cable replacement project cable replacement …...cable replacement project this document has been...

New England Power Company d/b/a National Grid

Salem Cable Replacement Project

Energy Facilities Siting Board Petition Salem, Massachusetts

September 2013



This document has been redacted for Critical Energy Infrastructure Information (CEII). 9/12/13

Table of Contents

Vanasse Hangen Brustlin, Inc. Page i

Table of Contents

GLOSSARY ................................................................................................................................. G-1

1.0 PROJECT OVERVIEW .................................................................................................. 1-1

1.1 Introduction ............................................................................................................. 1-1

1.2 Overview of Analysis ............................................................................................. 1-2

1.3 Project Need ............................................................................................................ 1-3

1.4 Project Alternatives ................................................................................................ 1-4

1.5 Technology Selection ............................................................................................. 1-5

1.6 Description of the Preferred Route and Noticed Alternative............................... 1-6

1.6.1 Preferred Route ......................................................................................... 1-6

1.6.2 Noticed Alternative ................................................................................... 1-6

1.7 Ancillary Facilities ................................................................................................. 1-7

1.7.1 Salem Harbor Substation Facilities ......................................................... 1-7

1.7.2 Canal Street Substation Facilities ............................................................ 1-7

1.8 Summary of Project Schedule and Cost ............................................................... 1-8

1.8.1 Project Schedule........................................................................................ 1-8

1.8.2 Project Cost ............................................................................................... 1-9

1.9 Construction Overview .......................................................................................... 1-9

1.10 Community Outreach ........................................................................................... 1-10

1.11 ISO-NE Approval ................................................................................................. 1-11

1.12 Project Team ......................................................................................................... 1-14

1.12.1 New England Power Company.............................................................. 1-14

1.12.2 Burns & McDonnell ............................................................................... 1-14

1.12.3 Vanasse Hangen Brustlin, Inc. ............................................................... 1-14

1.12.4 Keegan Werlin LLP ................................................................................ 1-15

1.12.5 Energy Initiatives Group, LLC .............................................................. 1-15

1.12.6 Exponent .................................................................................................. 1-16

1.12.7 Bowditch & Dewey, LLP....................................................................... 1-16

1.12.8 Haley & Aldrich, Inc. ............................................................................. 1-16

1.13 Conclusion ............................................................................................................ 1-17

2.0 PROJECT NEED .............................................................................................................. 2-1

2.1 Introduction ............................................................................................................. 2-1

2.2 Siting Board Precedent ........................................................................................... 2-1

2.3 Description of Salem Area Transmission System ................................................ 2-2

2.4 S and T Cable Asset Condition and Operating History ....................................... 2-3

2.4.1 S Cable Asset Condition and Operating History .................................... 2-4

2.4.2 T Cable Asset Condition and Operating History .................................... 2-8

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2.4.3 Conclusion on Asset Condition ............................................................. 2-10

2.5 Need for Additional Transmission Capacity ...................................................... 2-11

2.5.1 Footprint Capacity Needs ....................................................................... 2-11

2.5.2 Transmission System Needs without Footprint .................................... 2-17

2.5.3 Conclusions of Transmission Planning Studies .................................... 2-20

2.6 Conclusion ............................................................................................................ 2-20

3.0 PROJECT ALTERNATIVES ......................................................................................... 3-1

3.1 Introduction ............................................................................................................. 3-1

3.2 Siting Board Precedent and Overview of Alternatives Evaluation ..................... 3-3

3.3 No-Build Alternative .............................................................................................. 3-4

3.4 Underground Transmission Alternatives .............................................................. 3-5

3.4.1 Single Duct Bank Alternative .................................................................. 3-5

3.4.2 Two Duct Bank Alternative ..................................................................... 3-9

3.4.3 Reuse of Existing T Cable Duct Bank and Manhole System .............. 3-12

3.5 Overhead Transmission Alternatives .................................................................. 3-13

3.5.1 Overhead Circuits through Salem .......................................................... 3-13

3.5.2 Overhead Circuits around Salem ........................................................... 3-13

3.6 Railroad Corridor Alternative .............................................................................. 3-21

3.7 Cross-Harbor Transmission Alternatives ............................................................ 3-23

3.7.1 Overhead Transmission across Salem Harbor ...................................... 3-23

3.7.2 Jet Plow Alternative ................................................................................ 3-23

3.7.3 HDD Alternative ..................................................................................... 3-30

3.8 Comparison of Viable Alternatives ..................................................................... 3-38

4.0 ROUTE SELECTION PROCESS.................................................................................. 4-1

4.1 Introduction and Overview of Siting Methodology ............................................. 4-1

4.2 Project Study Area .................................................................................................. 4-2

4.3 Route Selection ....................................................................................................... 4-2

4.3.1 Route Selection Guidelines ...................................................................... 4-2

4.3.2 Initial Route Identification ....................................................................... 4-2

4.3.3 Screening ................................................................................................... 4-2

4.4 Identification of Candidate Routes ........................................................................ 4-5

4.4.1 Candidate Route A (Boardman – Congress)........................................... 4-5

4.4.2 Candidate Route B (Boardman – Lafayette) ........................................... 4-6

4.4.3 Candidate Route C (Forrester – Congress) ............................................. 4-6

4.4.4 Candidate Route D (Forrester – Lafayette) ............................................. 4-7

4.4.5 Candidate Route E (Andrew – Congress) ............................................... 4-7

4.4.6 Candidate Route F (Andrew – Charter – Lafayette) .............................. 4-8

4.4.7 Candidate Route G (Briggs – Congress) ................................................. 4-8

4.4.8 Candidate Route H (Briggs – Lafayette) ................................................. 4-9

4.4.9 Candidate Route I (Andrew – Derby – Lafayette) ................................. 4-9

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4.5 Analysis of Candidate Routes.............................................................................. 4-10

4.5.1 Environmental/Constructability Criteria ............................................... 4-10

4.5.2 Scoring ..................................................................................................... 4-11

4.5.3 Weighting ................................................................................................ 4-16

4.5.4 Candidate Route Cost Comparisons ...................................................... 4-23

4.5.5 Reliability Comparisons ......................................................................... 4-24

4.5.6 Ranking and Identification of Preferred Route, Preferred Route

Variation, and Noticed Alternative ........................................................ 4-24

4.6 Conclusion ............................................................................................................ 4-25

5.0 COMPARISON OF PROPOSED ACTIVITIES ALONG PREFERRED

ROUTE AND NOTICED ALTERNATIVE ................................................................. 5-1

5.1 Introduction ............................................................................................................. 5-1

5.2 Description of Preferred Route and Noticed Alternative ..................................... 5-2

5.2.1 Preferred Route ......................................................................................... 5-2

5.2.2 Noticed Alternative ................................................................................... 5-3

5.3 Route Maps and Photographs ................................................................................ 5-4

5.3.1 Route Maps ............................................................................................... 5-4

5.3.2 Route Photographs .................................................................................... 5-4

5.4 Construction Methods and Schedule ..................................................................... 5-4

5.4.1 Underground Transmission Construction Methods ............................... 5-4

5.4.2 Construction Schedule ............................................................................ 5-10

5.4.3 Environmental Mitigation, Compliance, and Monitoring .................... 5-12

5.4.4 Safety and Public Health Considerations .............................................. 5-12

5.5 Environmental Impact Comparison of Preferred Route and Noticed

Alternative ............................................................................................................. 5-13

5.5.1 Land Use ................................................................................................. 5-13

5.5.2 Tourist Attractions .................................................................................. 5-17

5.5.3 Public Shade Trees ................................................................................. 5-18

5.5.4 Traffic ...................................................................................................... 5-21

5.5.5 Noise ........................................................................................................ 5-26

5.5.6 Potential to Encounter Subsurface Contamination ............................... 5-29

5.5.7 Dust Control/Air Quality ........................................................................ 5-30

5.5.8 Historic and Archaeological Sites.......................................................... 5-31

5.5.9 Electric and Magnetic Fields (“EMF”) ................................................. 5-34

5.5.10 Visual Impacts......................................................................................... 5-38

5.5.11 Wetlands and Waterways ....................................................................... 5-38

5.5.12 Conclusion ............................................................................................... 5-39

5.6 Reliability Comparison of Preferred Route and Noticed Alternative ............... 5-40

5.7 Cost Comparison of Preferred Route and Noticed Alternative ......................... 5-40

5.8 Conclusion of Comparison of Preferred Route and Noticed Alternative ......... 5-41

5.9 Ancillary Facilities ............................................................................................... 5-41

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5.9.1 Salem Harbor Substation ........................................................................ 5-42

5.9.2 Canal Street Substation ........................................................................... 5-45

5.10 Cable Removal ..................................................................................................... 5-48

5.10.1 Construction Methods ............................................................................ 5-48

5.11 Overall Project Cost ............................................................................................. 5-51

5.12 Conclusion ............................................................................................................ 5-52

6.0 CONSISTENCY WITH THE CURRENT HEALTH,

ENVIRONMENTAL PROTECTION, AND RESOURCE USE AND

DEVELOPMENT POLICIES OF THE COMMONWEALTH ............................... 6-1

6.1 Introduction ............................................................................................................. 6-1

6.2 Health Policies ........................................................................................................ 6-1

6.3 The Restructuring Act ............................................................................................ 6-2

6.4 The Green Communities Act ................................................................................. 6-2

6.5 The Global Warming Solutions Act ...................................................................... 6-2

6.6 State and Local Environmental Policies ............................................................... 6-3

6.7 Resource Use and Development Policies ............................................................. 6-3

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List of Appendices

Appendix No. Description

2-1 Existing Ratings of the S and T Cables and the S 145E and T 145E

lines

2-2 Standard Large Generator Interconnection Procedures (“LGIP”)

2-3 Northeast Power Coordinating Council Reliability Reference Directory

#1—Design and Operation of the Bulk Power System

2-4 ISO New England Planning Procedure No. 3—Reliability Standards

for the New England Area Bulk Power Supply System

2-5 ISO New England Planning Procedure No. 5-3—Guidelines for

Conducting and Evaluating Proposed Plan Application Analyses

2-6 ISO New England Planning Procedure No. 5-6—Scope of Study for

System Impact Studies under the Generation Interconnection Proce-

dures

2-7 ISO New England Operating Procedure No. 12—Voltage and Reactive

Control

2-8 National Grid Transmission Group Procedure (TGP 28)—

Transmission Planning Guide

2-9 Worst Case Load Flow Results

3-1 Attachment D to ISO New England Planning Procedure No.4

3-2 Correspondence: MA Department of Marine Fisheries and National

Marine Fisheries Service

3-3 Feasibility Study of Constructing the New S-145 and T-146 Transmis-

sion Lines via a Horizontal Directional Drill Installation under the Sa-

lem Harbor

5-1 GIS-based Public Tree Inventory: National Grid, Salem, Massachu-

setts

5-2 Evaluation of Magnetic Fields from the National Grid Canal Street to

Salem Harbor 115-kV Underground Circuits

5-3 Current Status of Research on Extremely Low Frequency Electric and

Magnetic Fields and Health: Salem Harbor to Canal Street 115-kV

Transmission Line

5-4 Salem Harbor Substation Development Plan

5-5 Canal Street Substation Development Plan

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List of Tables

Table No. Description Page

1-1 Preliminary Construction Schedule ............................................................... 1-8

1-2 Total Anticipated Project Cost (in 2013 dollars) ........................................... 1-9

1-3 Salem Outreach and Consultation Meetings ............................................... 1-12

2-1 S Cable Outage Durations and Fluid Releases .............................................. 2-6

2-2 S Cable Recurring Maintenance History ....................................................... 2-7

2-3 T Cable Recurring Maintenance History ..................................................... 2-10

2-4 New England Load and Losses for 2016 (MW) .......................................... 2-13

2-5 Interface MW Levels in Summer Peak Cases ............................................. 2-14

2-6 Interface MW Levels in Shoulder Peak Cases ............................................ 2-14

2-7 Summer Peak Loading on S and T Cables in N-1 Contingency

Conditions ................................................................................................... 2-15

2-8 Shoulder Loading on S and T Cables in N-1 Contingency Conditions ...... 2-15

2-9 First Element out of the N-1-1 Contingencies ............................................. 2-16

3-1 Anticipated Permits and Approvals for Single Duct Bank Alternative ........ 3-7

3-2 Estimated Costs for Single Duct Bank Alternative (2013 dollars) ................ 3-8

3-3 Anticipated Permits and Approvals for Two Duct Bank Alternative .......... 3-10

3-4 Estimated Costs for Two Duct Bank Alternative (2013 dollars)................. 3-11

3-5 Anticipated Permits and Approvals for Overhead Transmission

Alternative around Salem ............................................................................ 3-18

3-6 Estimated Costs for Overhead Transmission Alternative around

Salem (2013 dollars).................................................................................... 3-20

3-7 Summary of Marine Fisheries Resources within Salem Harbor ................. 3-27

3-8 Anticipated Permits and Approvals for Jet Plow Alternative ...................... 3-29

3-9 Estimated Costs for Jet Plow Alternative across Salem Harbor (2013

dollars) ......................................................................................................... 3-30

3-10 Anticipated Permits and Approvals for HDD Alternative........................... 3-36

3-11 Estimated Costs for HDD Alternative across Salem Harbor (2013

dollars) ......................................................................................................... 3-37

3-12 Summary of Transmission Project Alternatives .......................................... 3-41

4-1 Route Evaluation Criteria and Scoring Scale Summary .............................. 4-18

4-2 Candidate Route Evaluation Matrix ............................................................ 4-21

4-3 Raw Environmental Scores and Weighted Environmental Scores by

Candidate Route .......................................................................................... 4-23

4-4 Candidate Route Cost Estimates ................................................................. 4-24

4-5 Ranking Summary of Candidate Routes ..................................................... 4-25

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Table No. Description Page

5-1 Preliminary Construction Schedule ............................................................. 5-11

5-2 Land Uses within Preferred Route and Noticed Alternative ....................... 5-15

5-3 Land Use Comparisons for Preferred Route and Noticed Alternative ........ 5-16

5-4 Public Shade Trees along Preferred Route and Noticed Alternative .......... 5-18

5-5 Traffic, Road Width, and Public/Private Transportation along the

Preferred Route ............................................................................................ 5-22

5-6 Traffic, Road Width, and Public/Private Transportation along

Noticed Alternative ..................................................................................... 5-24

5-7 Lengths of Preferred Route and Noticed Alternative with Low,

Moderate, and High Potential for Significant Traffic Congestion .............. 5-25

5-8 Typical Construction Sound Levels ............................................................ 5-27

5-9 Land Use and Length Comparisons for Preferred Route and Noticed

Alternative ................................................................................................... 5-28

5-10 Historic and Archaeological Resources along Preferred Route and

Noticed Alternative ..................................................................................... 5-33

5-11 Modeled Magnetic Field Levels (mG) for Vertical and Horizontal

Configurations ............................................................................................. 5-35

5-12 Modeled Magnetic Field Levels (mG) for Congress Street Bridge

Configuration ............................................................................................... 5-36

5-13 Modeled Magnetic Field Levels (mG) for Manhole Approach

Configuration ............................................................................................... 5-36

5-14 Modeled Magnetic Field Levels (mG) for Manhole Entrance

Configuration ............................................................................................... 5-37

5-15 Environmental Comparison of Preferred Route and Noticed

Alternative ................................................................................................... 5-39

5-16 Estimated Costs ........................................................................................... 5-41

5-17 Total Anticipated Project Cost (in 2013 dollars) ......................................... 5-52

6-1 Federal Permit/Consultation Requirements ................................................... 6-3

6-2 State Permit/Consultation Requirements ....................................................... 6-4

6-3 Local Permit Requirements ........................................................................... 6-4

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List of Figures (see Map Book)

Figure No. Description

1-1 USGS Locus Map

1-2 Aerial Locus Map

2-1 Overview of Salem Area Transmission System

2-2 Schematic Diagram of Salem Area Transmission

3-1 Overhead Transmission Alternative Overview Map

3-2 Natural Resource Constraints along Overhead Transmission Alternative

3-3 Jet Plow Alternative

3-4 Jet Plow Alternative: Navigational Features in Salem Harbor

3-5 Jet Plow Alternative: Marine Resources in Salem Harbor

3-6 HDD Alternative

3-7 HDD Alternative: Navigational Features in Salem Harbor

3-8 HDD Alternative: Marine Resources in Salem Harbor

4-1 Project Study Area

4-2 Streets Considered for Initial Screening

4-3 Street Segments Advanced for Routing

4-4 Complete Candidate Routes

4-5 Land Uses within Project Study Area

4-6 Historic Resources within Project Study Area

4-7 Potential Sources of Subsurface Contamination within Project Study Area

4-8 Preferred Route and Noticed Alternative

5-1 Preferred Route

5-2 Noticed Alternative

5-3 Preferred Route Photographs and Photograph Locations

5-4 Noticed Alternative Photographs and Photograph Locations

5-5 Land Use Maps for Preferred Route

5-6 Land Use Maps for Noticed Alternative

5-7 Cultural and Historic Points of Interest

5-8 Environmental/Historic Resource Maps for Preferred Route

5-9 Environmental/Historic Resource Maps for Noticed Alternative

5-10 Proposed Planting Plan, Canal Street

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Glossary

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GLOSSARY

AFUDC allowance for funds used during construction

All Lines In analysis of impact on power system with all elements in service

analysis

BMcD Burns & McDonnell

BMPs best management practices

BOH City of Salem Board of Health

Cables S and T cables

CELT capacity, energy, loads, and transmission

Chapter 91 The Massachusetts Public Waterfront Act, G.L. Chapter 91

City City of Salem

CZM Massachusetts Office of Coastal Zone Management

DG distributed generation

DMF Massachusetts Division of Marine Fisheries

DPA Designated Port Area

DPU Massachusetts Department of Public Utilities

DPW City of Salem Department of Public Works

DR demand response

EE energy efficiency

EFSB Massachusetts Energy Facilities Siting Board

EIG Energy Initiatives Group, LLC

ELF extremely low frequency

EMF electric and magnetic fields

EOEEA Massachusetts Executive Office of Energy and Environmental Affairs

Footprint Footprint Power LLC

Glossary

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GLOSSARY

frac-out an event during a drilling operation in which excessive drilling pressure causes drill fluids to escape to the surface

G gauss (magnetic field unit of measure)

GIS geographic information systems OR gas-insulated switchgear

G.L. Massachusetts General Law

GHG greenhouse gas

GWSA Global Warming Solutions Act

H&A Haley & Aldrich, Inc.

HDD horizontal directional drill

HPFF high-pressure fluid-filled pipe-type cable system

HPGF high-pressure gas-filled pipe-type cable system

HPPT high-pressure pipe-type cable system

HVED high voltage extruded dielectric cable system

Hz hertz

ISO-NE Independent System Operator New England

kcmil A unit of area, equal to the area of a circle with a diameter of one mil (one thousandth of an inch)

KEMA KEMA Consulting

kV kilovolt

KW Keegan Werlin LLP

LGIP Large Generator Interconnection Procedures

LTE long-term emergency rating

MassGIS Massachusetts Office of Geographic Information

MBTA Massachusetts Bay Transportation Authority

MBUA Massachusetts Bureau of Underwater Archaeology

Glossary

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GLOSSARY

MCP Massachusetts Contingency Plan

MEPA Massachusetts Environmental Policy Act

mG milligauss (or one-thousandth of 1 gauss)

MHC Massachusetts Historical Commission

MVA megavolt amperes

MW megawatt

MWPA Massachusetts Wetlands Protection Act

N-1 analysis analysis of impact on power system with a single transmission element `

N-1-1 analysis analysis of impact on power system with a second transmission element out of service

NEEWS New England East-West Solutions

NEP New England Power Company d/b/a National Grid

NEPOOL New England Power Pool

NMFS National Marine Fisheries Service

NPDES National Pollutant Discharge Elimination System

NPDES CGP NPDES General Permit for Discharges from Construction Activities

NRHP National Register of Historic Places

OSHA Occupational Safety and Health Administration

PNF Project Notification Form

PPA Proposed Plan Application

psi pounds per square inch

PVC polyvinyl chloride

RAO Response Action Outcome

ROW right-of-way

Glossary

Page G-4 Vanasse Hangen Brustlin, Inc.

GLOSSARY

SCFF self-contained fluid-filled cable system

SEMA/RI southeast Massachusetts/Rhode Island

SF6 sulfur hexafluoride

SH shoulder peak

SIS System Impact Study

Siting Board Massachusetts Energy Facilities Siting Board

SP summer peak

SRHP State Register of Historic Places

SWPPP Storm Water Pollution Prevention Plan

TMB thermo-mechanical bending

TMP traffic management plan

TOR Threat of Release

TOY time-of-year restriction

URAM Utility Release Abatement Measure

USEPA United States Environmental Protection Agency

USEPA MOU USEPA Memorandum of Understanding

USGS U.S. Geological Survey

VHB Vanasse Hangen Brustlin, Inc.

WHO World Health Organization

WQC Water Quality Certification

Section 1.0: Project Overview

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1.0 PROJECT OVERVIEW

1.1 INTRODUCTION

New England Power Company d/b/a National Grid (“NEP”) submits this analysis (“Analysis”)

to the Energy Facilities Siting Board (the “Siting Board”) in support of its petition for authority

to construct, operate and maintain replacements for NEP’s existing S-145 and T-146

115 kilovolt (“kV”) underground cables between NEP’s Salem Harbor and Canal Street

Substations (individually, the “S cable” and “T cable”; collectively, the “Cables”) with cables at

the same voltage but of higher capacity in a new duct bank and manhole system within the City

of Salem (“City” or “Salem”). The new Cables will be designed to meet the long-term needs of

the area transmission system, both with and without the proposed Footprint Power LLC

(“Footprint”) generating facility.

NEP proposes to construct the proposed replacement project in two discrete phases. First, NEP

will install the new Cables in a new manhole and duct bank system within a new transmission

corridor underneath existing roadways. Next, the existing direct-buried S cable will be removed

from its current location, and the existing T cable will be pulled from its duct bank (which will

be abandoned in place). In addition, ancillary improvements will be made at both substations as

described in Section 1.7. The replacement of these two separate 115 kV cables and the

improvements at the two substations comprise the proposed project (the “Project”). The routing

for the proposed cables and the location of proposed substation improvements are shown on a

U.S. Geological Survey (“USGS”) quadrangle base map as Figure 1-1. Figure 1-2 shows the

proposed routing on a 2008 aerial photo from the Massachusetts Office of Geographic

Information (“MassGIS”).

NEP’s plans to replace the Cables have developed in parallel with, and been informed by,

proposed changes in the generation located within Salem. At the center of the Salem area

transmission system is the Salem Harbor generating station, formerly owned by Dominion New

England, Inc. and now owned by Footprint. The Salem Harbor generating station, with

approximately 740 megawatts (“MW”) of net installed generating capacity, is slated for

retirement in 2014. On August 3, 2012, Footprint filed a petition with the Siting Board for

approval to construct and operate a natural gas-fired, combined-cycle, quick-start generating

facility at the current Salem Harbor generating site. Footprint’s plan involves the demolition

and remediation of the existing facilities at Salem Harbor and the construction of a new

692 MW generating facility (the “Footprint generating facility”) with a proposed on-line date of


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June 2016.1 As discussed in Section 2, NEP’s proposed Project will provide the increased

transmission capacity necessary to interconnect Footprint’s generating facility to the regional

transmission system.

Concurrently with its Petition to the Siting Board, NEP has also filed with the Department of

Public Utilities (“DPU”): (1) a related request for approval of the two transmission lines pursuant

to G.L. c. 164, § 72 (“Section 72”); and (2) a request for exemptions from the requirements of

local zoning pursuant to G.L. c. 40A, § 3. Section 72 requires a petitioner to seek approval from

the DPU “for authority to construct and use or to continue to use as constructed or with altered

construction a line for the transmission of electricity for distribution in some definite area.” Under

this statute, the DPU must determine that “such line will or does serve the public convenience and

is consistent with the public interest.” G.L. c. 40A, § 3 authorizes the DPU to issue zoning

exemptions for “[l]ands or structures” to be used by “public service corporations” if such

zoning exemptions are required and “reasonably necessary for the convenience or welfare of

the public.”

As set forth in detail below, consistent with the requirements of G.L. c. 164, §§ 69H, 69J, the

Project will provide a reliable energy supply for the Commonwealth of Massachusetts with a

minimum impact on the environment at the lowest possible cost. Specifically, the Project will

serve the public interest by: (1) replacing the existing Cables, which are quickly reaching the end

of their useful lives; (2) interconnecting a new, natural gas-fired generating facility to the regional

transmission system; and (3) improving the reliability of the electric system by providing

additional transmission capacity to reliably serve anticipated load growth in the region over the

long term, while minimizing environmental impacts and costs. For these reasons, NEP requests

the Siting Board’s approval of the Project. To ensure that the Project is placed into service in a

timely manner to serve the interconnection requirement of the Footprint generating facility by

June 2016, the Company requests approval by the Siting Board no later than August 2014.

1.2 OVERVIEW OF ANALYSIS

The balance of Section 1 presents an overview of the Project. The remaining sections of this

Analysis provide detailed information and analysis to support the Project, specifically: the need

for the replacement transmission lines and related facilities (Section 2); a comparison of project

alternatives (Section 3); a description of the route selection process that was used to identify the

Preferred Route and Noticed Alternative for the proposed transmission lines (Section 4); a

comparative analysis of the Preferred Route and Noticed Alternative (Section 5); and an analysis

1 Although Footprint’s petition to the Siting Board seeks approval for a 692 MW generating facility, Footprint’s application to ISO

New England for a Large Generator Interconnection Agreement requested an SIS for a 715 MW generating facility. The Company’s

need analysis in this proceeding has therefore been conducted based on the 715 MW capacity contemplated by Footprint’s

interconnection request.



of the Project’s consistency with the health, environmental protection, resource use, and

development policies of the Commonwealth of Massachusetts (Section 6).

1.3 PROJECT NEED

Section 2 of the Analysis evaluates the need for the Project based, first, on the condition of the

existing cables, and second, on Footprint’s anticipated interconnection requirements and system

capacity. The Cables were originally installed in 1971 and 1951, respectively, and are

approaching the end of their useful lives. The S cable has been subject to an increasing number of

dielectric fluid releases in recent years, which have created reliability, cost and environmental

concerns associated with the cable’s continued operation. The T cable, while having a somewhat

more favorable reliability history, has experienced sporadic fluid releases. When these releases

occur, NEP must locate the fluid leaks, take these facilities out of service, conduct expensive

repairs expeditiously, and perform the necessary environmental remediation to minimize and

address adverse impacts to the environment. Locating and repairing the fluid leaks often require

the Cables to be taken out of service, which can negatively affect the reliability of the area

transmission system. Further, it has become increasingly difficult and expensive to obtain

replacement parts to perform routine maintenance and repairs on both of the Cables. Indeed,

recent repairs to the Cables have cost over $1.3 million in the past decade. Accordingly, the

Project is needed for replacement purposes as soon as it can be constructed in order to address

these recurring fluid releases and failures, and end-of-useful life conditions.

In addition to the need to replace the cables for asset condition reasons, there is a need to

increase the capacity of the Cables from Salem Harbor to Canal Street in order to interconnect

the proposed new Footprint generating facility to be built at the existing Salem Harbor

generating facility site. Specifically, the capacity of the existing transmission system is not

sufficient to meet the interconnection requirements of Footprint’s generating facility without

placing significant limitations on the operation of that facility. The Footprint generating facility

is slated to commence commercial operation in June 2016. Even if the Footprint generating

facility is not ultimately placed in service, the proposed Cables will be sized to ensure that the

Cables will reliably serve expected load growth well into the future. A full analysis of the need,

including power flow analyses and detailed analyses of various contingency situations for the

Project, is presented in Section 2 of this Analysis.

In summary, the Cables need to be replaced to address the cost, reliability, and environmental

issues created by their generally deteriorating condition. Moreover, the additional capacity

provided by the Project will be needed by June 2016 in order to serve the interconnection

requirements of the Footprint generating facility at the Salem Harbor site. Thus, based upon the

above, and as more fully discussed in Section 2, there are significant reliability grounds to

justify the replacement of the Cables in the near term.



1.4 PROJECT ALTERNATIVES

In accordance with Siting Board precedent, NEP evaluated a series of project alternatives that

have the potential to meet the identified need in order to determine the approach that best

balances reliability, cost and environmental impact. Several circumstances unique to the Project

influenced the evaluation of the project alternatives. First, due to transmission system

constraints, it will not be possible to take either cable out of service for an extended period of

time to support construction. Therefore, a new cable system must be constructed and ready for

service prior to taking either of the existing Cables out of service. This fact dictates certain

construction sequencing and defines the options available for Project alternatives.

Second, both Cables must be physically removed from the ground once they are retired. The

T cable is a low-pressure fluid-filled cable installed in a duct bank. The S cable is a direct-

buried, medium-pressure fluid-filled cable system, which uses a pressurized dielectric fluid as

part of the overall insulation system. While in service, the Cables and fluid therein are not

regulated by the Massachusetts Department of Environmental Protection (“DEP”) unless a

release of fluid occurs. However, once the Cables are permanently taken out of service, they

will no longer be monitored for leaks and natural degradation of the Cables could reasonably be

expected to release oil into the environment. This would make the Cables potential uncontrolled

sources of contamination, requiring notification to DEP of these Threats of Release (“TORs”)

and implementation of Immediate Response Actions to abate the TORs (i.e., remove the

Cables) as soon as practicable. All project alternatives must therefore include the removal of

both of the existing Cables, along with the attendant impacts and costs of the removal.

Third, in order to meet the interconnection requirements of the proposed Footprint generating

facility, NEP intends to put the replacement cables in service by June 2016. Without a properly

sized set of new cables, the Footprint generating facility would be at risk of not being able to

operate as its full capacity, and NEP therefore evaluated alternatives that could be constructed

within this time frame.

Finally, because the purpose of the Project is to replace essential existing transmission

infrastructure, non-transmission alternatives such as additional energy efficiency (“EE”) and

distributed generation (“DG”) would not meet the identified need. While EE and DG are

important resource alternatives that are appropriate solutions in certain settings, they do not serve

as a substitute for the replacement of existing transmission lines that have reached the end of their

useful lives, but are integral to the transmission network and are required to interconnect a new

generator to the electric grid. Since EE and DG do not possess these essential attributes and would

not meet the identified need, they were not evaluated as suitable alternatives.

With these considerations in mind, the Company evaluated a range of project alternatives. The

degree to which the various alternatives could effectively and efficiently meet the resource need

is described in Section 3. More specifically, Section 3 describes and analyzes: (1) a no-build



alternative (Section 3.3); (2) various underground transmission alignments, including a single

duct bank alternative, a two duct bank alternative, and reuse of the existing T cable duct bank

(Section 3.4); (3) multiple overhead transmission alternatives (Section 3.5); (4) a railroad

corridor alternative (Section 3.6); and (5) cross-harbor transmission alternatives, including

traversing Salem Harbor through both a jet plow and horizontal direction drill (“HDD”)

technique (Section 3.7).

The analysis of project alternatives conducted by NEP determined that the proposed

replacement and upgrade of the Cables within a new single duct bank and manhole system

within City streets will most effectively provide a reliable energy supply with a minimum

impact on the environment at the lowest possible cost. All cost estimates were developed to

comply with Appendix D to ISO New England Planning Procedure No. 4—Procedure for

Pool-Supported PTF Cost Review (September 17, 2010). The cost estimates provided are

classified as conceptual grade estimates, which are based on key project elements with a limited

amount of detailed engineering. Conceptual grade estimates have an accuracy of -25% to +50%

and do not consider possible future variances in commodity or labor costs.

1.5 TECHNOLOGY SELECTION

NEP analyzed the two main types of underground cable systems being installed in the United

States today at this voltage level: (1) high voltage extruded dielectric (“HVED”); and (2) high-

pressure pipe-type (“HPPT”) cable systems.

The HVED cable system consists of a stranded copper or aluminum conductor, extruded solid

dielectric insulation (cross-linked polyethylene or ethylene propylene rubber), a metallic shield,

a moisture barrier and a protective jacket. These cables can be installed either by direct burial or

within a manhole and duct bank.

The HPPT cable system consists of three paper-insulated cables installed in a sealed steel pipe.

The pipe is filled with dielectric fluid or nitrogen gas, which is maintained under pressure

(typically 200 psi). If the pipe is filled with nitrogen gas, the cable system is called a high-pressure

gas-filled (“HPGF”) pipe-type cable system. If the pipe is filled with a synthetic dielectric fluid,

the cable system is called a high-pressure fluid-filled pipe-type cable system.

For the Project, NEP evaluated using either a HVED cable system or a HPGF cable system. The

overall life-cycle costs would be higher for the HPGF cable system because of the higher

maintenance costs associated with the pressure monitoring system and a cathodic protection

system that protects the steel pipe from corrosion. Overall, NEP determined that an HVED cable

system will be preferable for the following reasons:

· It is simpler to operate (i.e., less maintenance);

· It does not require the installation and operation of a pressurizing system;



· It does not require the installation and maintenance of a cathodic protection system;

· Multiple suppliers for this type of cable system are available; and

· The current industry trend in the United States is to install HVED at 115 kV.

Accordingly, HVED has been selected as the proposed technology for the Project.

1.6 DESCRIPTION OF THE PREFERRED ROUTE AND NOTICED ALTERNATIVE

Section 4 of this Analysis presents the routing analysis used to select the Preferred Route and a

Noticed Alternative for the proposed underground cables between the existing Salem Harbor

Substation and the Canal Street Substation. The routing analysis considered environmental

factors, cost and reliability.

After identifying an array of candidate routes, NEP developed an objective scoring analysis to

compare the routes on a variety of human and natural environmental criteria. The cost and

reliability attributes of the routes were also evaluated. This analysis resulted in the selection of a

Preferred Route and a Noticed Alternative. The Preferred Route and Noticed Alternative are

described below and are shown on Figures 1-1 and 1-2.

1.6.1 Preferred Route

The Preferred Route for the new Cables is approximately 1.63 miles long and travels from the

Salem Harbor Substation along Fort Avenue and Webb Street, turns southwest onto Essex

Street, turns north to connect to Forrester Street, then continues west onto Forrester and

Washington Square South. The route then turns south along Washington Square West,

Hawthorne Boulevard, and Congress Street; west onto Leavitt Street and Fairfield Street; north

on Cabot Street; west on Cypress Street; and then north across a vacant NEP-owned parcel to

connect to the Canal Street Substation.

1.6.2 Noticed Alternative

NEP has also selected a Noticed Alternative that is geographically diverse from the Preferred

Route described above. Although NEP believes that the Preferred Route is superior for the

reasons set forth in Section 4 of the Analysis, the Noticed Alternative would also be feasible

and would allow for flexibility in different route combinations for potential optimization. The

Noticed Alternative travels from the Salem Harbor Substation along Fort Avenue and Webb

Street, turns southwest onto Andrew Street and Washington Square North, and south along

Washington Square West and Hawthorne Boulevard. The route then turns west onto Charter

Street, south along Lafayette Street, west on Gardner Street, and north on Canal Street to

connect to the Canal Street Substation. Although portions of this route overlap segments of

the Preferred Route because of the compact study area between the two substations, the



Noticed Alternative provides a potential alternative to the Preferred Route. The Noticed

Alternative route is approximately 1.86 miles long.

1.7 ANCILLARY FACILITIES

Construction of the Project will require upgrades at two existing substations: the Canal Street

Substation and the Salem Harbor Substation. The locations of these substations are shown on

the locus maps provided as Figures 1-1 and 1-2.

1.7.1 Salem Harbor Substation Facilities

The electrical equipment associated with the existing underground Cables will be removed.

This includes cable termination structures, surge arresters, voltage transformers, current

transformers, rigid copper conductor, aluminum conductor, disconnect switches, dielectric fluid

reservoirs, and one steel dead-end structure. Four oil circuit breakers will also be replaced with

new sulfur hexafluoride (“SF6”) gas circuit breakers.

To accommodate the new underground cables, the new cable riser termination structures will

be installed in the area currently used as a parking lot, thereby allowing for removal of the

existing structures without an electric outage. Once the demolition of the existing cable

termination structures is complete, the new cables can be tied into the electric substation.

The new equipment to be installed will include similar components as the ones that were

removed, but without the rigid copper conductor, dielectric fluid reservoirs, and with two steel

dead-end structures. New relay, control, and communication equipment will also be installed

inside the existing control house.

1.7.2 Canal Street Substation Facilities

All existing electrical equipment, support structures, and foundations will be removed with the

exception of the existing steel lattice transmission structures that will remain in place and will be

repainted. The removed equipment will include underground cable terminations, surge arresters,

rigid copper conductor, aluminum conductor, wave traps, voltage transformers, current

transformers, disconnect switches, dielectric fluid reservoirs, outdoor relay and communication

cabinets, and a small building that contains service power equipment and a telephone.

New electrical equipment, support structures, and foundations will be installed at the substation.

This includes similar components as the ones that were removed, but without the rigid copper

conductor, dielectric fluid reservoirs, and outdoor relay and communication cabinets. A new

control building will be installed that will house new relay, control, and communication

equipment.



The site will be graded to allow for the installation of the new equipment, and the existing

retaining wall at the rear of the property will be replaced in kind with some minor improve-

ments. New landscaping features will be installed to allow for visual screening of the electrical

equipment, and a new perimeter fence will be installed around the property.

1.8 SUMMARY OF PROJECT SCHEDULE AND COST

1.8.1 Project Schedule

Construction activities are anticipated to be completed over an approximately an 18-month

period beginning in November 2014. Some additional work, such as removal of the de-

energized T cable from its existing duct bank and final pavement restoration, will extend

through September 2016. The following is the preliminary schedule for the installation of the

cables:

Table 1-1: Preliminary Construction Schedule

Construction of New Cable System

November 2014 – September 2015 Duct bank and manhole installation and temporary pavement restoration

November 2014 – March 2016 Construction at Canal Street and Salem Harbor Substations for new cable

termination structures and equipment

November 2015 – February 2016 Cable installation, pulling, splicing, and testing

March 2016 – April 2016 Cutover and energize new Cables

Removal of the Old Cables and Final Restoration

March 2016 – May 2016 Final restoration on the new cable route

To be determined in consultation with

the City of Salem

Removal of the existing Cables and final restoration along

Canal Street and Derby Street

Construction at the Salem Harbor and Canal Street Substations will run in parallel with the

installation of the cable system. It should be noted that some adjustments to the proposed

schedule may be required to coordinate with other proposed projects in the area. It is not

anticipated that these schedule changes will delay placing the new cables in service by May 2016.

Section 5 includes additional details on the construction schedule.



1.8.2 Project Cost

Cost estimates are based on pricing obtained from manufacturers and recent underground

projects conducted by NEP. In accordance with ISO New England (“ISO-NE”) cost estimation

procedures, the cost estimate provided in Table 1-2 is currently considered conceptual at -

25%/+50%. It includes both direct and indirect costs, a 25% contingency and inflation at 2%

for the several-year development and construction schedule. Table 1-2 also presents the cost of

the Project in nominal dollars based on anticipated expenditures over the construction period.

Table 1-2: Total Anticipated Project Cost (in 2013 dollars)

Cost

(millions)

Construction Cost

Preferred Route $33.40

S Cable Removal $5.37

T Cable Removal $0.58

Substation Improvements $12.27

Project Administration and Development $10.81

Total Project Cost (2013 dollars) $62.43

Total Project Cost (future dollars)* $63.84

* Assuming 2% annual inflation rate based on anticipated timing of expenditures

1.9 CONSTRUCTION OVERVIEW

Each proposed cable will consist of three solid dielectric cables installed in individual polyvinyl

chloride (“PVC”) conduits. The trench for the duct bank will be approximately four feet wide

by five to eight feet deep. The duct bank will contain a total of ten PVC conduits: six 6-inch-

diameter PVC conduits for the insulated cables; one 4-inch diameter PVC conduit for a relay

and communication circuit; and three 2-inch diameter PVC conduits for a grounding cable and

a possible future temperature monitoring cable. The PVC conduits will be encased in a

common concrete envelope.

The proposed new duct bank and manhole system installed between Salem Harbor Substation

and Canal Street Substation will be installed in existing public ways in the City. The overall

length of the proposed cables will be 1.63 miles.

Construction of an underground cable project typically consists of four principal phases:

(1) manhole installation; (2) trench excavation, duct bank installation, and pavement patching;



(3) cable pulling, splicing and testing; and (4) final pavement restoration. These phases will be

conducted in sequence at each location. It is anticipated that several phases of construction will be

ongoing simultaneously in different sections of the routes. Section 5 provides a detailed

description of each phase of the construction process.

Soils removed during trench excavation will be handled using a “clean trench” approach. As a

trench is excavated, soils will be loaded directly into a dump truck and removed from the work

area for off-site reuse or disposal, rather than stockpiled along the roadway. This reduces the

size of the work area and reduces the potential for sediment runoff and dust.

Street restoration typically occurs in two steps. After construction of the duct bank, the

pavement is temporarily patched. Subsequently, the pavement will be repaired or replaced as

required by the Salem Department of Public Works (“DPW”) and the Massachusetts

Department of Transportation (“MassDOT”).

As discussed in Section 5, potential impacts from Project construction will include temporary

traffic congestion, construction noise, and sediment and dust generation. Various mitigation

measures will help minimize potential temporary impacts from construction. Proposed

mitigation measures are described in Section 5.4 and 5.5.

1.10 COMMUNITY OUTREACH

NEP has been working closely with the City over the course of the development of the Project.

The information and insight into conditions in the Project area provided by several departments

within the City government, most particularly the City Engineer and the DPW, were very

helpful in developing the routing analysis and selection of Preferred Route and Noticed

Alternative. NEP has also been conducting outreach to residents located in the vicinity of the

Project.

