWER GENERATION ENERGY DEMANDS Natural Gas System Capacity and Energy Analysis

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ISO-NE PUBLIC

2025 Power Generation Demands – Constrained Transmission System

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2025 Power Generation Demands – Constrained TX System

Electric Demands Units 2025_S1_UN 2025_S2_UN 2025_S3_UN 2025_S4_UN 2025_S5_UN 2025_S6_UN

Winter Peak

Demand

MW MWhr Bcf/d

8,429 202,286

1.416

8,113 194,714

1.363

5,708 137,000

0.959

7,875 189,000

1.323

8,435 202,429

1.417

8,054 193,286

1.353

Winter Minimum Demand

MW MWhr Bcf/d

2,381 57,143 0.400

2,214 53,143 0.372

375 9,000 0.063

2,690 64,457 0.452

3,071 73,714 0.516

1,429 34,286 0.241

Summer Peak

Demand

MW MWhr Bcf/d

13,750 330,000

2.310

13,214 317,143

2.220

8,714 209,143

1.464

13,577 325,857

2,281

14,077 337,857

2.365

12,292 295,000

2.065

Summer Minimum Demand

MW MWhr Bcf/d

2,524 60,571 0.424

2,214 53,143 0.372

185 4,429 0.031

2,798 67,143 0.470

2,601 62,429 0.437

1,357 32,571 0.228

REVISED

Natural gas volumes were converted to their electrical equivalents using a heat rate of 7,000 Btu/kWh

ISO-NE PUBLIC

2025 Power Generation Demands – Unconstrained Transmission System

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2025 Power Generation Demands – Unconstrained TX System


Winter Peak

Demand

MW MWhr Bcf/d

8,405 201,714

1.412

7,982 191,571

1.341

5,702 136,857

0.958

7,869 188,857

1.322

8,429 202,286

1.416

8,042 193,000

1.351


MW MWhr Bcf/d

1,893 45,429 0.318

1,173 28,143 0.197

119 2,857 0.020

2,548 61,143 0.428

3,036 72,857 0.510

1,417 34,000 0.238

Summer Peak

Demand

MW MWhr Bcf/d

13,637 327,286

2.291

12,964 311,143

2.178

8,542 205,000

1.435

13,577 325,875

2.281

14,071 337,714

2.364

12,113 290,714

2.035


MW MWhr Bcf/d

2,548 61,143 0.428

1,744 41,857 0.293

143 3,429 0.024

2,792 67,000 0.469

2,601 62,429 0.437

1,452 34,857 0.244

REVISED


ISO-NE PUBLIC

2030 Power Generation Demands – Constrained Transmission System

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2030 Power Generation Demands – Constrained TX System


Winter Peak

Demand

MW MWhr Bcf/d

9,054 217,286

1.521

7,405 177,714

1.244

4,667 112,000

0.784

8,530 204,714

1.433

9,375 225,000

1.575

6,304 151,286

1.059


MW MWhr Bcf/d

2,899 69,571 0.487

1,619 38,857 0.272

0 0 0

3,238 77,714 0.554

3,458 85,143 0.596

83 2,000 0.014

Summer Peak

Demand

MW MWhr Bcf/d

14,280 342,714

2.399

12,202 292,857

2.050

6,643 159,429

1.116

14,464 347,143

2.430

14,845 356,286

2.494

8,500 204,000

1.428


MW MWhr Bcf/d

2,375 57,000 0.399

1,036 24,857 0.174

0 0 0

3,137 75,286 0.527

3,310 79,429 0.556

0 0 0

REVISED


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2030 Power Generation Demands – Unconstrained Transmission System

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2030 Power Generation Demands – Unconstrained TX System


Winter Peak

Demand

MW MWhr Bcf/d

9,060 217,429

1.522

6,321 151,714

1.062

4,625 111,000

0.777

8,524 204,571

1.432

9,375 225,000

1.575

6,173 148,143

1.037


MW MWhr Bcf/d

1,500 36,000 0.252

0 0 0

0 0 0

3,315 79,571 0.557

3,494 83,857 0.587

0 0 0

Summer Peak

Demand

MW MWhr Bcf/d

13,976 335,429

2.348

10,935 262,429

1.837

6,530 156,714

1.097

14,464 347,143

2.430

14,845 356,286

2.494

8,230 197,714

1.384


MW MWhr Bcf/d

2,155 51,714 0.362

0 0 0

0 0 0

3,125 75,000 0.525

3,315 79,571 0.557

0 0 0

REVISED


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Minimum/Maximum Amounts of Gas-System Energy – Gas Topology Cases #1 / #6

