Steady-State Analysis of New England’s Interstate Pipeline Delivery Capability

Levitan & Associates, Inc.www.levitan.com

Presentation to the NEPOOL Participants Committee

January 5th, 2001

January 5, 20012

Levitan & Associates, Inc. (LAI) Practice Areas

Energy Markets Simulation and Optimization Modeling

Merchant Generation Economics

Pipeline Transportation Management

Fuel Supply Procurement

Power System Engineering/Heat Balance Optimization

ISO Interconnection Policy and Pricing

NUG Contract Administration (Reformation and Buyouts)

Environmental Compliance Strategy

Litigation Support

January 5, 20013

Steady-State Analysis of New England’s Interstate Pipeline Delivery Capability

What the Study Is & Is Not

Individual & Consolidated Models

Steady-State Perspective

No Temporal & Force Majeure

Market Dynamics in New England

January 5, 20015

New England Natural Gas Supply Sources

WCSB

Gulf Onshore

Gulf Offshore

SableIsland

LNG

RockyMountain

January 5, 20016

Tennessee

Iroquois

PNGTS

M&N

Algonquin

New England’s Interstate Pipelines

January 5, 20017

New England’s Interstate Pipelines

Western Canadian Gas thru TCPL, Iroquois

and PNGTSEastern Canadian

Gas thru M&N

Western Canadian Gasthru Tennessee

Gulf Coast Gasthru AlgonquinAnd Tennessee

LNG fromAlgeria and

Trinidad

Steady-State Modeling Results

January 5, 20019

Confidentiality

ISO-NE & LAI has and will continue to comply with the

NEPOOL Information Policy - Rev 3, dated August 10, 2000

Proprietary Information kept Confidential

Steady-State hydraulic model developed from interstate

pipeline public domain information

• FERC 567 Reports & FERC Flow Diagrams Reflecting Peak Day

Design

January 5, 200110

Steady-State Highlights

No summer peak day pipeline deliverability constraints through 2005

Delivery constraints are apparent in Winter 2003

• Shortfall in gas requirements 1,755 MW out of 8,946 MW assumed

• There are 71 gas-fired units, 51 of which are dual fueled

Delivery constraints intensify by Winter 2005

• Shortfall in gas requirements 3,226 MW out of 11,579 MW assumed

• There are 75 gas-fired units, 54 of which are dual fueled

Theoretical mitigation potential thru back-up fuel

No pipeline delivery constraints on a peak day in Winter 2000-01

Findings and Observations

January 5, 200112

High Ref High Ref High Ref

1755

1164

3226

1484

1176

443

3159

468

0

500

1000

1500

2000

2500

3000

3500

60-Day

Peak Day

Projected Shortfalls in Gas Requirements (MW)*

* 6970 Btu/kWh

2001 2003 2005

January 5, 200113

Summary of Peak Day Scenarios – Total Regional Demand vs. System Capacity

3000

3200

3400

3600

3800

4000

4200

4400

4600

4800

2001 2003 2005

MM

cf/d

System Capacity High Reference

January 5, 200114

Steady-State Modeling Results

------1501406HighSummer Peak Day

31595138672837HighWinter 60-Day

32265249062837HighWinter Peak Day

468767822837ReferenceWinter 60-Day

14842419072837ReferenceWinter Peak Day2005

11761918612837HighWinter 60-Day

17552858802837HighWinter Peak Day

443728042837ReferenceWinter 60-Day

11641898722837ReferenceWinter Peak Day2003

------7512617HighWinter Peak Day2001

Capacity

(MW)

Volumes

(MMcf/d)

Merchant Generators

LDCs

Unserved MerchantPipeline Demand

(MMcf/d)ForecastScenarioYear

Unserved merchant capacity does not take into account back-up fuel capabilities.

January 5, 200115

Back-up Fuel Issues

Infrastructure• Air Permits • Delivery Logistics

• Tankage • Refill

Operational Constraints, e.g. switch-on-the-fly

Sustainability

January 5, 200116

Mitigation Potential

447.5524.0971.55,89011,579High

141.5241.0382.52,2637,551Reference

Excess or Shortfall w/

Back-up Fuel Use

(MMcf/d)

Peak Day Transport Shortfall

(MMcf)

Peak Day Gas

Available w/ Back-up Fuel

Use

(MMcf)

Back-up Fuel

Capability

(MW)

New Entry

(MW)Case

Contingency Cases

January 5, 200118

Contingency Cases

ISO Contingencies• Loss of Major Gas-fired Generating Unit

• Loss of 2000 MW HydroQuebec Phase II Line

Gas Contingencies • Scenario 1 - Loss of compression at Burrillville on

Algonquin

• Scenario 2 - Loss of compression at Agawam on Tennessee

• Scenario 3 - Loss of 36-inch line on Tennessee

January 5, 200119

ISO Contingency: Loss of Major Gas-Fired Generating Unit

No significant loss of pressure or flows

Interstate pipelines have the ability to divert and/or re-route gas along the 1100-mile transportation path

January 5, 200120

ISO Contingency: Loss of 2000 MW HydroQuebec Phase II Line

Winter Peak Day - System cannot transport any additional gas

Summer Peak Day - More than sufficient pipeline capacity to support replacement gas fueled generation

January 5, 200121

Gas Contingency Scenario 1

Available compression capacity at Burrillville on Algonquin derated from 11,400 hp to 5,700 hp