Communications with the City began in April 2009 with a series of preliminary meetings that

included the Mayor’s Office, the City Engineer, DPW, Community Development and Planning,

the Conservation Commission Agent, the Harbormaster, and the City Council President. NEP

then conducted two open houses in 2010 and 2011, and invited the entire City to the meetings

through newspaper advertisements, local cable channel announcements, and direct invitations

to business owners and residents in the area. City residents and business owners were invited to

learn about the Project and provide feedback concerning the routing of the proposed cables.

NEP held two additional informational meetings (3/22/10 and 4/20/10) with the business

community, arranged through the Chamber of Commerce and the Mayor’s Office. Four

separate informational meetings were also held for the various neighborhood associations in the

City. The meetings with the City and neighborhood residents yielded valuable information that

was incorporated into the routing study and selection of the Preferred Route and Noticed

Alternative.



NEP held two additional informational meetings and a third open house in March and April of

2013. An additional informational meeting, arranged through State Representative John

Keenan’s office and the Mayor’s office, was held on August 28, 2013. Residents and business

owners in the area of the Preferred Route and Noticed Alternative were invited as well as State

and City officials and district councilmen. The purpose of these meetings was to update

residents and businesses as to the Project schedule and the results of the Company’s route

selection process.

A list of meetings held with City officials and neighborhood groups is provided below in

Table 1-3.

Prior to construction, NEP will contact additional City departments and regional authorities to

coordinate construction so that impacts on local residents and businesses are minimized.

Departments and authorities to be contacted include the Salem Police Department, the Salem

Fire Department, the Salem School Department, Salem State College, Destination Salem—the

Office of Tourism, Salem Chamber of Commerce, and the Salem Trolley Company.

In addition, prior to construction, NEP will notify abutters of the intended dates of construction

in their area and of any known lane closures or detours. This notice will provide a web site

address with current construction schedules and activities, and a phone number and direct

contact for residents to use to address any concerns or questions.

1.11 ISO-NE APPROVAL

The replacement of the Cables will require the filing of a Proposed Plan Application (“PPA”)

with ISO-NE under Transmission, Markets and Services Tariff Section I.3.9 and ISO-NE

Planning Procedure 5-1. At this time, NEP expects that the PPA will require only Level I, or

“For Information Only,” analysis, and that ISO-NE will be able to issue a determination of “no

significant impact” as a result of the proposed changes within four to six weeks of the filing.



Table 1-3: Salem Outreach and Consultation Meetings

Date Agency/Group

2009

4/7/09 Meeting with Mayor of Salem and Chief Administrative Aide

10/22/09 Meeting with City Engineer

11/3/09 Meeting with Ken Sanderson (DEP)

11/5/09 Meeting with David Knowlton (City Engineer), Jason Silva (Mayor’s Office), Richard Rennard (DPW)

2010

1/12/10 Meeting with David Knowlton (City Engineer), Jason Silva (Mayor’s Office), Richard Rennard (DPW)

1/12/10 Meeting with MassDOT

1/14/10 Meeting with Lynne Montague, Chief of Staff, Representative John Keenan

1/20/10 Meeting with Representative John Keenan

1/22/10 Meeting with President Bob McCarthy (Salem City Council President)

2/1/10 Meeting with President Bob McCarthy (Salem City Council President); Councilors Ronan, Pelletier, and Patajo

(Salem City Council Members)

2/5/10 Meeting with Carey Duques (Conservation Agent), Peter Gifford (Assistant Harbormaster and Director of Inspectional

Services)

3/16/10 Meeting with Rinus Oosthoek (Executive Director, Chamber of Commerce)

3/16/10 Communication with Stan Franzeen (Historic Derby Street Neighborhood Association), Lucy Corchado (Point

Neighborhood Association), Jim Rose (South Salem Neighborhood Association), Shirley Walker (Downtown

Neighborhood Association), Salem Rotary Club

3/16/10 Communication with Salem Rotary Club

3/17/10 Communication with Lynn Duncan (Director, Department of Planning & Community Development)

3/17/10 Meeting with David Knowlton (City Engineer)

3/22/10 Meeting with Rinus Oosthoek (Executive Director, Chamber of Commerce) and the business community

3/22/10 Communication with Lucy Corchado (Point Neighborhood Association), Jim Rose (South Salem Neighborhood

Association), Shirley Walker (Downtown Neighborhood Association)

3/25/10 Communication with Kimberly Dunn (Owner, Salem Waterfront Hotel, 225 Derby St )

3/29/10 Meeting with Lucy Corchado (Point Neighborhood Association). Also invited: Members of Historic Derby Street

Association, South Salem Neighborhood Association, Downtown Neighborhood Association.

4/15/10 Mailed project fact sheet to all 300-foot abutters of both routes

4/20/10 Meeting with Chamber of Commerce

5/4/10 Mailed Open House invite to all abutters

5/11/10 Communication with Lucy Corchado (Point Neighborhood Association), Stan Franzeen (Historic Derby Street

Neighborhood Association), Jim Rose (South Salem Neighborhood Association), Shirley Walker (Downtown

Neighborhood Association), Janet Andersen, Sandra Power. Cc: Barbara Kelley, Bill Sano, Cindy Carr, Dinah Cardin,

Dolores Jordan, Liz Cronin

5/11/10 Communication with Jason Silva (Chief Administrative Aide, Mayor’s Office); Douglas Wagner, David Knowlton,

Lynn Duncan

5/11/10 Communication with Bob McCarthy (City Council President)

5/11/10 Communication with Representative John Keenan

5/12/10 Mail Open House invite to Chamber’s office

5/12/10 Communication with Rinus Oosthoek (Executive Director, Chamber of Commerce)

5/12/10 Communication with N. Malia Griffin (Community Affairs, Dominion Salem Harbor Station)

5/12/10 Communication with Salem Police & Fire Officials

5/13/10 Communication with David Cody (Fire Chief), Captain Dennis Levasseur (Fire Department )

5/18/10 Communication with Susan Lynn Marallo (Facilities Manager, PerkinElmer, 35 Congress St)



Table 1-3: Salem Outreach and Consultation Meetings (Cont’d.)

Date Agency/Group

5/19/10 Meeting with Historic Commission

5/20/10 First Open House at the Salem Waterfront Hotel

6/19/10 Salem Chamber of Commerce Energy Fair

7/2/10 Mailed invitations to Open House to Jason Silva, David Knowlton, Captain Dennis Levasseur (Fire Department)

7/7/10 Meeting with Chief David Cody (Fire Chief), Captain Dennis Levasseur (Fire Department)

8/3/10 Telephone Meeting with Bob McCarthy (City Council President)

10/13/10 Meeting with Salem City Council

11/3/10 Meeting with David Knowlton (City Engineer)

12/9/10 Meeting with Salem Tree Warden

2011

2/15/11 Meeting with Representative John Keenan

2/17/11 Second Open House at the Salem Waterfront Hotel

4/11/11 Meeting with Derby Street Neighborhood Association

5/3/11 Meeting with Forrester Street Neighborhood Association

5/24/11 Meeting with Senator Berry, Representative Keenan, Mayor Driscoll

9/12/11 Meeting with Derby Street Neighborhood Association

2012

4/10/12 Meeting with Forrester Street Neighborhood Association

4/26/12 Press Release

4/27/12 Communication with Chamber of Commerce

6/9/12 Conference with Representative Keenan’s Chief of Staff

2013

2/6/13 Meeting with North Shore Chamber of Commerce, Representative Keenan, Mayor Driscoll, Footprint

2/28/13 Meeting with Conservation Commission

3/12/13 Meeting with Representative Keenan, Senator Lovely, Mayor Driscoll, Councilor McCarthy

3/12/13 Meeting with Footprint and Brown Rudnick, LLP to coordinate outreach efforts

3/28/13 Meeting with City Engineer, DPW, Tree Warden, Planning Department

3/28/13 Meeting with business community

4/2/13 Meeting with Neighborhood Associations

4/2/13 Meeting with Salem News Reporter

4/5/13 Mailed OH Invitation to all 300' abutters

4/9/13 Meeting with Salem News Editorial Board

4/10/13 Third Open House at the Hawthorne Hotel

4/10/13 Meeting with City Engineer, Representative from Mayor’s Office

4/10/13 Meeting with Assistant Harbormaster

4/10/13 Meeting with Board of Health Agent

4/10/13 Meeting with Senior Sanitarian

6/04/13 Tour of Similar Project with Representative Keenan

6/17/13 Meeting with Representative Keenan, Senator Lovely, Mayor Driscoll

6/17/13 Meeting with City Engineer

7/23/13 Meeting with Drew Russo of Congressman Tierney’s Office

8/28/13 Meeting with business community and Neighborhood Organizations



1.12 PROJECT TEAM

1.12.1 New England Power Company

NEP is a Massachusetts corporation doing business as National Grid. NEP is a wholly-owned

subsidiary of National Grid USA, which is itself a wholly-owned subsidiary of National

Grid plc. NEP is a transmission affiliate of National Grid plc and owns and operates

approximately 6,000 miles of interconnected electrical infrastructure in the Commonwealth of

Massachusetts.

1.12.2 Burns & McDonnell

Burns & McDonnell Engineering Company, Inc. (“BMcD”) is the engineering consultant for the

Project. Founded in 1898, BMcD is a full-service engineering, architectural, construction, and

environmental firm. Based in Kansas City, Missouri and employing approximately 4,000

professionals, BMcD plans, designs, permits, constructs, and procures transmission and

distribution, substation, and telecommunication systems for public power in every region of the

country. BMcD has performed program management, engineering, and construction management

services for multiple large-scale transmission line projects both underground and overhead in the

New England region. These projects have included the 70-mile Middletown-Norwalk project,

which contained 24 miles of 345 kV underground transmission line, and the Glenbrook Cables

project, which contained nine miles of double-circuit 115 kV underground transmission line. Both

projects were located in southwestern Connecticut. BMcD has also recently performed full

program management and engineering services for the Greater Springfield Reliability Project, a

primarily overhead transmission line project located in and around Springfield, Massachusetts.

1.12.3 Vanasse Hangen Brustlin, Inc.

Vanasse Hangen Brustlin, Inc. (“VHB”) is an 800-person engineering and environmental

consulting firm based in Watertown, Massachusetts. VHB’s engineers, scientists, planners, and

regulatory specialists are engaged in environmental analyses, modeling, licensing and

permitting for energy infrastructure projects throughout the Northeast. In recent years, VHB

and its staff have worked with clients to complete the permitting of: (1) National Grid’s

Northbridge-Uxbridge 115 kV Transmission Tap Project; (2) National Grid’s E-157

Transmission Line Project in Westborough; (3) National Grid’s Z-126 Transmission Line

Project in Millbury and Auburn; and (4) NSTAR’s 320-507 Line and 320-508 Line

Reconductoring Projects in Lexington and Waltham. In past years, VHB has also successfully

completed environmental permitting and licensing for a wide range of electric transmission,

distribution, and substation projects for major electric providers throughout New England.



1.12.4 Keegan Werlin LLP

Keegan Werlin LLP (“KW”) serves as regulatory counsel for the Project on permitting and

licensing matters. Based in Boston, the firm specializes in representing clients in all aspects of

energy, environmental, and regulatory processes. KW’s attorneys include former utility

regulators and attorneys from energy, environmental, and resource management agencies. The

firm’s clients include electric utilities, local gas distribution companies, interstate gas pipeline

companies, power developers, large electricity end users, and several government entities.

Attorneys in the firm have represented transmission companies and project developers in their

applications to the Siting Board and other permitting agencies for approval to construct electric

transmission lines, bulk generating facilities, and natural gas pipelines. In recent years, KW has

served as counsel to: (1) National Grid in relation to the permitting of transmission facilities

associated with the Interstate Reliability Project in Millbury, Sutton, Northbridge, Uxbridge,

and Millville; (2) NSTAR Electric in connection with the permitting for a 345 kV transmission

line and ancillary facilities located in Carver, Plymouth, Bourne, Sandwich, and Barnstable;

(3) NSTAR Electric in connection with the permitting for proposed modifications to an existing

switching station in Plympton; (4) NSTAR Electric in conjunction with National Grid in

connection with the permitting of upgrades to existing 115 kV underground transmission

facilities in Boston and Everett; (5) National Grid in relation to its permitting of transmission

facilities in the Towns of Groveland, West Newbury, Merrimac, and Amesbury; (6) Cape Wind

Associates, LLC in the permitting of its proposed 420 MW Wind Park and associated

transmission facilities; and (8) NSTAR Electric in connection with the permitting for three

345 kV transmission lines and ancillary facilities located in Boston, Stoughton, Canton, and

Milton. In past years, KW has also represented a variety of other non-utility generators, electric

and gas distribution companies, marketers and suppliers, large end users, and governmental and

educational institutions on electricity and natural gas issues in a wide array of energy,

regulatory, environmental, and permitting matters.

1.12.5 Energy Initiatives Group, LLC

Energy Initiatives Group, LLC (“EIG”) is a specialized group of experienced professionals that

provide project development, planning, strategy, execution, management, engineering, and

operations consulting in the areas of electric transmission, generation, distribution, transporta-

tion, and renewable energy services. EIG provides these services to utility companies, project

developers, regulatory agencies, energy companies, financial organizations, transportation

companies, government agencies, and other organizations in the energy industry.



1.12.6 Exponent

Exponent Inc., based in New York City, is a multidisciplinary organization of scientists,

physicians, and engineers that performs in-depth investigations including evaluation of complex

human health and environmental issues. Exponent Inc. has been contracted to assess the effect of

the Project on magnetic field levels in the Project vicinity. Their study includes an assessment of

Project compliance with exposure guidelines and regulatory guidance documents regarding

exposure to electric and magnetic fields.

1.12.7 Bowditch & Dewey, LLP

Bowditch & Dewey, LLP (“B&D”), with offices in Boston, Framingham, and Worcester,

serves as zoning counsel for the Project in Massachusetts. B&D is a general practice law firm

founded in 1914 and employs lawyers having substantial experience in complex permitting

matters. B&D has assisted the National Grid team in the review and analysis of municipal

zoning and general bylaws and analyzed the zoning and other municipal requirements for the

Project.

1.12.8 Haley & Aldrich, Inc.

Haley & Aldrich, Inc. (“H&A”) is the trenchless crossing consultant for the Project. Since

1957, H&A has provided geotechnical engineering, environmental consulting, and construction

services throughout New England, as well as on complex projects nationally. We currently

have over 500 staff members in 27 offices throughout the U.S. with our corporate headquarters

located in Burlington, Massachusetts. H&A routinely provides underground solutions for

Industrial, Commercial Real Estate & Development, and Energy & Infrastructure clients.

During the past decade, our Energy & Infrastructure Group has provide specialty engineering

services on a wide variety of capital improvement projects for numerous energy utilities and

independent power producer clients H&A has performed geotechnical engineering services for

multiple large-scale electric and natural gas transmission line projects in the northeast. These

projects have included the 70-mile Middletown-Norwalk project, which contained 24 miles of

345 kV underground transmission line, and five trenchless crossings. H&A is currently

designing seven trenchless crossing for PSE&G on their upgrade program in Camden County,

New Jersey. H&A has also recently performed geotechnical engineering services for support of

overhead electric transmission lines on the Interstate Reliability and Greater Springfield

Reliability Projects under the NEEWS program in Connecticut and Massachusetts.

Additionally, H&A has designed and overseen construction of gas transmission lines as part of

the Tennessee Gas Pipeline ConneXion project in western Massachusetts and pipelines for

Spectra Energy, National Grid and other northeast utility systems.



1.13 CONCLUSION

As demonstrated herein, NEP has shown that the Project satisfies the Siting Board’s governing

standards under G.L. c. 164, §§ 69H, 69J in that it will provide for a reliable energy supply with

a minimum impact on the environment at the lowest possible cost. The replacement of the

Cables with new higher capacity facilities is needed to address existing asset conditions and

future transmission requirements in the greater Salem area. The Project has been shown to be

superior to an array of potential alternatives from a reliability, cost, and environmental impact

perspective. NEP has identified and analyzed a reasonable set of potential alternative routes,

compared those routes based on appropriate criteria, and selected a Preferred and Noticed

Alternative route that best achieve NEP’s goals of reliability, constructability, and minimization

of cost and environmental impacts.

Moreover, as described above and as demonstrated throughout this Analysis, the Project will

“serve the public convenience and is consistent with the public interest,” consistent with the

requirements of Section 72. Specifically, there is a need for the Project to address system

reliability requirements; further, NEP extensively considered potential alternatives to and the

environmental impacts of the proposed Project, and appropriate mitigation has been proposed.

As such, the Project meets the standards applicable under Section 72 for authorization to

construct and operate its transmission facilities. For the same reasons, pursuant to the

requirements of G.L. c. 40A, § 3, NEP is a “public service corporation” and the zoning

exemptions sought for the Canal Street Substation are required and “reasonably necessary for

the convenience or welfare of the public.”

For these reasons, NEP has demonstrated that the Project is consistent with Siting Board and

DPU standards and precedent and requests the Siting Board’s approval to construct and operate

the Project.

Section 2.0: Project Need


2.0 PROJECT NEED

2.1 INTRODUCTION

This section discusses NEP’s determination that the existing Cables require replacement because

they are approaching the end of their service lives and cannot fully meet the capacity require-

ments of the proposed new Footprint power generation facility. Section 2.2 summarizes the

relevant Siting Board precedent for determining whether a transmission facility is needed for

reliability, economic efficiency and/or environmental impact purposes, or to interconnect a new

or expanded jurisdictional generating facility to the transmission system. Section 2.3 describes the

Salem Area Transmission System and provides information regarding the role of the S-145E and

T-146E lines within that system. Section 2.4 presents the current asset condition and operating

history of the Cables, which demonstrate that the Cables need to be replaced for reliability, cost,

and environmental reasons. Section 2.5 presents NEP’s analysis establishing the need for

additional transmission capacity from the Cables, in the very short term if the Footprint

generating facility is constructed, or in the longer term in the event that the proposed generating

facility is not constructed. Section 2.6 presents the conclusion regarding the need for the Project.

Currently, the S cable is more than 40 years old and has a documented history of dielectric fluid

releases, resulting in loss of cable availability and the need to locate, repair, and remediate

releases within City streets. In 2005, in response to these fluid releases, NEP commissioned

KEMA Consulting (“KEMA”) to assess the overall condition and remaining useful life of the

S cable. KEMA ultimately recommended that NEP actively consider options for the

replacement of the S cable. NEP has also determined that the more-than-60-year-old T cable

has similar asset condition issues and, in light of its age, is in need of replacement in the near

term. Thus, as explained in greater detail below, replacement of these Cables is required in

order to address reliability, cost, and environmental concerns.

In determining the size of the replacements for the Cables, NEP analyzed the capacity needs of

the proposed Footprint facility (which is scheduled to commence commercial operation in June

2016) under a range of operating and load conditions, consistent with the ongoing System Impact

Study (“SIS”) for that project. Given the extant need to replace the Cables, NEP also considered

what the area transmission system would require in the event that the Footprint generating facility

was not constructed. Ultimately, NEP concluded that new Cables with summer long-term

emergency (“LTE”) ratings of approximately 400 megavolt amperes (“MVA”) will best meet the

needs of the area both with and without the proposed Footprint generating facility over the long

term.

2.2 SITING BOARD PRECEDENT

Under G.L. c. 164, §§ 69H and 69J, the Siting Board is charged with: (1) providing a necessary

energy supply; (2) at least cost; and (3) with a minimum impact on the environment. In carrying

out its statutory mandate with respect to proposals to construct energy facilities in the

Commonwealth, the Siting Board evaluates whether there is a need for additional energy



resources to meet: (1) reliability objectives; (2) economic efficiency objectives; or

(3) environmental objectives. See, e.g., New England Power Co., EFSB 10-1/D.P.U. 10-

107/D.P.U. 10-108, at 5 (2012); NSTAR Electric Co., EFSB 10-2/D.P.U. 10-131/D.P.U. 10-132,

at 4 (2012); New England Power Co., EFSB 09-1/D.P.U. 09-52/D.P.U. 09-53, at 4-5 (2011);

Western Massachusetts Electric Co., EFSB 08-2/D.P.U. 08-105/08-106, at 8 (2010). According-

ly, the need for a particular facility is demonstrated by showing need on any (or all) of these three

bases. New England Power Co., EFSB 10-1/D.P.U. 10-107/D.P.U. 10-108, at 5; NSTAR Electric

Co., EFSB 10-2/D.P.U. 10-131/D.P.U. 10-132, at 4; New England Power Co., EFSB 09-1/D.P.U.

09-52/D.P.U. 09-53, at 4-5; Western Massachusetts Electric Co., EFSB 08-2/D.P.U. 08-105/08-

106, at 8.

The Siting Board has acknowledged that the Massachusetts electric system is integrated with

the regional electric system, creating a link between Massachusetts and the surrounding region

in terms of system reliability. See Cabot Power Corp., 7 DOMSB 233, 248-49 (1998). The

Siting Board has also noted the inherent reliability and economic benefits that flow to

Massachusetts as a result of this integration. Id. Where a project proponent is basing need on

reliability objectives, the Siting Board evaluates the reliability of the electric system in light of

changes in demand or supply or in the event of certain reasonably foreseeable contingencies.

Cabot Power Corp., 7 DOMSC at 249; New England Electric System, 2 DOMSC 1, 9 (1977);

Eastern Utilities Associates, 1 DOMSC 312, 316-318 (1977).

Further, when jurisdictional transmission facilities are proposed to interconnect to a new or

expanded generating facility, the Siting Board evaluates the need for the transmission

interconnection based upon a showing that: (1) the existing transmission system is inadequate

to interconnect the new or expanded generator; and (2) the new or expanded generator is likely

to be available to contribute to the regional energy supply. Cape Wind Associates, LLC and

Commonwealth Electric Company d/b/a NSTAR Electric, 15 DOMSB 1, at 29 (2005) (“Cape

Wind”); see Cambridge Electric Light Company, 12 DOMSB 305, at 318 (2001). A primary

purpose of this standard is to ensure that a proposed transmission line is not built unnecessarily.

Cape Wind, at 28-29. If the generator is planned and subject to the Siting Board’s jurisdiction,

that showing may be made by reference to the Siting Board’s approval of the proposed

generating facility. Cape Wind, at 29.

2.3 DESCRIPTION OF SALEM AREA TRANSMISSION SYSTEM

The electric transmission system in Salem consists of four 115 kV transmission lines connected

to a 115 kV switchyard at the Salem Harbor Substation. Two of these lines, the S-145E and

T-146E, run in a westerly direction from the Salem Harbor Substation to the Wakefield

Junction Substation in Wakefield, Massachusetts. The Cables that are the subject of this filing

make up approximately 1.5 miles of the S-145E and T-146E transmission lines between the

Salem Harbor Substation and the Canal Street Substation. From the Canal Street Substation, the

S-145E and T-146E lines rise from underground to proceed overhead to the Railyard and West

Salem Substations, and continue on to Wakefield Junction. The other two 115 kV transmission

lines, the B-154S and C-155S, run in a northerly direction from Salem Harbor Substation to the



Danvers Municipal Substation in South Danvers, where they change designation to the B-154N

and C-155N lines, respectively, and then ultimately connect to the NEP Substation at Ward Hill

in Haverhill. The existing summer ratings of the Cables and the S-145E and T-145E lines are

listed in Appendix 2-1.

At the center of the Salem area transmission system is the Salem Harbor generating station,

formerly owned by Dominion New England, Inc. and now owned by Footprint. The Salem

Harbor generating station, with approximately 740 MW of net installed generating capacity, is

slated for retirement in 2014. On August 3, 2012, Footprint filed a petition with the Siting Board

for approval to construct and operate a natural gas–fired, combined-cycle, quick-start generating

facility at the current Salem Harbor generating site. Footprint’s plan involves the demolition and

remediation of the existing facilities at Salem Harbor and the construction of a new generating

facility with a proposed on-line date of June 2016.

NEP is currently in the process of increasing the capacity of certain overhead 115 kV

transmission lines in the area to ensure that reliable transmission service will be maintained in

the Merrimack Valley and North Shore areas following the retirement of the Salem Harbor

generating facility. Specifically, NEP is reconductoring:

· The S-145/T-146 lines from Tewksbury #22 Substation to the North Reading Tap;

· The B-154N/C-155N lines from King Street Tap to the South Danvers #42 Substation; and

· The Y-151 line from Tewksbury Junction to the West Methuen #63 Substation.

Figure 2-1 shows the approximate location of the Salem Harbor Substation and the S-145E,

T-146E, B-154S, and C-155S lines. Figure 2-2 shows, in schematic form, the major

transmission lines in the Salem area including those presented in Figure 2-1.

2.4 S AND T CABLE ASSET CONDITION AND OPERATING HISTORY

NEP monitors and assesses the condition of its assets on an ongoing basis. These assessments

have resulted in the finding that the aged Cables need to be replaced.

The S and T Cables, installed in 1971 and 1951, respectively, are self-contained fluid-filled

(“SCFF”) cable systems. SCFF cable systems use a pressurized dielectric fluid as part of their

high voltage insulation. SCFF cable systems can operate reliably for decades with very few

forced outages. However, in some cases, a cable’s integrity can be compromised by corrosion,

contractor damage, or other external mechanical forces, resulting in the release of dielectric

fluid to the immediate surrounding environment. Such releases must be detected, located, and

repaired as quickly as possible to ensure system reliability and to minimize releases to the

environment. Both cable systems have experienced fluid releases; releases on the S cable have

become more frequent within the last ten years.



The T cable system has not experienced as many releases as the S cable system. However,

replacement parts for both Cables’ associated accessories (fluid alarms, fluid reservoirs, etc.)

are no longer manufactured and therefore are not readily obtainable. This causes significant

difficulties when performing routine maintenance and repairs to both cable systems. SCFF

cable was the first commercially successful transmission cable design at 115 kV and higher

voltages. However, this technology became less popular in the U.S. as pipe-type and solid

dielectric cable designs evolved. In the 1990s, pipe-type cable became the dominant

underground technology in the United States. More recently, solid dielectric cable designs

(cross-linked polyethylene and ethylene propylene rubber) have become popular designs for

115 kV underground cable installations. As these other types of cable have become more

prominent, the number of manufacturers of SCFF cables and their associated accessories has

substantially declined worldwide. Therefore, it is increasingly difficult to obtain replacement

materials to maintain the SCFF lines. Similarly, the availability of experienced craftsmen

proficient in the repair of SCFF cable systems has also significantly declined, particularly for

repairs of the S cable. There are currently only two companies in the U.S. with craftsmen

capable of performing repairs on this cable. When these craftsmen are committed to other

projects, NEP reaches out to firms in Canada or the United Kingdom for personnel capable of

completing these repairs.

2.4.1 S Cable Asset Condition and Operating History

The S cable is a medium-pressure fluid-filled cable system, which uses a pressurized dielectric

fluid as part of the overall insulation system. The circuit consists of three single-phase cables

constructed with a hollow core conductor to provide a channel for the dielectric fluid, a lapped

paper insulation impregnated with dielectric fluid, a corrugated aluminum sheath that serves as

the cable metallic shield and forms a hermetic seal, and a high-density polyethylene jacket for

corrosion control. The system is pressurized by fluid reservoirs situated at both ends of the

cables. The cable system operates in a range between 15 and 25 pounds per square inch (“psi”).

The S cable is direct-buried within the public roadway network in Salem and has a concrete cap

installed over it to provide mechanical protection. The following diagram depicts a cross

section of the S cable.



S Cable Cross Section

The S cable has experienced at least 24 hydraulic failures with subsequent dielectric fluid

releases since its installation in 1971, with 13 (more than 50 percent) of these releases occurring

in the past ten years. These releases were reported to the DEP where required pursuant to

G.L. c. 21E. The cost associated with locating, repairing, and remediating these fluid releases

has been significant: since 2003, NEP has spent more than $1.3 million on activities (locating,

repairing, and environmental remediation) associated with hydraulic failures on the S cable.

Table 2-1 lists the number of dielectric fluid releases, quantity of fluid released, and the

duration of out-of-service time for the S cable from 2000 to 2012.



Table 2-1: S Cable Outage Durations and Fluid Releases

Year

Number of Dielectric

Fluid Releases

Duration S Cable

Out-of-Service

(Hours)

Dielectric Fluid Release

(Gallons)

2000 1 7.5 <10

2001 0 0 0

2002 1 275.5 475

2003 4 467 204

2004 5 199 491

2005 1 48 <10

2006 1 57 239

2007 0 0 0

2008 0 0 0

2009 1 55 115

2010 1 320 <10

2011 0 0 0

2012 0 0 0

The causes of these hydraulic failures have included: (1) cracked solder wipes at joint casings

and terminations; (2) corrosion of the aluminum sheath due to jacket damage; (3) failure of

reservoir piping/fittings; (4) deterioration of the rubber gasket located in the air terminations;

(5) cracks in the joint’s epoxy sheath insulator; and (6) in two cases, an accidental third-party

breach. The failure mechanisms are a function of the age of the cable; the thermal and

mechanical behavior of the cables under load cycles, known as thermo-mechanical bending

(“TMB”); and a potentially compromised environment around the cables. Over time, TMB can

weaken or damage cable insulation and other cable components; in the S cable, TMB has

resulted in numerous solder wipe failures which will inevitably continue over time.

In addition, the construction of the cables, particularly the aluminum sheath, contributes to the

failure mechanisms. Although aluminum is corrosion-resistant when installed above ground, it

corrodes quickly when it comes in contact with soil following deterioration of the cable’s

polyethylene outer jacket. The outer jacket is tested annually to identify deterioration; however,

jacket failure can occur between inspection cycles. Given the S cable’s age and operating

history, it is likely that jacket failure and sheath corrosion will continue to occur on the S cable.



Table 2-2: S Cable Recurring Maintenance History

Year Location Description of Problem

1973 Joint #3 C Phase Solder Wipe Leak


1987 Salem Harbor Yard Piping Leak

1987 Derby @ Congress A Phase Sheath Repair

1989 Derby @ Congress A Phase Solder Wipe Leak

1991 New Derby Street C Phase Third Party Damage

1992 Joint #1 B Phase Solder Wipe Leak


1994 Derby @ Congress B Phase Corrosion Leak

2000 Canal St. Terminal Termination Leaks

2002 Derby @ Lafayette B Phase Corrosion Leak

2003 Canal St. Terminal Termination Leaks

2003 Joint #2 A Phase Solder Wipe Leak

2003 Derby @ Congress A Phase Corrosion Leak


2004 Canal St. Terminal Termination Leak

2004 Salem Harbor Yard Cracked Reservoir Fitting


2004 Joint #6 B Phase Wipe & Insulator

2004 Salem Harbor Yard Cracked Reservoir Fitting

2005 Canal St. Terminal Termination Leak

2006 Derby @ Lafayette B Phase Solder Wipe Leak

2009 Joint #6 B Phase Wipe & Insulator

2010 10 Ft. west of Joint #6 B Phase Third Party Damage

Table 2-2 provides a summary of the S cable repairs since 1973. The process of responding to and

remediating these releases and repairing the cables is complex and time consuming since it

requires the involvement of Licensed Site Professionals and field personnel trained to handle the

dielectric fluid and affected soils. When releases occur, NEP works diligently and expeditiously

in coordination with the relevant government agencies to assess and remediate the affected area.

Because the underground cable is not accessible for visual inspection, specialized release-locating

techniques must be employed to locate the fluid release. These activities can be prolonged and



labor-intensive, potentially resulting in further fluid loss to the environment. Locating the fluid

releases may require excavation at multiple locations in the public way to expose the cable. These

excavation activities result in inconveniences to residents and businesses due to traffic delays,

parking restrictions, and noise. There is also a higher risk for inadvertent damage to the cables

during excavation.

During repairs, the cable is unavailable for service. Because releases must be addressed

promptly for environmental and cable-operation reasons, the outages are frequently “forced” as

opposed to scheduled. Depending on the time of year, a forced outage can negatively affect the

reliability of the balance of the transmission system and expose the system to further reliability

issues if other contingencies occur.

In light of the S cable’s extensive history of dielectric fluid releases, in 2005 NEP commissioned

KEMA to assess the remaining useful life of the S cable. At the end of the study, KEMA

recommended that NEP actively consider options for the replacement of the S cable. Since that

time, NEP has conducted an analysis of options for replacing the S cable, resulting in the current

proposal.

The S cable is reaching the end of its useful life. It has been the subject of 13 dielectric fluid

releases within the last ten years and the Company cannot predict the timing or frequency of

future releases. These releases require response action by NEP in order to address impacts to the

environment. Further, the repair and remediation associated with such releases negatively affect

the reliability of the transmission system serving Salem and the surrounding area and have had

significant cost consequences. Given the age and operating history of the S cable, NEP cannot

reasonably wait until the cable experiences a catastrophic failure before undertaking the proposed

replacement. Consequently, NEP has determined that there is an immediate need to replace the

existing S cable and to then remove the existing S cable to prevent future dielectric fluid leaks.

2.4.2 T Cable Asset Condition and Operating History

The T cable is an 8–12 psi low-pressure fluid-filled cable system, another subset of SCFF

cables, consisting of two cables per phase (designated the T-146X and T-146Y). Each single-

phase cable consists of a hollow core conductor that provides a channel for the dielectric fluid,

lapped paper insulation impregnated with dielectric fluid, and a lead sheath that serves as a

metallic shield and forms the hermetic seal. The system was installed in 1951 and originally

operated as two separate circuits. Since the S cable was installed in 1971, the T-146X and

T-146Y have been operated in parallel as a single circuit. The following diagram depicts a cross

section of the T cable.



T Cable Cross Section

Table 2-3 provides a summary of the maintenance history on the T cable over the years.

Although the T-146X and T-146Y have performed reasonably well over their more-than-60-

year operating history, the T cable has had some reliability issues, with most repairs involving

the stop joints between the two hydraulic sections of the cable system. These repairs are mostly

the result of cracks developing in the stop joint’s epoxy cone insulators which are used to

isolate the hydraulic sections. The line experienced one electrical failure in 1991 as a result of a

failed splice on the T-146X cable.



Table 2-3: T Cable Recurring Maintenance History

Year Cable Description of Problem

1955 T-146Y A Phase Stop Joint

1959 T-146X B Phase Stop Joint

1959 T-146Y C Phase Stop Joint


1963 T-146Y C Phase Stop Joint

1973 T-146X C Phase Stop Joint


1976 T-146Y A Phase Stop Joint

1991 T-146X B Phase Splice Failure

1996 T-146Y B Phase Stop Joint

1998 T-146X C Phase Stop Joint

2007 T-146X B Phase Normal Joint

The design of the T cable, like that of the S cable, subjects it to deterioration as it ages due to

TMB and corrosion of the cable’s lead sheath. Over time, the thickness of the lead sheath

deteriorates as a result of corrosion,2 and the lead may become brittle, resulting in a loss of

mechanical strength and eventual sheath failure. Once the sheath is compromised, moisture can

enter the paper insulation and electrical failure follows shortly thereafter.

NEP also is concerned about its future ability to address the aging and deterioration of the

cable system’s fluid accessories (reservoirs and alarms). There has been a steady decrease in

the number of manufacturers of these accessories. As the cable system continues to age,

obtaining replacement parts to perform routine maintenance and repairs is becoming

increasingly more difficult and expensive. For these reasons, NEP has concluded it is time to

replace the T cable before it experiences a more serious failure and to then remove the

existing T cable from the duct bank.

2.4.3 Conclusion on Asset Condition

Based upon the factors discussed above, NEP has concluded that both Cables will continue to

experience failures, resulting in adverse reliability, cost, and environmental consequences.

2 NEP uses an active cathodic protection system consisting of an anode bed and rectifier to limit the amount of corrosion on the lead sheath.



Moreover, the ability to repair both Cables going forward is significantly diminished due to the

very limited number of manufacturers of these cables and accessories and the limited

availability of craftsmen proficient in the repair of these cables. Further, the need for ongoing,

time-consuming, and costly repairs not only negatively affects the reliability of the Cables, but

can also be disruptive to the community when these repairs need to occur in active City streets.

Accordingly, the age and condition of these Cables require their immediate replacement in

order to maintain the reliability of the transmission system in this area, to avoid future

environmental incidents, and to minimize the cost of maintenance and repair of these important

facilities.

2.5 NEED FOR ADDITIONAL TRANSMISSION CAPACITY

Given the need to replace the Cables, NEP conducted an analysis of the transmission needs in the

region under two separate scenarios to determine the appropriate scope of any replacement

project. The first scenario evaluated the capacity that would be required in order to interconnect

and integrate the proposed Footprint generating facility into the existing transmission system

under a range of operating conditions. The second scenario evaluated the long-term needs of the

regional transmission system without generation at the Salem Harbor substation. Under each

scenario, there is a need to increase the capacity of the Cables in order to ensure the long-term

reliability of the regional transmission system. These scenarios have been analyzed under the

applicable ISO-NE and NEP planning criteria and guidelines. The analyses are described below.

2.5.1 Footprint Capacity Needs

Footprint proposes to construct a new generating facility at the Salem Harbor site with a

proposed on-line date of June 2016. Footprint intends to interconnect to NEP’s transmission

system at the existing Salem Harbor 115 kV Substation through the addition of two new

115 kV breaker positions. To that end, on January 12, 2012, Footprint submitted to ISO-NE an

Interconnection Request and a request for an SIS for the interconnection of a 715 MW3 gas-

fired, combined-cycle facility under the ISO-NE Open Access Transmission Tariff, Schedule

22—Standard Large Generator Interconnection Procedures (“LGIP”). The LGIP is attached as

Appendix 2-2.

ISO-NE asked NEP to complete the SIS on its behalf. The SIS was conducted pursuant to the

LGIP and in accordance with the following procedures:

3 Although Footprint’s petition to the Siting Board seeks approval for a 692 MW generating facility, Footprint’s

application to ISO New England for a Large Generator Interconnection Agreement requested an SIS for a 715 MW generating facility. The Company’s need analysis in this proceeding has therefore been conducted based on the 715

MW capacity contemplated by Footprint’s interconnection request.



· Northeast Power Coordinating Council Reliability Reference Directory #1—Design

and Operation of the Bulk Power System (Appendix 2-3);

· Interconnection Procedures contained in the LGIP;

· ISO-NE Planning Procedure No. 3—Reliability Standards for the New England Area

Bulk Power Supply System (Appendix 2-4);

· ISO-NE Planning Procedure No. 5-3—Guidelines for Conducting and Evaluating

Proposed Plan Application Analyses (Appendix 2-5);

· ISO-NE Planning Procedure No. 5-6—Scope of Study for System Impact Studies under

the Generation Interconnection Procedures (Appendix 2-6);

· ISO-NE Operating Procedures 12 (Appendix 2-7); and

· National Grid Transmission Group Procedure, TGP 28, Transmission Planning Guide

(Appendix 2-8).

NEP has completed the steady state analyses that will serve as a basis for the SIS, and has filed

a draft of the steady state report with ISO-NE for review. As part of the SIS, NEP conducted

steady state analyses that identified the capacity needed on the Cables to reliably serve a

715 MW Footprint facility. These studies included “All Lines In,” N-1, and N-1-1 contingency

analyses performed under summer peak load and shoulder load conditions. NEP’s study results

demonstrate that the existing Cables do not have sufficient capacity to allow the proposed

Footprint facility to generate at full capacity.

NEP’s study methodology and findings to date are summarized below. NEP will provide a

copy of the draft Steady State Report as soon as it is available for release. NEP will provide a

copy of the SIS when it has been finalized through the New England Power Pool (“NEPOOL”)

Committee process.

Steady State Load Assumptions

Pursuant to the requirements of the LGIP, System Impact Studies are conducted using projected

loads as of the proposed commercial operation date of a project. The proposed commercial

operation date of the Footprint generating facility is May 31, 2016; consequently, power flow

cases representing 2016 peak and shoulder load conditions were used in the study. The peak

load is based on the 2016 summer peak 90/10 load presented in the CELT 2012 forecast, and

the shoulder peak load is calculated as 75 percent of the summer 50/50 peak load. Consistent

with ISO-NE practice, modeled peak load levels include 100 percent of passive demand

response and 75 percent active demand response. Modeled shoulder load levels include

100 percent of passive demand response but no active demand response, since active demand

response resources are not typically called at off-peak load levels. Table 2-4 shows the peak

and shoulder peak load levels used for the SIS.



Table 2-4: New England Load and Losses for 2016 (MW)

2016 Case

2012 CELT

Load & Losses

(MW)

Active DR

(MW)

Passive DR

(MW)

Total

(MW)

Peak 32,397 1,152 1,645 29,600

Shoulder 22,964 0 1,233 21,731

Projects Included in the Base Case

Because the following projects have ISO-NE PPA determinations, they were assumed to be in-

service for purposes of the SIS:

· Reconductoring the overhead portion of the O-167 115 kV line from Mystic Station to

Everett, MA;

· Upgrading the 115 kV cable section of 423-515/O-167 from Mystic Station to Everett, MA;

· Reconductoring the S-145/T-146 115 kV lines from Tewksbury, MA to the North Reading Tap;

· Reconductoring the Y-151 115 kV line from Tewksbury Junction to West Methuen, MA;

· Reconductoring the B-154N and C-155N 115 kV lines from the King Street Tap to South

Danvers, MA;

· Maine Power Reliability Projects; and

· The NEEWS Interstate Reliability Project, Greater Springfield Reliability Project, and

Rhode Island Reliability Project.

Projects associated with ISO-NE’s ongoing Greater Boston Study were not included because

they have not received ISO-NE PPA determinations.

Power Flow Cases

Eight power flow cases were studied for each load level. These power flow cases represented

varying combinations of stress on the north-south, southeast Massachusetts/Rhode Island

(“SEMA/RI”), and east-west interfaces. Table 2-5 summarizes the five summer peak interface

cases studied. Table 2-6 summarizes the three shoulder peak cases studied.