64

• Gas Topology Case #1 - Minimum amount of gas-system energy available for power generation - Reflects Existing Gas Pipelines, Existing LDC Peak-Shaving, & Pipeline

Projects

• Gas Topology Case #6 - Maximum amount of gas-system energy available for power generation - Reflects Existing Pipelines, Existing LDC Peak-Shaving, Pipeline Expansion

Projects, LDC Peak-Shaving Growth, Pipeline Growth, Distrigas & FSRU


IDENTIFY GAS-FIRED ENERGY SURPLUS (SERVED) / DEFICIENCIES (UNSERVED) Natural Gas System Capacity and Energy Analysis

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ISO-NE PUBLIC

Identify Gas-Fired Energy Surplus (served) / Deficiencies (unserved)

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• Use the same process that was identified in the aforementioned (capacity) slides of 19 - 56

REVISED

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Compare Minimum/Maximum Energy Demands Against Electrical Energy Equivalent and Quantify Gas-Fired Energy Surplus/Deficiencies – Sample Winter Calculation

67

2025 2030 Units Winter Gas-System Capacity 5.678 5.719 Bcf/day Winter LDC Demands 5.378 5.556 Bcf/day Winter Surplus 0.300 0.163 Bcf/day Electrical Capacity Equivalent 1,786 969 MW/day Electrical Energy Equivalent 42,864 23,256 MWhr/day Electrical MMBTU Equivalent 300,000 163,000 MMBtu/d Maximum Gas-Only MMBtu Need 350,000 150,000 MMBtu/day Maximum Gas-Only MMBTU Margin -50,000 +13,000 MMBTU/day Electrical Energy Equivalent Margin -7,152 +1,848 MWhr/day Compile Winter Energy Deficiency = Sum(Winter Days) Sum (Winter Days) MWhr/Winter Compile Summer Energy Deficiency=Sum(SummerDays) Sum (SummerDays)MWhr/Summer Identify Frequency of Winter Energy Deficiencies Identify Frequency of Summer Energy Deficiencies

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Conduct the Natural Gas Pipeline Energy Analysis

68

• Run all 20 Scenarios through all Six Gas Topology Cases to determine the amounts and frequency of unserved gas-fired energy

• Results & findings for all Gas Topology Cases, Case #1 through Case #6, will be presented


NEXT STEPS & SCHEDULE Natural Gas System Capacity and Energy Analysis

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Next Steps and Schedule

• May 24-25, 2017: - Present the results and findings of the Natural Gas System Peak-Gas-

Day Capacity and Energy Analysis

70

REVISED

ISO-NE PUBLIC 71


APPENDICES Natural Gas System Capacity and Energy Analysis

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Appendices

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• Appendix 1 – Definition of Terms & Equations

• Appendix 2 – Gas-Fired Generation by Pipeline & LNG/LDC

• Appendix 3 – Map of Northeastern Natural Gas Pipelines and LNG Import Terminals


APPENDIX 1 DEFINITION OF TERMS & EQUATIONS Natural Gas System Capacity and Energy Analysis

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Definition of Terms

75

• Receipt Point –The point on a gas pipeline's system at which gas volumes (supply) are injected into the pipeline.

• Delivery Point - The point on a gas pipeline's system at which it delivers gas volumes (supply) that have been transported.

• A good glossary of terms for the natural gas sector can be found at: http://www.spectraenergy.com/Natural-Gas-Oil-101/Glossary-of-Energy-Terms/A/

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How Much Capacity and Energy Can 1 Billion Cubic Feet/Day (Bcf/d) of Natural Gas Fuel?