January 5, 200122

Increased horsepower requirements at other compressor stations

Fall in delivery pressures to levels that could disrupt plant operations

No observed impact on other pipelines

Gas Contingency Scenario 1

January 5, 200123

Gas Contingency Scenario 2

Available compression capacity at Agawam on Tennessee derated from 9,760 hp to 3,253 hp

January 5, 200124

Downstream compressor stations able to make-up for loss

No unacceptably low delivery pressures for merchant plants observed

No impact on other pipelines

Gas Contingency Scenario 2

January 5, 200125

Gas Contingency Scenario 3

7 miles of Tennessee’s 36-inch line at NY-MA border removed

January 5, 200126

Downstream compressors able to compensate for pressure loss

Gas Contingency Scenario 3

Recommendations

January 5, 200128

Recommendations

Advocate the streamlining of FERC’s pipeline certification process

Promote coordination of power and natural gas scheduling protocols

Increase understanding of merchant generators’ fuel-switching capabilities

Certify quality of interstate transportation arrangements

Study Assumptions

January 5, 200130

Steady-State Demand AssumptionsTwo Gas Demand Cases developed by ISO-NE & LAI: Reference Case & High Case

Reference Case High Case

Annual Net Energy Growth Rate

1.5% 2.4%

Summer Peak Demand Growth Rate

1.7% 2.9%

Winter Peak Demand Growth Rate

1.6% 2.5%

Capacity Additions 7,551 11,579

January 5, 200131

Electric Assumptions

ISO-NE develops electric side assumptions PROSYM production simulation model Analysis performed for 2000 - 2005 ISO-NE assumptions for:

• projected NEPOOL loads,

• existing & proposed capacity and capacity attrition

• net-interchange with New York, New Brunswick and Hydro-Quebec

ISO-NE delivers hourly gas demands for NEPOOL units for peak day (summer/winter) and 60 day winter average (Dec 15th thru Feb 15th)

January 5, 200132

Load Profiles and Seasonality

Winter• Reliance on Peak Day System Flow diagrams from

various certificate applications to serve merchant generators

Summer• Statistical inference from LDCs’ normalized sales

January 5, 200133

Merchant Entry in New England (High Case)

2000 2001 2002 2003 2004 2005

2876

2493

2182

1395

971

1662

0

500

1000

1500

2000

2500

3000W

inte

r C

apac

ity

(MW

)

January 5, 200134

Merchant Entry by Pipeline

Iroquois Tennessee Algonquin M&N PNGTS

1118

2654 2645 2698

443

0

500

1000

1500

2000

2500

3000W

inte

r C

apac

ity

(M

W)

January 5, 200135

Merchant Entry by Pipeline* (2005 High Case)

278.22698M&N

440.72645Algonquin

67.3443PNGTS

479.72654Tennessee

163.21118Iroquois

MMcf/dWinter MWPipeline

* No LNG units

January 5, 200136

Heat Rate vs. Gas Requirements

Plant Type

Heat Rate

(Btu/kWh)

(HHV)

Gas Requirements

(MMcf/d)

Fossil Steam 9,600 127

Advanced Combined Cycle

6,900 83

January 5, 200137

Gregg’s WinFlow Steady-State Model

WinFlow is a shell, requiring extensive and elaborate customization

WinFlow calculates the balanced steady-state pressure-flow relationships for pipeline networks

January 5, 200138

Validation of Steady-State Models

Each individual interstate pipeline model matched its Peak Day Flow diagram within industry tolerances 5# psi 10 hp

Steady-state models for Algonquin, Tennessee and M&N were reviewed and informally validated with individual pipelines

January 5, 200139

Scheduling Priorities during Constraints

Primary Firm Transportation LDCs, to a lesser extent, QFs and some merchants

Secondary Firm Transportation (quasi-firm) Marketers and merchant generators

Interruptible Transportation Industrials, merchant generators

Market Dynamics in New England

January 5, 200141

New England Natural Gas Infrastructure

New England’s Major Interstate Pipelines• Iroquois • Portland• Algonquin • Maritimes & Northeast• Tennessee

Existing pipeline delivery capacity = 3.6 Bcf/d.

Daily LNG sendout capability at Everett = 0.450 Bcf/d.• Expansion of 0.60 Bcf/d for 1,550 MW Sithe New Mystic Station,

possibly Island End• About 1.4 Bcf/d peak day deliverability behind the citygates• Liquids via truck 0.1 Bcf/d

January 5, 200142

Interstate Transportation Market Dynamics 14 pipeline projects placed in-service during 1999-’00

+ 2.0 Bcf/d in the Greater Northeast

New Pipelines in New England, M&N and PNGTS, result in + 0.615 Bcf/d, or about 3800 MW• Counterflow capability through Dracut Tennessee• Pressure and flow benefits improve network reliability

New LNG supplies from Trinidad

Commoditization of the “Supply Chain”• Repackaged Btu services • Synthetics• Increased liquidity • Risk management

January 5, 200143

Typical New England LDC Daily Gas Send-Out

Storage InjectionsPipeline

Storage Withdrawals

LNG/Propane

Source: WEFA, Northeast Natural Gas Markets, Opportunities and Risks, November 1998

January 5, 200144

LAI Project Team

Richard LevitanPrincipal

John BitlerPrincipal

Edward McGee, P.E.Managing Consultant

Jack Elder, P.E. Manager, Power Systems and Technology

John Pitts Senior Consultant

John Mesko, P.E.Senior Consultant

Lilly ZhuConsultant

Shilpa ShahAssistant Consultant

Levitan & Associates, Inc.www.levitan.com

Tel: 617-531-2818Email: rll@levitan.com