Table 2-5: Interface MW Levels in Summer Peak Cases1

Interface SP1 SP2 SP3 SP4 SP5

North to South High (2718) High (2632) High (2455) High (2656) Low (1242)

SEMA/RI Export High (3445) High (3334) High (3419) Low (2277) High (3483)

East to West High (2671) Low (1430) Low (1959) Low (1574) Low (1828)

1 Difference between SP2 and SP3 reflects different generation units dispatched in the northeast Massachusetts/ Boston area

Table 2-6: Interface MW Levels in Shoulder Peak Cases

Interface SH1 SH2 SH3

North to South High (2408) High (2698) Low (1473)

SEMA/RI Export High (3513) Low (2533) High (3426)

East to West High (3443) High (2689) High (2400)

“All Lines In” Analysis

The “All Lines In” analysis tested the impact of the Footprint generating facility on the power

system within the study area with all elements in service (i.e., no contingencies). In order for

the Footprint generating facility to reliably be dispatched at full capacity, all system elements in

the study area must be within their summer normal ratings under these conditions in a steady-

state power flow assessment using each of the eight base cases at summer peak load and

shoulder load.

NEP conducted an “All Lines In” steady state analysis to determine the required cable ratings

under normal conditions. The study determined that, under the worst-case dispatch at 2016

shoulder load conditions, the required normal rating for the Cables would be 233 MVA per

cable. This constitutes the minimum acceptable normal rating for the replacement cables with

the Footprint generating facility in service. As can be seen by comparison with Appendix 2-1,

the existing T cable does not have sufficient capacity to fully serve the proposed Footprint

generating facility even under “All Lines In” conditions.

N-1 Analysis

In the N-1 analysis, a steady state power flow assessment was conducted using each of the eight

base cases to determine the thermal and voltage impacts of the Footprint generating facility on the

performance of the power system under contingency conditions within the study area. In order for

the Footprint generating facility to be allowed to routinely dispatch at the full capacity studied, the

area transmission system must be able to withstand N-1 contingencies under both summer peak



load and shoulder load conditions. Beginning with “All Lines In,” the impact of a single

transmission system event (an N-1 contingency) was evaluated with the Footprint generating

facility in service. Tables 2-7 and 2-8 below show the projected loading on the Cables for the

worst-case N-1 contingency event under each of the eight power flow cases described above.

Loadings that exceed the LTE ratings of the existing Cables are shown in red.

Table 2-7: Summer Peak Loading on S and T Cables in

N-1 Contingency Conditions

Monitored

Element SP1 SP2 SP3 SP4 SP5

S Cable 343 MVA* 359 MVA* 349 MVA* 341 MVA* 362 MVA*

T Cable 345 MVA* 362 MVA* 352 MVA* 343 MVA* 366 MVA*

* Loading exceeds the LTE rating of the existing cable

Table 2-8: Shoulder Loading on S and T Cables in

N-1 Contingency Conditions

Monitored

Element SH1 SH2 SH3

S Cable 362 MVA* 371 MVA* 347 MVA*

T Cable 364 MVA* 375 MVA* 351 MVA*

* Loading exceeds the LTE rating of the existing cable

As the tables show, the Cables overload under certain N-1 contingencies for all summer peak

load and shoulder load cases.4 Thus, there is a need for additional cable capacity (beyond the

capacity of the existing Cables) to interconnect the proposed Footprint generating facility based

on the results of the N-1 steady state analysis.

N-1-1 Analysis

The area transmission system must also be able to withstand a second contingency while keeping

element loading within LTE ratings following an initial element out under both summer peak and

shoulder load conditions. This is referred to as an “N-1-1” analysis. In an N-1-1 analysis, certain

limited system adjustments are allowed between the initial element out and the application of the

second contingency, including generation re-dispatch (ramping up or down of generation), so

long as total re-dispatch is kept within MW limits of ten-minute reserves. Under several N-1-1

4 The magnitude of these overloads can be determined by comparing the loadings provided in Tables 2-7 and 2-8 with the LTE ratings of the existing Cables as presented in Appendix 2-1.



contingency events, the Footprint generating facility would be required to ramp down its output

after the first contingency to keep the Cables within thermal ratings. Table 2-9 lists the facilities

that were studied as the first element out.

Table 2-9: First Element out of the N-1-1 Contingencies

345 kV Lines Out of Service 115 kV Lines Out of Service Transformers Out of Service

326 Sandy Pond–Scobie S-145 Tewks–Wkfld Jct Wakefield Junction T1

337 Sandy Pond–Tewks S-145E SH–Wkfld Jct Wakefield Junction T2

338 Tewks–Woburn T-146 Tewks–Wkfld Jct Wakefield Junction T3

339 Tewks–Wkfld Jct T-146E SH–Wkfld Jct Wakefield Junction T4

349 Wkfld Jct–Mystic B-154N King Street–S Danvers West Amesbury T2

394 Seabrook–Ward Hill B-154S S Danvers–SH Ward Hill T3

397 Ward Hill–Tewks C-155N King Street–S Danvers Ward Hill T4

351 Mystic–Cambridge C-155S S Danvers–SH Ward Hill T5

G-133E Ward Hill–E Methuen Mystic Autotransformer

G-133W E Methuen–W Methuen Woburn Autotransformer

NEP’s analysis indicates that the worst N-1-1 contingencies involve the loss of either the

S-145E line or the T-146E line, followed by the loss of one of a number of other transmission

lines. For the worst case, the loading on the cable left in service would be 647 MVA. For the

second-worst case, the loading on the remaining cable would be 511 MVA. The third-worst

case would result in the remaining cable being loaded to 475 MVA. Loading on the Cables

would exceed the LTE ratings of the existing Cables for several other contingency pairs.

The impact of these N-1-1 contingencies can be addressed in either of two ways. First, the

Cables could be rebuilt with LTE ratings of at least 647 MVA each, so that each cable would be

able to accommodate the post-contingency loadings. Alternatively, the Cables could be built

with lower LTE ratings if Footprint were willing to ramp down its generating facility following

the first contingency loss of certain transmission facilities.5 After discussion with NEP and

ISO-NE, Footprint chose to ramp down its units under certain contingencies and load

conditions, allowing the new Cables to be built with an LTE of approximately 400 MVA. As

evidenced by the comparative results for peak load and shoulder load, the nature of flows out of

Salem Harbor on a contingency is such that growth of local area load will serve to decrease the

5 ISO-NE determined that per ISO-NE Planning Procedure 5-6—Scope of Study for System Impact Studies under the Generation Interconnection Procedures, paragraph 5, manually ramping down of the resource under study is an acceptable condition.



loading on the cables over time. Thus, acceptable loading for the initial in-service year of the

generation is expected to produce acceptable loading in future years.

Conclusions

NEP conducted a SIS for the proposed Footprint generating facility pursuant to Schedule 22 of

the ISO-NE Open Access Transmission Tariff. The SIS is currently in draft form, as it has not

yet been reviewed by all relevant NEPOOL committees. However, NEP has completed the

steady state analyses on a draft basis and has a high level of confidence in its results. These

results indicate that the normal rating of the existing T cable is insufficient to fully serve the

proposed Footprint generating facility under “All Lines In” conditions, and that the LTE ratings

of the existing Cables are insufficient to avoid thermal overloads under N-1 conditions. Thus,

there is a need for additional cable capacity to reliably interconnect the proposed Footprint

generating facility.

In addition, NEP’s analysis demonstrated that a much higher LTE rating of at least 647 MVA

would be required for each cable in order to allow Footprint to generate at full capacity under

all N-1-1 contingencies in all load conditions. However, Footprint has chosen to ramp down its

generation under certain contingencies and load conditions, allowing the new Cables to be built

with an LTE of approximately 400 MVA.

Based upon the factors above and in accordance with Siting Board precedent, the existing

transmission system is inadequate to meet the capacity needs required to interconnect Footprint’s

proposed generating facility. See Cape Wind, at 28-29. Moreover, Footprint’s petition before the

Siting Board is currently undergoing review and, if approved, that generating facility is proposed

to provide generation resources to the region by June 2016. See id. For these reasons, NEP’s

proposed replacement of the Cables with increased capacity cables is necessary to serve the

Footprint generating facility in accordance with Siting Board precedent. See id.

2.5.2 Transmission System Needs without Footprint

In addition to the analysis described above, NEP conducted steady state analyses that identified

the capacity needed on the Cables to reliably serve the area load in the absence of the Footprint

generating facility. The purpose of this analysis was to ensure that the replacement Cables are

sized to address system load and capacity requirements even if the Footprint generating facility

does not go forward, thereby avoiding a series of potential construction projects over time to

increase the capacity of the cables as load continues to grow in the Salem area in the future.

Similar to the analysis with the Footprint generating facility, these studies include “All Lines

In,” N-1, and N-1-1 contingency analyses performed under summer peak and shoulder load

conditions. NEP’s study methodology and findings are summarized below. A table showing the

load flow results for the “All Lines In” cases and for the worst N-1 and N-1-1 contingencies is

attached at Appendix 2-9.



Steady State Load Assumptions

The same load assumptions used in the Footprint analysis were used for this analysis for the initial

study year. ISO-NE 2012 CELT Load Forecast was used to characterize loads during the study

period (2016 through 2026 and beyond). Results of the 2016 power flow cases were extrapolated

by means of the CELT forecast noted above, using compound annual growth rates derived from

that forecast of 1.2 percent from 2016 through 2021 and 1.1 percent from 2021 through 2026.

Projects Included in the Base Case

The same projects assumed in the Footprint analysis were used for this analysis.

Power Flow Cases

The same power flow cases used in the Footprint analysis were used for this analysis; however,

the Footprint generation was turned off and replaced with generation from outside the northeast

Massachusetts/Boston area.

“All Lines In” Analysis

The “All Lines In” analysis tested the ability of the power system within the study area to

serve the area load with all elements in service (i.e., no contingencies). In order to declare

this demonstrated, all system elements in the study area must be within their summer

normal ratings under the worst conditions in the steady-state power flow assessment using

each of the eight base cases.

Worst-case “All Lines In” results without Footprint showed S and T cable loadings of

approximately 67 MVA in the initial study year of 2016. This falls within existing summer

normal ratings. Extrapolation to 2021 and 2026 respectively yielded 71 MVA and 75 MVA

loadings.

N-1 Analysis

The N-1 analysis typically tests the ability of the power system within the study area to serve

the area load under a single transmission contingency. However, for a load area served by

cables, it is important to check the capability of the system to serve the load under an extended

outage case. This is due to the fact that failures in underground cables can take much longer to

detect and repair than failures in overhead lines. In order to declare this demonstrated, all

system elements in the study area must be within their summer normal ratings under the worst

conditions with a single cable out of service in the steady-state power flow assessment using

each of the eight base cases.



The worst-case contingencies under the N-1 analysis without Footprint resulted in cable

loadings of approximately 162 MVA in 2016. This falls within the summer normal rating of the

existing Cables. Extrapolation to 2021 and 2026 yielded 172 MVA and 181 MVA loadings.

Extrapolation beyond 2026 indicated that the normal ratings of the existing Cables would be

exceeded in 2051 and 2040, respectively. It should be noted that if loading can be handled by

the summer normal rating, then it can also be handled by the summer LTE rating since the latter

rating is higher than the normal rating.

N-1-1 Analysis

The N-1-1 analysis tested the ability of the power system within the study area to serve the area

load under a transmission contingency with an initial element already out of service. As

previously discussed, certain system adjustments are allowed between the loss of the first and

second elements. However, for a load area such as the Salem region without Footprint or other

generation in operation, the only possible adjustment would be post-contingency load shedding,

which is not a desirable design. In order to declare the N-1-1 ability demonstrated, all system

elements in the study area must be within their summer LTE ratings under the worst transmission

contingency conditions with a single element out of service in the steady-state power flow

assessment using each of the eight base cases.

The worst-case cable loading results under the N-1-1 analysis without Footprint occurred with

both Cables in service. Under this worst-case contingency, the Cables would be loaded to

approximately 246 MVA in 2016. This falls within the summer LTE ratings of the existing

Cables. Extrapolation to 2021 and 2026 yielded 262 MVA and 276 MVA cable loadings.

Extrapolation beyond 2026 indicated that the LTE ratings of the existing Cables would be

exceeded in 2039 and 2031, respectively.

Conclusions

The normal and LTE ratings of the existing cables are sufficient for serving load in the Salem

area without the Footprint facility in the initial in-service year of 2016. The ratings are

sufficient to serve area load through 2030, assuming load growth predicted by the ISO-NE

2012 CELT. However, carrying out the load growth to later years, the existing T cable would

cease to be sufficient in 2031 and the existing S cable would cease to be sufficient in 2039.

In order to meet the needs of the proposed Footprint generating facility, the new Cables will be

built with normal and LTE ratings substantially greater than those of the existing cables. At

these ratings, the new Cables will be able to reliably serve load in the area for the foreseeable

future, even in the absence of the Footprint generating facility. Accordingly, the cables

proposed by NEP will be sufficient to address long-term system reliability conditions in an

efficient manner.



2.5.3 Conclusions of Transmission Planning Studies

NEP determined that, both with and without the proposed Footprint generating facility, the

expected loading on both Cables under the required planning conditions would exceed

allowable emergency thermal ratings designed to protect transmission system elements from

damage caused by thermal overloads. The need for increased cable capacity with the Footprint

generating facility in operation is immediate in order to meet Footprint’s proposed June 2016

in-service date. The need for increased cable capacity without the Footprint generating facility

begins in 2031. Consequently, in replacing the current aged and failing Cables, NEP must

increase the capacity of the existing Cables in order to meet applicable reliability standards with

or without the Footprint facility.

2.6 CONCLUSION

The Cables have reached the end of their useful lives. These fluid-filled cables have

experienced approximately 36 hydraulic failures and subsequent dielectric fluid releases. The

releases and cable repairs have resulted in cable outages, costs for environmental response,

assessment and remediation in accordance with the Massachusetts Contingency Plan (“MCP”),

and public inconveniences because releases are located and repairs performed within City

streets. The replacement of the Cables will result in increased reliability and capacity, decreased

repair and remediation costs, decreased environmental impacts from releases, and decreased

inconvenience to the public.

In addition, the capacity of the Cables must be increased to provide sufficient capacity to

reliably interconnect the proposed Footprint generating facility. NEP’s interconnection studies

have demonstrated that, when combined with Footprint’s ramp-downs under certain

circumstances, the Cables must be built with an LTE of approximately 400 MVA to address

certain N-1-1 contingencies. As NEP implements the necessary replacement of the Cables,

additional capacity would be required even in the event that Footprint was not constructed, in

order to avoid the increasing risk of thermal overloads in the long term under future peak load

conditions and associated contingencies which could pose a substantial reliability risk to the

area’s transmission capacity. By providing this additional capacity in the short term as the

replacement project goes forward, NEP will avoid the expense and disruption of a series of

potential further cable replacement projects as load continues to grow in the area. Based on the

level of need established by the transmission studies conducted, NEP has determined that

increasing the capacity of each of the Cables to approximately 400 MVA LTE will meet the

identified need under the scenarios reviewed. Therefore, in accordance with Siting Board

standards, the proposed replacement of the Cables is needed in order to meet system reliability

requirements.

Section 3.0: Project Alternatives


3.0 PROJECT ALTERNATIVES

3.1 INTRODUCTION

This section discusses the various Project alternatives that NEP identified and evaluated for

their potential to address the resource need identified in Section 2. In summary, NEP

determined that the existing underground electric transmission cables in Salem require

replacement because they are approaching the end of their service life, and system conditions in

the Salem area, particularly with the addition of the proposed new Footprint generating facility,

require two new cables, with approximately 400 MVA LTE ratings, to meet the needs of the

transmission system in the area.

There are circumstances unique to the Project that are important to the evaluation of the Project

alternatives considered. First, due to transmission system constraints, it will not be possible to

take either Cable out of service for an extended period of time to support construction.

Therefore, a new cable system must be constructed and ready for service prior to taking either

of the existing Cables out of service. This fact dictates certain construction sequencing and

defines the options available for Project alternatives.

Second, both the T cable and the S cable must be physically removed from the ground once they

are retired. The T cable is a low-pressure fluid-filled cable installed in a duct bank and, unless

difficulties are encountered, can be pulled from manholes after flushing to remove the dielectric

fluid.. The S cable is a direct-buried, medium-pressure fluid-filled cable system, which uses a

pressurized dielectric fluid as part of the overall insulation system. While in service, the Cables

and fluid contained therein are not regulated by DEP”) unless a release of fluid occurs from the

cable system. While the Cables are active, the fluid pressure is monitored and therefore any loss

of pressure, which may indicate a loss of fluid (release) to the environment, is evaluated.

Releases to the environment are subject to the G.L. c. 21E, § 6 and evaluation and remediation

provisions specified at 310 CMR 40.0000, the MCP.

Specifically, the provisions of 310 CMR 40.0000 would apply when a leak or release

developed from the Cables, or when a “Threat of Release” (“TOR”) was created by a low alarm

on an active cable or as a result of abandoning a fluid-impregnated cable in place. Pursuant to

310 CMR 40.0310, releases of this fluid to soil or groundwater in any quantity must be reported

to the DEP when the resulting contaminants exceed certain reporting concentrations. Actual

leaks from the Cables would result in fluid-saturated soil that inherently contains petroleum

concentrations in excess of the reportable concentration. Therefore, it would be necessary to

notify DEP and conduct clean-up activities in the area where releases occurred. This would

apply even to slow leak rates. Although these leaks would be difficult to identify once the cable

was abandoned, they could be encountered during performance of other utility work or

redevelopment. Leaks that were not expeditiously addressed could result in undue migration of

the fluid and possible impacts to groundwater or other sensitive receptors. Typically, these



releases result in a 120-day DEP notification requirement, and assessment and remedial actions

must be undertaken until no significant risk to health, welfare, and the environment is present

and regulatory closure is achieved.

Pursuant to 310 CMR 40.0312, potential leaks from the Cables would be considered a TOR by

DEP, thereby requiring notification to DEP within two hours of discovery of the TOR.

Implementation of an Immediate Response Action to abate the TOR (i.e., remove the cable)

would then be required to occur as soon as it was practicable. Since the abandoned fluid-

impregnated cable would degrade over time and would represent a potential uncontrolled

source of contamination (i.e., since it was no longer in service and there were no regular

inspections or maintenance activities being performed to identify and address leaks), it would

be reasonable to expect the degraded cable would release oil to the environment, thereby

resulting in a TOR 20-hour reportable condition. If the cable was removed from the ground as

part of proposed construction activities, a TOR would not exist, since the cable at the time of

removal would be known to be intact and not leaking, and degradation would not occur within

the proposed construction/removal time frame. All project alternatives must therefore include

the removal of both of the existing Cables, along with the attendant impacts and costs of the

removal.

Third, as discussed in Section 2.5.1, additional capacity is needed on the Cables to reliably

serve the proposed Footprint generating facility, consistent with its interconnection request.

Without a properly sized set of new Cables in place, the Footprint generating facility would be

at risk of being unable to operate at its full designated capacity. The evaluation of project

alternatives must therefore include consideration of whether an alternative can be implemented

in time for Footprint’s proposed in-service date of June 2016.

Finally, because the purpose of the Project is to replace essential existing transmission

infrastructure, non-transmission alternatives such as additional EE and DG would not meet the

identified need. While EE and DG are important resource alternatives that are appropriate

solutions in certain settings, they do not serve as a substitute for the replacement of existing

transmission lines that are integral to the transmission network and that are required to

interconnect a new generator to the electric grid, but are approaching the end of their useful

lives. Since EE and DG do not possess these essential attributes and would not meet the

Project’s identified need, they were not evaluated as Project alternatives.

The following section presents a summary and review of the Siting Board precedent for the

consideration of Project alternatives and an overview of the alternatives evaluation completed

by NEP for the Project (Section 3.2). The sections that follow describe the Project alternatives

considered, including a “no-build” alternative (Section 3.3), underground transmission

alternatives (Section 3.4), overhead transmission alternatives (Section 3.5), a railroad corridor

alternative (Section 3.6), and cross-harbor transmission alternatives (Section 3.7).



Finally, a summary comparison of viable alternatives is presented (Section 3.7). This

comparison demonstrates that the replacement and upgrade of the Cables within a single new

duct bank and manhole system within city streets is the superior approach in terms of its ability

to meet the identified need with the lowest reasonable cost, the fewest environmental impacts,

and a high degree of reliability.

It should be noted that all cost estimates contained in this section have been developed to

comply with Appendix D to ISO-NE’s Planning Procedure No. 4—Procedure for Pool-

Supported PTF Cost Review (September 17, 2010), provided in Appendix 3-1, which provides

guidance and establishes a standardized approach to cost estimating for regional electric

transmission projects. The cost estimates provided herein are classified as conceptual grade

estimates, which are appropriate for project approaches that are being considered as a potential

solution to meet an identified need. In these instances, key project elements are identified, but a

limited amount of detailed engineering has been completed. Conceptual grade estimates are

based on recent costs of similar materials and construction activities, have a target accuracy of

-25% to +50%, and do not consider possible future variances in commodity or labor costs.

3.2 SITING BOARD PRECEDENT AND OVERVIEW OF ALTERNATIVES

EVALUATION

The Siting Board is required to evaluate proposed projects to ensure a reliable energy supply for

the Commonwealth with a minimum impact on the environment at the lowest possible cost

(G.L. c. 164, § 69H). In addition, G.L. c. 164, § 69J requires a proposed project proponent to

present “alternatives to planned action,” which may include (a) other methods of generating,

manufacturing, or storing; (b) other sources of electric power or natural gas; and (c) no

additional electric power or natural gas. Western Massachusetts Electric Co., EFSB 08-

2/D.P.U. 08-105/08-106, at 32 (Sept. 28, 2010) (“GSRP Decision”).

The Siting Board, in implementing its statutory mandate, requires a petitioner to show that on

balance its proposed project is superior to alternative approaches in terms of the cost,

environmental impact, and ability to meet a previously identified need. GSRP Decision at 32;

Cape Wind Associates LLC and Commonwealth Electric Company d/b/a/ NSTAR Electric, 15

DOMSB 1, at 33 (2005) (“Cape Wind”); NSTAR Electric, EFSB 04-1, at 21; Cambridge

Electric Light Company, 12 DOMSB 305, at 321 (2001); NEPCO Decision, 7 DOMSB 333, at

358 (1998); BECO Decision, 6 DOMSB 208, at 252 (1997); ComElec Decision, 5 DOMSB

273, at 299 (1997); Boston Edison Company Decision, 13 DOMSC 63, at 67-68, 73-73 (1985).

In addition, the Siting Board requires a petitioner to consider reliability of supply as part of its

showing that the proposed project is superior to alternative project approaches. Cape Wind, 15

DOMSB at 34; NSTAR Electric, EFSB 04-1, at 21; Cambridge Electric Light Company, 12

DOMSB at 321; NEPCO Decision, 7 DOMSB at 358; BECO Decision, 6 DOMSB at 253-257;



ComElec Decision, 5 DOMSB at 300; Massachusetts Electric Company, 18 DOMSC 383, at

404-405 (1989).

NEP developed a review process that identified multiple potential alternatives. These

alternatives were then screened for their ability to meet the identified resource need and for

overall feasibility and constructability. Any alternative that clearly did not meet the identified

resource need and/or that was deemed to be infeasible from a construction standpoint was

eliminated from further evaluation. The remaining project alternatives were then reviewed in

more detail for potential environmental impacts (including permitting requirements), reliability

considerations, and cost analysis. Based on a comparison of these project alternatives, a

preferred project approach was determined.

3.3 NO-BUILD ALTERNATIVE

For the “no-build” alternative, NEP would not pursue construction or development of any new

facilities or resources, but instead would continue to rely upon the existing system configura-

tion and facilities.

The Cables are an integral part of NEP’s regional 115 kV transmission system that delivers

electric energy to substations owned by NEP, Massachusetts Electric Company, and several

municipal utilities. In the future, the Cables will be instrumental in delivering energy from the

proposed new Footprint generating facility.

NEP has determined that the Cables are reaching end-of-life conditions and need to be

replaced. The S cable is more than 40 years old and has a documented history of dielectric fluid

releases. The T cable is more than 60 years old and has similar asset condition difficulties. The

releases and cable repairs have resulted in cable outages; costs for environmental responses,

assessment, remediation in accordance with the MCP, and public inconvenience as releases are

located and repairs performed within City streets. As further detailed in Section 2.4,

replacement parts for these types of cables are not readily obtainable and finding experienced

craftsmen to work on these Cables is becoming increasingly difficult, making it harder to

maintain and repair them. If NEP does not implement a long-term solution to address the

current condition of these Cables, NEP’s ability to maintain and repair the Cables will decline

further, causing additional environmental releases and further costs to be incurred, with

associated negative impacts to service reliability for NEP’s customers.

In addition, as presented in detail in Section 2.5, NEP has determined that, once the proposed

Footprint generating facility is in service, the expected loading on both of the existing Cables

under the required planning conditions would exceed allowable emergency thermal ratings

designed to protect transmission system elements from damage caused by thermal overloads.

The need for increased cable capacity with the Footprint generating facility in operation is

immediate in order to meet Footprint’s proposed June 2016 in-service date. Even without the



Footprint generating facility in service, the increased capacity from the replaced cables will

serve growing loads in the area and obviate the need for a series of potential upgrades to the

Cables over the ensuing decades, thus avoiding the negative impacts and associated costs of

such construction. Consequently, in replacing the current aged and failing cables, NEP is

proposing to increase the capacity of the Cables in order to meet applicable reliability standards

with or without the Footprint generating facility.

Because the existing Cables need to be replaced and upgraded in order to meet applicable

reliability standards and serve increased capacity needs, NEP determined that the “no build”

alternative would not meet the identified resource need and eliminated it from further

consideration.

3.4 UNDERGROUND TRANSMISSION ALTERNATIVES

NEP considered three underground transmission alternatives to replace and upgrade the

existing Cables:

1. Installation of both replacement cables within a single new duct bank and manhole

system along a single route (“Single Duct Bank Alternative”);

2. Installation of the two replacement cables within two new, separate duct bank and

manhole systems along different routes (“Two Duct Bank Alternative”); and

3. Installation of one of the replacement cables within the existing T cable duct bank

(“Reuse of Existing T Cable Duct Bank and Manhole System”).

3.4.1 Single Duct Bank Alternative

NEP considered the replacement of both Cables with new cables installed in a common duct

bank and manhole system along one new route to meet the identified resource need. This

scenario generally would involve the following steps:

Underground Transmission Work

· Construction Year 1:

o Construction of a single new duct bank and manhole system, designed to accommodate

the installation of two cables, within City streets between the Salem Harbor and Canal

Street Substations.




o Installation of the new cables.

o Pavement restoration.

o Removal of the existing S cable. This would include excavation of the former direct

buried S cable, backfill, and pavement restoration along the entire length of its corridor.

o Removal of the existing T cable from the duct bank and disposal of the existing cable and

accessories.

Substation Work (overlapping with Underground Transmission Work)

· Construction Years 1 and 2: Modifications to the existing Salem Harbor and Canal

Street Substations.

The Single Duct Bank Alternative would take approximately 18 months to complete, with

some additional work (such as removal of the de-energized Cables and final pavement

restoration) possibly extending beyond that time period.

NEP evaluated whether a new duct bank could be constructed adjacent to the existing S cable,

but concluded that the northern and southern ends of the route were too narrow or too crowded

with other utilities to accommodate both of the existing Cables (which must remain in place

during construction) as well as a new duct bank and manhole system.

The following sections present an evaluation of the land use and environmental impacts,

permitting, reliability, and cost considerations associated with the Single Duct Bank Alternative.

Land Use and Environmental Impacts

Land uses within the Project Area for this alternative are best characterized as urban and include a

mix of residences, small businesses, commercial retail centers, and community buildings. In

addition, the Project Area is located within downtown historic Salem and along its working

waterfront. There are a large number of historic properties and popular tourist attractions within

this portion of the City. Because the installation of these facilities would be entirely within City

streets, the predominant conflict would be with existing underground utilities, and potential

environmental impacts would largely be confined to temporary construction impacts related to

traffic disruption, dust, and noise. There would be no direct impact to natural resources such as

vegetated wetlands, rare species habitats, aquifers, or marine resources.



Permitting Requirements

Table 3-1 presents the federal, state, and local permit approvals anticipated for the Single Duct

Bank Alternative.6

It should be noted that NEP previously obtained an Advisory Ruling from the Massachusetts

Environmental Policy Act (“MEPA”) Unit staff of the Executive Office of Energy and

Environmental Affairs (“EOEEA”) for a recent project in Worcester indicating that city streets

that currently contain underground utilities, even if they do not currently include electric

transmission lines, are not considered a “new, unused or abandoned” right-of-way (“ROW”) for

purposes of the MEPA review threshold. As such, this alternative would not require MEPA

review because it would not exceed any review thresholds.

Table 3-1: Anticipated Permits and Approvals for

Single Duct Bank Alternative

Issuing Authority Permit/Approval

FEDERAL

U.S. Environmental Protection Agency (“USEPA”)

National Pollution Discharge Elimination System (“NPDES”) General Permit for Discharges from Construction Activities (“CGP”)

STATE

DEP Public Waterfront Act Chapter 91 Minor Modification (“Chapter 91”)

Massachusetts Historical Commission (“MHC”)

Project Notification Form (G.L. c. 9, § 27C)

DPU/Siting Board Authorization to Build an Electric Transmission Line (G.L. c. 164, § 72)

Grant of Required Zoning Exemptions (G.L. c. 40A, § 3)

Approval of Petition to Construct (G.L. c. 164, § 69J)

LOCAL

Salem Conservation Commission Order of Conditions under Massachusetts Wetlands Protection Act (“MWPA”) and City of Salem Wetlands Protection and Conservation Ordinance

Salem City Council Grants of Location (G.L. c. 166, § 22 and Chapter 38, Article IV of the Salem Code of Ordinances)

Salem Zoning Board of Appeals Special Permit (Section 3.3.2 of the Salem Zoning Ordinance)

6 It is assumed that the need for zoning relief from the Salem zoning code would be the same for all transmission alternatives and associated substation modifications.



Reliability

This alternative meets all required transmission planning criteria applicable to the Company.

Any necessary maintenance or response to a particular failure in the system would be relatively

straightforward and would involve minimal environmental impacts as work would be done

using existing manholes for access.

Cost

The estimated project cost of the Single Duct Bank Alternative is approximately $62.43 million

(see Table 3-2). This estimate is based on recent costs of similar materials and construction

activities, has a target accuracy of -25% to +50%, and does not consider possible future

variances in commodity or labor costs.

Table 3-2: Estimated Costs for Single Duct Bank Alternative (2013 dollars)

Cost

(millions)

Underground Transmission Construction

Installation of two underground transmission cables $33.40

Removal of existing S cable $5.37

Removal of existing T cable (duct bank to remain) $0.58

Underground Transmission Cost Subtotal: $39.35

Substation Upgrades

Salem Harbor Substation $7.02

Canal Street Substation $5.25

Substation Cost Subtotal: $12.27

Permitting, Project Administration and Development $10.81

Total $62.43

Conclusion

This project alternative is technically feasible and was advanced for final comparison with

other alternatives.



3.4.2 Two Duct Bank Alternative

NEP considered the replacement of both existing Cables with new cables installed in two new,

separate underground manhole and duct bank systems between the Salem Harbor Substation

and the Canal Street Substation. This scenario would generally involve the following steps:

Underground Transmission Work


o Installation of one replacement cable in a new underground duct bank and manhole

system within City streets between the Salem Harbor and Canal Street Substations.



o Installation of the second replacement cable in a second new underground duct bank and

manhole system within different City streets from the first cable. Note that the existing

S cable corridor could be used for this because it must be removed once it is taken out of

service.


o If the existing S cable corridor was not used as the route for the second new underground

duct bank and thus needed to be excavated separately, removal of the existing S cable

could begin during this construction year, and would include excavation of the direct-

buried cable, backfill, and pavement restoration along the entire length of its corridor.


o Any remaining removal of the existing S cable (if corridor was not reused).

o Removal of the existing T cable from the duct bank and disposal of the existing cable and

accessories.

Substation Construction (overlapping with Underground Transmission Work)

· Construction Years 1 and 2: Modifications to the existing Salem Harbor and Canal

Street Substations.

It is estimated that the Two Duct Bank Alternative would take two to three construction years

to complete, with one construction year each for the installation of the new cables and a third

construction year for the removal of any remaining existing Cables.

The following sections present an evaluation of the land use and environmental impacts,

permitting, reliability, and cost considerations associated with this Project alternative.




Land uses within the Project Area for this alternative are best characterized as urban and include a

mix of residences, small businesses, commercial retail centers, and community buildings. In

addition, the Project Area is located within downtown historic Salem and along its working

waterfront. There are a large number of historic properties and popular tourist attractions within

this portion of the City. Because the installation of these facilities would be entirely within City

streets, the predominant conflict would be with existing underground utilities, and potential

environmental impacts would largely be confined to temporary construction impacts related to

traffic disruption, dust, and noise. There would be no direct impact to natural resources such as

vegetated wetlands, rare species habitats, aquifers, or marine resources.

Permitting

Table 3-3 presents the federal, state, and local permit approvals anticipated for the Two Duct

Bank Alternative.

As previously discussed, NEP has obtained an Advisory Ruling from the EOEEA MEPA Unit

staff indicating that city streets that currently contain underground utilities, even if they do not

currently include electric transmission lines, are not considered a “new, unused or abandoned”

ROW for purposes of the MEPA review threshold. As such, this alternative would not require

MEPA review because it would not exceed any review thresholds.

Table 3-3: Anticipated Permits and Approvals for Two Duct Bank Alternative


FEDERAL

USEPA NPDES General Permit for Discharges from Construction Activities

STATE

DEP Chapter 91 Minor Modification

MHC Project Notification Form (G.L. c. 9, § 27C)




LOCAL

Salem Conservation Commission Order of Conditions under MWPA and City of Salem Wetlands Protection and Conservation Ordinance

Salem City Council Grants of Location (G.L. c. 166, § 22 and Chapter 38, Article IV of the Salem Code of Ordinances)

Salem Zoning Board of Appeals Special Permit (Section 3.3.2 of the Salem Zoning Ordinance)



Reliability

This alternative meets all required transmission planning criteria applicable to the Company.

Any necessary maintenance or response to a particular failure in the system would be relatively

straightforward and would involve minimal environmental impacts as work would be done

using existing manholes for access.

Cost

The estimated cost of installing two cables within new, separate duct bank and manhole

systems within city streets varies depending upon whether the existing S cable corridor is used

for one of the new routes. The estimated cost including reuse of the S cable corridor is

approximately $69 million. If the S cable corridor is not reused, the approximate cost for this

alternative increases to $74 million. A breakdown of the total estimated costs for the Two Duct

Bank Alternative is included in Table 3-4. The cost estimates provided are conceptual grade

estimates based on recent costs of similar materials and construction activities, have a target

accuracy of -25% to +50%, and do not consider possible future variances in commodity or

labor costs.

Table 3-4: Estimated Costs for Two Duct Bank Alternative (2013 dollars)

Estimated Cost Including

Reuse of the S Cable Corridor

Cost

(millions)

Estimated Cost Without

Reuse of the S Cable Corridor

Cost

(millions)

Underground Transmission Construction Underground Transmission Construction

Installation of two underground transmission cables

$43.28 Installation of two underground transmission cables

$43.28

Removal of existing S cable (with reuse) $0.43 Removal of existing S cable (without reuse) $5.37

Removal of existing T cable (duct bank to remain)

$0.58 Removal of existing T cable (duct bank to remain)

$0.58

Underground Transmission Cost Subtotal: $44.29 Underground Transmission Cost Subtotal: $49.22

Substation Upgrades Substation Upgrades

Salem Harbor Substation $7.33 Salem Harbor Substation $7.33

Canal Street Substation $6.22 Canal Street Substation $6.22

Substation Cost Subtotal: $13.55 Substation Cost Subtotal: $13.55

Permitting, Project Administration and Development:

$10.81 Permitting, Project Administration and Development:

$10.81

Two Duct Banks with S Cable Corridor

Reuse Total (millions)

$68.65 Two Duct Banks without S Cable

Corridor Reuse Total (millions)

$73.59

Conclusion

The Two Duct Bank Alternative is a feasible alternative and was advanced for further

evaluation and comparison with other alternatives.



3.4.3 Reuse of Existing T Cable Duct Bank and Manhole System

NEP considered the reuse of the existing T cable duct bank and manhole system to

accommodate one of the two replacement cables. Following an engineering review, NEP

determined that reuse of the T cable duct bank and manhole system would not be feasible for

the following reasons:

· Inability of new cables installed in old system to achieve required capacity: NEP

completed an analysis to determine the maximum cable size that could be installed

within the existing duct bank system and the resulting cable rating. Based upon this

study, it was determined that the maximum cable size that could be installed is a

1250 kcmil copper cable. Because of the configuration, depth, and thermal properties of

the existing concrete-encased system, this cable’s maximum rating would fall short of

the capacity required to meet the identified resource need in Section 2.

· Condition of the existing duct: The existing duct is a bituminized fiber pipe made from

layers of wood pulp and pitch pressed together. This type of pipe, which is no longer an

industry-acceptable product for new installations, is highly prone to deformation,

blistering, and general degradation over time. Attempted reuse of the existing more-

than-60-year-old duct could be problematic and require significant excavation and

repair work before the new cable could be pulled through.

· Potential need to significantly expand or replace several existing splice vaults: A new

1250 kcmil solid dielectric copper conductor would be less flexible than the conductor

currently installed, would be larger, and would require more physical space within the

duct than the existing conductor. In addition, several of the existing vaults, specifically

vaults in which the current system accommodates a 90-degree bend, likely could not be

reused. These vaults would need to be replaced in their entirety, and it is possible that

the duct bank in the vicinity of the vaults would need to be realigned and reconstructed

to remove the need for a 90-degree bend within the splice vault. All vaults would have

to be inspected for structural integrity and any necessary repairs made before new cable

could be pulled through and spliced.

Due to the issues identified above, reuse of the existing T cable duct bank and manhole system

was dismissed from further consideration.



3.5 OVERHEAD TRANSMISSION ALTERNATIVES

NEP considered the construction of overhead transmission circuits to meet the identified need.

As presented in the following sections, two options were considered as part of the Overhead

Transmission Alternatives:

1. Overhead Circuits through Salem; and

2. Overhead Circuits around Salem.

3.5.1 Overhead Circuits through Salem

NEP conducted a high-level screening analysis of routing opportunities within Salem to

determine the feasibility of installing two 115 kV overhead transmission circuits between the

Salem Harbor Substation and the Canal Street Substation. According to the Installation and

Maintenance of Electric Transmission Lines Regulations (220 CMR 125.00), transmission lines

and their supporting structures must maintain certain minimum clearances from objects such as

buildings, roads, and other distribution wires. For example, 115 kV conductors must be either

11 feet or 18 feet away from buildings, depending on whether the conductors are passing by or

over the building. The typical widths of streets in the Project Area between Salem Harbor

Substation and the Canal Street Substation range from 20 feet to 60 feet, and these streets are

lined with residences, business and industrial buildings. Because there is no existing overhead

transmission ROW through downtown Salem, new property rights would need to be obtained

on private properties or along existing City streets to accommodate the necessary clearances

and ROW widths. A new 115 kV transmission ROW for two separate overhead circuits would

require anywhere from 50 to 150 feet of width, depending upon the configuration of the

facility. Because of the widths and clearances required for electric transmission lines of this

voltage, the property acquisition and demolition that would be required to obtain a suitable and

safe corridor through the City would permanently affect a very large number of residents and

businesses and cause material social, economic, and visual impacts to the City.

Additionally, the presence of historic districts within downtown Salem would complicate any

attempt to acquire rights for an overhead route through the City. Any above-ground facilities

within these areas have the potential to alter the existing historical character of the area. In

conclusion, based on Salem’s urban and historical setting, NEP determined that this approach

was highly impractical and eliminated it from further consideration.

3.5.2 Overhead Circuits around Salem

NEP conducted a screening analysis to determine whether it was feasible to construct two

115 kV overhead transmission circuits around the perimeter of the City to meet the Project

need. NEP was unable to locate a feasible overhead transmission line route within or directly



adjacent to existing ROWs that would directly connect the Salem Harbor Substation and the

Canal Street Substation.

However, NEP found that connecting the Salem Harbor Substation with NEP’s existing West

Salem Substation also would address the Project need. At present, electricity generated at the

Salem Harbor site flows along the Cables to the Canal Street Substation, and from there via

overhead circuits to the Railyard and West Salem substations and into the regional transmission

grid (Figure 2-2). Overhead circuits between the Salem Harbor and West Salem substations

could theoretically connect Salem Harbor generation with the transmission grid, thus

eliminating the need for the existing Cables. Existing overhead transmission lines between the

West Salem and Railyard substations would then continue to supply the distribution load served

from the Railyard Substation.

NEP’s existing overhead transmission loop extending out of Salem Harbor is not located in a

manner that would allow geographically advantageous connections around the City to the West

Salem Substation. In order to connect these two substations by following existing transmission

ROWs, it would be necessary to traverse land areas extending north to the Haverhill/Methuen

area, then west and south to Tewksbury and Wakefield, and then west to West Salem (a total

distance of approximately 78.5 miles).

Consequently, NEP developed an overhead transmission alternative that would connect the

Salem Harbor and West Salem substations by using a combination of existing overhead

transmission corridors, existing railroad corridors, and new ROW that would need to be obtained

from current landowners. This alternative route would be approximately 6.9 miles in length and

would involve the construction of two single overhead circuits on separate transmission structures

within a common corridor. The overhead route would follow an existing ROW for 3.5 miles

between Salem Harbor Substation and the Waters River Substation (a municipal facility) in

Peabody, traverse alongside an existing railroad ROW for 2.0 miles to Allens Lane. The route

would then follow a newly created transmission corridor for 1.4 miles along Allens Lane and

Hingston Street and across The Meadow at Peabody Golf Course to connect to the West Salem

Substation (Figure 3-1). Construction of this option would take approximately 18 months once

real estate acquisition and permitting were complete. In this scenario, the Canal Street Substation

would no longer be needed and it would be decommissioned and removed.