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• Assume a future, average fleet heat-rate of 7,000 Btu/kWhr

• Determine the 24 hour Capacity (MW) and Energy (MWhr) equivalent of 1.0 Bcf/d of natural gas:

((1.0 Bcf/day) / 24 hr /day) / 7,000 Btu/kWhr

((1.0 X 1012 Btu/day) / 24 hr/day) / 7,000 Btu/kWhr

41,667 X 106 Btu X 1 kWhr hr 7,000 Btu

41,667 X 106 = 41,667 X 103 kW 7,000 7

= 5,952,429 kW or 5,952 MW (Capacity) 5,952 MW * 24 hr = 142,858 MWhr (Energy)

REVISED


APPENDIX 2 GAS-FIRED GENERATION BY PIPELINE & LNG/LDC Natural Gas System Capacity and Energy Analysis

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ISO-NE PUBLIC

2025 Scenarios – Gas-Fired Generation by Pipeline & LNG/LDC

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The Algonquin Gas Transmission (AGT) System is the most utilized pipeline:

1. Algonquin Gas Transmission System (AGT) has between 42-45 gas-fired generators totaling between 8,004 MW – 8,611 MW.

2. Iroquois Gas Transmission System (IGTS) has between 5-6 gas-fired generators totaling between 1,553 MW – 1,837 MW.

3. Maritimes & Northeast Pipeline (M&N) has between 6-10 gas-fired generators totaling between 1,786 – 1,922 MW.

4. Tennessee Gas Pipeline (TGP) has between 20-22 gas-fired generators totaling between 4,413 MW – 4,646 MW.

5. Portland Natural Gas Transmission System (PNGT) has 4 generators totaling 435 MW.

6. Distrigas LNG has 2 units totaling 1,500 MW

7. Regional LDCs have 4 units totaling 16 MW

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2030 Scenarios – Gas-Fired Generation by Pipeline & LNG/LDC

79

The Algonquin Gas Transmission (AGT) System is the most utilized pipeline:

1. Algonquin Gas Transmission System (AGT) has between 42-49 gas-fired generators totaling between 8,004 MW – 10,905 MW.

2. Iroquois Gas Transmission System (IGTS) has between 5-6 gas-fired generators totaling between 1,553 MW – 1,884 MW.

3. Maritimes & Northeast Pipeline (M&N) has between 6-10 gas-fired generators totaling between 1,786 – 2,925 MW.

4. Tennessee Gas Pipeline (TGP) has between 20-22 gas-fired generators totaling between 4,413 MW – 4,874 MW.

5. Portland Natural Gas Transmission System (PNGT) has 4 generators totaling 435 MW.

6. Distrigas LNG has 2 units totaling 1,500 MW.

7. Regional LDCs have 4 units totaling 16 MW.

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Gas-Fired Generation on Algonquin Pipeline

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UNIT NAME CAPACITY (MW) ADD_S5_2030_Canal1 474 ADD_S5_2030_Canal2 472 ADD_S5_2-030_MidTown 304 ADD_S5_2030_MidTown4 347 ADD_S5_2030_Montvil 421 ADD_S5_2030_Mystic7 494 ADD_S5_2030_NHH1 388 ANP-BELLINGHAM 1_1 260 ANP-BELLINGHAM 2_2 260 BROCKTON_GT_C1 0 CLEARY 9/9A CC_S9 110 DARTMOUTH CT GENE_C3 21 DARTMOUTH POWER_C1 68 DIGHTON POWER LLC_1 177 EDIT_QP384_CPVTowcC1 775 EDIT_QP387_FootprtC1 674 EDIT_QP440_WallinrG6 50 EDIT_QP440_WallinrG7 50 EDIT_QP444_MedwayIG1 104 EDIT_QP444_MedwayIG2 104 EDIT_QP449_Canal3 333 FORE RIVER 11_S1 417 FORE RIVER 12_C2 410 KENDALL CT_4 168

UNIT NAME CAPACITY (MW) KENDALL STEAM 1_1 17 KENDALL STEAM 2_2 21 KENDALL STEAM 3_3 26 KLEEN ENERGY_C1 620 LAKE ROAD 1_1 260 LAKE ROAD 2_2 260 LAKE ROAD 3_3 260 MANCHESTER 10/10A_10 165 MANCHESTER 11/11A_11 165 MANCHESTER 9/9A CC_9 165 MATEP (COMBINED C_C1 50 MILFORD POWER_C1 170 MYSTIC 7_7 565 NEA BELLINGHAM_C1 340 PIERCE STATION_1 97 POTTER 2 CC_C2 97 THOMAS A. WATSON 1_1 57 THOMAS A. WATSON 2_2 57 TIVERTON POWER_C1 280 WALLINGFORD UNIT 1_1 49 WALLINGFORD UNIT 2_2 52 WALLINGFORD UNIT 3_3 48 WALLINGFORD UNIT 4_4 49 WALLINGFORD UNIT 5_5 54 WATERBURY GENERATY_1 100