A variation on this alternative is a hybrid route that would involve 3.7 miles of overhead

construction on the existing ROW from the Salem Harbor Substation to a point just past the

Waters River Substation, and then 2.9 miles of underground construction along city streets in

Peabody between the Waters River and West Salem Substations. This was investigated as a

means of avoiding the cost and land use impacts of acquiring new ROW between Waters River

Substation and West Salem Substation. This hybrid route is addressed in more detail below.



Land and Easement Acquisitions

There are several constraints that could present difficulties for building any of the overhead

alternatives. Between the Salem Harbor and Waters River Substations, NEP currently owns an

existing 200-foot-wide ROW currently occupied by two existing lines, the B-154S and C-155S.

To accommodate two new 115 kV transmission lines along this corridor, the B-154S and C-155S

would likely need to be rebuilt and an additional 50 feet of easement width would need to be

acquired.

NEP does not own or have rights to existing ROWs along the majority of the route between the

Waters River and West Salem Substations. Approximately 3.4 miles of new ROW would need to

be acquired as shown in Figure 3-1 for this project alternative. Although the proposed overhead

transmission lines could continue along an existing railroad corridor for approximately 2.0 miles

of the total 3.4 miles, there is currently an existing municipal distribution line on the western side

of the corridor that could interfere with the construction of two new 115 kV circuits. Additional

property rights would also need to be acquired adjacent to the railroad corridor to expand the

ROW to approximately 150 feet to provide adequate clearances for the new lines. Given the

general proximity of the existing structures (homes and businesses) to the railroad property,

easement acquisition would not provide adequate clearance. As previously outlined in

Section 3.5.1, there are regulatory requirements for minimum clearances for transmission lines

and their supporting structures from various objects such as buildings, roads, and other

distribution circuits. Compliance with the required clearances would not be possible with the

existing structures in the area between the Waters River Substation and the West Salem

Substation. Property acquisition and structure demolition of approximately 60 residences,

10 industrial buildings, and eight commercial buildings would be necessary.

In addition to the property acquisition along this corridor, NEP would have to negotiate an

agreement with the railroad company to partially collocate within its existing corridor. In

general, railroads do not grant permanent easement rights; instead, they grant terminable

licenses, which would put NEP in the undesirable position of lacking permanent, secure

property rights along this portion of the Project.

Finally, this route would exit the railroad corridor at Allens Lane and turn southeast, following

Hingston Street and crossing The Meadow at Peabody Golf Course in order to connect to the

West Salem substation. This last 1.4-mile leg of the route would require the acquisition of a

new ROW easement and would likely also require the acquisition and demolition of properties

along Hingston Street.

This alternative would require upgrades at both the Salem Harbor and West Salem Substations.

This could include expanding the existing limits of the Salem Harbor Substation, potentially

requiring additional easement rights.



Hybrid Overhead/Underground Variation

Due to the difficulties of building an overhead route between the Waters River and West Salem

Substations, NEP also considered converting to underground transmission cables for this

portion of the alternative. This would likely involve installation of a duct bank and manhole

system within city streets through Peabody and Salem for approximately 2.9 miles (see

Figure 3-1). From the Waters River Substation, the overhead circuits would continue southward

along the west side of the railroad ROW within the available NEP-owned parcel for

approximately 0.2 miles, at which point the line would transition underground. At this

transition location, an approximately 100-foot-by-100-foot transition station would be installed

on the existing NEP-owned parcel. From the transition station, the underground cables would

cross under the railroad corridor and continue southward along North Central Street, paralleling

the railroad corridor. The cables would follow North Central Street for approximately 0.4 miles

to its intersection with Pulaski Street, continue southward along a short distance of Pulaski

Street, and then follow Central Street for approximately 0.5 miles to the intersection with Main

Street. Turning eastward onto Main Street, the route would travel approximately 0.3 miles, then

turn southwest onto Washington Street. After traveling along Washington Street for

approximately 0.3 miles, the route would turn south on Aborn Street and continue onto Sutton

Street and Marlborough Road, traveling approximately 1.1 miles to the intersection with NEP’s

existing ROW near Osborn Hill Drive. The route would continue southward along Marlbor-

ough Road just past the ROW, then travel westward paralleling the south side of the ROW

across a NEP-owned parcel for approximately 0.1 miles to connect directly to the West Salem

Substation. The West Salem Substation would need to be expanded to provide a connection for

the new underground cables. The total duration of construction would be approximately

12 months for the overhead portion and 12-24 months for the underground portion depending

upon subsurface conditions encountered.


The proposed corridors for both variations of this alternative would traverse a broad range of land

uses including densely developed areas, open space, forested lands, and both tidal and freshwater

wetland systems. Figure 3-2 provides an overview of the natural environments along the

proposed overhead transmission alternative route around Salem.

Construction of either variation of this alternative could result in significant impacts to both

tidal and freshwater wetland systems from the required expansion of the existing fill islands

within Collins Cove and the North River, and from tree clearing that would be required in other

wetland areas to accommodate the new lines. In addition, the impacts to private residences and

businesses would be significant, because the areas within and adjacent to the existing and to-be-

acquired ROW tends to be densely developed, especially between the Waters River Substation

and the West Salem Substation.



The all-overhead variation of this alternative would cross six bodies of water (Collins Cove,

North River, Danvers River, Waters River, Goldthwait Brook, and Strongwater Brook) and six

open spaces (McCabe Park, Kernwood Country Club, Farnham Park, Emerson Park, and The

Meadow at Peabody Golf Course). As discussed above, this variation would require the

acquisition of and subsequent demolition of 82 residential and commercial structures. It would

also require the acquisition of an additional 50 feet of easement from the Salem Harbor

Substation to the Waters River Substation, a license to collocate in the railroad corridor, and an

entirely new easement from Waters River Substation to the West Salem Substation, totaling

approximately 52 acres of land. For a project of this length, the process of negotiating the

acquisition of land rights from multiple abutting landowners could take many years to complete

(with significant associated uncertainty and cost implications). The required rights acquisition

process would result in delays to the desired Project schedule and jeopardize NEP’s ability to

complete the Project consistent with the identified resource need. This is a significant concern

particularly in light of Footprint’s need for these facilities to meet its proposed in-service date

of June 2016.

Land impacts associated with hybrid variation would be fewer, as acquisitions along the

railroad corridor would be avoided. However, it would not avoid the substantial environmental

impacts associated with the construction of overhead circuits along the northern portion of the

route. The hybrid variation would still require crossing five bodies of water (Collins Cove,

North River, Danvers River, Waters River, and Strongwater Brook) and four open spaces

(McCabe Park, Kernwood Country Club, Marrs Park, and McGrath Park). It would also still

require the expansion of the ROW between the Salem Harbor and Waters River Substations

and the expansion of the West Salem Substation, as well as the construction of a transition

station just south of the Waters River Substation.

Permitting

Table 3-5 summarizes the federal, state, and local permit approvals that are anticipated to be

required for this alternative. Because the hybrid variation does not completely avoid the

wetlands, water bodies, or open spaces associated with the all-overhead variation, the permit

approvals required for both variations are expected to be the same.

Of particular note, Article 97 land dispositions would be required for this alternative because NEP

would need to acquire rights on several parcels of land owned by the Commonwealth of

Massachusetts. These lands include McCabe Park and McGrath Park in Salem and Farnham,

Emerson, and Marrs Parks in Peabody. An Article 97 land disposition is required in any instance

where there is a change in physical or legal control on land owned or held by the Commonwealth

or its political subdivisions for recreational or conservation purposes. The EOEEA and its

agencies generally do not support Article 97 land dispositions unless exceptional circumstances

exist.



Table 3-5: Anticipated Permits and Approvals for

Overhead Transmission Alternative around Salem1


FEDERAL


U.S. Army Corps of Engineers (“USACE”)

Individual Permit Section 10 Rivers and Harbors Act of 1899 (“Section 10”)

Individual Permit Section 404 Federal Clean Water Act (“Section 404”)

Section 106 National Historic Preservation Act (“Section 106”)

STATE




EOEEA MEPA Certificate

Article 97 Land Disposition

DEP Individual 401 Water Quality Certification (BRP WW11)

Chapter 91 Waterways License (BRP WW01)

Massachusetts Office of Coastal Zone Management (“CZM”)

CZM Consistency Review

MHC Project Notification Form (G.L. c. 9, § 27C)

LOCAL


Peabody Conservation Commission Order of Conditions under MWPA and City of Peabody Wetlands Protection Ordinance

Danvers Conservation Commission Order of Conditions under MWPA and Town of Danvers Wetland Bylaw

1 This alternative may also require zoning relief from the Salem, Peabody, and/or Danvers zoning codes.

To prove “exceptional circumstances,” the proponent must show that all other options to avoid

the Article 97 disposition have been explored and no feasible and substantially equivalent

alternatives exist. Such demonstration would be difficult for this Project alternative because there

are other options that meet the project need that do not require the disposition of Article 97 lands.

At a minimum, Article 97 approval from the Legislature would significantly extend the

permitting timeline for this alternative compared to other options.

In addition, many of the permits required for this alternative contain statutory standards that

require an applicant to prove that there is no practicable alternative to the proposed discharge or

action which would have less adverse impact on the regulated natural resource area. Such

demonstration would be difficult for this alternative because there are other alternatives presented

herein that meet the Project need and can avoid impacts to regulated natural resource areas.



In conclusion, NEP has determined that it would be difficult to obtain permits for any variation of

this alternative given the necessity to overcome regulatory standards for practicable alternatives

and the requirement of an applicant to present a project that is the least environmentally damaging

practicable alternative to meet the Project need. Even if it were possible to obtain permits for this

alternative, it is reasonable to expect that it would take at least 18–24 months to proceed through

the regulatory process. Given this, NEP does not believe that it could permit and construct any

variation of this alternative prior to Footprint’s June 2016 in-service date.

Reliability

There are no significant reliability concerns for either the all-overhead or hybrid variations,

which would be constructed to current standards.

Cost

The estimated cost for the all-overhead alternative around the City, including assumed costs for

real estate acquisition, substation upgrades, and transmission construction, is approximately

$145 million. The cost of real estate acquisition was estimated to be $48 million. It was

assumed that properties along the railroad would need to be acquired in fee because of the

dense nature of development along this corridor. Most properties have buildings that would be

within the clearance area and would need to be demolished. The cost of property and easement

acquisition was based on assessed value and did not include demolition and other site

preparation costs. The cost estimate also includes the cost of rebuilding the two existing

transmission lines on the NEP easement portion of the route, estimated to be $16 million. The

cost estimates provided in Table 3-6 are conceptual grade estimates based on recent costs of

similar materials and construction activities. They have a target accuracy of -25% to +50% and

do not consider possible future variances in commodity or labor costs.



Table 3-6: Estimated Costs for Overhead Transmission

Alternative around Salem (2013 dollars)

Cost

(millions)

Overhead Transmission Line

Construction of New Transmission Line* $107.27


Removal of existing T cable (duct bank to remain)

$0.58

Overhead Transmission Cost Subtotal: $113.22

Substation Upgrades



West Salem Substation $2.17


Permitting, Project Administration and Development: $10.81

Overhead Alternative Total (millions) $144.78

* Includes rebuild cost on existing transmission ROW as well as real estate acquisition costs to expand ROW and acquire new ROW along railroad corridor.

While the hybrid variation would avoid much of the estimated $48 million in real estate costs

associated with the all-overhead variation, the cost of installing 2.9 miles of underground cables

would be prohibitively high (approximately $61 million) and would negate any real estate

savings. Furthermore, the hybrid variation would still require expansion of the existing NEP

easement between the Salem Harbor and Waters River Substation and the rebuilding of the two

existing transmission lines within that ROW, as well as the additional expense of building a

transition station just south of the Waters River Substation. Due to the significantly increased

costs and relatively little environmental advantages compared to the all-overhead variation,

NEP did not pursue further evaluation of this variation.

Conclusion

An all-overhead transmission alternative between the Salem Harbor Substation and the West

Salem Substation is a technically feasible option and was advanced for further comparison.

NEP also considered a hybrid route involving overhead construction between the Salem Harbor

and Waters River substations and underground construction between the Waters River and

West Salem substations. This variation is technically feasible and was advanced for further



comparison. However, NEP determined that while this alternative would require less land

acquisition, overall it would be more expensive and have only slightly fewer environmental

impacts than the all-overhead variation.

3.6 RAILROAD CORRIDOR ALTERNATIVE

NEP conducted a high level screening analysis of using an existing railroad corridor as an

option for the new cable route. It is important to note that the MBTA’s Newburyport/Rockport

line operates on this railroad corridor.

NEP reviewed an overhead and an underground option for connecting to the railroad corridor

from Salem Harbor Substation. As described in Section 3.5, NEP currently owns an existing

200-foot-wide ROW between the Salem Harbor substation and the intersection of the railroad

corridor with March Street Court. To accommodate two new 115 kV transmission lines in this

ROW, the existing B-154S and C-155S lines would likely need to be rebuilt and an additional

50 feet of easement width would need to be acquired. From March Street Court, the route

would follow the railroad corridor southward, paralleling Sergeant James Ayube Memorial

Drive (Route 107) to the east and the North River to the west. The railroad corridor in this area

is very narrow and it would be very difficult to build two overhead transmission lines in this

corridor.

Alternately, NEP considered building an underground cable route from the Salem Harbor

substation to the railroad corridor. This would require approximately 0.9 miles of underground

construction within City streets.

With both the overhead and underground options, the replacement Cables would follow the

railroad alignment into the single-track railroad tunnel near the commuter rail station. This

tunnel runs under Washington Street for approximately 2,100 feet between Bridge Street and

Mill Street. Upon exiting the tunnel near Mill Street, the railroad corridor runs parallel to Canal

Street for approximately 1,200 feet between Mill Street and the Canal Street Substation. Within

this portion of the railroad corridor, the tracks are approximately 10 feet below the surrounding

street grade, and the tracks are walled on both sides.

The installation of an underground duct bank and manholes within the railroad corridor would

be extremely difficult because the majority of this corridor is very narrow, especially along the

walled portion of the track and in the tunnel. In many areas along the corridor, there appears to

be less than 10 feet between the tracks and the corridor walls. Given the limited space,

installation of a duct bank and manhole system along this corridor would require open

excavation directly adjacent to the active rail, which would likely be unacceptable to the

railroad operator. At one or both ends of this potential railroad alignment, installing electric

transmission cables from street grade to the depressed railroad bed would be extremely

difficult.



Given the length of the railroad corridor, manholes would need to be installed at various

intervals along to the corridor. Manhole locations would have to be chosen based on cable

pulling needs, and would need to be installed in a way that would not obstruct the tracks during

initial construction or during any subsequent entry into the manholes for ongoing maintenance.

There does not appear to be room within the railroad corridor for manhole installation.

Based on reviews of railroad corridors for other projects, it is anticipated that work hours would

be severely restricted due to the activity of commuter rail trains. The MBTA operates its

commuter rail service on the tracks roughly from 5:30 a.m. through 1:00 a.m. on weekdays,

and from 7:30 a.m. through 12:00 a.m. on weekends. This allows for an extremely narrow

window of nighttime work between the hours of approximately 1:30 a.m. and 4:30 a.m., based

on the typical railroad requirement of a cushion of time after the last train and before the first

train. Construction equipment would likely need to be transported to and from the site each

work period so that the tracks were not fouled during construction, further narrowing the

available work hours. Constructing underground transmission lines with such restricted work

hour windows would become impractical and inefficient, resulting in a substantially longer

construction duration and higher costs. Future emergency response access would be

significantly impacted due to coordination with the MBTA’s hours of operation, adding time to

outage restoration efforts. There most likely would also be restrictions on accessing the

manholes for routine inspection and maintenance.

Historically, rail line corridors were constructed with thermally undesirable soils consisting of

large slag aggregate used as railroad bed fill. Overtime, soils along railroad corridors often

become contaminated by petroleum products, coal ash, and pesticides. These soil types require

special handling due to contamination and represent large thermal impedances that restrict the

cable’s ability to release heat. Additional conductors and thermally-engineered backfill along

the entire route could be required to obtain the desired capacity, adding significantly to the cost.

Another challenge would be securing acceptable property rights for the new facilities. Railroad

operators do not allow permanent easements on their corridors. Railroads typically issue a

license agreement, which is revocable at any time. In the future, the railroad operator could

require the relocation of these new facilities at a significant expense to ratepayers.

On a screening level, National Grid concluded that the railroad corridor was not suitable for

underground transmission line installation. The corridor does not appear wide enough to

construct the proposed transmission lines. The depressed elevation of the tracks and the long

tunnel would present significant construction difficulties. The heavy use of the tracks for

MBTA commuter traffic would likely result in impractical work hour restrictions for initial

construction and future maintenance. For these reasons, NEP rejected the railroad corridor as a

viable alternative.



3.7 CROSS-HARBOR TRANSMISSION ALTERNATIVES

NEP evaluated the following scenarios which involved installing overhead or underground

transmission lines across or under Salem Harbor:

1. Overhead Transmission Lines across Salem Harbor;

2. Jet Plow Alternative; and

3. Horizontal Directional Drill (“HDD”) Alternative.

It should be noted that all cross-harbor options would still require the removal of the existing

Cables from within City streets.

3.7.1 Overhead Transmission across Salem Harbor

For the purposes of this analysis, NEP first considered installing overhead transmission circuits

across Salem Harbor. However, according to the Installation and Maintenance of Electric

Transmission Lines Regulations (220 CMR 125.00), a 40-foot clearance is required to allow for

uninhibited vessel navigation through the harbor. Maintaining this clearance without

intermediate structures would require design tensions greater than the design capacity of

standard transmission conductors and would be impractical to design and build. Furthermore,

there could be additional clearance requirements imposed by the USACE and/or the Salem

Harbormaster’s Office. Placing intermediate structures within the harbor would directly

interfere with navigation throughout the harbor, would require extensive environmental

permitting, and could cause significant impacts to existing marine resources. Finally, an

overhead circuit across Salem Harbor would also require new overhead ROW easements in

order to connect from the harbor to each substation. Based on these substantial obstacles, NEP

determined that it was highly impractical to pursue this approach to meet the Project need, and

this option was eliminated from further analysis and consideration.

3.7.2 Jet Plow Alternative

The Jet Plow Alternative would involve the installation of two circuits along an approximately

1.4-mile corridor under the harbor using jet plow technology. Each of the circuits would contain

six solid dielectric cables, for a total of 12 cables with a horizontal separation of 20 feet cable-to-

cable, resulting in an overall installation width of approximately 260 feet (including 20 feet

outside of the outermost cables on each side).



Jet Plow Typical Cross Section

At the southern end, this alternative would require the installation of two underground cables

along separate routes for a total of approximately 1.0 to 1.5 miles of City streets to connect to the

Canal Street Substation (the total length of land-based construction would depend on the routes

chosen). At the northern end, one 0.3-mile underground route would be needed to connect to the

Salem Harbor Substation. Figure 3-3 shows the routing considered for this alternative.

In jet plow installation, a rubber-tired or skid-mounted plow with an approximate 15-foot width is

pulled along the sea floor by an installation barge. High-pressure water from vessel-mounted

pumps is injected into the seabed sediments through nozzles alongside the plow, causing the

sediments to temporarily fluidize and create a liquefied trench approximately five feet wide. As

the plow is being pulled along the route behind the barge, the electric cables are laid into the

temporarily liquefied trench through the back of the plow. The trench is backfilled by the water

current and the natural settlement of the suspended material. Depth of burial is controlled by

adjusting the angle of the plow relative to the sea floor, with a typical target depth of approximate-

ly six to eight feet. The actual burial depth would depend on the substrate encountered along the

route. Following installation, the cables are armored from surface damage using a combination of

sandbags and concrete mattresses in areas of high marine activity.

At each landfall location, the cable is installed using a short-range HDD between an upland

manhole location and a temporary cofferdam (typically 20 feet by 50 feet in size) located a

short distance offshore. To accomplish this, a tunnel is drilled between the upland manhole and

the offshore cofferdam, and a polyethylene conduit is pulled through the tunnel. The jet plow is



then positioned adjacent to the cofferdam, and the cable is fed through the plow and pulled

through the conduit to the upland manhole.

Overall anticipated construction duration for the Jet Plow Alternative is estimated to be

18 months, of which 12 months would involve marine construction. Construction along the

land routes and at the substations could occur simultaneously with marine construction

operations, and the remaining six months would involve completion of upland infrastructure

construction, substation construction, and cable installation.

The following sections present an evaluation of the land use, navigation and environmental

impacts, permitting, reliability, and cost considerations associated with this Project alternative.

Navigational Features, Marine Resources, and Land Use

Figure 3-4 shows the existing navigational features within the harbor, and Figure 3-5 shows the

marine resource features within the harbor.

Navigational Features

Salem Harbor is one of the region’s largest natural harbors. The main ship entrance into the port

is a federally maintained channel leading from the northeast that, at a depth of 32 feet at mean

low water, is one of the deepest channels in the state. This shipping lane and a City-maintained

turning basin are located off the Blaney Street docks. The dredged portion of this shipping

channel is approximately 8,500 feet long (1.5 miles) and 300 feet wide, widening to 400 feet at

the turns. In addition to the large turning basin within Salem’s inner harbor, there is one 8-foot-

deep federal channel northeast of Derby Wharf, and another channel on the other side of the

wharf beginning at the approach to and continuing up into the South River. The approach

channel to the South River is maintained to a depth of 10 feet, decreasing to eight feet at the

river entrance and then to six feet just south of Pickering Wharf. These channels provide access

for recreational boats and smaller commercial vessels into the Pickering, Central, and Derby

wharves on the South River (City of Salem Municipal Harbor Plan Renewal, 2008).

The Jet Plow Alternative would have a high potential to be in direct conflict with existing

navigation features and future plans for additional dredging. In a letter dated May 20, 2010, the

Salem Assistant Harbormaster commented on the potential impacts of a jet-plowed installation

within Salem Harbor, including the permanent displacement of 300 moorings for recreational

boaters and the attendant impact on two private marina businesses and one yacht club, as well

as general conflicts with the proposed Salem Wharf Project off Blaney Street, which would

house a new port terminal building, a boardwalk, and dock space for waterborne travel,

recreational, and commercial vessels. Installation of a jet-plowed cable in this area would be in

direct conflict with the public use of the harbor and would result in loss of access to the public

and loss of revenue to the City resulting from loss of moorings.



Marine Resources

Salem Harbor provides essential forage habitat for a variety of fish and invertebrate species

including alewife (Alosa pseudoharengus), blueback herring (Alosa aestivalis), rainbow smelt

(Osmerus mordax), American eel (Anguilla rostrata), white perch (Morone americana), Atlantic

tomcod (Microgadus tomcod), Atlantic cod (Gadus morhua), striped bass (Morone saxatilis),

bluefish (Pomatomus saltatrix), pollock (Pollachius virens), and American lobster (Homarus

americanus). It is also habitat for the forage, spawning, and early development of winter flounder

(Pseudopleuronectes americanus), an important recreational and commercial species currently in

decline according to state and federal assessments. In addition, populations of soft shell clams

(Mya arenaria), blue mussels (Mytilus edulis), Atlantic sea scallop (Placopecten magellanicus),

and eelgrass (Zostera marina) have been mapped by the Massachusetts Division of Marine

Fisheries (“DMF”) within the harbor. Eelgrass beds are important as nursery habitat for finfish

and invertebrates and play a key role in nutrient cycling and sediment filtering. Eelgrass meadows

in Salem Harbor declined by 70 percent between 1995 and 2006, making the harbor an area of

particular concern for DMF and other state and local organizations.

Jet plow installation within Salem Harbor would result in direct impacts to these marine

resources. To protect fisheries resources, the DMF recommends time-of-year (“TOY”)

restrictions on any project with the potential to affect marine fisheries. Construction for this

alternative could be limited or prohibited during the periods shown in Table 3-7 to protect fish

and shellfish identified in Salem Harbor. Additional consultations with the DMF would be

necessary to establish required mitigation measures and Project-specific TOY restrictions for

jet-plowed installation of circuits within Salem Harbor. Letters from DMF as well as a letter

from the National Marine Fisheries Service (“NMFS”) are included in Appendix 3-2.

Land Use

This project alternative would require construction of approximately 1.0 to 1.5 miles of new

underground transmission lines within City streets between the harbor and Canal Street

Substation. Land uses in this area consist mainly of residential neighborhoods with small

businesses and community buildings mixed in. In addition, approximately 0.3 mile of new

underground transmission lines would be required on the Footprint property between the harbor

and the Salem Harbor Substation. NEP does not currently have the easement rights to cross two

private parcels along the land-based portions of this alternative. The parcels on both sides of

Salem Harbor where the lines would surface are privately owned, and NEP would have to

obtain easement rights on either side of the harbor to install the cables. In addition, according to

the DEP Waste Site List, the soils at both of these parcels are known or suspected to contain

contamination that would require special disposal. Because of the contamination in the existing

soils and groundwater in these locations, a well-developed mitigation plan would need to be in

place to avoid additional contamination to the surrounding area.



Table 3-7: Summary of Marine Fisheries Resources within Salem Harbor

Species

Spring TOY

Restriction

Fall TOY

Restriction Presence Status

Alewife (Alosa pseudoharengus) April 1–June 15 Sept. 1–Nov. 15 Present; not spawning

Blueback herring (Alosa aestivalis) April 1–June 30 Sept. 1–Nov. 15 Present; not spawning

Rainbow smelt (Osmerus mordax) March 1–May 31 None Present; not spawning

American eel (Anguilla rostrata) March 15–June 30 Sept. 15–Oct. 31 Present; not spawning

White perch (Morone americana) April 1–June 15 None Present; not spawning

Atlantic tomcod (Microgadus tomcod) Feb. 15–April 30 None Present; not spawning

Atlantic cod (Gadus morhua) April 1–June 30 Dec. 1–Jan. 31 Present; not spawning

American lobster (Homarus americanus) May 31–July 31 Spawning run/habitat present based on recent and/or historical documentation

Winter flounder (Pseudopleuronectes

americanus) Feb. 15–June 30 None Spawning run/habitat present

based on recent documentation

Soft shell clam (Mya arenaria) May 1–Sept. 30 Spawning run/habitat present based on recent and/or historical documentation

Blue mussel (Mytilus edulis) May 15–August 31 Spawning run/habitat present based on recent and/or historical documentation

Atlantic sea scallop (Placopecten

magellanicus) None Sept. 1–Nov.15 Spawning run/habitat present

based on recent and/or historical documentation

Permitting


required for this Project alternative.

Of particular note, the Public Waterfront Act (G.L. Chapter 91) and its regulations

(310 CMR 9.00) require that a Waterways License or Permit be obtained from DEP for

structures and uses located in, under, or over flowed and filled tidelands of the Commonwealth.

This Project alternative would be located within both flowed and filled tidelands of the

Commonwealth. According to the 2008 Salem Harbor Plan (“2008 SHP”), a portion of the

Salem waterfront has been identified by the Commonwealth as a Designated Port Area

(“DPA”). The DPA consists of the land, piers, and water southeast of Derby Street and Fort

Avenue, extending from the Footprint property to (and including) the northernmost wharf of

the Hawthorne Cove Marina.

Many of the permits required for this Project alternative contain statutory standards that require

an applicant to prove that there is no practicable alternative to the proposed discharge or action



that would have less adverse impact on the regulated natural resource area. Such demonstration

would be difficult for this Project alternative because there are other Project alternatives

presented herein that would meet the Project need and could avoid impacts to regulated natural

resource areas.

In addition, this Project alternative does not meet statutory tests for approval under Chapter 91

for non-water-dependent projects located within a DPA, because water-dependent uses require

“direct access to or location in tidal or inland waters, and therefore cannot be located away from

said waters.” 310 CMR 9.12(2). The availability of feasible land-based alternatives generally

negates the use of tidelands by non-water-dependent facilities.

In conclusion, NEP has determined that it would be difficult to obtain permits for this project

alternative given the necessity to overcome regulatory standards for practicable alternatives and

the requirement of an applicant to present a project that is the least environmentally damaging

practicable alternative to meet the project need. Even if it were possible to obtain permits for

this project alternative, the permitting process is expected to take at least 18–24 months. Given

this, NEP estimated that it would not be possible to permit and construct this project alternative

prior to Footprint’s in-service date of June 2016.



Table 3-8: Anticipated Permits and Approvals for Jet Plow Alternative1


FEDERAL


USACE Individual Permit Section 10

Individual Permit Section 103 of the Marine Protection, Research and Sanctuaries Act of 1972

Individual Permit Section 404

National Historic Preservation Act, Section 106 Review

STATE







CZM CZM Consistency Review

MHC and Massachusetts Bureau of Underwater Archaeology (“MBUA”)

Project Notification Form (G.L. c. 9, § 27C)

LOCAL


Salem City Council Grant of Location (G.L. c. 166, § 22 and Chapter 38, Article IV of the Salem Code of Ordinances)

1 This alternative may also require zoning relief from the Salem zoning code.

Reliability

A jet-plowed replacement cable could present future reliability, emergency response, and

environmental challenges should the cables require repairs due to damage or failure. Submarine

cables are susceptible to damage from anchors, dredging activities, barge spuds (steel shafts

that hold the barge in place), and the installation of moorings. Should the submarine portion of

a cable be damaged in one of these ways or otherwise fail during the lifetime of the system, it

would be difficult to locate and diagnose the problem. Submarine cable failures typically take

in excess of six weeks to repair. Specialized equipment and contractors would likely need to be

mobilized to the site to locate the fault, and once the problem had been identified, repairs would

likely require emergency environmental permits. By comparison, underground cable repairs

typically take two to three weeks.



Cost

The estimated cost for the installation of two 1.4-mile submarine circuits via jet plow and their

associated land-based portions comes to approximately $170 million. A breakdown of the total

estimated costs for the Jet Plow Alternative is included in Table 3-9. These conceptual grade

estimates are based on recent costs of similar materials and construction activities, have a target

accuracy of -25% to +50%, and do not consider possible future variances in commodity or

labor costs.

Table 3-9: Estimated Costs for Jet Plow Alternative across

Salem Harbor (2013 dollars)

Cost

(millions)

Jet Plow Alternative

Installation of cables (submarine and land route) $139.41


Removal of existing T cable $0.58

Cable Construction Cost Subtotal: $145.36

Substation Upgrades




Permitting, Project Administration and Development: $10.81

Total Cost (millions) $169.79

Conclusion

The Jet Plow Alternative is technically feasible and was advanced for further comparison with

other alternatives.

3.7.3 HDD Alternative

The following sections present an overview of the details associated with this alternative. NEP

commissioned Burns & McDonnell and their sub-consultant Haley & Aldrich to complete a

detailed investigation into the feasibility, risks, and estimated costs for installing the new Cables

under Salem Harbor using HDD technology. See Appendix 3-3 for the complete feasibility

study document.



The HDD Alternative would involve the installation of two circuits along an approximately

2.0-mile corridor under the harbor using horizontal directional drilling technology. High-

pressure fluid-filled (“HPFF”) cables would be used to accommodate the long pull length

needed for this alternative. To achieve the required ratings with this cable technology, 18 total

cables would be required (three cables installed in each of six cable pipes; see diagram below).7

HDD Typical Cross Section

At the southwest end, this alternative would require the installation of two underground cables

along separate routes for a total of approximately 1.0 to 1.5 miles of City streets to connect to

the Canal Street Substation (the total length of land-based construction would depend on the

routes chosen). Two more separate land-based routes totaling approximately 0.5 miles would

7 The size and number of cables required is dictated by a combination of depth of burial, installation conditions, and cable technology. Thus, the Jet Plow Alternative, proposed as solid dielectric cables installed in trenches excavated in the harbor floor, would require two cables per phase for a total of 12 cables (six for each circuit), while the HDD alternative, proposed as HPFF cable, would require 18 total cables for both circuits.



be needed to connect to the Salem Harbor Substation. Figure 3-6 shows the routing considered

for this alternative.

In a typical HDD installation, a pilot hole is first drilled down from the surface along a designed

profile and back up to the surface on the other side. Bentonite drilling fluid, composed of

bentonite clay and water, is delivered to the drill head along a small pipe known as a drill string.

This fluid prevents the newly established hole from collapsing and removes cutting spoil as the

fluid returns to the entry point of the pilot hole. The bentonite clay is processed to remove the

cuttings and is recycled for use as the drilling operation continues.

Once the pilot hole has been drilled, it is then enlarged with one or more reaming passes,

depending on the proposed pipe diameter. The rotating reaming/cutting tool is attached to the

drill at the exit point, and drawn back toward the drilling rig at the entry point of the pilot hole.

On the last pass through with the reaming tool, the prefabricated pipe is attached to the drill and

drawn through the enlarged pilot hole. Once the pipe is in place, the cables can be pulled

through the pipe.

Due to the length of the crossing in Salem Harbor and the lack of space on either side of the

harbor in which to assemble the pipes, a temporary mid-harbor platform would need to be

installed. In this situation, the process described above would occur twice per pipe (once from

each side of the harbor, out to the mid-harbor platform). At the mid-harbor platform, the cables

from either side would be spliced together, and a steel casing would be welded over the splice

to connect the two sides of the pipe. The connected pipe would then be overboarded from the

platform into a pre-excavated shallow trench (approximately five to ten feet deep). This entire

process would be repeated five times to install all six cable pipes required for this alternative.

With all of the pipes installed, the shallow burial depth at the mid-harbor platform would result

in a permanently restricted area approximately 200 feet wide by 500 feet deep (2.3 acres). It

should be noted that there is a possibility that, based on further evaluation of subsurface

conditions, the longest segment between the Salem Harbor Substation and the mid-harbor

platform could require the installation of a second mid-harbor platform to safely install the

cables without causing cable stress and risking installation failures. This would result in a

second 2.3-acre area with permanent navigation-related restrictions.

At the Salem Harbor substation, there is limited subsurface space and the circuits must be

separated to launch from separate points (three cable pipes from each point). Between the mid-

harbor platform and Palmer Cove, the circuits could follow a common corridor. On either side

of the harbor, the cables would need to be installed underground to connect to the existing

Canal Street and Salem Harbor Substations. At the northern end, this installation would take

place within the existing pavement on the Footprint property. At the southern end, the

installation would pass directly beneath the Palmer Cove Yacht Club support piers and the

Salem Community Gardens adjacent to the ball field. The six cable pipes would then be

installed within City streets to reach the Canal Street Substation. The circuits would need to be

separated into two routes to fit within the streets.



Construction of the HDD Alternative, including drilling operations, cable pulling, the

installation of cables along the land-based routes, and substation work, could take up to 18

months. Drilling operations and installation of the cables in the harbor would require the mid-

harbor platform to be in place for 14 months or more, potentially including two summer

seasons. Construction along the land routes and at the substations could occur simultaneously

with drilling operations. The Palmer Cove ball fields would be occupied for at least three

consecutive months for HDD equipment staging, pipe stringing, and welding. Once both the

marine and upland pipes were in place, the HDD equipment would be demobilized at Palmer

Cove. At a later date, cable installation activities would again occupy the Palmer Cove ball field

for up to two months.

The HPFF cable required for the HDD Alternative is presently available from only one

manufacturer in the U.S., and lead times are currently projected at 24–30 months. Combined

with the expected permitting required, the extended construction duration and material lead

times make it unlikely that the Project could be completed before July 2017 at the earliest.

Extensive testing and stringent disposal requirements would be necessary for any contaminated

dredged or excavated marine sediments, as well as for materials from the entry and exit sites.

The soils at both the Salem Harbor Substation and the baseball field adjacent to Palmer Cove

are known or suspected to contain contamination that would require special disposal.

Furthermore, there is little information available about the geology of Salem Harbor; existing

data from limited borings and USGS surficial geology mapping shows that depth to bedrock is

highly variable, which could pose a significant risk to the success of the HDD. Unforeseen

changes in geological conditions can result in drill stem or product pipe failure, return of drill

mud to the surface at unplanned locations (known as “frac-out”), and cross-contamination.

These would increase the potential for environmental impacts, would increase construction

duration, and would affect the use of the Harbor and the recreational area off Leavitt Street.

Navigational Features, Environmental Impact, and Land Use

Figure 3-7 shows the navigational features within the harbor, and Figure 3-8 shows the marine

resources within the harbor.

Navigational Features

As discussed Section 3.7.2, Salem Harbor is one of the region’s largest natural harbors, with

three federal shipping channels and a City-maintained turning basin which provide access for

recreational boats and smaller commercial vessels into the Pickering, Central, and Derby

wharves on the South River. The depth of drilling would need to be carefully planned to avoid

conflict with maintenance dredging of existing federal navigation channels and to be consistent

with the 2008 Salem Harbor Plan’s future proposed dredging. In addition, the 2.3-acre restricted

area around the mid-harbor platform could permanently displace moorings for recreational

boaters.



Environmental Impact

As detailed in Section 3.7.2, Salem Harbor provides essential forage, spawning, and early

development habitat for a variety of fish and invertebrate species including the declining winter

flounder. Eelgrass beds, which provide important nursery habitat for finfish and invertebrates,

have also been mapped in the harbor by DMF.

For the HDD Alternative, the cables would generally be installed at a depth that would avoid

direct impacts to marine resources; however, the 2.3-acre area around the mid-harbor platform

would result in direct impacts to land under the ocean. The proposed placement of the mid-harbor

platform optimizes pipe stress issues, avoids navigational channels, and minimizes impacts to

small water craft anchorage, but falls within an area of eelgrass mapped by DMF.

To protect fisheries resources, the DMF recommends TOY restrictions on any project with the

potential to impact marine fisheries. Construction for this alternative could be limited or

prohibited during the TOYs for the fish and shellfish identified in Salem Harbor as shown in

Table 3-7 in Section 3.7.2. Additional consultations with the DMF would be necessary to

establish required mitigation measures and Project-specific TOY restrictions for HDD installation

of circuits within Salem Harbor. Letters from DMF and NMFS are included in Appendix 3-2.

With all HDD operations, there is an inherent risk that drill fluids could escape to the surface

and cause delays. This risk can be minimized with engineering controls and fluid management

plans, but cannot be entirely eliminated.

Over the life of the cable system, dielectric fluid releases could occur from any of the pipes

installed beneath the harbor. HPFF cable systems operate with three conductors installed in a steel

pipe that is filled with dielectric fluid and pressurized to approximately 200 psi. The fluid acts as

an insulator and prevents electrical discharge in the cable’s paper insulation. If the steel pipe is

compromised by corrosion or third-party damage, the dielectric fluid would be released to the

surrounding environment. In an HDD installation, the leak location would not be accessible and

would be a low point in the hydraulic system. Given the nominal operating pressure of 200 psi, a

significant release of dielectric fluid would occur before the leak could be contained.

Land Use

This project alternative would require construction of approximately 1.0 to 1.5 miles of new

underground transmission lines within City streets between the ball field and the Canal Street

Substation. Land uses in this area consist mainly of residential neighborhoods with small

businesses and community buildings mixed in. In addition, approximately 0.5 miles of new

underground transmission lines would be required on the Footprint property between landfall

and the Salem Harbor Substation.

NEP does not currently have the easement rights to cross two private parcels along the land-

based portions of this alternative. The parcels on both sides of Salem Harbor where the lines



would surface are privately owned, and NEP would have to obtain easement rights on either

side of the harbor to install the cables. In addition, according to the DEP Waste Site List, the

soils at both of these parcels are known or suspected to contain contamination that would

require special disposal. Because of the contamination in the existing soils and groundwater in

these locations, a well-developed mitigation plan would need to be in place to avoid additional

contamination to the surrounding area.

Permitting


required for this project alternative.

Of particular note, this project alternative would be located within both flowed and filled tidelands

of the Commonwealth and would require that a Waterways License or Permit be obtained from

DEP under Chapter 91 and its regulations. The Commonwealth has also identified the land, piers,

and water southeast of Derby Street and Fort Avenue as a DPA.

Many of the permits required for this project alternative contain statutory standards that require

an Applicant to prove that there is no practicable alternative to the proposed discharge or action

that would have less adverse impact on the regulated natural resource area. Such demonstration

would be difficult because there are other alternatives presented herein that would meet the

Project need and could avoid impacts to regulated natural resource areas.



Table 3-10: Anticipated Permits and Approvals for HDD Alternative1


FEDERAL


USACE Individual Permit Section 10

Individual Permit Section 103 of the Marine Protection, Research

and Sanctuaries Act of 1972

Individual Permit Section 404

National Historic Preservation Act, Section 106 Review

STATE







CZM CZM Consistency Review

MHC and MBUA Project Notification Form (G.L. c. 9, § 27C)

LOCAL


Salem City Council Grant of Location (G.L. c. 166, § 22 and Chapter 38, Article IV of the Salem Code of Ordinances)

1 This alternative may also require zoning relief from the Salem zoning code.

In addition, this Project alternative does not meet statutory tests for approval under Chapter 91

for non-water-dependent projects located within a DPA, because water-dependent uses require

“direct access to or location in tidal or inland waters, and therefore cannot be located away from

said waters.” See 310 CMR 9.12(2). The availability of feasible land-based alternatives

generally negates the use of tidelands by non-water-dependent facilities.

In conclusion, NEP has determined that it would be difficult to obtain permits for this Project

alternative given the necessity to overcome regulatory standards for practicable alternatives and

the requirement of an applicant to present a project that is the least environmentally damaging

practicable alternative to meet the project need. Even if it were possible to obtain permits for

this Project alternative scenario, the permitting process is expected to take at least 18–24

months. Given this, NEP estimated that it would not be possible to permit and construct this

Project alternative prior to Footprint’s in-service date of June 2016.



Reliability

HDD-installed replacement cables could present future reliability, emergency response, and

environmental challenges should the cables require repairs due to damage or failure. These

HPFF cables could be damaged by anchors, dredging activities, barge spuds, and mooring

installations; for this project, damage would be most likely to occur at the shallow mid-harbor

splicing location. Maintenance for HDD-installed cables would be more complex than for jet-

plowed cables because they are not accessible except at the mid-harbor platform location,

where the cables could be resurfaced for possible repair activities and reburied. These repairs

would require emergency environmental permits and specialized equipment and contractors,

and would be time-consuming, costly, and potentially deleterious to the harbor environment

and the many activities it supports. The HPFF cables could also result in environmental

challenges in the form of dielectric fluid leaks to the surrounding sea floor and waters of the

harbor. Again, there is only one manufacturer of HPFF cables in the U.S., which puts future

availability of replacement cables at risk.

Cost

The estimated cost of 2.0 miles of HDD installation and its associated land-based portions is

estimated to be approximately $162 million. A breakdown of the total estimated cost for the

HDD Alternative is included in Table 3-11 below. The cost estimates provided are conceptual

grade estimates based on recent costs of similar materials and construction activities. They have

a target accuracy of -25% to +50% and do not consider possible future variances in commodity

or labor costs.

Table 3-11: Estimated Costs for HDD Alternative across Salem Harbor (2013 dollars)

Cost

(millions)

HDD Cable Alternative

Installation of cables (submarine and land route) $129.61


Removal of existing T cable $0.58

Cable Transmission Cost Subtotal: $135.56

Substation Upgrades




Permitting, Project Administration and Development $10.81

HDD Alternative Total Cost (millions) $162.08



Conclusion

The HDD Alternative is technically feasible and was advanced for further comparison with

other alternatives.

3.8 COMPARISON OF VIABLE ALTERNATIVES

As described in Sections 3.3 through 3.7, ten alternative concepts, including a no-build

alternative, were initially considered to meet the identified resource need. The no-build

alternative was rejected because it would neither improve reliability, meet the need for

increased capacity (with or without the proposed new Footprint generation facility), nor address

the end-of-life conditions of the existing Cables.

NEP concluded that five of the nine remaining alternative concepts were technically feasible;

these were advanced for further comparison in terms of environmental impacts, cost, and

reliability:

· Underground Single Duct Bank Alternative: Installation of two cables within one new duct

bank and manhole system within City streets;

· Underground Two Duct Bank Alternative: Installation of two cables within two new

separate duct bank and manhole systems along different routes within City streets;

· Overhead Circuits around Salem: Installation of overhead transmission circuits between

Salem Harbor Substation and West Salem Substation around the outer perimeter of Salem;

· Jet Plow Alternative: Jet plow installation of two transmission cables across Salem Harbor;

and

· HDD Alternative: HDD installation of two transmission cables across Salem Harbor.

Table 3-12 presents a summary and comparison of these five alternatives.

As discussed in Section 3.7, both the Jet Plow and HDD Alternatives involve a high risk of

failure or extensive delay in obtaining necessary permits because they are not water-dependent

uses and there are practicable alternatives that would result in fewer adverse impacts to aquatic

ecosystems. They would result in significant environmental impacts to natural marine resources

as well as human uses of Salem Harbor, and long-term reliability of the cables would be

problematic because repairs would require emergency permitting and six or more weeks of

disruption in the harbor, and would depend on the limited availability of replacement cables

and specialized equipment and contractors. The costs of these two alternatives are also more

than double the cost of the underground alternatives. Based on these factors, these alternatives

were determined to be inferior and were dismissed from further consideration.



The overhead transmission alternative between the Salem Harbor and West Salem Substation

would cross and disturb several open spaces, fill tidal and freshwater wetland systems, and

require trees to be removed along the route. This alternative would also require a significant

amount of property acquisition and demolition to create room for overhead circuits, which

could delay the Project for several years. It would require many more permits and cost more

than double the amount of the underground alternatives. Further, it is possible that NEP would

not be able to obtain an Article 97 disposition because there are feasible and substantially

equivalent alternatives that would meet the Project need without a disposition. The overhead

alternative was consequently eliminated from further consideration.

The two viable underground alternatives would have similar permit requirements and would

require the same amount of time for repairs. Neither alternative would cause any long-term

impacts to the natural environment. Both would have temporary noise, dust, and traffic impacts

to the human environment during construction. However, the Single Duct Bank Alternative has

a few advantages over the Two Duct Bank Alternative. First, it would have a shorter overall

construction schedule than the Two Duct Bank Alternative, resulting in a shorter duration of

impacts to the City as a whole. The shorter construction time frame would also increase the

probability that the Project could be delivered by Footprint’s June 2016 on-line date. Finally,

Single Duct Bank Alternative would have somewhat lower overall costs than the Two Duct

Bank Alternative. Based on these factors, NEP concluded that the best solution to address the

identified need is the construction of two new, higher-capacity cables in a single new duct bank

and manhole system within City streets between the Salem Harbor and Canal Street

Substations. The Company therefore concluded that the Single Duct Bank Alternative was

superior to the other alternatives and it was thus carried forward to the routing analysis

presented in Section 4 of this Analysis.



Table 3-12: Summary of Transmission Project Alternatives

Underground Single Duct Bank

Alternative

Underground Two Duct Bank

Alternative

Overhead Circuits around

Salem Jet Plow Alternative HDD Alternative

Two new cables in one route within City streets

Two new cables in two separate routes within City streets

Two overhead circuits installed around the outer perimeter of Salem

Jet plow installation of two circuits across Salem Harbor HDD installation of two circuits across Salem Harbor

Constructability Good Good Difficult; property acquisition and demolition would be required

Possible but not without significant and permanent disruption to vessel navigation

Potential impacts to marine resources and commercial and recreational boating in Salem Harbor

Possible but not without significant disruption to vessel navigation

Potential impacts to marine resources and commercial and recreational boating in Salem Harbor

Permit Considerations Applicable permits/regulations: EFSB, NPDES CGP, MWPA, Section 401 Minor Project Modification, local ordinances

* MEPA review not required

Applicable permits/regulations: EFSB, NPDES CGP, MWPA, Section 401 Minor Project Modification, local ordinances

* MEPA review not required

Applicable permits/regulations: EFSB, NPDES CGP, MWPA, Section 401 Individual WQC, MEPA, Section 404, Section 106, Article 97, local ordinances and bylaws

Risk of failure to obtain Article 97 disposition; feasible and substantially equivalent alternatives exist that would meet the Project need

Applicable permits/regulations: EFSB, NPDES CGP, MWPA, Section 401 Individual WQC, MEPA, Section 404, Section 106, Section 10, Section 103, Chapter 91,Coastal Zone Consistency Review, local ordinances

Risk of failure to obtain permits under Chapter 91 and Section 401; not a water-dependent use, and practicable non-aquatic alternatives exist

Applicable permits/regulations: EFSB, NPDES CGP, MWPA, Section 401 Individual WQC, MEPA, Section 404, Section 106, Section 10, Section 103, Chapter 91, Coastal Zone Consistency review, local ordinances

Risk of failure to obtain permits under Chapter 91 and Section 401; not a water-dependent use, and practicable non-aquatic alternatives exist

Schedule Considerations 2 construction years 2–3 construction years 18 months of construction

Several years for negotiating acquisitions and demolitions

16 months of construction

Potential for significant delays in construction and permitting

14 months of construction (could extend into two summer seasons)

24-30 months of lead time for HPFF cables

Potential for significant delays in construction and permitting

Impact Summary No natural environmental impacts

18 months of noise, dust, and traffic impacts from construction along a single new route

No natural environmental impacts

24 months of noise, dust, and traffic impacts from construction along two new routes

Crossing several open spaces

Filling tidal and freshwater wetland systems

Tree clearing

Need to acquire and demolish property

Significantly more visual impacts from overhead structures

18 months of noise, dust and traffic impacts from construction

Direct conflict with navigation features, future dredging, and Salem Wharf Project

Permanent loss of 300 moorings

Disturbance to declining eelgrass population and essential forage, spawning, and early development habitat for variety of fish and invertebrate species, including declining winter flounder

Potential for spread of existing contaminated soils

18 months of noise, dust, and traffic impacts from construction

Direct conflict with navigation features during construction

Close coordination necessary to avoid conflicts with future dredging

Mid-harbor platform would disturb declining eelgrass population and essential forage, spawning, and early development habitat for variety of fish and invertebrate species, including declining winter flounder; and potentially cause permanent loss of moorings

Potential for spread of existing contaminated soils

Palmer Cove ball fields occupied for up to 4 months for staging equipment and welding and stringing out pipe

18 months of noise, dust, and traffic impacts from construction

Reliability 2–3 weeks for cable fault repairs

6–8 weeks for duct bank repairs

2–3 weeks for cable fault repairs

6–8 weeks for duct bank repairs

Lack of permanent easement rights along railroad corridor could require Company to relocate lines at a future date

Submarine cables susceptible to damage from anchors, dredging, barge spuds, moorings

6+ weeks for repairs

Repair, maintenance, and spare cable storage require specialized equipment and contractors

Emergency environmental permits required for repairs

Submarine cables at mid-harbor locations susceptible to damage from anchors, dredging, barge spuds, moorings

6+ weeks for repairs

Repair, maintenance, and spare cable storage require specialized equipment and contractors

Emergency environmental permits required for repairs

Limited availability of cables for future replacement

Cost (2013 dollars) $62.43 million $68.65 to $73.59 million $144.70 million $169.79 million $162.08 million

Section 4.0: Route Selection Process


4.0 ROUTE SELECTION PROCESS

4.1 INTRODUCTION AND OVERVIEW OF SITING METHODOLOGY

This Section discusses the systematic route selection process NEP followed to select the

Preferred Route and a Noticed Alternative for the proposed replacement of the existing Cables.

Following an analysis of a variety of potential project alternatives as described in Section 3 of

this Analysis, NEP determined that the preferred approach to meet the identified Project need at

the lowest reasonable cost, with the least environmental impact, and with high reliability is to

install the replacement cables within a new duct bank and manhole system within City streets

between the existing Salem Harbor Substation and the Canal Street Substation. NEP began the

process of identifying potential routes for the replacement cables by demarcating a geographic

Project Study Area (Section 4.2).

NEP then established route selection guidelines for the process of identifying all feasible

potential routing options. Potential routes identified for screening and analysis included

established ROWs (all existing City streets) that could be connected to provide non-circuitous

routes between the Canal Street and Salem Harbor Substations. Once potential routes were

identified, NEP then undertook a two-step route selection process that concluded with the

identification of a Preferred Route and a Noticed Alternative (Section 4.3). The process was

designed to make sure that no superior route was overlooked. The first step in the route

selection process included an initial evaluation of the City streets chosen for potential routes

within the Project Study Area. This evaluation included a review of aerial photographs, review

of data available from MassGIS for land use and environmental features, field reconnaissance,

review of underground utility mapping, and communication with City officials and the public.

This step concluded with the elimination of those routes that had major flaws or lacked

attractive features relative to the other routing options available.

Those route segments that were not screened out in step one were combined into “candidate

routes” and assessed in more detail in step two (Section 4.4). These candidate routes were

evaluated, scored, and ranked by applying a set of objective environmental criteria and

evaluating conceptual cost estimates (Section 4.5). The reliability of the candidate routes was

also considered, although it was not found to be a discriminating factor between the different

routes. NEP used the scoring and ranking process to select the Preferred Route and the

geographically diverse Noticed Alternative (Section 4.6). The Preferred Route and the Noticed

Alternative are compared in more detail in Section 5 of this Analysis.

It is important to note that it will not be possible to take either Cable out of service for an

extended period of time to support construction. Therefore, a new cable system must be

constructed and ready for service prior to taking either of the existing Cables out of service.



This fact dictates certain construction sequencing and defines the options available for Project

alternatives.

4.2 PROJECT STUDY AREA

The Project Study Area was developed to evaluate routing opportunities that could provide a

relatively direct connection between the Canal Street and Salem Harbor substations over a

reasonable distance and is depicted in Figure 4-1.

The Study Area encompasses the central part of the City of Salem. Major features of the Study

Area include the Salem Harbor Substation in the east; the major commercial area along and east

of Washington Street in the northwestern portion of the Study Area; densely populated residential

neighborhoods in the southern and north/central portions of the Study Area; and important

cultural and historic features such as the historic Salem Common, Peabody Essex Museum, and

other tourist attractions such as the Salem Witch Museum and Salem Maritime National Park.

4.3 ROUTE SELECTION

4.3.1 Route Selection Guidelines

NEP created route selection guidelines to be used in the process of developing and selecting

complete candidate routes for the replacement cables. First, NEP determined that direct routes

were preferred over circuitous routes. Shorter, more direct routes generally have less

environmental impact, involve less construction disruption, and are generally less expensive

and easier to maintain. Second, NEP determined that established ROWs should be used where

possible. The use of established linear corridors such as streets generally reduces impacts to the

natural environment. In addition, the use of existing streets can simplify the process of

acquiring the necessary property rights to construct the needed facilities, thereby reducing the

overall cost of the Project.

4.3.2 Initial Route Identification

Using the route selection guidelines, NEP mapped all potential streets within the Project Study

Area that could be used to develop a relatively direct route between the Canal Street Substation

and the Salem Harbor Substation. The result is shown in Figure 4-2, which depicts the potential

routing opportunities identified in this initial step.

4.3.3 Screening

NEP assessed the initial set of identified routes to determine which routes were appropriate for

further study. As part of this process, NEP undertook several key planning and outreach

initiatives, including meetings with several department heads from the City, to identify whether



siting a new duct bank and manhole system within these streets would conflict with City

projects or facilities. As part of this process, NEP met with representatives from the Salem

Harbormaster’s Office, Conservation Commission, Historic Commission, Engineering

Department, Department of Planning and Community Development, Mayor’s Office, City

Council, DPW, and the Tree Warden’s office. NEP also met with representatives from

Footprint and Spectra Energy, and held public meetings to provide information regarding the

Project and solicit input from the public regarding important considerations and public

resources in the Project Study Area. As part of this process, NEP identified existing City streets

where major infrastructure projects were recently completed or were scheduled to be completed

in the near future in order to ensure appropriate coordination throughout construction.

Existing utility mapping for the Project Study Area was obtained to determine the underground

infrastructure features for each street being considered. Field reviews were then conducted to

identify any additional issues along each street that may not have been evident from desktop

analyses.

Any street where the existing utility density was too high to install a new duct bank and

manhole system was eliminated from further consideration. In addition, some streets were

eliminated from further consideration due to input from City personnel or based on analysis and

field observations. In summary, as a result of the initial screening process, the following

segments of City streets were eliminated from further consideration:

· Essex Street from the intersection with Forrester Street to Hawthorne Boulevard contains

multiple underground utilities, existing manholes, and other subsurface structures distributed

throughout the roadway that make installation of the replacement cables infeasible. In

addition, some of the existing underground utilities that traverse or are perpendicular to Essex

Street cross it at very low angles, requiring an extended length of the existing utility infra-

structure to be exposed during construction.

· Forrester Street from Webb Street to its bend southward toward Essex Street was eliminated

due to its narrow road width and the presence of several underground utilities.

· Bridge Street was eliminated because of recent major improvements undertaken by the City.

The City’s reconstruction activities for Bridge Street included removing the top 18 inches of

roadway; re-grading the road sub-base; then reconstructing the road and installing new

sidewalks, curbing, street and intersection lighting, and a new bike path. The City Engineer

and the Director of the DPW specifically requested that NEP avoid constructing in Bridge

Street.

· Washington Street contains the MBTA’s Newbury/Rockport Commuter Rail line (which is

subterranean along Washington Street between Mill Street and Bridge Street) and several

underground utilities that present numerous obstacles to the installation of a new duct bank

and manhole system.

· Cedar Street between the Canal Street Substation and Lafayette Street contains the existing

T cable duct bank system. There is no room within this route to accommodate construction of



the new duct bank and manhole system without prior removal of the existing T cable. Prior

removal is not possible, since both the existing Cables must remain energized until the

replacement cables are installed.

· Derby Street from Fort Avenue west to Orange Street is physically constrained. This section

of road way is very narrow and contains a multitude of existing utilities including gas, sewer,

water, and telecommunications, as well as the existing Cables. There is not sufficient room to

install the new duct bank without prior removal of one of the existing Cables, and prior

removal is not possible since the existing Cables must remain energized until the replacement

cables are installed.

· Canal Street and Washington Street from Canal Street substation to New Derby Street

would not be able to accommodate construction of the new duct bank and manhole system

without prior removal of the existing S cable. Multiple large-diameter sewers (42 inches and

72 inches), gas, water, and telecommunications facilities, as well as the existing S cable, leave

minimal space available for the installation of the new duct bank and manhole system. As

stated above, prior removal of the existing cable is not possible because both Cables must

remain energized until the replacement cables are installed.

· New Derby Street from Washington Street east to Dodge Street Court also contains a large

number of sewers, gas, water, and telecommunications facilities in addition to the existing S

cable. Without prior removal of the existing cable, there would be no room to install the new

duct bank and manhole system. Again, removal is not possible because the existing Cables

must remain energized until the new cables are installed.

· Palmer Street does not offer any distinct advantage over Leavitt Street, which aligns directly

with Fairfield Street. With Cedar Street eliminated, use of Palmer Street would require two

additional bends that could be avoided by using Leavitt Street.

Once the streets listed above were eliminated from further consideration, the following streets

were also eliminated from further consideration as they were no longer a logical component of

a non-circuitous route between the Canal Street and Salem Harbor substations:

· Webb Street from Andrew Street to Bridge Street

· Church Street between Washington Street and Saint Peter Street

· St. Peter Street between Church Street and Bridge Street

· Brown Street between Saint Peter Street and Washington Square West

· Front Street between Washington Street and Lafayette Street

· Lafayette Street between Charter Street and Essex Street

The following streets were advanced for further consideration and inclusion into complete

candidate routes:

· Fort Avenue from the Salem Harbor Substation to Essex Street

· Webb Street between Essex Street and Andrew Street

· Essex Street from Fort Avenue to Forrester Street



· Forrester Street between Essex Street and Washington Square South

· Boardman Street from Webb Street to Washington Square East

· Briggs Street between Webb Street and Washington Square East

· Andrew Street from Webb Street to Washington Square North

· Washington Square East between Andrew Street and Briggs Street, and between

Boardman Street and Forrester Street

· Washington Square North from Andrew Street to Washington Square West

· Washington Square West between Washington Square North and Essex Street

· Washington Square South from Washington Square West to Washington Square East

· Hawthorne Boulevard between Essex Street and Derby Street

· Charter Street from Hawthorne Boulevard to Lafayette Street

· Derby Street between Hawthorne Boulevard and Lafayette Street

· Webb Street from Andrew Street to Bridge Street

· Congress Street between Derby Street and Leavitt Street

· Lafayette Street from Charter Street to Gardner Street

· Leavitt Street between Congress Street and Lafayette Street

· Fairfield Street from Lafayette Street to Cabot Street

· Cabot Street between Fairfield Street and Cypress Street

· Cypress Street from Cabot Street to Canal Street

· Gardner Street between Lafayette Street and Canal Street

· Canal Street from Gardner Street to the Canal Street Substation

These streets are depicted in Figure 4-3.

4.4 IDENTIFICATION OF CANDIDATE ROUTES

Having eliminated individual street segments in the initial screening process, NEP then

organized all of the remaining street segments into nine potential candidate routes for further

evaluation. These candidate routes are described in detail in the following sections and shown

in Figure 4-4.

4.4.1 Candidate Route A (Boardman – Congress)

This approximately 1.66-mile route (shown as the light green line on Figure 4-4) exits the Salem

Harbor Substation and travels along Fort Avenue and Webb Street, passing by the Bentley

Elementary School and ball fields, a church, and a mix of residences and businesses. The route

then turns southwest into a residential neighborhood on Boardman Street, passing in front of a

funeral home as it turns south onto Washington Square East and follows along the east side of

Salem Common. It turns west along the south side of the Common following Washington Square

South, passing in front of an apartment building, a funeral home, and the Hawthorne Hotel.



The route then turns south onto Washington Square West and Hawthorne Boulevard, passing a

church, the Boys and Girls Club, and several multi-family residences and businesses. Continuing

south onto Congress Street, this route passes the Salem Waterfront Hotel and Marina, the Essex

County Registry of Deeds, and other businesses and office buildings and then transitions into a

mix of residential neighborhoods and commercial uses approaching Leavitt Street. Turning west

onto Leavitt Street, the route passes a yacht club and the Palmer Cove Park and Playground, as

well as a funeral home at the intersection with Lafayette Street. Crossing Lafayette Street and

continuing onto Fairfield Street, the route turns north onto Cabot Street, west on Cypress Street,

and then north across a vacant NEP-owned parcel to connect to the Canal Street Substation.

Fairfield, Cabot, and Cypress Streets are all primarily residential neighborhoods.

4.4.2 Candidate Route B (Boardman – Lafayette)

This approximately 1.80-mile route (shown as the dark purple line on Figure 4-4) exits the

Salem Harbor Substation and travels along Fort Avenue and Webb Street, passing by the

Bentley Elementary School and ball fields, a church, and a mix of residences and businesses.

The route then turns southwest into a residential neighborhood on Boardman Street, passing in

front of a funeral home as it turns south onto Washington Square East and follows along the

east side of Salem Common. It turns west along the south side of the Common following

Washington Square South, passing in front of an apartment building, a funeral home, and the

Hawthorne Hotel.


church, the Boys and Girls Club, and several multi-family residences and businesses. Turning

west onto Charter Street, the route passes behind the Peabody Essex Museum and in front of a

multi-story apartment building and several historic/tourist attractions (including the Charter

Street Cemetery and the Salem Witch Trial Memorial). At Lafayette Street, the route turns

south, crossing Derby Street and passing a fire station, a mixed-use development, a parking lot,

two funeral homes, the North Shore Medical Center, and many businesses before transitioning

to a more residential area with multi-family units approaching Gardner Street. The route turns

west onto Gardner Street and north onto Canal Street, passing through a residential

neighborhood, to connect to the Canal Street Substation.

4.4.3 Candidate Route C (Forrester – Congress)

This approximately 1.63-mile route (shown as the red line on Figure 4-4) exits the Salem


Elementary School and ball fields and through a mix of residences and businesses. The route

then turns southwest into a residential neighborhood on Essex Street, then briefly northward

onto Forrester Street near a variety store. It continues west down Forrester through a residential

neighborhood and west along the south side of the Common on Washington Square South,

passing in front of an apartment building, a funeral home, and the Hawthorne Hotel.




church, the Boys and Girls Club, and several multi-family residences and businesses. Continuing

south onto Congress Street, this route passes the Salem Waterfront Hotel and Marina, the Essex

County Registry of Deeds, and other businesses and office buildings and then transitions into a

mix of residential neighborhoods and commercial uses approaching Leavitt Street. Turning west






4.4.4 Candidate Route D (Forrester – Lafayette)

This approximately 1.76-mile route (shown as the dark pink line on Figure 4-4) exits the Salem


Elementary School and ball fields and through a mix of residences and businesses. The route

then turns southwest into a residential neighborhood on Essex Street, then briefly northward

onto Forrester Street near a variety store. It continues west down Forrester through a residential

neighborhood and west along the south side of the Common on Washington Square South,

passing in front of an apartment building, a funeral home, and the Hawthorne Hotel.











4.4.5 Candidate Route E (Andrew – Congress)

This approximately 1.72-mile route (shown as the dark blue line on Figure 4-4) exits the Salem


Elementary School and ball fields, a church, and a mix of residences and businesses. It then turns

southwest into a residential neighborhood along Andrew Street (a one-way street). The route then

runs along the north side of the Salem Common on Washington Square North, passing several

multi-family residences, a retirement home, an inn, and the Salem Witch Museum.



Continuing south along Washington Square West and Hawthorne Boulevard, the route passes by

several buildings owned by the Peabody Essex Museum, the Hawthorne Hotel, a church, the

Boys and Girls Club, and several multi-family residences and businesses. Continuing south onto

Congress Street, this route passes the Salem Waterfront Hotel and Marina, the Essex County

Registry of Deeds, and other businesses and office buildings and then transitions into a mix of

residential neighborhoods and commercial uses approaching Leavitt Street. Turning west onto

Leavitt Street, the route passes a yacht club and the Palmer Cove Park and Playground, as well as

a funeral home at the intersection with Lafayette Street. Crossing Lafayette Street and continuing

onto Fairfield Street, the route turns north onto Cabot Street, west on Cypress Street, and then

north across a vacant NEP-owned parcel to connect to the Canal Street Substation. Fairfield,

Cabot, and Cypress Streets are all primarily residential neighborhoods.

4.4.6 Candidate Route F (Andrew – Charter – Lafayette)

This approximately 1.86-mile route (shown as the dark green line on Figure 4-4) exits the Salem






Continuing south along Washington Square West and Hawthorne Boulevard, the route passes

by several buildings owned by the Peabody Essex Museum, the Hawthorne Hotel, a church, the

Boys and Girls Club, and several multi-family residences and businesses. Turning west onto

Charter Street, the route passes behind the Peabody Essex Museum and in front of a multi-story

apartment building and several historic/tourist attractions (including the Charter Street

Cemetery and the Salem Witch Trial Memorial). At Lafayette Street, the route turns south,

crossing Derby Street and passing a fire station, a mixed-use development, a parking lot, two

funeral homes, the North Shore Medical Center, and many businesses before transitioning to a

more residential area with multi-family units approaching Gardner Street. The route turns west

onto Gardner Street and north onto Canal Street, passing through a residential neighborhood, to


4.4.7 Candidate Route G (Briggs – Congress)

This approximately 1.75-mile route (shown as the light blue line on Figure 4-4) exits the Salem


Elementary School and ball fields, a church, and a mix of residences and businesses. It then

turns southwest into a residential neighborhood along Briggs Street (a one-way street). The

route then turns north along Washington Square East and passes a multi-family home and the

Knights of Columbus function hall, then turns west to follow Washington Square North passing

several multi-family residences, a retirement home, an inn, and the Salem Witch Museum.





Boys and Girls Club, and several multi-family residences and businesses. Continuing south onto

Congress Street, this route passes the Salem Waterfront Hotel and Marina, the Essex County

Registry of Deeds, and other businesses and office buildings and then transitions into a mix of

residential neighborhoods and commercial uses approaching Leavitt Street. Turning west onto

Leavitt Street, the route passes a yacht club and the Palmer Cove Park and Playground, as well as

a funeral home at the intersection with Lafayette Street. Crossing Lafayette Street and continuing

onto Fairfield Street, the route turns north onto Cabot Street, west on Cypress Street, and then

north across a vacant NEP-owned parcel to connect to the Canal Street Substation. Fairfield,

Cabot, and Cypress Streets are all primarily residential neighborhoods.

4.4.8 Candidate Route H (Briggs – Lafayette)

This approximately 1.89-mile route (shown as the yellow line on Figure 4-4) exits the Salem


Elementary School and ball fields, a church, and a mix of residences and businesses. It then

turns southwest into a residential neighborhood along Briggs Street (a one-way street). The

route then turns north along Washington Square East and passes a multi-family home and the

Knights of Columbus function hall, then turns west to follow Washington Square North passing

several multi-family residences, a retirement home, an inn, and the Salem Witch Museum.


by several buildings owned by the Peabody Essex Museum, the Hawthorne Hotel, a church, the

Boys and Girls Club, and several multi-family residences and businesses. Turning west onto

Charter Street, the route passes behind the Peabody Essex Museum and in front of a multi-story

apartment building and several historic/tourist attractions (including the Charter Street

Cemetery and the Salem Witch Trial Memorial). At Lafayette Street, the route turns south,

crossing Derby Street and passing a fire station, a mixed-use development, a parking lot, two

funeral homes, the North Shore Medical Center, and many businesses before transitioning to a

more residential area with multi-family units approaching Gardner Street. The route turns west

onto Gardner Street and north onto Canal Street, passing through a residential neighborhood, to


4.4.9 Candidate Route I (Andrew – Derby – Lafayette)

This approximately 1.83-mile route (shown as the light pink line on Figure 4-4) exits the Salem










Boys and Girls Club, a funeral home, and several multi-family residences and businesses.

Turning west onto Derby Street, the route passes a parking garage, the New England Pirate

Museum, a gas station, a fire house, and many small businesses and restaurants. At Lafayette

Street, the route turns south, passing two funeral homes, the North Shore Medical Center, and

several businesses and restaurants before transitioning to a more residential area with multi-family

units approaching Gardner Street. The route turns west onto Gardner Street and north onto Canal

Street, passing through a residential neighborhood, to connect to the Canal Street Substation.

4.5 ANALYSIS OF CANDIDATE ROUTES

This section discusses the objective evaluation NEP performed to compare the candidate routes

from an environmental, cost, and reliability perspective. This analysis was used to determine

the Preferred Route for the replacement of the Cables. Consistent with Siting Board standards,

NEP also identified a Noticed Alternative with an appropriate measure of geographic diversity.

While less advantageous than the Preferred Route, the Noticed Alternative would be feasible to

construct and serves as a largely distinct alternative to the Preferred Route.

4.5.1 Environmental/Constructability Criteria

NEP selected 12 project-appropriate criteria to evaluate constructability considerations and

relative levels of potential natural and human environmental impacts. In developing the

evaluation criteria for the Project, NEP solicited input from City officials and the public in several

different forums including several public open houses, regularly scheduled meetings of various

civic and neighborhood groups, and meetings with representatives from City government.

Because the Project Study Area lies within an urban environment, most of the criteria are

associated with the potential for disruption to the human environment. The seven selected

human environment criteria were: (1) residential land uses, (2) commercial or industrial land

uses, (3) sensitive land uses (including tourist attractions not listed by MHC as historic

resources), (4) recreational land uses, (5) historic resources, (6) potential for traffic congestion,

and (7) public/private transportation facilities.

Two natural environment criteria were included in this routing analysis: (1) potential to

encounter subsurface contamination during construction, and (2) the number of public shade

trees along each candidate route segment. There are no vegetated wetlands, rare species

habitats, drinking water supply districts, or Areas of Critical Environmental Concern along the

candidate routes. Portions of some of the candidate routes are located within local- and state-

jurisdictional resource areas such as 100-year floodplain (Bordering Land Subject to Flooding),

200-foot Riverfront Area, and 100-foot buffer zone of Inland Bank; however, these resources

were not considered important differentiators among the route segments because all proposed



activities are anticipated to be within previously disturbed areas (i.e., City streets) and proper

construction management will protect against the potential for erosion and sedimentation

impacts. Similarly, some candidate routes would cross over the South River, but would make

use of an existing utility bay within Congress Street and would not require any in-water work.

Lastly, three criteria were included that relate to ease of construction: (1) length of route,

(2) existing road width, and (3) existing utility density. Route length correlates to construction

duration; narrow roads may increase the probability of traffic impacts through lane reductions

or road closures; and increased utility density can slow the construction process and increase

construction duration.

All of the environmental and constructability criteria used for this evaluation are summarized in

Table 4-1 in Section 4.5.3. Land uses, historic resources, and potential sources of subsurface

contamination within the Project Study Area and along each complete candidate route are

shown in Figures 4-5, 4-6, and 4-7, respectively.

4.5.2 Scoring

NEP used a three-level ranking scale in which lower scores represented the lowest potential for

impact and higher scores represented the highest potential for adverse impact. Data for each

criterion were broken down into three categories which were then assigned a score of “1”, “2”,

or “3”.

Scores for each criterion were added together to get a Raw Score for each candidate route.

Sources of information used in these evaluations included existing map resources (MassGIS,

USGS topographic maps, and aerial photography), DEP’s MCP data, and field reconnaissance.

The following sections present specific details regarding the scoring criteria that were

developed to compare the various candidate routes.

4.5.2.1 Human Environment Criteria

Residential Land Use

Residents along a candidate route could be subject to temporary traffic disruption, street

closings, noise, and/or dust. This routing criterion was measured by the number of residential

(single- and multi-family) and mixed-use units along each route. This evaluation was

completed through review of available property assessment data and field reconnaissance of

each candidate route. Residential structures were identified as single- or multi-family homes by

counting mailboxes or gas/electric meters and confirming data against Salem’s GIS and

property assessment data to determine the number of units within each structure. The total

number of housing units along the candidate routes ranged from 400 to 662 units. Based on this

data, each route was given a score of one to three depending on the relative number of housing



units as described below. To provide context for the ranges chosen for each rank, the ranges for

the actual data have been provided in brackets.

1- Route passes 0–500 residences [400–438 residences]

2- Route passes 501–600 residences [547 residences]

3- Route passes 601 or more residences [624–662 residences]

Commercial/Industrial Land Use

Business and industry along a candidate route could be affected by temporary construction

impacts such as traffic disruption, street closings, noise, and/or dust. This criterion was

measured by the number of commercial and/or industrial buildings along each route. This

number was determined by conducting a GIS analysis with a subsequent field reconnaissance

to count the total number of commercial, industrial, or mixed-use buildings along each route.

The number of commercial or industrial buildings along the candidate routes ranged from 23 to

38. Based on this distribution, each route was given a score of one to three depending on the

relative number of commercial, industrial, or mixed-use units as described below. To provide

context for the ranges chosen for each rank, the ranges for the actual data have been provided in

brackets.

1- Route passes 0–27 commercial/retail facilities or industry [23–26 facilities]

2- Route passes 28–37 commercial/retail facilities or industry [30–33 facilities]

3- Route passes 38 or more commercial/retail facilities or industry [38 facilities]

Sensitive Land Use

These types of land uses could be affected by temporary construction impacts such as traffic

disruption, road closings, noise, and/or dust. This routing criterion included police and fire

stations, hospitals, schools, nursing homes, funeral homes, churches, daycares, notable tourist

attractions, and elder care facilities. Many of the City’s tourist attractions are also considered

historic resources; to avoid redundancies, only those attractions that are not listed on the federal

or state historic registers were included as sensitive land uses. Tourist attractions that are listed

on the federal or state historic registers were evaluated as part of the historic resource category.

Sensitive land use evaluations were completed through a combination of GIS analysis and field

reconnaissance of the candidate routes. The number of sensitive uses along each candidate

route ranged from 11 to 17. Based on this data, each route was given a score of one to three

depending on the relative number of sensitive land uses as described below. To provide context

for the ranges chosen for each rank, the ranges for the actual data have been provided in

brackets.

1- Route passes 0–13 sensitive land uses [11–13]

2- Route passes 14–15 sensitive land uses [14–15 uses]

3- Route passes 16 or more sensitive land uses [16–17 uses]



Recreational Land Use

These types of land uses along a candidate route could be affected by temporary construction

impacts such as traffic disruption, street closings, noise, and/or dust. Typical recreational uses

included ball fields, tennis courts, parks, and playgrounds. Many of these recreational land uses

were also considered historic resources; to avoid redundancies, only those that were not listed

on the federal or state historic registers were included as recreational land uses. Locations that

were listed on the federal or state historic registers were evaluated as part of the historic

resource category. Recreational land use evaluation along each route was completed through a

combination of GIS analysis and field reconnaissance. All candidate routes passed by two

recreational land uses, so every route was given a score of two:

1- Route passes fewer than two recreational land uses [no data in this category]

2- Route passes two recreational land uses [all routes]

3- Route passes more than two recreational land uses [no data in this category]

Historic Resources

Some of these resources could be affected by temporary construction impacts such as traffic

disruption, street closings, noise, and/or dust. This criterion included individually inventoried

buildings, inventoried areas, local historic districts, and National Register–listed individual

buildings and districts. As previously noted, historic resources that were tourist attractions or

recreational uses were included in this category. The number of historic resources along the

candidate routes ranged from 129 to 148. Based on this data, each route was given a score of one

to three depending on the relative number of historic resources as described below. To provide

context for the ranges chosen for each rank, the ranges for the actual data have been provided in

brackets.

1- Route passes 0–129 historic resources [129 resources]

2- Route passes 130–139 historic resources [135–139 resources]

3- Route passes 140 or more historic resources [143–148 resources]

Potential for Traffic Congestion

Existing traffic information was obtained from City departments or through public documents

for proposed or ongoing projects in the area that were available at the time of the development

of this Analysis. This information was reviewed to determine the traffic congestion potential for

each candidate route. Factors considered included traffic volumes (where available),8 presence

of major commuting routes, and presence of on-street parking (many commercial businesses

rely on available on-street parking for their patrons). In addition, field reconnaissance was

8 Traffic counts were not completed as part of this evaluation because sufficient current and relevant information was available from existing data sources and from public documents available at the time of this evaluation.



undertaken to confirm the potential for traffic congestion. Each route was given a score of one

to three depending on the relative potential for significant congestion and street closings and the

availability of alternate routes as follows:

1- Low potential for significant traffic congestion and street closings (low to moderate traffic

volume, wide road/shoulders, alternate travel routes available)

2- Moderate potential for significant traffic congestion (higher traffic volumes, land use

conflicts, and/or limited work space)

3- High potential for significant traffic congestion (higher traffic volumes, major commuting

route, lack of alternate routes, density of businesses relying on on-street parking, etc.)

Public/Private Transportation Facilities

Existing information was reviewed and a field reconnaissance was completed to determine the

potential for the construction to temporarily disrupt public bus and trolley routes, private coach

bus routes, or major transportation facilities. Each route was given a score of one to three

depending on the relative number of facilities and the anticipated level of disruption as follows:

1- Route does not pass any significant transportation facilities and does not travel along any

public/private transportation route

2- Route passes one or more significant public/private transportation facilities or travels along a

bus or trolley route, but should not cause significant access or interruption of service issues

3- Route passes one or more significant public/private transportation facilities or travels along

many bus or trolley routes; significant congestion, traffic or construction conflicts or

interruption of services likely

4.5.2.2 Natural Environment Criteria

Public Shade Trees

A shade tree inventory was conducted to identify the number of trees within publicly owned

areas along each candidate route. The shade tree inventory counted all trees within publicly

owned areas regardless of diameter at breast height. The number of trees along each candidate

route ranged from 85 to 126, with nearly half of the routes containing fewer than 100 trees and

the more than half of the routes containing significantly more than 100 trees. Based on this

data, each route was given a score of one to three depending on the relative number of trees as

described below. To provide context for the ranges chosen for each rank, the ranges for the

actual data have been provided in brackets.

1- Route passes fewer than 80 public shade trees [no data in this category]

2- Route passes 81–100 public shade trees [85–96 trees]

3- Route passes 101 or more public shade trees [111–126 trees]



Potential to Encounter Subsurface Contamination

Both an environmental database search and an online review of the DEP database of MCP sites

were performed to determine the potential for each candidate route to encounter subsurface

contamination from historical releases or former land development practices. The DEP online

database was used to collect information on all DEP sites with a release tracking number that

were within one quarter-mile of the proposed cable routes. An environmental database search was

also analyzed and refined to focus on the limits of potential disturbance associated with each route

segment. Sites were counted only if cleanup had not yet been completed. For all routes, the

number of MCP sites was either seven or ten. Based on this limited range, each route was given a

score of one to three according to the number of MCP sites:

1- Route passes fewer than 7 MCP sites [no data in this category]

2- Route passes 7 MCP sites

3- Route passes 10 MCP sites

4.5.2.3 Ease of Construction Criteria

Length of Route

The length of the route determines the overall construction duration; all else being equal, the

shorter the route, the shorter the duration of construction and disruption to stakeholders. The

lengths of the candidate routes ranged from 8,588 feet to 9,973 feet. Based on this data, each

route was given a score of one to three based on the relative length of the route as described

below. To provide context for the ranges chosen for each rank, the ranges for the actual data

have been provided in brackets.

1- Route is less than 9,000 feet long [8,588–8,757 feet]

2- Route is 9,001–9,500 feet long [9,100–9,485 feet]

3- Route is 9,501 or more feet long [9,685–9,973 feet]

Existing Road Width

The existing roadway width determines the available workspace above-grade to perform the

necessary construction activities (divert traffic, excavate, place ducts, encase ducts in concrete,

backfill, and replace paving) to build a below-grade duct bank. At a roadway width of less than

30 feet there would be a much greater probability that traffic flow would be affected either via

reduced lane widths or via full closure of one or both lanes. Because existing road widths varied

greatly along each of the candidate routes, this criterion evaluated the total percentage of the

route which was narrower than 30 feet. Percentages ranged from 11 percent to 29 percent, with

three routes that could be affected for significantly less than 20 percent of their length, while the

remaining routes could be affected for more than 20 percent of their length. Based on this

distribution, each route was given a score of one to three depending on the percentage of the

route that was narrower than 30 feet:



1- Less than 10 percent of route is narrower than 30 feet and may be affected by lane

reductions or closures [no data in this category]

2- Between 10 and 20 percent of route is narrower than 30 feet and may be affected by lane

reductions or closures [11–13 percent]

3- More than 20 percent of route is narrower than 30 feet and may be affected by lane

reductions or closures [23–29 percent]

Existing Utility Density

The number of existing longitudinal utilities in the roadway determines the available below-

grade space to physically place the duct bank and manhole systems. During the initial screening

process to develop candidate routes, streets with insufficient space for a new transmission line

were eliminated (see Section 4.3). All of the candidate routes evaluated in this section were

determined to be feasible for construction; however, increased utility density could hamper the

construction process and increase construction duration and attendant traffic disruption and

noise impacts. As part of this evaluation, subsurface utility maps from the City and other utility

owners were collected and some field verification was performed. Maps were then reviewed by

project engineers and a ranking of low, medium, or high density was assigned to each of the

street segments within the candidate routes. The street segment data was then used to rank

complete routes based on the percentage of each route that was of medium or high utility

density, which could contribute to construction complications. For nearly half of the routes, less

than 60% of the route was medium or high utility density, while more than half were medium

or high utility density for significantly more than 60% of the route. Based on this data, each

route was given a score of one to three depending on the percentage of the route that was

medium or high utility density:

1- Less than 50 percent of route is medium or high utility density potentially slowing

construction and increasing construction disruption [no data in this category]

2- Between 50 and 60 percent of route is medium or high utility density, potentially slowing

construction and increasing construction disruption [55–57 percent]

3- More than 60 percent of route is medium or high utility density, potentially slowing

construction and increasing construction disruption [67–69 percent]

4.5.3 Weighting

The assignment of weights to individual criteria can be useful in ensuring that scoring results

reflect the importance of the respective criteria in the scoring process. There are numerous

residential neighborhoods and economically important business districts, and many tourists

visit the City to view nationally significant points of interest located along some of the

candidate routes. Traffic impacts could be especially disruptive in these areas, and existing

utility density could play an important role in the duration of construction and the attendant

impacts to these areas. In order to properly reflect the importance of potential impacts to these



resources, a triple weight was assigned to residential land uses, commercial/industrial land uses,

and potential for traffic congestion. A double weight was assigned to sensitive land uses,

existing road width, and existing utility density. The remaining criteria were assigned a weight

of one. The criteria and their weights are summarized in Table 4-1.