TOTAL (MW) 10,905

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Gas-Fired Generation on Iroquois Pipeline

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UNIT NAME CAPACITY (MW) ADD_S5_2030_BrdgHrb3 332 BRIDGEPORT ENERGY_10 527 EDIT_QP412_BH6_CT 484 KIMB ROCKY RIVER _C1 22 MILFORD POWER 1_1 260 MILFORD POWER 2_2 260

TOTAL (MW) 1,884

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Gas-Fired Generation on M&N Pipeline

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UNIT NAME CAPACITY (MW) ADD_S5_2030_Newngtn 347 ADD_S5_2030_Schiller 83 ADD_S5_2030_Yarmth 187 ADD_S5_2030_Yarmth4 522 BUCKSPORT ENERGY 4_4 183 EP NEWINGTON ENER_C1 520 MAINE INDEPENDENC_C1 269 MAINE INDEPENDENC_C2 269 WESTBROOK ENERGY _C1 272 WESTBROOK ENERGY _C2 272

TOTAL (MW) 2,925

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Gas-Fired Generation on PNGTS Pipeline

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UNIT NAME CAPACITY (MW) RUMFORD POWER_C1 270 VERSO COGEN 1_1 54 VERSO COGEN 2_2 56 VERSO COGEN 3_3 55

TOTAL (MW) 435

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Gas-Fired Generation on Tennessee Pipeline

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UNIT NAME CAPACITY (MW) ADD_S5_2030_Mermack 380 ADD_S5_2030_WSprng 82 ALTRESCO_C1 173 ANP-BLACKSTONE EN1_1 260 ANP-BLACKSTONE EN2_2 260 BERKSHIRE POWER_1 246 CDECCA_C1 58 DEXTER 1_1 47 DEXTER 2_2 16 EDIT_QP489_BurilvC1 489 GRANITE RIDGE ENE_S1 763 LENERGIA ENERGY C_C1 77 MASS POWER_C1 264 MILLENNIUM_C1 375 OCEAN ST PWR GT1/_C1 289 OCEAN ST PWR GT3/_C3 287 PAWTUCKET POWER_C1 68 RISEP_C1 582 WATERS RIVER JET 1_1 20 WATERS RIVER JET 2_2 45 WEST SPRINGFIELD 1_1 47 WEST SPRINGFIELD 2_2 47

TOTAL (MW) 4,874

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Gas-Fired Generation Fueled by Distrigas

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UNIT NAME CAPACITY (MW) MYSTIC 8_8A 750 MYSTIC 9_9A 750

TOTAL (MW) 1,500

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Gas-Fired Generation Behind Gas LDC City Gates

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UNIT NAME CAPACITY (MW) ADD_IC_NG_WMA 0 ADD_ST_NG_RI 0 FRAMINGHAM JET 1_J1 11 NECCO COGENERATIOY_1 5

TOTAL (MW) 16


APPENDIX 3 MAP OF NORTHEASTERN NATURAL GAS PIPELINES AND REGIONAL LNG IMPORT TERMINALS Natural Gas System Capacity and Energy Analysis

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Map of Northeastern Natural Gas Pipelines and LNG Import Terminals

88 Source = Northeast Gas Association

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Map of Algonquin Pipeline

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Map of Tennessee Pipeline

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Source = Kinder Morgan/TGP

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Map of PNGTS Pipeline

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Source = PNGTS

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Map of M&N Pipeline

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Source = Spectra Energy

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Map of Iroquois Pipeline

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Source = IGTS

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Map of Distrigas LNG Terminal

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Source = Engie

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Map of Canaport LNG Terminal

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Source = Repsol


END OF PRESENTATION Natural Gas System Capacity and Energy Analysis

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2016 economic studies – part ii natural gas system

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