Table 4-1: Route Evaluation Criteria and Scoring Scale Summary

HUMAN ENVIRONMENT CRITERIA

Criterion Weight Score Range

Residential Land Use 3 1 Route passes 0–500 residences [400–438 residences]

2 Route passes 501–600 residences [547 residences]

3 Route passes 601 or more residences[624–662 residences]

Commercial/Industrial

Land Use

3 1 Route passes 0–27 commercial/retail facilities or industry

[23-26 facilities]

2 Route passes 28–37 commercial/retail facilities or industry

[30-33 facilities]

3 Route passes 38 or more commercial/retail facilities or industry [38

facilities]

Sensitive Land Use 2 1 Route passes 0–13 sensitive land uses [11–13 uses]

2 Route passes 14–15 sensitive land uses [14–15 uses]

3 Route passes 16 or more sensitive land uses [16–17]

Recreational Land Use 1 1 Route passes fewer than two recreational land uses [no data in this

category]

2 Route passes two recreational land uses [all routes]

3 Route passes more than two recreational land uses [no data in this

category]

Historic Resources 1 1 Route passes 0–129 historic resources [129 resources]

2 Route passes 130–139 historic resources [135–139 resources]

3 Route passes 140 or more historic resources [143–148 resources]

Potential for Traffic

Congestion

3 1 Low potential for significant traffic congestion and street closings

(low to moderate traffic volume, wide road/shoulders, alternative

travel routes available)

2 Moderate potential for significant traffic congestion (higher traffic

volumes, land use conflicts, and/or limited work space)

3 High potential for significant traffic congestion (higher traffic

volumes, major commuting route, lack of alternate routes, density of

businesses relying on on-street parking, etc.)

Public/Private

Transportation

Facilities

1 1 Route does not pass any significant transportation facilities and does

not travel along any public/private transportation route

2 Route passes one or more significant public/private transportation

facilities or travels along a bus or trolley route, but should not cause

significant access or interruption of service issues

3 Route passes one or more significant public/private transportation

facilities or travels along many bus or trolley routes; significant

congestion, traffic/construction conflicts or interruption of service

issues likely



Table 4-1: Route Evaluation Criteria and Scoring Scale Summary (Cont’d.)

NATURAL ENVIRONMENT CRITERIA


Public Shade Trees 1 1 Route passes fewer than 80 public shade trees [no data in this

category]

2 Route passes 81–100 public shade trees [85–96 trees]

3 Route passes 101 or more public shade trees [111–126 trees]

Potential to Encounter

Subsurface

Contamination

1 1 Route passes fewer than 7 MCP sites [no data in this category]

2 Route passes 7 MCP sites [5 routes]

3 Route passes 10 MCP sites [4 routes]

EASE OF CONSTRUCTION CRITERIA


Length of Route 1 1 Route is less than 9,000 feet long [8,588–8,757 feet]

2 Route is 9,001–9,500 feet long [9,100–9,485 feet]

3 Route is 9,501 or more feet long [9,685–9,973 feet]

Existing Road Width 2 1 Less than 10 percent of route is narrower than 30 feet and may be

affected by lane reductions or closures [no data in this category]

2 Less than 20 percent of route is narrower than 30 feet and may be

affected by lane reductions or closures [11–13 percent]

3 More than 20 percent of route is narrower than 30 feet and may be

affected by lane reductions or closures [23–29 percent]

Existing Utility

Density

2 1 Less than 50 percent of route is medium or high utility density,

potentially slowing construction and increasing construction

disruption [no data in this category]

2 Between 50 and 60 percent of route is medium or high utility

density, potentially slowing construction and increasing construction

disruption [55–57 percent]

3 More than 60 percent of route is medium or high utility density,

potentially slowing construction and increasing construction

disruption [67–69 percent]

Following initial scoring, Raw Scores were multiplied by weight to provide Weighted Scores;

the results are presented in Table 4-2. A summary of Raw Scores and Weighted Scores for each

candidate route is shown in Table 4-3.



Table 4-2: Candidate Route Evaluation Matrix

Candidate Route

Human Environment Criteria Natural Environment Criteria Ease of Construction Criteria

Residential Land Uses

Commercial/

Industrial Uses

Sensitive

Land

Uses

Recreational

Land

Uses

Historic

Resources

Traffic

Score

Public

Transport

Score

Public

Shade

Trees

Potential for

Subsurface

Contamination

(# of Active

MCP Sites)

Length Road Width Utility Density

Total

Housing

Units

Single-

Family

Units

Multi-

Family

Units

Total

Buildings Feet Miles

% of Route

Narrower than

30 Feet

% of Route with

Medium or High

Utility Density

Total

Environmental

Score

Route A

Boardman - Congress 413 39 103 24 12 2 138 1 1 115 7 8757 1.66 29% 57%

Raw Score 1 1 1 2 2 1 1 3 2 1 3 2 20 Raw Score

Weight 3 3 2 1 1 3 1 1 1 1 2 2

Weighted Score 3 3 2 2 2 3 1 3 2 1 6 4 32 Weighted Score

Route B

Boardman - Lafayette 637 31 112 31 14 2 129 2 1 85 10 9485 1.80 25% 69%


Weight 3 3 2 1 1 3 1 1 1 1 2 2


Route C

Forrester - Congress 424 41 105 26 11 2 138 1 1 123 7 8588 1.63 13% 55%


Weight 3 3 2 1 1 3 1 1 1 1 2 2


Route D

Forrester - Lafayette 648 33 114 33 13 2 129 2 1 93 10 9316 1.76 10% 68%


Weight 3 3 2 1 1 3 1 1 1 1 2 2


Route E

Andrew - Congress 438 40 106 26 13 2 144 2 2 126 7 9100 1.72 27% 57%


Weight 3 3 2 1 1 3 1 1 1 1 2 2


Route F

Andrew - Charter - Lafayette 662 32 115 33 15 2 135 3 2 96 10 9828 1.86 23% 69%


Weight 3 3 2 1 1 3 1 1 1 1 2 2


Route G

Briggs - Congress 400 40 100 23 15 2 148 2 2 119 7 9245 1.75 29% 57%


Weight 3 3 2 1 1 3 1 1 1 1 2 2


Route H

Briggs - Lafayette 624 32 109 30 17 2 139 3 2 89 10 9973 1.89 25% 69%


Weight 3 3 2 1 1 3 1 1 1 1 2 2


Route I

Andrew - Derby - Lafayette 547 31 112 38 16 2 143 3 3 111 7 9685 1.83 13% 67%


Weight 3 3 2 1 1 3 1 1 1 1 2 2




Table 4-3: Raw Environmental Scores and

Weighted Environmental Scores by Candidate Route

Candidate Route Description Raw Score Weighted Score

Candidate Route C Forrester – Congress 19 30

Candidate Route A Boardman – Congress 20 32

Candidate Route E Andrew – Congress 24 38

Candidate Route G Briggs – Congress 25 40

Candidate Route D Forrester – Lafayette 24 44

Candidate Route B Boardman – Lafayette 26 48

Candidate Route F Andrew – Charter – Lafayette 30 54

Candidate Route H Briggs – Lafayette 31 56

Candidate Route I Andrew – Derby – Lafayette 32 56

The Weighted Scores shown above were used to identify the Preferred Route and Noticed

Alternative as discussed in Section 4.5.6.

4.5.4 Candidate Route Cost Comparisons

Circuit installation cost estimates were based on pricing obtained from manufacturers and on

the actual cost of recent underground projects completed by NEP. Many factors could affect the

overall cost of an underground project, including cost of materials,9 contractor or manufacturer

availability, and work restrictions imposed by the local community. Subsurface conditions such

as the type and depth of soil and rock that must be excavated to place the cable could also

dramatically affect project cost. Construction costs in rock formations are significantly higher

than construction costs in clay. The presence of existing underground infrastructure could also

present a substantial uncertainty when estimating the cost of an underground project. These

factors were used to develop a cost per mile for routes in the general conditions found in the

project area. This cost per mile estimate was then applied to each individual route to get the

total circuit cost estimate for each candidate route, listed in Table 4-4 below.

9 For example, the cost of copper has fluctuated significantly over the planning stages of this Project.



Table 4-4: Candidate Route Cost Estimates

Candidate Route Description

Approximate

Length

(miles)

Estimated Circuit

Installation Costs

(millions)

Candidate Route C Forrester – Congress 1.63 $33.40

Candidate Route A Boardman – Congress 1.66 $34.03

Candidate Route E Andrew – Congress 1.72 $35.30

Candidate Route G Briggs – Congress 1.75 $35.93

Candidate Route D Forrester – Lafayette 1.76 $36.15

Candidate Route B Boardman – Lafayette 1.80 $36.99

Candidate Route I Andrew – Derby – Lafayette 1.83 $37.62

Candidate Route F Andrew – Charter – Lafayette 1.86 $38.32

Candidate Route H Briggs – Lafayette 1.89 $38.89

4.5.5 Reliability Comparisons

NEP considered whether there was a difference in the candidate routes with regard to reliability

and determined that there was no meaningful difference between the operating characteristics

for the routes under consideration. That is, each of the proposed routes would result in a cable

installation that would meet the identified need in a reliable manner. Accordingly, reliability

was not a determining factor in terms of route selection.

4.5.6 Ranking and Identification of Preferred Route, Preferred Route

Variation, and Noticed Alternative

NEP reviewed the Candidate Routes to select a Preferred Route and a Noticed Alternative for

the new cable system. The following sections provide detail regarding the identification of

these routes.

4.5.6.1 Identification of Preferred Route

A review of the environmental scores, cost estimates, and overall rankings of the candidate

routes, as summarized in Table 4-5, showed that Candidate Route C (Forrester – Congress) was

ranked as the best route for the Preferred Route as it had both the lowest cost and the best

environmental impact score.



Table 4-5: Ranking Summary of Candidate Routes

Candidate Route Description

Weighted

Environmental

Score

Environmental

Score

Ranking

Circuit Cost

Estimate1

(millions)

Cost

Ranking

Candidate Route C Forrester – Congress 30 1 $33.40 1

Candidate Route A Boardman – Congress 32 2 $34.03 2

Candidate Route E Andrew – Congress 38 3 $35.30 3

Candidate Route G Briggs – Congress 40 4 $35.93 4

Candidate Route D Forrester – Lafayette 44 5 $36.15 5

Candidate Route B Boardman – Lafayette 48 6 $36.99 6

Candidate Route F Andrew – Charter –

Lafayette

54 7 $38.32 8

Candidate Route H Briggs – Lafayette 56 8 $38.89 9

Candidate Route I Andrew – Derby –

Lafayette

56 8 $37.62 7

1 “Circuit cost” represents those costs associated with the construction of the cable only. See Section 4.5.4.

4.5.6.2 Identification of Noticed Alternative

In identifying a Noticed Alternative, NEP examined the remaining candidates for a route that

varied geographically from the Preferred Route by, to the extent possible, avoiding construction

along the same streets. This removed Candidate Routes A, B, D, E, and G from consideration,

since they make use of Forrester, Boardman, and Congress Streets (all routes make use of

Hawthorne Boulevard between Washington Square South and Charter Streets). Of the remaining

Candidate Routes (F, H, and I), Candidate Route H was dismissed as the route with the worst

environmental score and the worst cost ranking. Candidate Route I was the least expensive of the

three but had the worst environmental score. An additional consideration with Route I is that

resources along Derby Street between Lafayette Street and Congress Street would be impacted by

the removal of the existing Cables as well as the construction of the new cables. This is not

reflected in the environmental score but in fact makes Candidate Route I have a greater potential

for environmental impact relative to the other routes. Thus, Candidate Route F was judged to be

the superior of the three geographically distinct routes and was selected as the Noticed

Alternative.

4.6 CONCLUSION

NEP’s route selection process addressed the Siting Board’s standards in an objective and

comprehensive fashion. A wide array of candidate routes was identified to satisfy the Project

Need, and the process was designed so that no clearly superior route was overlooked. NEP



systematically compared the candidate routes based upon reasonable criteria to evaluate their

environmental impacts and costs. The Preferred Route reflects the best-scoring route based on

the established criteria and enables NEP to meet the identified need in accordance with Siting

Board precedent. NEP also selected a Noticed Alternative with an appropriate measure of

geographic diversity for further consideration in a more detailed comparison to the Preferred

Route in Section 5 of this Analysis. The Preferred Route and the Noticed Alternative are shown

in Figure 4-8.

Section 5.0: Comparison of Proposed Activities along Preferred Route and Noticed Alternative


5.0 COMPARISON OF PROPOSED ACTIVITIES ALONG

PREFERRED ROUTE AND NOTICED ALTERNATIVE

5.1 INTRODUCTION

This Section provides a detailed analysis and comparison of the potential temporary and

permanent environmental impacts, costs, and reliability considerations relating to the Preferred

Route and the Noticed Alternative selected for the Project.

Section 5.2 provides a description of the Preferred Route and Noticed Alternative.

Section 5.3 introduces a set of detailed aerial photographs identifying the locations of important

features along the Preferred Route and Noticed Alternative and at the substations. Section 5.3

also presents a series of street-level photographs designed to illustrate the routes along which

the proposed replacement cables will be installed and to show the existing substation locations.

Section 5.4 describes the construction methods for installing two underground transmission

cables in a single duct bank and manhole system and provides the anticipated schedule for this

Project.

Section 5.5 describes and compares the human and natural environmental impacts resulting

from the Project if constructed along the Preferred Route or the Noticed Alternative, and

proposes appropriate mitigation. To compare potential environmental impacts associated with

the Preferred Route and Noticed Alternative, a series of human and natural environmental

criteria were evaluated, including existing land uses (residential, commercial and/or industrial,

sensitive, and recreational), tourist attractions, public shade trees, traffic, noise, potential to

encounter subsurface contamination, dust control/air quality, historic and archaeological

resources, electric and magnetic fields (“EMF”), visual impacts, and wetlands and waterways.

Potential impacts associated with each of these criteria include construction-related (temporary)

impacts and operation-related (permanent) impacts. Examples of potential temporary

construction-related impacts include traffic impacts and short-term construction noise

associated with the operation of heavy equipment. An example of a permanent impact would

include visual impacts associated with the installation of new equipment at each

substation.

The mitigation measures presented herein serve to provide an overview of the typical

mitigation implemented by NEP on similar projects. NEP will develop more comprehensive

site-specific mitigation plans during the detailed engineering phase of the Project based on

continued coordination with the City and its residents and business owners, Footprint, and

Spectra (who is building a gas pipeline into the Footprint generating facility). For instance,

based on a meeting between NEP and the Salem Health Agent and Senior Sanitarian on April



10, 2013, NEP will be expected by the Salem Board of Health (“BOH”) to develop more

detailed mitigation plans for review and comment by the BOH prior to the start of construction.

Section 5.6 presents a discussion of the reliability of each route.

Section 5.7 presents a comparison of the costs of the proposed facilities if constructed along the

Preferred Route or the Noticed Alternative.\

Section 5.8 presents a summary of the analysis for the comparison of the Preferred Route and

Noticed Alternative.

Section 5.9 presents an analysis of the potential temporary and permanent environmental

impacts associated with the necessary modifications to the Canal Street and Salem Harbor

substations. The proposed substation modifications are common to all of the routes considered.

Section 5.10 describes the work involved in removing the existing Cables and any associated

impacts and mitigation measures.

Section 5.11 synthesizes the total project costs for building the Project along the Preferred

Route, including cable installation, substation improvements, and removal of both existing

Cables.

Finally, Section 5.12 summarizes the advantages of the Preferred Route relative to the Noticed

Alternative and concludes that the Preferred Route is superior to the Noticed Alternative based

upon a full consideration of reliability, cost, and human and natural environmental impact factors.

5.2 DESCRIPTION OF PREFERRED ROUTE AND NOTICED ALTERNATIVE

5.2.1 Preferred Route

The Preferred Route selected for the proposed cables is approximately 1.63 miles long and

traverses City streets to connect the Salem Harbor Substation to the Canal Street Substation.

The Preferred Route exits the Salem Harbor Substation and proceeds in a westerly direction

along Fort Avenue and Webb Street, traveling past the Bentley Elementary School with its

associated ball fields and through a mix of residences and small businesses. From Webb Street,

the Preferred Route turns southwest into a residential neighborhood on Essex Street. It briefly

turns northward onto Forrester Street near an existing variety store, then continues west down

Forrester Street through a residential neighborhood and along the south side of the Common on

Washington Square South, passing in front an apartment building, a funeral home, and the

northern side of the Hawthorne Hotel.



The route then turns south onto Washington Square West and Hawthorne Boulevard, passing

the western side of the Hawthorne Hotel (at the corner of Washington Square South and

Hawthorne Boulevard), a church, the Boys and Girls Club, and several multi-family residences

and businesses. Continuing south onto Congress Street, this route passes the Salem Waterfront

Hotel, the Essex County Registry of Deeds, and other businesses and office buildings and then

transitions into a primarily residential neighborhood approaching Leavitt Street. Turning west






5.2.2 Noticed Alternative

Like the Preferred Route, the Noticed Alternative traverses City streets to connect the Salem

Harbor Substation to the Canal Street Substation. Although the Noticed Alternative is less

advantageous than the Preferred Route (as discussed in Section 4 and as further detailed

below), the Noticed Alternative is constructible and provides a distinct alternative to most

segments of the Preferred Route.

The Noticed Alternative is approximately 1.86 miles long. It exits the Salem Harbor Substation

and proceeds in a westerly direction along Fort Avenue and Webb Street past the Bentley

Elementary School with its associated ball fields, past a church, and through a mix of

residences and businesses. It then turns southwest into a residential neighborhood along

Andrew Street (a one-way street). The route then runs along the north side of Salem Common

on Washington Square North, passing several multi-family residences, a retirement home, an

inn, and the Salem Witch Museum.


several buildings owned by the Peabody Essex Museum as well as the Hawthorne Hotel, a












5.3 ROUTE MAPS AND PHOTOGRAPHS

5.3.1 Route Maps

To help familiarize the reviewer with the routes being analyzed in this Section of the Analysis,

a series of maps have been prepared for the Preferred Route and the Noticed Alternative

(Figures 5-1 and 5-2, respectively). Photographs along each of the routes are provided in Figure

5-3 and 5-4. In addition, figures for each route were created to depict land use, cultural and

historic points of interest, and environmental/historic resources. These are included as Figures

5-5 through 5-9 in Sections 5.5.1 and 5.5.8, respectively. All figures use 2008 aerial

photography available from ArcGIS Online, with overlays from MassGIS to represent the

routes and to note the locations of community features such as schools, hospitals and medical

facilities, fire stations, police stations, funeral homes, recreation sites, wetland resources and

adjacent water bodies, and other points of interest.

5.3.2 Route Photographs

As a further reference for reviewers, a series of street-level route photographs were prepared.

These photographs, along with photograph location key maps, are provided as Figures 5-3 and

5-4. These street-level photographs were taken in April 2013. The photograph series begins at

the Salem Harbor Substation and ends at the Canal Street Substation.

5.4 CONSTRUCTION METHODS AND SCHEDULE

The replacement cable system will be constructed using conventional underground electric

transmission line construction techniques in a progression of activities. This section describes

these activities and addresses construction-related topics such as schedule, work hours,

environmental compliance and monitoring, and safety and public health considerations. While

this section does not compare the routes, it provides baseline information that is needed to

determine human and natural environmental resource impacts.

5.4.1 Underground Transmission Construction Methods

Each of the two proposed cables will consist of three solid dielectric insulated cables installed

in individual PVC conduits. The nominal trench excavation for the duct bank will be four feet

wide and five to eight feet deep depending on site conditions. The duct bank will contain a total

of 10 PVC conduits: six 6-inch-diameter PVC conduits for the insulated cables; one 4-inch-

diameter PVC conduit for a relay and communication circuit; and three 2-inch-diameter PVC

conduits (two for grounding conductors and one for possible future temperature-monitoring

cables). The PVC conduits will be encased in a common concrete envelope. To reduce

magnetic fields, the duct bank will also contain a passive loop (a de-energized loop of

conducting wire) at the manhole approaches.



Generally, there are four principal phases of construction for an underground cable project:

(1) manhole installation; (2) trench excavation, duct bank installation, and pavement patching;

(3) cable pulling, splicing, and testing; and (4) final pavement restoration. Each of these phases

is described in more detail below. The phases will be conducted in sequence at each location;

NEP anticipates that several phases of construction will be ongoing simultaneously in different

sections of the route. Pavement will be temporarily patched after in-street construction is

completed in each location, and will subsequently be repaired or replaced as required by the

Salem DPW to restore the street surface. NEP will coordinate with City officials and with

Footprint and Spectra on location-specific construction schedules.

5.4.1.1 Manhole Installation

Two adjacent precast concrete manholes (one manhole for each circuit) will be placed

approximately every 1,500 to 2,000 feet along the route. The length of cable that can be pulled

through the conduits dictates the distance between manholes. Other factors contributing to the

final placement of the manholes include allowable pulling tensions, sidewall pressure on the

cable as it goes around a bend, and the maximum length of cable that can be transported on a

reel based on the reel’s width, height, and weight. Manholes are typically installed in a

sequential schedule; each set of two manholes will take approximately 10 to 12 days to install.

Manholes facilitate cable installation and splicing and allow access for maintenance and future

repairs. The manhole dimension is determined by the space required for cable pulling, splicing,

and supporting the cable in the manhole. For this Project, each manhole will be approximately

8 feet wide by 24 feet long and 8 feet high. The manhole depth will vary by location with the

manhole base being typically approximately 10 to 12 feet below grade. The manholes will be

located entirely underground; the only visible aspects at ground level will be the manhole

covers.

NEP will implement appropriate Best Management Practices (“BMPs”) for the control of

erosion and sedimentation from the work site during excavation activities associated with the

manhole installation. Regular inspections will be undertaken to ensure control mechanisms are

maintained. In any area where stormwater is directed to a local storm drain, NEP will install

and maintain sedimentation devices such as filter fabric barriers to prevent sediment from

entering the storm drain system. When construction is complete at each location, the filter

fabric will be removed from the storm drain. All excavated soil will be loaded directly into

trucks and transported to an off-site stockpile area. This will limit the potential for soils to

migrate off-site and into the municipal storm drain system. As needed, suitable soils will be

used to backfill the excavation. Any excess soil will be tested and disposed of properly.

The Project will obtain coverage under the NPDES CGP and will maintain a Stormwater

Pollution Prevention Plan (“SWPPP”) on site.



A photograph of a typical manhole installation is provided below.

Manhole Installation, Nantucket, MA

5.4.1.2 Trench Excavation and Duct Bank Installation

The underground duct banks for the Project will be installed using open-cut trenching. For each

segment of the route, the width of the trench will be marked on the street, Dig-Safe will be

contacted, the location of existing utilities will be marked, and the pavement will be saw cut.

Saw cutting provides a clean break in the pavement and defines the trench for the next activity.

Saw cutting is a relatively fast operation and is not performed every day; it is paced to avoid

proceeding too far ahead of the crew that follows.

Following saw cutting, the existing pavement will be broken up with pneumatic hammers and

loaded by backhoe into awaiting dump trucks. Pavement will be handled separately from the

soil because the pavement will be recycled at an asphalt batching plant.



The trench will then be excavated to the required depth by backhoe. In some areas, part of the

excavation will be done by hand to avoid disturbing existing utility lines and/or service

connections. A “clean trench” method will be used in which soil is loaded directly into a dump

truck for off-site recycling, disposal, or reuse. Soil will not be stockpiled along the side of the

trench. This method will reduce the size of the required work area and reduce the potential for soil

migration and nuisance dust. Any rock encountered during excavation will be removed by

mechanical means. As it is needed, suitable soils will be reused in the trench as backfill. Excess

soil will be tested and disposed of.

The trench will be sheeted and shored as required by soil conditions and Occupational Safety and

Health Administration (“OSHA”) safety rules. The shoring is designed to permit the passage of

traffic adjacent to the trench and to allow the trench to be covered with a steel plate to permit

traffic over the trench during non-working hours. Under the typical conditions known for this

area, it is anticipated excavation and shoring will proceed at roughly 65 feet to 90 feet per day.

More intensive efforts are likely to be necessary at street intersections because these locations

tend to have the greatest concentration of underground utilities. Usually, a crew excavates the

street intersection in advance of the normal work zone so that obstructions can be precisely

identified and the conduit locations can be determined before the main work crew reaches the

intersection.

Once a portion of the trench is excavated, each PVC conduit will be assembled and lowered into

the trench. The area around the conduits will be protected with high strength thermal concrete

(3,000 psi), the trench backfilled, and the surface restored. Backfill materials may consist of clean

excavated material, thermal sand, and/or a thermal concrete mix. The following diagram

illustrates a typical duct bank cross section.



Typical Duct Bank Cross Section

It is anticipated that a typical business or residence will see activities related to trench

excavation, duct bank installation, and pavement patching in the front of their house/business or

general vicinity for two to three weeks. (As noted above, installation of manholes will have

taken an additional approximately 10 to 12 days in locations where manholes are proposed.)

The pace of construction may be slower in areas of higher existing utility density, where

unanticipated obstructions are encountered, where the trench depth is increased, or in areas of

higher traffic volumes. Depending upon the number of these conditions that are encountered,

duct bank construction durations can increase up to approximately five weeks. Overall, in-street

work involving the installation of manholes, installation of the duct bank and temporary

pavement restoration is expected to take approximately twelve months (see Section 5.4.2).

During excavation activities associated with the duct bank installation, NEP will implement

appropriate BMPs for the control of erosion and sedimentation at the work site. Regular

inspections will be undertaken to ensure that control mechanisms are maintained. In any area

where dewatering is required or stormwater is directed to a local storm drain, NEP will install and

maintain sedimentation devices such as filter fabric barriers to prevent sediment from entering the

storm drain system. When construction is complete at each location, the filter fabric will be

removed from the storm drain. In the event that the ground water is impacted by contaminated

soils, it will be disposed of as necessary to prevent introduction into the storm drain system. All



excavated soil will be loaded directly into trucks and transported to an off-site stockpile area. This

will limit the potential for soils to migrate off-site and into the municipal storm drain system. As

needed, suitable soil will be used to backfill the excavation. Any excess soil will be tested and

disposed of properly. The Project will obtain coverage under the NPDES Construction General

Permit and will maintain a SWPPP onsite.

During the trenching and duct bank construction, NEP will make every reasonable effort to

maintain access to adjacent residences and businesses. At various points in the trenching and duct

bank construction process, it will be necessary to have an open trench that may temporarily

impede access, but once the crews are finished the trench will be steel-plated to re-establish

access to nearby homes and commercial buildings. At the end of each work day, any remaining

open trenches will be covered with securely anchored steel plates of sufficient thickness to

withstand traffic loading.

5.4.1.3 Cable Installation and Testing

Following the installation of the manholes and duct bank, the cable will be pulled through the

conduit. Prior to the installation of the cable, the conduit will be tested and cleaned by pulling

through a swab and mandrel (a close-fitting cylinder designed to prove a conduit’s shape and

size). When the mandrel has been pulled successfully, the conduit is ready for installation of the

cable.

First, sections of each cable will be installed between two consecutive manholes. To install the

cable sections, the cable reel will be set up at the “pull-in” manhole and the cable puller will be

set up at the “pulling-out” manhole. Installation of cable sections between two manholes will

typically take three eight-hour days. This process will be repeated until all of the cable sections

are installed.

Once adjacent cable sections are installed, they will be spliced together in the manholes. Splicing

high-voltage solid dielectric transmission cable is a time-consuming, complex operation. It

typically requires 40–60 hours to complete the splicing of all three cables at each manhole. The

splicing activities will not be continuous, but will take place over four or five extended work days

at each manhole location. The splicing operation requires a splicing van and a generator. The

splicing van contains all of the equipment and material to make a complete splice. At times, an air

conditioning unit will be used to control the moisture content in the manhole. A portable

generator will provide the electrical power for the splicing van and air conditioning unit. The

generator will be muffled to minimize noise and has been used successfully in other locations

with sensitive receptors.

Typically, the splicing van will be located at one manhole access cover. The air conditioner will

be located near the second manhole access cover and the generator will be located in a

convenient area that does not restrict traffic movement around the work zone.



Once the complete cable system is installed, it will be field-tested from the substations. At the

completion of successful testing, the line will be energized.

5.4.1.4 Final Pavement Restoration

NEP will work closely with the Salem DPW and the MassDOT to determine the restoration

requirements for all disturbed roadways and sidewalks. All pavement restoration will conform

to the standards and policies of the Salem DPW, MassDOT, and the DPU’s Street Restoration

Standards from D.T.E. 98-22.

Final repaving will include a mill and overlay with bituminous asphalts to the limits agreed

upon with the Salem DPW and MassDOT. A leveling course will be provided at driveways as

needed to meet the new road surface elevation.

Sidewalk restorations with pavers or concrete, depending on existing materials, will comply

with all requirements of the Salem DPW, MassDOT, and D.T.E. 98-22.

5.4.1.5 Congress Street Bridge

The Preferred Route traverses the Congress Street Bridge across the South River in an available

utility bay beneath the southbound side of the bridge. No specialized procedures will be

required to install the conduits and cables within this utility bay. No in-water work will be

required and no impacts to the South River are anticipated.

5.4.2 Construction Schedule

Project activities required to install and energize two new cable systems (including all

necessary substation work) are anticipated to be completed over an approximately 18-month

period. An additional four months of construction will be required to remove the existing cables

and restore the streets to existing conditions in coordination with the City. The following table

presents the preliminary construction schedule for the Project, which is based on an anticipated

date of September 1, 2014 for receipt of all required permits.



Table 5-1: Preliminary Construction Schedule

Construction of New Cable System

November 2014 – September 2015 Duct bank and manhole installation and temporary pavement restoration

November 2014 – March 2016 Construction at Canal Street and Salem Harbor Substations for new cable

termination structures and equipment

November 2015 – February 2016 Cable installation, pulling, splicing, and testing

March 2016 – April 2016 Cutover and energize new Cables

Removal of the Old Cables and Final Restoration

March 2016 – May 2016 Final restoration on the new cable route

To be determined in consultation with

the City of Salem

Removal of the existing Cables and final restoration along

Canal Street and Derby Street

It should be noted that some adjustments to the proposed schedule will be required to

coordinate with other proposed projects by the City, MassDOT, Footprint, and Spectra. Some

Project construction activities may be advanced or delayed to align with construction of these

other projects.

5.4.2.1 Construction Hours and Schedule Considerations

Based on preliminary coordination with the City, typical construction hours for street

excavation are limited to the hours between 7:30 a.m. and 4:30 p.m., while other types of

construction are limited by the Salem noise ordinance to the hours between 8:00 a.m. and

5:00 p.m., with some flexibility as necessary to meet construction requirements. Certain

construction activities will require extended work days, most notably cable splicing, which will

require a 10- to 12-hour work day. NEP will work with the City and community to limit the

impacts of any extended work schedules. The City does not typically endorse night work but

will consider it for this Project if it can be determined that it is appropriate and will not cause

hardships for certain businesses and residents.10 The Company would consider the use of

extended hours if requested by the City to accelerate the pace of work in specific areas. No

work will occur on weekends or holidays. The City imposes a street opening moratorium from

December through April, but has indicated there may be some flexibility with these dates. The

City has requested that NEP avoid work in certain areas along the Project from October 1 to

November 1 to avoid impacts to the Halloween tourist season. Construction activities will also

10 Meeting Notes prepared by VHB from a meeting between NEP and City of Salem’s Engineer Office, April 10, 2013, Salem

Engineer’s Office, Salem, Massachusetts.



be coordinated with Footprint, Spectra, and other active construction projects along the

installation routes to minimize impacts to the City.

5.4.3 Environmental Mitigation, Compliance, and Monitoring

Construction mitigation measures reduce the potential for temporary impacts to the human and

natural environment identified along the routes. These measures address traffic management,

construction noise control, stormwater runoff and sediment migration control, dust control/air

quality, public shade tree preservation, removal of any subsurface contamination encountered

during earthwork, solid waste disposal, and preservation of historical and archaeological sites.

Throughout the construction process, NEP will retain the services of an environmental monitor

to enforce compliance with all federal, state, and local permit requirements and NEP company

policies. At regular intervals and during periods of prolonged precipitation, the monitor will

inspect all locations to determine that environmental controls are functioning properly and to

make recommendations for correction or maintenance as necessary. In addition to retaining the

services of an environmental monitor, NEP will require the construction contractor to designate

the Construction Supervisor or equivalent to be responsible for daily inspection and compliance

with permit requirements and NEP policies. This person will also be responsible for providing

direction to the other members of the construction crew regarding work methods as they relate

to permit compliance. Additionally, all construction personnel will be trained on Project

environmental issues and obligations prior to the start of construction. NEP will conduct regular

construction progress meetings to reinforce the contractor’s awareness of these issues.

5.4.4 Safety and Public Health Considerations

National Grid will design, build, and maintain the facilities for the Project so that the health and

safety of the public are protected. This will be accomplished through adherence to all federal,

state, and local regulations, as well as industry standards and guidelines established for

protection of the public. More specifically, the proposed Project will be designed, built, and

maintained in accordance with the Massachusetts Code for the Installation and Maintenance of

Electric Transmission Lines (220 CMR 125.00) and the National Electrical Safety Code. The

facilities will be designed in accordance with sound engineering practices using established

design codes and guides published by, among others, the DPU, the Institute of Electrical and

Electronic Engineers, the American Society of Civil Engineers, the American Concrete

Institute, and the American National Standards Institute.



5.5 ENVIRONMENTAL IMPACT COMPARISON OF PREFERRED ROUTE

AND NOTICED ALTERNATIVE

This section describes the existing land uses and human and environmental resources along the

Preferred Route and Noticed Alternative, presents a comparative analysis of potential impacts

to specific resources as a result of installation of the replacement cables along the routes, and

describes the measures that NEP has identified to mitigate such impacts.

The following sections present the criteria NEP considered in assessing the potential for

impacts to natural and social environments. These included existing land uses (residential,

commercial and/or industrial, sensitive, and recreational), public shade trees, traffic, noise,

potential to encounter subsurface contamination, dust/air quality, wetlands and waterways,

historic and archaeological resources, EMF, and visual impacts.11

5.5.1 Land Use This section describes land uses along the Preferred Route and the Noticed Alternative. 5.5.1.1 Preferred Route Along Fort Avenue and Webb Street, the Preferred Route passes through the Salem Harbor

generating facility property and through a mix of residences and businesses, as well as past

David J. Beattie Park, ball fields at Memorial Park, and the Bentley School. On Essex Street

and Forrester Street, it travels through residential neighborhoods. Along Washington Square

South, land uses are a mix of residential and commercial uses. Prominent features include the

open space at the Salem Common, the Hawthorne Hotel, an apartment complex, and a funeral

home. This route then turns south along Washington Square West and Hawthorne Boulevard,

where adjacent land uses are best characterized as a mix of residential and commercial uses.

This route continues south through the intersection with Derby Street and along Congress Street

where adjacent land uses are primarily commercial and industrial on the east side of Congress

Street and a mix of residential and commercial on the west side of Congress Street. This route

then turns west onto Leavitt Street in front of the Palmer Cove Park and Playground and passes

primarily through residential neighborhoods for the remainder of its route to Canal Street.

5.5.1.2 Noticed Alternative Along Fort Avenue and Webb Street, the Noticed Alternative passes through the Salem Harbor

generating facility property and through a mix of residences and businesses, as well as past

David J. Beattie Park, ball fields at Memorial Park, and the Bentley School. This route then

11 NEP determined that there are no surface water supply protection areas, wellhead protection areas, vernal pools, or protected species or habitats along or near the Preferred Route or the Noticed Alternative. Environmental resources are depicted along with historical resources on Figures 5-8 and 5-9.



turns onto Andrew Street, where it travels through a residential neighborhood to Washington

Square North. As this route follows Washington Square North to the west, land uses are

primarily residential on the north side of the street with Salem Common on the south side.

Along Washington Square West and Hawthorn Boulevard, land uses consist of mixes of

residential, commercial, and industrial uses with the Salem Witch Museum, Peabody Essex

Museum, and the Hawthorne Hotel as prominent features. This route then turns west onto

Charter Street and then south onto Lafayette where land uses are best characterized as

commercial and industrial. As the route follows Lafayette Street to the south of Harbor Street, it

passes Lafayette Park and continues through an area best characterized as a mix of residential

and commercial uses. The route continues along Lafayette Street to the south of Palmer Street

and then west along Gardner Street; land uses along this portion of the route are primarily

residential. Finally, this route turns north onto Canal Street, where land uses are primarily

commercial and industrial on the west side, and residential on the east side.

5.5.1.3 Comparison of Preferred Route and Noticed Alternative

NEP assessed land use by two different methods: an assessment of land use by land area based

on MassGIS and an assessment of density by count of individual units (residences, businesses,

and sensitive receptors).

Land Use by Land Area Land uses along the Preferred Route and Noticed Alternative include a mix of residential,

commercial/industrial, and recreational uses. The land use information is shown in Land Use

Figures 5-5 (Preferred Route) and 5-6 (Noticed Alternative). To identify land uses along each

route, MassGIS land use data layers were overlaid onto aerial photographs, field investigations

were completed to confirm existing conditions, and project-specific land use categories and

maps were created by combining MassGIS data with information collected in the field. Table 5-2 summarizes the general land use acreage by percentage along the route corridors for

the Preferred Route and Noticed Alternative. As shown in the table, the Preferred Route is

primarily residential, with lower percentages of the route traveling through commer-

cial/industrial uses. The Noticed Alternative contains a more even mix of residential and

commercial/industrial uses along its length.



Table 5-2: Land Uses within Preferred Route and Noticed Alternative1

Land Use Type

Route Residential2

Commercial/

Industrial3

Mixed Commercial/

Residential4

Recreation/

Open Space5

Preferred Route 41% 26% 22% 11%

Noticed Alternative 36% 33% 17% 14%

1 Percentages for each land use were calculated using a 100-foot-wide route corridor centered on the middle of each street.

2 Residential: Includes areas that predominantly contain single- and multi-family housing units.

3 Commercial/Industrial: Includes areas that predominantly contain shopping centers, malls, restaurants, larger strip

commercial areas, neighborhood stores, and medical offices. Also includes heavy and light industrial facilities used for

manufacturing, storage, or assembly of raw or processed products.

4 Mixed Commercial/Residential: Includes areas that predominantly contain a mix of commercial and residential uses.

5 Recreation/Open Space: Includes areas that predominantly consist of playgrounds, ball fields, tennis courts, parklands,

and public open spaces.

Density of Land Use

Density of land use was assessed by tallying the total number of residential housing units,12

commercial/industrial buildings, sensitive receptors,13 and open space/recreation features along

the route. Table 5-3 below presents a comparison of land use density along the Preferred Route

and the Noticed Alternative. There are no permanent impacts to land uses along either route, as

the project will be installed entirely underground within City streets. However, a greater

number of residential housing units, commercial/industrial buildings, sensitive receptors and

open space/recreation areas would be affected by temporary construction impact along the

Noticed Alternative. Relative to the Preferred Route, the Noticed Alternative passes in front of

238 more residential units, seven more commercial/industrial buildings, and four more sensitive

receptors.

12 The number of residential (single- and multi-family) and mixed-use units along each route was identified through the review of available property assessment data and field reconnaissance. Residential structures were identified as single- or multi-family homes by counting mailboxes or gas/electric meters and confirming data against Salem’s GIS and property assessment data to determine

the number of units within each structure. 13 Sensitive receptors are land use features where occupants are more susceptible to potential impacts from the Project and where extra

consideration must be made in considering potential mitigation measures to minimize these impacts. Typical sensitive receptors include but are not limited to hospitals, schools, inns/hotels, day care facilities, elderly housing and convalescent facilities, fire stations, funeral homes, police stations, and churches. For the purposes of this analysis, NEP also considered as sensitive receptors any notable tourist attractions not listed as historic resources (see also Section 5.5.2).



Table 5-3: Land Use Comparisons for Preferred Route and Noticed Alternative

Land Use Preferred Route

Noticed

Alternative

Residential Housing Units (single/multi-family) 424 662

Commercial/Industrial Buildings 26 33

Sensitive Receptors 11 15

Open Space/Recreation 5 6

Conclusion

Despite having a relatively even mix of residential and commercial uses by acreage, the

Noticed Alternative is longer and much more densely occupied and thus contains a significantly

higher number of residential housing units compared to the Preferred Route. Based on the

potential for the Noticed Alternative to affect a higher number of individual uses than the

Preferred Route, NEP determined that the Preferred Route was superior with respect to their

potential for land use impacts from construction activities.

5.5.1.4 Mitigation

Construction of the replacement cables will not have any long-term impacts to land uses,

regardless of the route chosen, as all proposed facilities will be located underground within

existing City streets and at existing substation facilities.

The construction of the replacement cables will be completed in a manner that minimizes

temporary effects on residential, commercial, industrial, and recreational land uses through the

development and implementation of detailed construction management plans related to traffic

control and management, dust control/air quality, erosion and sediment control during

excavation activities, and noise control. Specific mitigation information related to these items is

provided in Section 5.4.1 (excavation activities), Section 5.5.4 (traffic control and manage-

ment), Section 5.5.5 (noise control), and Section 5.5.7 (dust control/air quality). Specific

mitigation related to visual impacts at the substations is provided in Section 5.9.

In addition, for underground transmission projects in urban settings, NEP typically requires the

contractor to complete pre-construction video surveys of structures and other features along the

proposed routes. If landowners give permission, both the internal and external conditions of

structures may be documented.



5.5.2 Tourist Attractions

Salem’s unique history and many historic and cultural attractions draw many visitors to the City

each year. NEP surveyed the major tourist sites, including historic sites, museums, hotels,

parking garages, and the trolley service to determine the locations of major tourist features

along the Preferred Route and Noticed Alternative. These sites/features are shown in

Figure 5-7, and are listed below with a brief description.

5.5.2.1 Preferred Route

Tourist destinations along the Preferred Route include the following:

· Hawthorne Hotel, 18 Washington Square West: Historic 93-room hotel located in the

central downtown area.

· Crowninshield-Bentley House, 126 Essex Street: Restored home circa 1727, owned by

the Peabody Essex Museum. Tours led by museum guides.

· Salem Waterfront Hotel, 225 Derby Street: Hotel with 86 rooms located adjacent to marina.

· Salem Trolley: Provides visitors with a narrated one-hour tour and all-day shuttle service.

Trolley route overlaps with the Preferred Route for approximately 0.13 miles.

5.5.2.2 Noticed Alternative

Tourist destinations along the Noticed Alternative include the following:

· Salem Witch Museum, 19.5 Washington Square North: Interpretation of the Salem Witch

Trials of 1692. Open 10:00 a.m. to 5:00 p.m. daily; 10:00 a.m. to 7:00 p.m. in July and

August.

· Hawthorne Hotel, 18 Washington Square West: See above for description.

· Crowninshield-Bentley House, 126 Essex Street: See above for description.

· Peabody Essex Museum (loading docks on Charter Street; main entrance on Essex

Street): Museum featuring exhibits, education center, historic buildings, and gardens. Open

daily 10:00 a.m. to 5:00 p.m.

· Old Burying Point Cemetery (also called the “Charter Street Cemetery”): Oldest

cemetery in Salem. Contains many early Salem residents and famous individuals. Open

dusk until dawn.

· Salem Trolley: (See description above.) Trolley route overlaps with the Noticed Alternative

for approximately 0.36 miles.




Along the Preferred Route there are three tourist attractions; along the Noticed Alternative,

there are five tourist attractions. Two of the attractions, the Crowninshield-Bentley House and

the Hawthorne Hotel, are located along both routes. Among the attractions along each route,

two of the attractions (the Salem Witch Museum and the Peabody Essex Museum) are major

cultural landmarks and attract a very high volume of visitors. These are both located along the

Noticed Alternative. In addition, the Noticed Alternative overlaps with the route of the Salem

Trolley for approximately 0.23 miles more than the Preferred Route.

Because fewer attractions are located along the Preferred Route and the Preferred Route

overlaps with a shorter distance of the Salem Trolley Route, NEP determined that the Preferred

Route was superior to the Noticed Alternative for this criterion.

5.5.2.4 Mitigation

Tourist attractions may be temporarily affected by construction activities such as disruption to

vehicular and pedestrian traffic, impedance of access, and noise. Mitigation proposed to address

these potential impacts is discussed in Section 5.5.4.4 (traffic and access) and Section 5.5.5.2

(noise). NEP will work closely with City officials to minimize such impacts.

There will be no permanent impact on these tourist features from the proposed facilities.

5.5.3 Public Shade Trees

G.L. c. 87 defines public shade trees as all trees within a public way or on the boundaries

thereof. Table 5-4 shows the number of public shade trees along the Preferred Route and

Noticed Alternative. NEP does not currently anticipate the need to cut any public shade trees to

facilitate construction along either route. A final assessment will be conducted in consultation

with the tree warden.

Table 5-4: Public Shade Trees along Preferred Route

and Noticed Alternative

Preferred Route Noticed Alternative

123 96




As presented in Table 5-4, approximately 123 public shade trees are located along the Preferred

Route. Public shade trees are located on both sides of the street and within existing sidewalk

areas. In general, the trees along Fort Avenue, Forrester Street, Boardman Street, Washington

Square South (along the Common), and Fairfield Street tend to be larger and more mature than

those located along the other sections of this route.


As presented in Table 5-4, a total of approximately 96 public shade trees are located along the

Noticed Alternative. These public shade trees are located on both sides of the street and within

existing sidewalk areas. In general, the trees along Fort Avenue, Webb Street, Andrew Street,

Washington Square North (along the Common), and Gardner Street tend to be larger and more

mature than those located along the other sections of this route.

5.5.3.3 Comparison of the Preferred Route and Noticed Alternative

As shown in Table 5-4, there are more public shade trees along the length of the Preferred

Route than along the Noticed Alternative. NEP does not anticipate the need to cut any public

shade trees to facilitate construction of either of the routes. As outlined in Section 5.5.3.4, NEP

will implement specific mitigation measures for the protection of public shade trees during

construction. In the course of constructing and maintaining underground electric transmission

facilities throughout its service area, it is NEP’s experience that these mitigation measures are

effective in minimizing long-term impacts to public shade trees. Because no impacts are

anticipated, the Preferred Route and Noticed Alternative are considered generally comparable

for this criterion.

5.5.3.4 Mitigation

To ensure the Project will result in minimal impact on public shade trees, NEP hired the Davey

Resource Group to evaluate the condition of all existing publicly-owned shade trees along the

Preferred Route and Noticed Alternative. The tree assessment took place September 13–15,

2010. All public shade trees along the Preferred Route and Noticed Alternative were located,

examined, identified, measured, and assessed by certified arborists. The full report entitled GIS-

based Public Tree Inventory National Grid Salem, Massachusetts is included in Appendix 5-1.

In most instances, public shade trees are located interior to the curb line and far enough

removed from the likely cable trench location that they would not be adversely affected either

by construction or by the long-term existence of the transmission cable. The report indicates

that street tree root systems are typically confined to the close proximity of the tree base and do

not commonly extend beyond the curb line and under paved streets because of high soil



compaction, little interstitial space, and the general lack of sufficient oxygen, soil, water, and

nutrients. Essentially, tree roots will grow where there is space, and will therefore grow on the

unimpeded edges of sidewalks and away from the street edge.

In each municipality in the Commonwealth, the Tree Warden is responsible for the care, control,

protection, and maintenance of all public shade trees (except those within a state highway), and

enforces all the provisions of law for the preservation of such trees. In order to ensure the long-

term protection of public shade trees, NEP will consult with the Salem Tree Warden prior to the

commencement of any work and throughout construction. NEP met with Salem DPW Director

and Tree Warden, Mr. Richard Rennard, Jr., on December 9, 2010 to initiate discussions. NEP

will fully comply with the City’s Tree Protection Bylaw and implement the following practices:

· Erect and maintain a temporary fence around the perimeter of individual tree pits (the

area between the curb and sidewalk where the tree resides). Remove fence when

construction is complete.

o Prohibit storage of construction materials, debris, or excavated material within tree pit

area or on any sidewalks.

o Prohibit vehicles, equipment, or foot traffic within tree pit area.

· Where excavation for new construction is required within the tree pit area and/or

sidewalk, the Salem Tree Warden will be contacted before any work begins.

o The Tree Warden will determine whether the contractor on site may commence with the

work or if a qualified arborist must be hired to conduct root pruning.

o If permission is granted to the contractor to commence with root pruning, the following

practices will be implemented:

§ Use narrow-tine spading forks and comb soil to expose roots.

§ Cut roots cleanly after excavation with clean, sharp tools, to promote callus for-

mation and wound closure.

§ Dress with a tree rooting hormone compound.

§ Backfill the excavation as soon as possible and water the soil around the roots to

avoid leaving air pockets. If backfilling immediately is not possible, exposed roots

will be covered with wet burlap and watered regularly to prevent roots from drying

out, and backfilling with soil will occur as soon as possible.

· Trees and vegetation will be repaired or replaced in a manner approved by the Salem

Tree Warden at the Company’s expense.

With the implementation of these mitigation measures, the Company anticipates that public

trees along the proposed route will be protected.



5.5.4 Traffic

This section evaluates the potential for traffic impacts along the Preferred Route and Noticed

Alternative. Traffic impacts associated with the Project will be temporary in nature and

confined to the period necessary to construct the Project. A variety of mitigation measures, as

outlined in Section 5.5.4.4 below, will be used to minimize traffic disruption during

construction. Implementation of a well-designed traffic management plan (“TMP”) will reduce

the potential for inconvenience.

To compare potential traffic impacts of the Preferred Route and Noticed Alternative, NEP reviewed

existing traffic conditions and the presence of public bus services, private trolley services, private

coach bus routes, and other major transportation facilities for each route. NEP collected existing

information from various sources including private transportation companies, City departments, and

public documents, and conducted field reconnaissance along each route. All of this information was

evaluated to determine the traffic congestion potential for each route. Key factors considered

included traffic volume counts (where available),14 presence of major commuting routes, locations

of key tourist destinations, public and private bus routes, and the presence of existing transportation

facilities such as parking garages, train stations, and bus stations.


The Preferred Route is approximately 1.63 miles in length. A large portion of this route is located

along roadways that host low to moderate traffic volumes and are used primarily for local traffic.

The heaviest traffic volume is along Hawthorne Boulevard and Congress Street north of Harbor

Street. This route generally follows roadways that are more than 30 feet wide,15 with only

13 percent of this route being less than 30 feet wide. This route includes streets that are used as

part of public bus, trolley, and motor coach routes, and that provide access to public parking lots

and a parking garage. Table 5-5 provides a detailed summary of existing traffic conditions and the

presence of private and public transportation features along specific segments of this route.

14 Traffic counts for each route were not completed as part of this evaluation as sufficient current and relevant information was available from existing data sources and public documents available at the time of the study.

15 The existing roadway width determines the available workspace above-grade to perform the necessary construction activities (divert traffic, excavate, place ducts, encase ducts in concrete, backfill, and replace paving) to build a below-grade duct bank. At a roadway width of significantly less than 30 feet, there would be a greater probability that traffic flow would be affected via either reduced lane widths or full closure of one or both lanes.



Table 5-5: Traffic, Road Width, and Public/Private

Transportation along the Preferred Route

Preferred Route

Road Width

(feet) Existing Traffic Characteristics Public/Private Transportation

Fort Avenue to Essex Street

(0.26 miles)

36 · Moderate traffic volume

· Two-way street

· Parking on south side

· Trolley route

· Motor coach route

Essex Street between

Gerrish Place and Webb Street

(0.08 miles)

24–54 · Moderate traffic volume

· Two-way street

· Parking on west side

· Trolley route

Forrester Street (connector segment) from

Gerrish and Essex to Forrester Street

(0.03 miles)

30 · Low traffic volume

· Two-way street

· Parking on north side

None

Forrester Street between Forrester

connector and Washington Square East

(0.16 miles)


· Two-way street

· Parking on both sides None

Washington Square South between

Washington Square East and

Washington Square West

(0.16 miles)


· One-way street

· Parking on west side

· Motor coach parking on north

side

· On-street bike route (shared

roadway)

Washington Square West between

Washington Square South and Essex Street

(0.03 miles)

54 · High traffic volume

(~14,000 average vehicles

per day*, or “vpd”)

· Congestion during peak hours

· Two-way street

· No parking available

· MBTA bus route


· Trolley route

Hawthorne Boulevard between Essex

Street and Charter Street

(0.08 miles)

45 · High traffic volume

(~16,500 average vpd*)

· Major access through down-

town and north to Rte 1A


· Two-way street

· Parking generally on both sides

· MBTA bus route



roadway)

Hawthorne Boulevard between Charter

Street and Derby Street

(0.04 miles)

45 · High traffic volumes

· Major access through

downtown and north to Rte 1A


· Two-way street

· Parking generally on both sides

· MBTA bus route


Congress Street between Derby Street and

Leavitt Street

(0.40 miles)


(~8,700 average vpd*)


· Two-way street

· Parking on both sides

· MBTA bus route

· Motor coach parking provided

on west side north of Harbor

Street

· Provides access to South

Harbor Garage


roadway)

Leavitt Street between Congress Street and

Lafayette Street

(0.17 miles)


· One-way street



roadway)

(From Lafayette Street) Fairfield Street to

Cabot Street to Cypress Street to

Canal Street Substation

(0.21 miles)

24–38 · All low traffic volume

· Two-way streets

· Fairfield has no parking

· Cypress and Cabot have

parking on both sides

None

* Estimated based on December 2003 and May 2004 peak hour traffic volumes reported in the Downtown Salem Transportation Improvement Study.




The Noticed Alternative is approximately 1.86 miles in length. A significant portion of this

route is located on roadways that host moderate to high traffic volumes and that provide access

to a mix of residences, businesses, and tourist destinations. Based on field reconnaissance, this

route experienced the highest level of rush hour congestion. Approximately 23 percent of this

route is along streets that are less than 30 feet wide. This route includes streets that are used as

part of public bus, trolley, and motor coach routes. Table 5-6 provides a detailed summary of

existing traffic conditions and the presence of private and public transportation features along

specific segments of this route.


The Preferred Route generally has traffic volumes that are similar to or lower than the Noticed

Alternative. Both routes use Fort Avenue and Hawthorne Boulevard. Between Fort Avenue and

Hawthorne Boulevard, the Preferred Route generally uses streets with low traffic volumes,

while the Noticed Alternative generally uses streets with moderate traffic volumes. The

Preferred Route also uses Congress Street, which has substantially lower traffic volumes than

Lafayette Street (which is used for the Noticed Alternative). Additionally, a shorter length of

roadway along the Preferred Route is used for public transportation than along the Noticed

Alternative.

In Section 4, NEP developed a metric to measure potential for traffic congestion. Those

categories were:

1- Low potential for significant traffic congestion and street closings (low to moderate traffic

volume, wide road/shoulders, alternate travel routes available)

2- Moderate potential for significant traffic congestion (higher traffic volumes, land use

conflicts, and/or limited work space)

3- High potential for significant traffic congestion (higher traffic volumes, major commuting

route, lack of alternate routes, density of businesses relying on on-street parking, etc.)



Table 5-6: Traffic, Road Width, and Public/Private

Transportation along Noticed Alternative

Noticed Alternative

Road Width

(feet) Existing Traffic Characteristics Public/Private Transportation

Fort Avenue to Essex Street

(0.26 miles)


· Two-way street

· Parking on south side

· Trolley route


Webb Street between Essex Street

and Andrew Street

(0.14 miles)


· Two-way street

· Parking on east side



roadway)

Andrew Street between

Webb Street and

Washington Square East

(0.15 miles)


· One-way street

· Parking on west side None

Washington Square North

between Andrew Street and

Brown Street

(0.19 miles)


· Two-way street


· MBTA bus route

· Trolley route


Washington Square West and

Hawthorne Boulevard between

Brown Street and Charter Street

(0.16 miles)

45–54 · High traffic volume (~13,800 avg. vpd

on Wash. Sq. West; ~16,500 avg. vpd on

Hawthorne Blvd.*)


· Two-way street

· Parking varies from both sides to one side

· MBTA bus route


· Trolley route


roadway)

Charter Street between

Hawthorne Boulevard and

Lafayette Street

(0.18 miles)


· Two-way street

· No parking

· Trolley route

Lafayette Street between

Charter Street and Derby Street

(0.08 miles)

40–45 · Low traffic volume

· Two-way street


· Trolley route

Lafayette Street between

Derby Street and Gardner Street

(0.42)

50 · High traffic volume (~14,000 north of

Dow Street and 23,000 south of

Dow Street*)

· Congestion throughout day

· Two-way street


· Two MBTA bus routes


roadway)


Gardner Street to Canal Street

(0.20)

30–45 · Low traffic volume

· Two-way street


· On-street bike route (shared roadway)

Canal Street to Substation

(0.09)

45 · High traffic volume (~14,500 avg. vpd*)

· Alternate route for through-town traffic

during peak hours

· Major access route to/from south

· Two-way street


· Access route to/from south to Salem

Commuter Rail station and Riley Plaza

parking lots

* Estimated based on December 2003 and May 2004 peak hour traffic volumes reported in the Downtown Salem Transportation Improvement Study.



The total lengths of the Preferred Route versus Noticed Alternative for each of these categories

are listed in the following table:

Table 5-7: Lengths of Preferred Route and Noticed Alternative with

Low, Moderate, and High Potential for Significant Traffic Congestion


Length scoring a “1” (Low Potential) 0.86 miles 0.15 miles

Length scoring a “2” (Moderate Potential) 0.26 miles 0.66 miles

Length scoring a “3” (High Potential) 0.51 miles 1.05 miles

As shown in the table, more than half of the Preferred Route scored a “1” (low potential for

traffic congestion), while a majority of the Noticed Alternative scored a “3” (high potential for

traffic congestion).

The Preferred Route is approximately 0.23 miles shorter than the Noticed Alternative, and

consists of streets that are generally wider: 87 percent of the Preferred Route is more than

30 feet wide, compared to only 77 percent of the Noticed Alternative. The greater width of the

Preferred Route should reduce the need for lane closures in one or both directions during

construction, and thus minimize traffic impacts.

Based on its shorter length, greater overall width, and generally lower traffic volumes and

potential for congestion, NEP determined that the Preferred Route was preferable to the

Noticed Alternative with respect to construction-related traffic impacts.

5.5.4.4 Mitigation

NEP recognizes that its construction efforts for this Project will overlap with those of Footprint

and Spectra. A technical advisory group will be formed to integrate construction activities with

Footprint, Spectra, and other construction projects in the City to limit construction-related

traffic volume wherever possible. Initial consultations have taken place with Footprint and

Spectra, and discussions with each will be ongoing throughout the Project. Prior to beginning

any work, NEP will work closely with various City Departments to develop a construction

TMP. Items to be addressed in the TMP include:

· Ongoing coordination with police and fire departments;

· Provisions for emergency vehicle access at all times;

· Lane location and width within the work zone to minimize impacts to vehicular traffic

movement and promote safe passage;



· Work schedule and duration of lane closures, road closures, and/or detours where necessary;

· Traffic control devices such as barricades, reflective barriers, advance warning signs, traffic

regulation signs, traffic control drums, flashers, detour signs, and other protective devices

as approved by the City;

· Locations where temporary provisions may be made to maintain access to homes and

businesses;

· Routing and safeguarding of pedestrian and bicycle traffic;

· Continuity of MBTA, school bus, private trolley tour, and private motor coach routes;

· Communication with adjacent businesses to avoid interruptions to critical product deliveries;

· Roadway level of service effects due to short-term lane closure(s); and

· Development of a system to notify municipal officials, local businesses, and the public of

the timing and duration of closed curbside parking spaces and travel restrictions.

The TMP will be submitted for review and approval by appropriate Salem authorities prior to

construction. Traffic control plans will be developed consistent with the Federal Highway

Administration’s Manual on Uniform Traffic Control Devices for Streets and Highways and

MassDOT’s publication, Work Zone Safety.

5.5.5 Noise

This section evaluates the potential for noise impacts along the Preferred Route and Noticed

Alternative. All of the potential noise impacts associated with the installation of the

replacement cables will be limited to the construction period. Noise from construction will have

the potential to affect adjacent residences, businesses, and other sensitive land use receptors.

The Project does not involve the installation of any new equipment or facilities that would

result in permanent noise increases over existing conditions.

Underground construction associated with the installation of the new transmission cables is

anticipated to extend through an 18-month period from November 2014 through May 2016,

with the potential for final pavement restoration to extend an additional few months.

Construction activities will follow the sequence outlined in Section 5.4 and identified in

Table 5-1. The potential for noise impacts from construction activities during the Project

depends on the construction equipment used for the four principal phases of construction and

the hours of operation. Sound levels from typical construction equipment that will be used

during the principal phases of construction, along with anticipated duration in front of any one

location are listed in Table 5-8. Noise levels listed in Table 5-8 will be sporadic and of limited

duration on a given day.



Table 5-8: Typical Construction Sound Levels

Activity Types of Equipment

Typical Sound

Levels

(dBA) at 50 Feet1,2

Manhole Installation

· Pavement Saw

· Manhole Crane

· Asphalt Paver

· Backhoe

· Dump Truck

82 to 90

Trench Excavation, Duct Bank Installation, and Pavement Patching

· Pavement Saw

· Concrete Batch Truck

· Pneumatic Hammer

· Mounted Impact Hammer (Hoe Ram)

· Backhoe

· Dump Truck

82 to 90

Cable Pulling, Splicing and Testing

· Generator

· Air conditioner

· Splicing Van

60 to 84

Final Pavement Restoration

· Asphalt Paver 85

1 Thalheimer, E., “Construction Noise Control Program and Mitigation Strategy at the Central Artery/Tunnel Project,” Noise Control Eng. Journal 48 (5), 2000 Sep-Oct.

2 USEPA, Noise from Construction Equipment and Operations, Building Equipment, and Home Appliances, prepared by Bolt, Baranek and Newman, Report No. NTID300.1, December 31, 1971.


Construction of the new 115 kV transmission line will follow the same basic construction

sequence regardless of the route selected. Consequently, the types and duration of construction-

related noise will be similar regardless of the route chosen. The relative impact of construction-

related noise along each route will depend in part on the total length of the route and on the land

uses along each route. Table 5-9 reviews the length of each route and the extent of residential

land uses, commercial land uses, and sensitive receptors along each route.

As can be seen from Table 5-9, the Preferred Route is approximately 0.23 miles shorter than the

Noticed Alternative. In addition, the Preferred Route passes by approximately 238 fewer

residences, seven fewer commercial/industrial buildings, and four fewer sensitive receptors

than the Noticed Alternative. Moreover, as discussed above, a greater percentage of the

Preferred Route consists of streets at least 30 feet wide. Therefore, construction is likely to

proceed more quickly down these streets than down the narrower streets of the Noticed

Alternative.



Table 5-9: Land Use and Length Comparisons for

Preferred Route and Noticed Alternative


Land Use

Residential Housing Units (single/multi-family) 424 662

Commercial/Industrial Buildings 26 33

Sensitive Receptors 11 15

Length (miles) 1.63 1.86

Overall, work along the Noticed Alternative has the potential to result in a longer duration of

construction noise impacts for a greater number of residences, commercial and industrial

buildings, and sensitive receptors. Therefore, the Preferred Route is superior to the Noticed

Alternative with respect to noise impacts.

5.5.5.2 Mitigation

In general, construction will occur in continued coordination with City engineers and will

comply with Salem’s Ordinance for Noise Control as well as with state noise requirements. In

addition, the following will be implemented by the Company:

· Requiring well-maintained equipment with functioning mufflers;

· Strict compliance with DEP’s Anti-Equipment Idling regulations to prevent equipment

from idling and producing unnecessary noise while not in productive use;

· The Company will provide all of its construction contractors with training that highlights

the Company’s requirements with respect to well-maintained equipment, anti-idling and

other relevant policies;

· The Company’s Stakeholder Relations team will provide regular Project updates via the

project website at www.salemcableproject.com. These regular updates will include

locations and types of work planned for the following two weeks. These communica-

tions will promote a well-informed public and help manage expectations relative to

construction activity and potential noise impacts; and

· The Company will maintain a direct line to a Stakeholder Representative during the

duration of the Project to provide abutters with a quick and easy means for raising any

specific concerns or questions.



5.5.6 Potential to Encounter Subsurface Contamination

Construction of the Project may result in the excavation of materials that have been

contaminated by historical releases or former land development practices in the vicinity of the

Preferred Route or Noticed Alternative. Both an environmental database search and an online

review of the DEP database of MCP sites were performed to determine the potential to encounter

subsurface contamination along each route. The DEP online database was used to collect

information on DEP sites (with a release tracking number) located within one quarter-mile of the

routes. An environmental database search was also analyzed and reviewed to determine the

potential to encounter contaminated sites along each route.


Seven active MCP sites are documented along the Preferred Route, and ten active MCP sites

are documented along the Noticed Alternative. Consequently, NEP concluded that the

Preferred Route would result in a lower potential to encounter subsurface contamination during

construction, and this route is therefore superior to the Noticed Alternative for this criterion.

5.5.6.2 Mitigation

Some excavated materials may be contaminated from historical releases or former land

development practices. As appropriate, NEP will contract with a Licensed Site Professional to

manage soils pursuant to the Utility Release Abatement Measure (“URAM”) or the Release

Abatement Measure (“RAM”) provisions of 310 CMR 40.0000, the MCP.

As required by the notification requirements pursuant to 310 CMR 40.0460, a URAM will not

be undertaken by the Proponent until proper notification is made to the DEP regarding:

· A release or threat of release of oil and/or hazardous material at the construction site for

which notification is required under the provisions of 310 CMR 40.0315;

· The Proponent’s intention to conduct a URAM in compliance with all applicable

requirements; and

· The name and license number of the Licensed Site Professional who has been employed to

carry out the URAM.

At locations where known historical releases (for which NEP is identified as the Responsible or

Potentially Responsible Party) have achieved a Temporary or Permanent Solution and a

Class A, B, or C Response Action Outcome (“RAO”) has been filed under the MCP, a post-

RAO RAM may be performed pursuant to 310 CMR 40.1067 and the applicable provisions of

310 CMR 40.0440. In historical release areas where a Permanent Solution has not yet been

achieved, valid Tier I or Tier II Permits will potentially be required to manage soils under a



RAM. As required by 310 CMR 40.0440, a RAM Plan will be submitted to DEP prior to

conducting the work at these locations.

5.5.7 Dust Control/Air Quality

This section evaluates the potential for fugitive dust and for emissions from construction

equipment along the Preferred Route and the Noticed Alternative. As previously presented in

Section 5.4, construction associated with the Project is anticipated to extend through an

18-month period from November 2014 through May 2016, with the potential for removal of the

existing Cables and final pavement restoration to extend an additional few months.

Construction activities will follow the sequence outlined in Section 5.4 and identified in

Table 5-1. The potential for construction activities to generate dust and equipment emissions

depends on the particular activity being completed, the equipment being used, and external

factors such as weather conditions. In general, routes that take longer to construct and that pass

in front of more residences, businesses, and sensitive receptors have a higher potential for

impacts from dust and emissions during construction.


As previously identified in Table 5-9, approximately 424 residential housing units (single and

multi-family), 26 commercial or industrial buildings, and 11 sensitive receptors are located

along the Preferred Route.


As previously identified in Table 5-9, approximately 662 residential housing units (single and

multi-family), 33 commercial or industrial buildings, and 15 sensitive receptors are located

along the Noticed Alternative.


Construction of the new 115 kV transmission line will follow the same basic construction

sequence regardless of the route selected. However, the potential for impacts from dust and

equipment emissions would be greater along the Noticed Alternative than along the Preferred

Route for several reasons. The Noticed Alternative is approximately 0.23 miles longer than the

Preferred Route, and is located in front of approximately 238 more residences, seven more

commercial and industrial buildings, and four more sensitive receptors than the Preferred

Route.

Overall, work along the Noticed Alternative has the potential to result in a longer duration of

construction-related dust and equipment emissions impacts for a greater number of residences,

commercial/industrial buildings, and sensitive receptors. Therefore, the Preferred Route is



superior to the Noticed Alternative with respect to potential dust and equipment emissions

impacts.

5.5.7.4 Mitigation

NEP will require its contractors to have water trucks with misters on site during construction

activities to control the release of dust from the work area. In addition, excavated soils will be

directly transferred from the trench to a covered truck to minimize the potential for the release

of dust and for soil migration from the work area. NEP met with the Salem Health Agent to

discuss the Project on April 10, 2013. During this meeting, the Salem Health Agent indicated

that a detailed dust control plan would need to be developed and submitted for review and

comment prior to construction. For any diesel-powered non-road construction equipment rated 50 horsepower or above, whose

engine is not certified to USEPA Tier 4 standards, and that will be used for 30 days or more

over the course of the Project, NEP will direct its contractors to retrofit the equipment with

USEPA-verified (or equivalent) emission control devices (e.g., oxidation catalysts or other

comparable technologies).

NEP exclusively uses ultra-low-sulfur diesel (“ULSD”) fuel in its own diesel-powered

construction equipment, and will require its contractors to do the same for this Project. ULSD

has a maximum sulfur content of 15 parts per million, compared to 500 parts per million for

low-sulfur diesel fuel (a 97 percent reduction). NEP and its contractors will comply with state law (G.L. c. 90, § 16A) and DEP regulations

(310 CMR 7.11(1)(b)) that limit vehicle idling to no more than five minutes in most cases.

There are exceptions for vehicles being serviced, vehicles making deliveries that need to keep

their engines running, and vehicles that need to run their engines to operate accessories. 5.5.8 Historic and Archaeological Sites This section presents an overview of the findings of cultural resource investigations conducted

to identify historic and archaeological resources in the vicinity of the Preferred Route and

Noticed Alternative. Archaeological resources include buried archaeological sites. To be

considered significant and eligible for listing on the State or National Registers of Historic

Places (“SRHP” and “NRHP” respectively), a cultural resource must exhibit physical integrity;

contribute to American history, architecture, archaeology, technology, or culture; and meet at

least one of the following four criteria: · Association with important historic events;

· Association with important persons;



· Distinctive design or physical characteristics; or

· Potential to provide important new information about the pre-contact, contact, or post-

contact periods of history.16

The State Historic Preservation Office within the MHC is responsible for reviewing

Massachusetts projects to assure that significant cultural resources will be protected or

otherwise preserved. The resource review also includes consultation with Wampanoag Tribe

of Gay Head (Aquinnah) Tribal Historic Preservation Officer.

A review of MHC’s Inventory of Historic and Archaeological Assets of the Commonwealth

was conducted for the Project Study Area. In addition, information available from the City was

reviewed to determine local historic districts within the Project Study Area.

The Preferred Route and Noticed Alternative are located immediately adjacent to many

individual historic buildings, historic areas, and historic districts. The historic properties

encompass a range of levels of documentation and designation, including Individually

Inventoried Buildings, Inventoried Areas, Local Historic Districts, and National Register–listed

and eligible individual buildings and districts. In Salem, some of the Local Historic Districts and

National Register–listed districts have overlapping or similar boundaries, and some individually

listed properties are within one or more of these districts. The buildings, areas, and districts along

each route are depicted in Figures 5-8 and 5-9, and these features are described below.


The Preferred Route passes through the Derby Waterfront, Salem Common, and Essex Institute

National Historic Districts, and eight Inventoried but undesignated historic areas. It also passes

through the Derby Street and Washington Square Local Historic Districts. There are

approximately 131 Individually Inventoried historic properties, including buildings that are

located within historic districts, along the Preferred Route. In addition, there are a total of three

documented archaeological sites located along the Preferred Route.


The Noticed Alternative passes through five National Historic Districts (Essex Institute, Salem

Common, Derby Waterfront, Downtown Salem, and Charter Street). It also passes through the

Derby Street and Washington Square Local Historic Districts and five Inventoried but

16 Pre-contact refers to the time prior to sustained interactions on the North American continent between the indigenous peoples of North America and European traders and settlers, focused along the eastern seaboard prior to the 16th century. Contact refers to the period of initial contact and the beginnings of European settlement and the resulting cultural dynamics between the indigenous peoples of North America and European traders and settlers, in the 16th century and into the 17th century. Post-contact is the time of descendant generations after Contact.



undesignated historic areas. There are approximately 117 Individually Inventoried historic

properties, including buildings that are located within historic districts, along the Noticed

Alternative. In addition, there are a total of three documented archaeological sites located along

the Noticed Alternative.


As shown in Table 5-10 below, the Preferred Route and the Noticed Alternative pass the same

number of archaeological resources. The Preferred Route passes more Individually Inventoried

Buildings, but fewer National Historic Districts and total historic districts/areas than the

Noticed Alternative. Based on this balance of resources, the Preferred Route and Noticed

Alternative were determined to be relatively equal in terms of their potential for impacts to

historic and archaeological resources.

Table 5-10: Historic and Archaeological Resources

along Preferred Route and Noticed Alternative

Resource Type Preferred Route Noticed Alternative

Archaeological Sites 3 3

Individually Inventoried Buildings 131 117

Total Districts/Areas 13 12

National Historic Districts 3 5

Local Historic Districts 2 2

Inventoried Areas 8 5

5.5.8.4 Mitigation

The Project will traverse through or adjacent to several historic districts including Local

Historic Districts, those listed on the NRHP, and districts determined eligible for listing in the

NHRP. In addition, several pre- and post-contact archaeological sites, as well as a number of

individual buildings or structures within the Project Study Area, are inventoried or listed in the

NRHP or SRHP.

G.L. c. 9, § 27C (Chapter 254 Review) requires that projects that are permitted, licensed,

funded, or requiring approval from state bodies be reviewed by the MHC to identify potential

impacts to historic and archaeological resources included in the SRHP. To initiate formal

consultation with the MHC, NEP will file a Project Notification Form (“PNF”) for the Project.

MHC will then review the proposed project and provide comments and recommendations

regarding mitigation measures to be implemented during construction such that the Project can

be completed with no adverse impact to historic and/or archaeological resources. MHC



typically requires proponents who file a PNF to send a copy to the local historic commission for

their input in the process as well.

NEP will work with the MHC and the Salem Historical Commission through the PNF process,

complete any required pre-construction surveys and review, and comply with any construction-

related requirements assigned to ensure that there are no adverse effects to historic and

archaeological resources from the Project.

5.5.9 Electric and Magnetic Fields (“EMF”)

Electric and magnetic fields are the fields created by the voltage (electric field) and the current

(magnetic field) on electric conductors. NEP, like all North American electric utilities, supplies

electricity that oscillates at a frequency of 60 cycles per second (“hertz” or “Hz”). Therefore,

the electric utility system, and its equipment and conductors, produce 60-Hz power-frequency

EMF. These fields can be calculated based on conductor location, current, and voltage. The

fields can also be measured.

Power-frequency EMF is present wherever electricity is used. Sources of EMF include utility

transmission lines, distribution lines, and substations, but also the electrical wiring in homes,

offices, and schools, and any appliances and machinery that use electricity.

Magnetic fields are measured in units called gauss (“G”). For the low levels normally

encountered during daily activities, however, the field strength is expressed in a much smaller

unit, the milligauss (“mG”), which is one-thousandth of 1 gauss. Magnetic-field intensities

from common sources can range from below 1 mG to above 1,000 mG. Magnetic fields are

present whenever current flows in a conductor, and are not dependent on the voltage on the

conductor. The magnetic-field strength is a function of both the current flow on the conductor

and the design of the transmission line. The strength of these fields also decreases with distance

from the source. Unlike electric fields, however, most common materials have little shielding

effect on magnetic fields.

Electric fields exist whenever voltages are present on conductors, and are not dependent on the

magnitude of current flow. The strength of the electric field is primarily a function of the

configuration and operating voltage of the line and decreases with distance from the source.

The electric field may be shielded (i.e., the strength may be reduced) by any conducting

surface, such as trees, fences, walls, buildings, and most types of other structures. The strength

of an electric field is measured in volts per meter or kilovolts per meter. Electric fields do not

travel through earth nor do they penetrate most building materials. Since the transmission

cables will be installed underground and encased in concrete, no above-ground electric fields

will be produced and no changes to ambient electric field strengths will result from construction

of the Project along any of the routes considered. Consequently, the following discussion

considers only magnetic field strengths.



5.5.9.1 Modeled Magnetic Fields Associated with Transmission Line Operation

Exponent, Inc. modeled magnetic fields associated with transmission line operation for five dual-

circuit configurations, including (1) a horizontal configuration,17 (2) a vertical configuration, (3) a

configuration approaching a manhole entrance, (4) a configuration at a manhole entrance, and

(5) a “bridge configuration” representing the cables as they cross the Congress Street Bridge (see

Appendix 5-2). The magnetic fields for the first four configurations were calculated at a height of

three feet above ground, and as a function of burial depth. The bridge configuration was modeled

at a height of three feet above the bridge surface based on the location of the existing utility bay in

the Congress Street Bridge. In all cases, a loading of 250 MVA was assumed for each cable,

representing a summer normal maximum expected loading condition with full generation

operating at Salem Harbor.

The modeled magnetic field levels for the proposed vertical and horizontal configurations are

presented in Table 5-11 below. The Company anticipates that the duct bank will typically be

buried to a depth of 2.5 to 4.5 feet below the street surface. Thus, modeled magnetic fields

associated with the Project would be approximately 26 to 55 mG directly above the centerline

of the duct bank, which typically would be located within a street or sidewalk.18 At a distance

of 25 feet to the centerline, magnetic fields would be approximately 4 to 10 mG. At a distance

of 50 feet to the centerline, magnetic fields would be approximately 1 to 5 mG.

Table 5-11: Modeled Magnetic Field Levels (mG)

for Vertical and Horizontal Configurations

Burial Depth (feet)

Distance from duct bank centerline (feet)

-50 -25 0 25 50

Horizontal Configuration

2.5 1 4 55 4 1

3.5 1 4 37 4 1

4.5 1 4 27 4 1

Vertical Configuration

2.5 5 10 43 9 5

3.5 5 10 32 9 5

4.5 5 10 26 9 5

The modeled magnetic field levels for the proposed bridge configuration are presented in

Table 5-12 below. Magnetic fields of approximately 68 mG are anticipated directly above the

17 The duct bank will be installed in a horizontal configuration along the majority of the route. The vertical configuration will be used as the duct bank approaches manhole locations, and where existing in-street utilities preclude the use of the horizontal configuration.

18 Because there is no formal ROW along city streets, edge-of-ROW measurements are not provided.



centerline of the duct bank, which is located in the southbound side of the bridge. They will

decline to 3 to 4 mG at a distance of 25 feet to the centerline, and to 1 mG at a distance of

50 feet to the centerline.


for Congress Street Bridge Configuration

Burial Depth (feet)


-50 -25 0 25 50

3 feet above bridge surface 1 3 68 4 1

The modeled magnetic field levels at the manhole approaches are presented in Table 5-13,

below. Magnetic field levels are higher in locations in close proximity to the manhole entrances

because of decreases in the self-cancellation of the magnetic field due to the reduced interaction

of the currents in the two circuits. Table 5-13 shows the modeled magnetic field levels in the

manhole approach configuration. Magnetic fields of approximately 98 mG are anticipated

directly above the centerline of the duct bank at manhole approaches at a burial depth of

2.5 feet, decreasing to 46 mG at a burial depth of 4.5 feet.


for Manhole Approach Configuration

Burial Depth (feet)


-50 -25 0 25 50

2.5 3 11 98 10 3

3.5 3 11 66 9 3

4.5 3 10 46 9 3

Finally, Table 5-14 shows the modeled magnetic field levels in the manhole entrance

configuration. The model included a passive loop in the design of the cable system as described

in Appendix 5-2 and predicted magnetic fields of approximately 53 mG directly above the

centerline of the duct bank at a burial depth of 3.8 feet and 48 mG directly above the centerline

of the duct bank at a burial depth of 4.5 feet.




for Manhole Entrance Configuration

Burial Depth (feet)


-50 -25 0 25 50

3.8 10 25 53 23 10

4.5 10 24 48 23 10


Existing utilities located within the Preferred Route and Noticed Alternative are very similar.

Therefore, the increase in magnetic fields resulting from the operation of the replacement

cables would be similar along the two routes. However, as discussed in Section 5.5.1.3, there

are 662 residences along the Noticed Alternative Route, compared to 424 residences along the

Preferred Route. Thus, use of the Preferred Route would reduce the number of residences that

would experience increased magnetic fields above background levels as a result of the Project.

5.5.9.3 Mitigation

Health scientists at Exponent have reviewed the conclusions of national and international

scientific and health organizations that have evaluated more than 30 years of research. None of

these organizations has concluded that exposure to EMF is a demonstrated cause of any long-

term health effects. The Exponent report entitled “Current Status of Research on Extremely

Low Frequency Electric and Magnetic Fields and Health: Salem Harbor to Canal Street 115-kv

Transmission Line,” included in Appendix 5-3, updated the World Health Organization’s

(“WHO”) assessment of research on EMF and health and concluded:

A significant number of epidemiologic and in vivo studies have been published

on ELF, EMF, and health since the WHO 2007 report was released in June 2007.

The weak statistical association between high, average magnetic fields and

childhood leukemia has not been appreciably strengthened or diminished by

subsequent research and remains unexplained and unsupported by the experi-

mental data. The recent in vivo studies confirm the lack of experimental data

supporting a leukemogenic risk associated with magnetic-field exposure.

Overall, the current body of research supports the conclusion that there is no

association between magnetic fields and adult cancer or cardiovascular disease,

although future research is needed that improves upon exposure estimations.

Recent literature suggested an association with magnetic fields and Alzheimer’s

disease, but no firm conclusions can be drawn from this literature set regarding

causation.



In conclusion, recent studies when considered in the context of previous research

do not provide evidence to alter the conclusion that ELF and EMF exposure is

not a cause of cancer or any other disease process at the levels we encounter in

our everyday environment.

National Grid has taken the following reasonable and prudent steps to minimize magnetic field

levels for this Project:

· In the vicinity of the manhole entrances, where magnetic fields are highest, the Company

will install a passive loop to reduce magnetic fields, as described in Appendix 5-2.

· The design of the duct bank and cables in each configuration has been optimized to

minimize magnetic fields.

· The placement of the ground continuity conductors has been optimized to minimize

magnetic fields.

These steps are consistent with the guidance of the National Institute of Environmental Health

Sciences, WHO, and other health agencies.

5.5.10 Visual Impacts

The proposed transmission cables and all related equipment will be installed underground

within City streets. Thus, there will be no permanent visual impacts resulting from the

installation of the proposed cables, regardless of the route chosen.

Potential visual impacts of the proposed substation improvements are discussed in Section 5.9.

5.5.11 Wetlands and Waterways

The proposed transmission cables and all related equipment will be installed underground

within City streets. Thus, there will be no temporary or permanent impacts to wetlands or water

bodies resulting from the installation of the proposed cables, regardless of the route chosen. As

shown in Figure 5-8, the Preferred Route, where it crosses the South River along Congress

Street, will be located within the 200-Foot Riverfront Area, the 100-year floodplain, and the

100-foot Buffer Zone to the Bank of the South River. As shown in Figure 5-9, the Noticed

Alternative, along a portion of Webb Street, is located within the 100-year floodplain associated

with Collins Cove. However, all work will be within the current roadway layout at these

locations. Section 5.4 identifies the Best Management Practices to be implemented to ensure

that there are no impacts to wetlands or water bodies from the Project.



5.5.12 Conclusion

The preceding sections have reviewed the temporary and permanent environmental impacts

associated with the installation of the replacement cables along the Preferred Route and Noticed

Alternative, including impacts to land use, tourist attractions, public shade trees, traffic, noise,

potential to encounter subsurface contamination, dust control/air quality, historic and

archaeological resources, EMF, and visual impacts. NEP has minimized potential environmental

impacts that will be associated with the Project through its route selection process; use of best

management practices; compliance with federal, state, and local rules and regulations; and

mitigation of any impacts that cannot be avoided.

Table 5-15 provides a summary of the factors considered for the comparison of the Preferred

Route and the Noticed Alternative. A +/=/– rating is used to summarize the results and compare

the routes, with a + symbol indicating that the route would have the lesser amount of impact for

that particular criterion.

Table 5-15: Environmental Comparison of Preferred Route and Noticed Alternative

Environmental Criteria Preferred Route Noticed Alternative

Land Use + –

Tourist Attractions + –

Public Shade Trees = =

Traffic + –

Noise + –

Subsurface Contamination + –

Dust Control/Air Quality + –

Historic/Archaeological Resources = =

Electric and Magnetic Fields + –

Visual/Aesthetics = =

Wetlands/Waterways = =

+ indicates less potential for impact, which means superior for use = indicates no difference between routes – indicates more potential for impact, which means inferior for use

There are clear differences between the Preferred Route and the Noticed Alternative. First, the

Preferred Route is 0.23 miles (approximately 1,240 feet) shorter than the Noticed Alternative.

Second, the Preferred Route abuts 238 fewer residential units, seven fewer commer-

cial/industrial buildings, and 4 fewer sensitive receptors than the Noticed Alternative. Because

of its greater length, the Noticed Alternative generally has greater potential for impacts across

the spectrum of human and environmental resources. Lastly, the Noticed Alternative



experiences the highest amount of traffic volume and congestion at rush hour and is used more

for public transportation routes than the Preferred Route. Overall, the Preferred Route consists

of roads that are generally wider, whereas the Noticed Alternative is composed of a higher

percentage of streets narrower than 30 feet. The existing roadway width determines the

available workspace above-grade to perform the necessary construction activities (divert traffic,

excavate, place ducts, encase ducts in concrete, backfill, and replace paving) to build a below-

grade duct bank. At a roadway width of less than 30 feet, there would be a much greater

probability that traffic flow would be affected via either reduced lane widths or full closure of

one or both lanes.

On the basis of this analysis, the Preferred Route is clearly superior to the Noticed Alternative

with respect to human and environmental impacts.

5.6 RELIABILITY COMPARISON OF PREFERRED ROUTE AND NOTICED

ALTERNATIVE

Many considerations go into determining the reliability of an electric transmission project,

including the total exposure (length) of the circuit, location of the facilities, and types of

construction methodology required (e.g., installations made using trenchless construction

techniques are not easily accessible and therefore not as easily maintained as a duct bank and

manhole system installed by open cut excavation). Since the length, physical environment, and

construction methodology of the Preferred Route and the Noticed Alternative are so similar,

NEP determined that there is no material difference between the routes in terms of reliability.

5.7 COST COMPARISON OF PREFERRED ROUTE AND NOTICED ALTERNATIVE

NEP developed detailed cost estimates for installation of the new cables along the Preferred

Route and the Noticed Alternative. These cost estimates were previously presented in Section 4

and are summarized below in Table 5-16.

As discussed above, the cost estimates provided herein are classified as conceptual grade

estimates, indicating that key project elements have been identified, but a limited amount of

detailed engineering has been completed. Conceptual grade estimates are based on recent costs

of similar materials and construction activities, have an accuracy of -25% to +50%, and do not

consider possible future variances in commodity or labor costs. The factors that affect the

overall cost of an underground project, and NEP’s estimation methods, are discussed in more

detail in Section 4.5.4.



Table 5-16: Estimated Costs

Route Circuit Length

(miles)

Circuit Cost

(millions)

Preferred Route 1.63 $33.40

Noticed Alternative 1.86 $38.32

As shown in the table, the cost of replacing the existing Cables is lowest if the Preferred Route

is used for the Project. This cost differential is driven by the greater length of the Noticed

Alternative; therefore, it is expected to persist as the Project moves into more detailed

engineering. For this reason, the Preferred Route is superior to the Noticed Alternative with

respect to cost.

5.8 CONCLUSION OF COMPARISON OF PREFERRED ROUTE AND NOTICED

ALTERNATIVE

Based on the comparison above, the Preferred Route was found to be superior to the Noticed

Alternative with respect to human and environmental impacts as well as cost, with no material

difference between the routes in terms of reliability. NEP therefore determined that the use of

the Preferred Route will best meet the identified need with minimum cost and the least

environmental impact.

5.9 ANCILLARY FACILITIES

The existing conditions at the Salem Harbor Substation and the Canal Street Substation are

discussed throughout the following subsections together with the proposed improvements and

mitigation for each substation. Because construction at each substation will be the same

regardless of the routes selected, substation impacts were not considered in the comparative

analysis of the routes.

NEP determined that there are no surface water supply protection areas, wellhead protection

areas, wetland resource areas or vernal pools at or near the substations. A review of NHESP

mapping of protected species and habitats in MassGIS determined that there is no Priority or

Estimated Habitat near the substations. Accordingly, no impacts to protected species and

habitats will occur.



5.9.1 Salem Harbor Substation

5.9.1.1 Scope of Improvements

At Salem Harbor Substation, the electrical equipment associated with the existing underground

Cables will be removed. This includes cable termination structures, surge arresters, voltage

transformers, current transformers, rigid copper conductor, aluminum conductor, disconnect

switches, dielectric fluid reservoirs, and one steel dead-end structure. Four oil circuit breakers

will also be replaced with new sulfur hexafluoride (“SF6”) gas circuit breakers.

To accommodate the new underground cables, the new cable riser termination structures will

be installed in the area currently used as a parking lot, thereby allowing for removal of the

existing structures without an electric outage. Once the demolition of the existing cable

termination structures is complete, the new cables can be tied into the electric substation.

The new equipment to be installed will include similar components as the ones that were

removed, but without the rigid copper conductor or dielectric fluid reservoirs, and with two

steel dead-end structures. New relay, control, and communication equipment will also be

installed inside the existing control house. The proposed development plan for the Salem

Harbor Substation is provided in Appendix 5-4.

5.9.1.2 Land Use

The Salem Harbor Substation is located on the property of the existing Salem Harbor

Generation Facility. This substation is completely surrounded by the industrial land use

associated with the generation facility. The proposed upgrades at the Salem Harbor Substation

will include replacement of some existing equipment and expansion (approximately

4,300 square feet) into the existing parking lot associated with the generation facility. These

upgrades will not have any long-term impacts to the surrounding land use at the generation

station.

5.9.1.3 Visual Impact

The proposed upgrades at the Salem Harbor Substation will include replacement of some

existing equipment and expansion (approximately 4,300 square feet) into the existing parking

lot associated with the generation facility. The visual impacts of these upgrades are likely to be

minimal, given the substation’s visual integration into the much larger generating facility

currently located at the Salem Harbor site.



5.9.1.4 Noise

The Salem Harbor Substation is completely surrounded by the industrial land use associated

with the generation facility. There are no residential buildings within 300 feet of the substation,

and the proposed upgrades at the Salem Harbor Substation will not include equipment that will

result in a permanent increase in operational noise levels over existing conditions.

5.9.1.5 Traffic

This substation is off Fort Avenue with main routes of access from Webb Street, Essex Street,

and Derby Street. All of these roadways experience moderate traffic volume. Traffic impacts

associated with the Project will be temporary in nature. A variety of mitigation measures as

outlined in Section 5.5.4.4 will be used to minimize traffic disruption to the surrounding

roadways during construction at this substation, and NEP will work to integrate construction

activities with Footprint, Spectra, and other construction projects in the City.

5.9.1.6 Public Shade Trees

The Salem Harbor Substation is located entirely on private property at the existing generating

facility and there are no public shade trees in the vicinity of the substation. There will be no

construction-related or long-term impacts to public shade trees at this substation location.

5.9.1.7 Potential to Encounter Subsurface Contamination

The Salem Harbor Substation is identified on the DEP Site List for releases attributable to #2 oil,

#6 oil, hydraulic oil, cable oil, polycyclic aromatic hydrocarbons, and heavy metals. These listings

are indicated as having various RAOs associated with them except for one, for which the

notification date is identified as January 2013.

Handling of contaminated materials, should they be encountered, is discussed in Section 5.5.6.2.

5.9.1.8 Air Quality/Dust Control

The potential for fugitive dust and for emissions from equipment resulting from construction

activities at the Salem Harbor and Canal Street Substations will be mitigated as discussed in

Section 5.5.7.4.

5.9.1.9 SF6-Insulated Switches at Salem Harbor Substation

SF6 gas will be used as an insulating medium for the four new 3000A, 63-kiloampere SF6 gas

circuit breakers that will be installed at the Salem Harbor Substation to replace four existing oil-

filled circuit breakers. The four new breakers will use a total of 340 pounds of SF6 gas. This

represents approximately 0.003 percent of National Grid’s Massachusetts nameplate capacity



of approximately 106,014 pounds of SF6. The equipment will be warrantied to have an SF6

emissions rate of less than 0.5% per year, and will be factory-tested prior to delivery.19

The SF6 pressure in the circuit breakers will be recorded as part of regular (monthly or bi-

monthly) substation equipment inspections; the pressure checks will serve as a redundant

method of leak detection should a low-SF6-pressure alarm fail to be initiated. The procurement

of breakers with extremely low emissions rates, combined with factor and field tests and

regular substation equipment inspections, minimizes potential SF6 emissions at Salem Harbor

Substation.

More generally, National Grid has implemented measures to quantify and to reduce its system-

wide SF6 emissions, with a focus on repairing or replacing its worst-performing pieces of SF6-

insulated equipment. National Grid calculates its system-wide SF6 emissions in accordance

with the Federal Mandatory Reporting Rule (40 CFR Part 98.300 Subpart DD (December 1,

2010)). The rule prescribes a “mass balance” approach to calculating annual SF6 emissions

based on year-to-year changes in the Company’s SF6 inventory, including SF6 purchased, added

to equipment, removed from equipment, and stored for future use. Using this approach,

National Grid estimated its system-wide calendar year 2012 SF6 emissions at 3,435 pounds, for

a leakage rate of 2.2 percent.

National Grid has established corporate goals for identifying and remediating the worst-

performing circuit breakers across its system. National Grid’s fiscal year 2013 (April 1, 2012–

March 31, 2013) goal was to identify the top 25 leaking circuit breakers on its system and to

repair or replace twelve of these circuit breakers. As of March 21, 2013, National Grid had

established the list and repaired or replaced twelve circuit breakers, thus meeting its goal.

National Grid also has established classroom and on-the-job training programs to ensure that

substation maintenance personnel are trained in the proper handling of SF6. Employees also

receive SF6 training after the installation of a major SF6-insulated substation. In 2012, substation

maintenance employees received basic SF6 training as part of their annual refresher training.

5.9.1.10 Historic and Archaeological Sites

The Salem Harbor Substation is not located within any National or Local Historic Districts or

any Inventoried Areas. There are no Individually Inventoried properties abutting this substation,

and no archaeological sites are known at this site.

19 The DEP is proposing a new regulation to control emissions of SF6 from gas-insulated switchgear (“(GIS”).). The regulation, 310 CMR 7.72: Reducing Sulfur Hexafluoride Emissions from Gas-Insulated Switchgear, would limit all companies that purchase new GIS to a 1% emission rate for such equipment. The leakage rate anticipated on the proposed switchgear will be warrantied to be well below 1% and would comply with the new regulation.



5.9.2 Canal Street Substation

5.9.2.1 Scope of Proposed Improvements

At the Canal Street Substation, all existing electrical equipment, support structures, and

foundations will be removed with the exception of the existing steel lattice transmission

structures that will remain in place and will be repainted. The removed equipment will include

underground cable terminations, surge arresters, rigid copper conductor, aluminum conductor,

wave traps, voltage transformers, current transformers, disconnect switches, dielectric fluid

reservoirs, outdoor relay and communication cabinets, and a small building that contains

service power equipment and a telephone.

New electrical equipment, support structures, and foundations will be installed at the substation.

This includes similar components as the ones that were removed, but without the rigid copper

conductor, dielectric fluid reservoirs, and outdoor relay and communication cabinets. A new

control building will be installed that will house new relay, control, and communication

equipment.

The site will be graded to allow for the installation of the new equipment, and the existing

retaining wall at the rear of the property will be replaced in kind with some minor improve-

ments. New landscaping features will be installed to allow for visual screening of the electrical

equipment, and a new perimeter fence will be installed around the property. Figure 5-10 shows

the proposed planting plan for the Canal Street Substation, and the proposed development plan

is provided in Appendix 5-5. In parallel, NEP will be seeking a special permit from the local

Zoning Board of Appeals as well as a grant of required zoning exemptions from the DPU.

5.9.2.2 Land Use

Land uses adjacent to the existing Canal Street Substation include commercial and industrial

uses to the north and west, and residential neighborhoods to the east and south. The proposed

upgrades at the Canal Street Substation will include replacement of existing equipment,

installation of a new control house, improvements to an existing timber retaining wall, grading,

and installation of a new fence. There will be no significant expansion of this facility and as

such there will be no long-term impacts to surrounding land uses.

5.9.2.3 Visual Impact

The Canal Street Substation is located in an area of mixed use with industrial/commercial

properties to the west and north and residences located to the east and south. Public utility use

at the Property dates back to 1951. Proposed changes at the site associated with the Project are

shown in Appendix 5-5 and on Figure 5-10. These changes include the removal of outdated

equipment, installation of new electrical equipment, and construction of a new control house.

No change in the footprint of the existing substation yard will be required and the kind, size,



height, and nature of the new control house and electrical equipment are consistent with the

existing equipment. The dominant visual features of the site, the two termination structures

bringing the overhead line in from the west, will remain unchanged. The site elevations will

remain the same but will be graded (including areas adjacent to the existing yard and extending

south into the currently vacant area fronting Cypress Street) and surfaced with crushed stone.

The existing timber retaining wall located on the eastern edge of the property will be replaced

with a new retaining wall. The chain-link perimeter fence will be replaced in the same location

and will match the existing height.

Replacement of the fence will require the removal of trees and shrubs that screen views into the

property. A landscape plan was developed to both to screen views of the electrical equipment

and improve the appearance of the Canal Street property, particularly from the vantage point of

residences located at the end of Cedar Street and on Cypress Street. Plantings include a mix of

deciduous and evergreen shrubs and trees such as maple, dogwood, cedar, crabapple,

arborvitae, forsythia, inkberry, juniper, sumac and yew. The proposed landscaping plan is

provided as Figure 5-10.

5.9.2.4 Noise

Land uses adjacent to the existing Canal Street Substation include an auto-repair shop to the

north, the MBTA railroad to the west, and residential neighborhoods to the east and south.

There are 37 residences within 300 feet of the substation, with the closest residences located on

Cypress Street to the south (two abutting residences will be 45 feet and 37 feet from the

footprint of the updated substation) and on Cedar Street and Cedar Street Court to the east (two

abutting residences will be 20 feet and 48 feet from the footprint of the updated substation).

Work at the Canal Street substation includes demolition and removal of old equipment;

removal of vegetation, grading and site preparation; installation of new electrical equipment,

support structures, and foundations; and landscaping. The proposed upgrades at the Canal

Street Substation will not include equipment that will result in a permanent increase in

operational noise levels over existing conditions. However, the planned improvements at the

substation are anticipated to take approximately 18 months, during which time nearby residents

may be impacted by elevated noise levels associated with a construction site (for example,

heavy construction vehicles such as delivery trucks, dump trucks, bulldozers and cranes).

The Company recognizes this and will mitigate the impacts to the extent reasonable. Proposed

mitigation with respect to construction noise impacts at the Canal Street Substation includes:

· Requiring well-maintained equipment with functioning mufflers;

· Strict compliance with DEP’s Anti-Equipment Idling regulations to prevent equipment

from idling and producing unnecessary noise while not in productive use;

· Operating stationary noise generating equipment, such as whole tree chippers or

compressors, away from nearby residences, where the flexibility to do so exists;



· The Company will provide all of its construction contractors with training that highlights

the Company’s requirements with respect to well-maintained equipment, anti-idling and

other relevant policies;

· The Company’s Stakeholder Relations team will provide regular project updates via the

project website at www.salemcableproject.com. These regular updates will include

locations and types of work planned for the following two weeks. These communications

will promote a well-informed public and help the Company manage expectations relative to

construction activity and potential noise impacts; and

· The Company will maintain a direct line to a Stakeholder Representative during the

duration of the Project to provide abutters with a quick and easy means for raising any

specific concerns or questions.

5.9.2.5 Traffic

This substation is located along Canal Street, which experiences moderate traffic volume.

Traffic impacts associated with the Project will be temporary in nature. A variety of mitigation

measures as outlined in Section 5.5.4.4 will be used to minimize traffic disruption to the

surrounding roadways during construction of this substation, and NEP will work to integrate

construction activities with Footprint, Spectra, and other construction projects in Salem.

5.9.2.6 Public Shade Trees

The Canal Street Substation is located entirely on private property owned by NEP. There are

five public shade trees in the public way (sidewalk) in front of this substation; however, there

are no activities proposed in their immediate vicinity. There will be no construction-related or

long-term impacts to public shade trees at this substation location.

5.9.2.7 Potential to Encounter Subsurface Contamination

Three DEP Site Listings appear to be associated with releases at the Canal Street Substation.

These releases are associated with petroleum-based constituents, primarily mineral oil dielectric

fluid. The listings are indicated as having various RAOs associated with them and are

considered closed by the DEP.

Handling of contaminated materials, should they be encountered, is discussed in Section

5.5.6.2.

5.9.2.8 Air Quality/Dust Control

The potential for fugitive dust and for emissions from equipment resulting from construction

activities at the Salem Harbor and Canal Street Substations will be mitigated as discussed in

Section 5.5.7.4.



5.9.2.9 Historic and Archaeological Sites

The Canal Street Substation is not located within any National or Local Historic Districts or any

Inventoried Areas. There are no Individually Inventoried properties abutting this substation, and

no archaeological sites are known at this site.

5.10 CABLE REMOVAL

This Section discusses the removal of the existing Cables and the associated impacts and

proposed mitigation measures.

5.10.1 Construction Methods

5.10.1.1 Removal of Old S Cable

Once the new S cable has been installed and is ready for service, the existing S cable will be de-

energized and cable removal activities will commence as coordinated with the City.

The first activity will be to purge the cable cores with water to remove as much dielectric fluid as

practical from the cables. This will be accomplished by connecting a water supply and pump at

one end of the hydraulic system to flush water down the cable cores, and a tanker truck at the far

end of the system to capture the dielectric fluid and water. The total amount of freestanding

dielectric fluid in the cable cores will be calculated and the amount pumped out of the cable will

be measured to determine when the majority of dielectric fluid has been removed from the cable

in preparation for disposal transport. It is anticipated that the amount of water pumped through the

cable cores will be at a minimum two times the volume of the dielectric fluid contained in the

cores. The removed dielectric fluid and water will be trucked off-site for proper disposal.

Once the dielectric fluid has been flushed from the cable core, excavation to remove the cable

can commence. The trench will generally be excavated using a mechanical excavator except in

areas where excavation must be done by less intrusive means (vacuum loader and/or hand

tools) to avoid disturbing existing utility lines and/or service connections. As with excavation of

soils for the new line, excavation of the S cable will use a clean trench method where soil are

loaded directly into trucks and transported to an off-site stockpile area. As needed, suitable soils

will be used to backfill the excavation. Any excess soil will be tested and disposed of properly.

Soil derived from areas of known contamination will be removed from the site for appropriate

testing and disposal. Contaminated materials will be handled under the URAM or RAM

provisions of 310 CMR 40.0000, the MCP (see Section 5.5.6.2).

The trench will be shored as required by soil conditions and OSHA construction requirements.

The shoring is designed to permit the passage of traffic adjacent to and atop the trench via steel

plating during non-working hours.



The trench will be lined with polyethylene sheeting and absorbent textiles to contain the release

of any residual dielectric fluid or water from the cable. Once the cable has been exposed, it will

be cut into manageable lengths, removed from the trench, placed into lined roll-off containers

and shipped off-site for recycling and/or disposal.

It is anticipated that excavation, shoring, and cable removal will proceed at roughly 100 feet to

400 feet per day. The cable removal activities will take two to five days to complete in front of

any particular business or residence. Factors that may affect the removal duration include

existing utility density, trench depth, and traffic volume. The removal of the old S Cable is

anticipated to take approximately two months to complete.

NEP will develop and implement appropriate BMPs for the control of erosion and sedimenta-

tion from the work site during excavation activities associated with the cable removal. Regular

inspections will be undertaken to ensure that control mechanisms are maintained. In any area

where dewatering is required or stormwater is directed to a local storm drain, NEP will install

and maintain sedimentation devices such as filter fabric barriers to prevent sediment from

entering the storm drain system. When construction is complete at each location, the filter

fabric will be removed from the storm drain. In the event that the ground water is impacted by

contaminated soils, it will be disposed of as necessary to prevent introduction into the storm

drain system. Excavated soil will be loaded directly into trucks and transported to an off-site

stockpile area. This will limit the potential for soils to migrate off-site and into the municipal

storm drain system.

During the trenching and cable removal activities, NEP will make every effort to maintain

access to adjacent residences and businesses. At various points in this process it will be

necessary to have an open trench which may temporarily impede access; however, once the

crews are finished the trench will be plated with DOT-approved traffic-grade steel to re-

establish access to nearby homes and commercial buildings. At the end of each work day, the

cable ends will be plugged or sealed to prevent potential migration of residual dielectric fluid

from the cable. Once removal activities are complete, temporary pavement will be installed to

restore the road to original grade until final pavement restoration activities commence.

Final repaving will include a mill and overlay with bituminous concrete (asphalt) to the limits

agreed upon with the DPW and MassDOT. A leveling course will be provided at driveways as

needed to meet the new road surface elevation.

Sidewalk restorations with pavers or concrete, depending on existing materials, will comply

with all requirements of the DPW, MassDOT, and D.T.E. 98-22.

At Salem Harbor Substation and Canal Street Substation, fluid reservoirs, cable terminations,

and other auxiliary equipment will be drained and removed for proper disposal.



5.10.1.2 Removal of Old T Cable

Once the new T cable has been installed and is ready for service, the existing T cable will be

de-energized and cable removal activities will commence as coordinated with the City.

As with the old S cable, the first activity will be to purge the cable cores with water to remove

as much dielectric fluid as practical from the cables, using the techniques described above for

the old S cable. Once the dielectric fluid has been removed from the core, the cables will be

removed by cutting the cables at adjacent manhole locations and pulling the cable from the duct

onto cable reels. The removed cables will have their ends sealed to prevent the release of any

residual dielectric fluid and will be transported off-site for recycling or proper disposal.

The need for excavation is not anticipated for the removal of the existing T cable; however, in

the event that pulling is significantly obstructed, localized excavation may be required to free

the cable. The removal of the existing T cable is anticipated to take approximately one month to

complete.

At Salem Harbor Substation and Canal Street Substation, fluid reservoirs, cable terminations,

and other auxiliary equipment will be drained and removed for proper disposal.

5.10.1.3 Human and Environmental Impacts

The existing cables traverse through the Salem Generating Facility property and west down

Derby Street, where they travel adjacent to the Salem Harbor Substation (commer-

cial/industrial) on the south side of the street and residential neighborhoods and David J. Beattie

Park on the north side. As they follow Derby Street to the west, land uses transition into mixed

commercial/residential, and they pass the House of Seven Gables and the Salem Maritime

National Historic Site. Continuing along Derby Street and past the intersection with Congress

Street and the Old Burying Ground Cemetery, land uses along the T cable route transition from

mixed commercial/residential along Lafayette Street to mostly residential along Cedar Street,

while land uses along the S cable route transition from mixed commercial/residential into

primarily commercial/industrial along Canal Street.

A large portion of these cable routes is located on roadways that host moderate to high traffic

volumes and that provide access to a mix of residences, businesses, and tourist destinations.

Some of these streets are used as part of public bus, trolley and motor coach routes, and provide

access to public parking lots and the commuter ferry service to Boston.

Impacts from construction activities associated with the removal of the existing cables will be

similar to those anticipated for the installation of the new replacement Cables. There will be no

permanent noise, dust, emissions, or visual impacts associated with the removal of the existing

cables. All potential impacts will be temporary and limited to the construction period.



5.10.1.4 Mitigation

All construction activities will be conducted in a manner that minimizes potential impacts to

abutting land uses. Mitigation measures will be similar to those specified for the installation of

the new replacement Cables (refer to Section 5.4.1 (excavation activities), Section 5.5.4 (traffic

control and management), Section 5.5.5 (noise control), and Section 5.5.7 (dust/air quality)).

5.11 OVERALL PROJECT COST

In addition to the detailed cost estimates developed for installation of the new cables along the

Preferred Route, NEP also developed detailed estimates for the proposed substation

improvements and for the removal of both of the existing Cables with the assumption that they

will be independent activities.

As discussed above, the cost estimates provided herein are classified as conceptual grade

estimates, indicating that key project elements have been identified, but a limited amount of

detailed engineering has been completed. Conceptual grade estimates are based on recent costs

of similar materials and construction activities, have an accuracy of -25% to +50%, and do not

consider possible future variances in commodity or labor costs. The factors that affect the

overall cost of an underground project, and NEP’s estimation methods, are discussed in more

detail in Section 4.5.4.

The cost of the new cable on the Preferred Route was identified in Section 5.7 ($33.40 million).

Additional components of the Project that will be incurred regardless of which route is chosen

include the following:

· S Cable removal: $5.37

· T Cable removal: $0.58

· Substation improvements: $12.27

· Project administration and development costs: $10.81 million.



Table 5-17: Total Anticipated Project Cost (in 2013 dollars)

Cost

(millions)

Construction Cost

Preferred Route $33.40

S Cable Removal $5.37

T Cable Removal $0.58

Substation Improvements $12.27

Project Administration and Development $10.81

Total Project Cost (2013 dollars) $62.43

Total Project Cost (future dollars)* $63.84

* Assuming 2% annual inflation rate based on anticipated timing of expenditures

Including these additional components, the conceptual grade estimate for the total Project is

$62.43 million in 2013 dollars or $63.84 in future dollars based on anticipated timing of

expenditures, assuming an annual inflation rate of two percent.

5.12 CONCLUSION

NEP determined that the Preferred Route is superior to the Noticed Alternative in terms of its

potential for environmental impacts. The Preferred Route also has a slight advantage in terms

of cost. Reliability of the routes was determined to be equal. Accordingly, NEP concluded that

use of the Preferred Route will best achieve the Siting Board’s statutory criteria of reliability,

minimum cost and least environmental impact.

In addition, NEP has committed to a broad range of measures to mitigate the temporary and

permanent impacts of the Project, including the installation of the replacement cables, work at

the Salem Harbor and Canal Street substations, and the removal of the existing Cables. With

the implementation of these mitigation measures, the impacts of the Project will be minimized

consistent with considerations of cost.

Section 6.0: Consistency with the Current Health, Environmental Protection, and Resource Use and Development Policies of The Commonwealth


6.0 CONSISTENCY WITH THE CURRENT HEALTH,

ENVIRONMENTAL PROTECTION, AND RESOURCE USE AND

DEVELOPMENT POLICIES OF THE COMMONWEALTH

6.1 INTRODUCTION

Pursuant to G.L. c. 164, § 69J, the Siting Board shall approve a petition to construct a facility if,

inter alia, the Siting Board determines that “plans for expansion and construction of the

applicant’s new facilities are consistent with current health, environmental protection, and

resource use and development polices as adopted by the commonwealth.” As discussed below,

and in more detail throughout the Analysis, the Project not only satisfies the requirements of

this statute, but also is fully consistent with other important state energy policies as articulated

in the Electric Utility Restructuring Act of 1997 (the “Restructuring Act”) and the more recent

Green Communities Act (c. 169 of the Acts of 2008) and Global Warming Solutions Act

(c. 298 of the Acts of 2008).

6.2 HEALTH POLICIES

The Restructuring Act provides that reliable electric service is of “utmost importance to the

safety, health, and welfare of the Commonwealth’s citizens and economy . . . .” See

Restructuring Act, § 1(h). The Legislature has expressly determined that an adequate and

reliable supply of energy is critical to the state’s citizens and economy. G.L. c. 164, § 69J. The

Project will be fully consistent with this policy. The Project will enhance system reliability at

low cost, thereby enhancing the safety, health, and welfare of the Commonwealth’s citizens and

economy. The Project will enhance the reliability of the interconnected electric transmission

system in the Salem area enabling NEP to continue to ensure the availability of sufficient and

reliable electric service to the citizens and businesses of the Commonwealth and the region.

As discussed in Section 5, all design, construction and operation activities will be in accordance

with applicable governmental and industry standards such as the National Electric Safety Code

and Occupational Safety and Health Administration regulations, and will have no adverse

health effects. In addition, since the Project will be consistent with, and promote, the

Commonwealth’s energy polices as outlined in the Restructuring Act, it will also be consistent

with its health policies. The Restructuring Act provides that, “since reliable electric service is of

the utmost importance to the safety, health and welfare of the Commonwealth’s citizens and

economy, electric industry restructuring should enhance the reliability of the interconnected

regional transmission system . . . .” See Restructuring Act, § 1(h).



6.3 THE RESTRUCTURING ACT

The Restructuring Act provides that NEP must demonstrate that the Project minimizes

environmental impacts consistent with the minimization of costs associated with the mitigation,

control, and reduction of the environmental impacts of the Project. Accordingly, an assessment

of all impacts of a proposed facility is necessary to determine whether an appropriate balance is

achieved both among conflicting environmental concerns, as well as among environmental

impacts, costs, and reliability. Sections 4 and 5 provide a comprehensive description of NEP’s

satisfaction of these requirements with respect to the Project. As fully demonstrated in Section

5 and throughout this Analysis, the Project has proposed specific plans to mitigate environmen-

tal impacts associated with the construction, operation, and maintenance of the proposed

transmission line, consistent with cost minimization. In addition, consistent with the

Restructuring Act, the Project will ensure the efficient operation of the wholesale generation

market by facilitating the interconnection of a proposed new generation resource, the Footprint

generating facility. As such, the Project is consistent with the policies of the Commonwealth as

set forth in the Restructuring Act.

6.4 THE GREEN COMMUNITIES ACT

On July 2, 2008, Massachusetts Governor Deval Patrick signed into law the Green Communi-

ties Act. The Green Communities Act is a comprehensive, multi-faceted energy reform bill that

encourages energy and building efficiency, promotes renewable energy, creates green

communities, implements elements of the Regional Greenhouse Gas Initiative, and provides

market incentives and funding for various types of energy generation. The Green Communities

Act (as amended and supplemented by St. 2012, c. 209, An Act Relative to Competitively

Priced Electricity) can be expected to result in greater renewable supplies and substantial new

conservation initiatives in future years. The improvements to the transmission system in the

greater Salem area will further the goals of the Green Communities Act by facilitating

alternative energy and by assuring the reliable efficient dispatch of affected generation. The

Project, therefore, advances the important policy objectives of the Green Communities Act.

6.5 THE GLOBAL WARMING SOLUTIONS ACT

On August 7, 2008, Governor Patrick signed into law the Global Warming Solutions Act

(“GWSA”). The GWSA established aggressive greenhouse gas (“GHG”) emissions reduction

targets of 25% from 1990 levels by 2020 and 80% from 1990 levels by 2050. Pursuant to the

GWSA, the Secretary of EOEEA issued the Clean Energy & Climate Plan for 2020 in

December of 2010. Among other provisions, the GWSA obligates administrative agencies such

as the Siting Board, in considering and issuing permits, to consider reasonably foreseeable

climate change impacts (e.g., additional GHG emissions) and related effects (e.g., sea level

rise). The improvements to the transmission system in the greater Salem area will have no



adverse climate change impacts or negative effects on sea levels. Consequently, the Project is

consistent with the GWSA.

6.6 STATE AND LOCAL ENVIRONMENTAL POLICIES

The Project will be constructed and operated to comply fully with all relevant state and local

environmental policies. As set forth in Section 5 and elsewhere, in addition to seeking approval

from the Siting Board, the Company will obtain all applicable state and local environmental

approvals and permits for the Project pursuant to the authority of EOEEA, DEP, and other state

and local agencies. The likely permits that the Company will need to secure in connection with

the Project are summarized in Tables 6-1, 6-2 and 6-3 below. By meeting the requirements for

acquiring each of these state and local permits, the Project will be in compliance with

applicable state and local environmental policies.

6.7 RESOURCE USE AND DEVELOPMENT POLICIES

The Project will be constructed and operated in compliance with Massachusetts’ policies

regarding resource use and development. Specifically, the Project will enhance the

reliability of the interconnected electric transmission system in the greater Salem area. For

example, in 2007, pursuant to the Commonwealth’s Smart Growth/Smart Energy policy

produced by EOEEA, Governor Patrick established Sustainable Development Principles,

including: (1) supporting the revitalization of city centers and neighborhoods by promoting

development that is compact, conserves land, protects historic resources, and integrates

uses; (2) encouraging reuse of existing sites, structures and infrastructure; and

(3) protecting environmentally sensitive lands, natural resources, critical habitats, wetlands

and water resources and cultural and historic landscapes. As described in Section 5, the

Project will support these principles because, among other reasons, the Project will reuse

existing sites, support the revitalization of the greater Salem area and will not adversely

impact environmentally sensitive lands. Accordingly, the Project is in compliance with and

furthers the Commonwealth’s policies regarding resource use and development.

Table 6-1: Federal Permit/Consultation Requirements

Regulatory Agency Program & Permit Jurisdiction

USEPA NPDES General Permit for Storm Water Discharges from Construction Activities

Land disturbance greater than one acre



Table 6-2: State Permit/Consultation Requirements


DEP · Request for Minor Project Modification pursuant to Chapter 91 Waterways Regulations

Work in, on, above or below Massachusetts tidelands, great ponds and non-tidal rivers and streams in accordance with the public trust doctrine.

MHC · G.L. c. 9, § 27C, determination of effect on historic and archaeological properties

· Massachusetts Antiquities Act

Historic and prehistoric cultural resources

DPU · G.L. c. 164, § 72, approval to construct new transmission line

· G.L. c. 40A, § 3, grant of required zoning exemptions

All inclusive, approval of transmission lines. Issuance of required zoning exemptions from the City of Salem Zoning Ordinance

Table 6-3: Local Permit Requirements


Salem Conservation Commission · Massachusetts Wetlands Protection Act

· Salem Wetlands Protection and Conservation Ordinance

Wetlands

Salem Zoning Board of Appeals · Salem Zoning Ordinance Activities triggering review under City Zoning Bylaws1

Salem Planning Board · Special Permit for Work Within Wetlands and Flood Hazard Overlay District

Activities triggering review under City Bylaws

Salem City Council · Grants of Location Work in City public ways

1 As described in Section 1 of the Analysis, the Company is seeking zoning relief, as necessary, in parallel with the City of

sSalem and with the DPU, as part of its consolidated petitions to the Siting Board and the DPU concerning the Project.

Appendix 2-1

Existing Ratings of

S and T Cables and

S-145E and T-145E Lines

The appendix material has been redacted for Critical

Energy Infrastructure Information (CEII).

Appendix 2-2

Standard Large Generator

Interconnection Procedures

(“LGIP”)

SCHEDULE 22

LARGE GENERATOR INTERCONNECTION PROCEDURES

TABLE OF CONTENTS

SECTION 1. DEFINITIONS

SECTION 2. SCOPE, APPLICATION AND TIME REQUIREMENTS.

2.1 Application of Standard Large Generator Interconnection Procedures.

2.2 Comparability

2.3 Base Case Data

2.4 No Applicability to Transmission Service

2.5 Time Requirements

SECTION 3. INTERCONNECTION REQUESTS

3.1 General

3.2 Type of Interconnection Services and Long Lead Time Generating Facility Treatment

3.3 Valid Interconnection Request

3.4 OASIS Posting

3.5 Coordination with Affected Systems

3.6 Withdrawal

SECTION 4. QUEUE POSITION

4.1 General

4.2 Clustering

4.3 Transferability of Queue Position

4.4 Modifications

SECTION 5. PROCEDURES FOR TRANSITION

5.1 Queue Position for Pending Requests

5.2 Grandfathering

5.3 New System Operator or Interconnecting Transmission Owner

SECTION 6. INTERCONNECTION FEASIBILITY STUDY

6.1 Interconnection Feasibility Study Agreement

6.2 Scope of Interconnection Feasibility Study

6.3 Interconnection Feasibility Study Procedures

6.4 Re-Study

SECTION 7. INTERCONNECTION SYSTEM IMPACT STUDY

7.1 Interconnection System Impact Study Agreement

7.2 Execution of Interconnection System Impact Study Agreement

7.3 Scope of Interconnection System Impact Study

7.4 Interconnection System Impact Study Procedures

7.5 Meeting with Parties

7.6 Re-Study

7.7 Operational Readiness

SECTION 8. INTERCONNECTION FACILITIES STUDY

8.1 Interconnection Facilities Study Agreement

8.2 Scope of Interconnection Facilities Study

8.3 Interconnection Facilities Study Procedures


8.5 Re-Study

SECTION 9. ENGINEERING & PROCUREMENT (“E&P”) AGREEMENT

SECTION 10. OPTIONAL INTERCONNECTION STUDY

10.1 Optional Interconnection Study Agreement

10.2 Scope of Optional Interconnection Study

10.3 Optional Interconnection Study Procedures


10.5 Interconnection Agreement Developed Based on Optional Interconnection Study

SECTION 11. STANDARD LARGE GENERATOR INTERCONNECTION AGREEMENT (LGIA)

11.1 Tender

11.2 Negotiation

11.3 Evidence to be Provided by Interconnection Customer; Execution and Filing of LGIA

11.4 Commencement of Interconnection Activities

SECTION 12. CONSTRUCTION OF INTERCONNECTING TRANSMISSION OWNER

INTERCONNECTION FACILITIES AND NETWORK UPGRADES

12.1 Schedule

12.2 Construction Sequencing

SECTION 13. MISCELLANEOUS

13.1 Confidentiality

13.2 Delegation of Responsibility

13.3 Obligation for Study Costs

13.4 Third Parties Conducting Studies

13.5 Disputes

13.6 Local Furnishing Bonds

APPENDICES TO LGIP

APPENDIX 1 INTERCONNECTION REQUEST

APPENDIX 2 INTERCONNECTION FEASIBILITY STUDY AGREEMENT

APPENDIX 3 INTERCONNECTION SYSTEM IMPACT STUDY AGREEMENT

APPENDIX 4 INTERCONNECTION FACILITIES STUDY AGREEMENT

APPENDIX 5 OPTIONAL INTERCONNECTION STUDY AGREEMENT

APPENDIX 6 LARGE GENERATOR INTERCONNECTION AGREEMENT

APPENDIX 7 INTERCONNECTION PROCEDURES FOR WIND GENERATION

SECTION I. DEFINITIONS

The definitions contained in this section are intended to apply in the context of the generator

interconnection process provided for in this Schedule 22 (and its appendices). To the extent that the

definitions herein are different than those contained in Section I.2.2 of the Tariff, the definitions provided

below shall control only for purposes of generator interconnections under this Schedule 22. Capitalized

terms in Schedule 22 that are not defined in this Section I shall have the meanings specified in Section

I.2.2 of the Tariff.

Administered Transmission System shall mean the PTF, the Non-PTF, and distribution facilities that

are subject to the Tariff.

Adverse System Impact shall mean any significant negative effects on the stability, reliability or

operating characteristics of the electric system.

Affected System shall mean any electric system that is within the Control Area, including, but not limited

to, generator owned transmission facilities, or any other electric system that is not within the Control Area

that may be affected by the proposed interconnection.

Affected Party shall mean the entity that owns, operates or controls an Affected System, or any other

entity that otherwise may be a necessary party to the interconnection process.

Affiliate shall mean, with respect to a corporation, partnership or other entity, each such other

corporation, partnership or other entity that directly or indirectly, through one or more intermediaries,

controls, is controlled by, or is under common control with, such corporation, partnership or other entity.

Applicable Laws and Regulations shall mean all duly promulgated applicable federal, state and local

laws, regulations, rules, ordinances, codes, decrees, judgments, directives, or judicial or administrative

orders, permits and other duly authorized actions of any Governmental Authority.

Applicable Reliability Council shall mean the reliability council applicable to the New England

Transmission System.

Applicable Reliability Standards shall mean the requirements and guidelines of NERC, the NPCC and

the New England Control Area, including publicly available local reliability requirements of

Interconnecting Transmission Owners or other Affected Parties.

At-Risk Expenditure shall mean money expended for the development of the Generating Facility that

cannot be recouped if the Interconnection Customer were to withdraw the Interconnection Request for the

Generating Facility. At-Risk Expenditure may include, but is not limited to, money expended on: (i)

costs of federal, state, local, regional and town permits, (ii) Site Control, (iii) site-specific design and

surveys, (iv) construction activities, and (v) non-refundable deposits for major equipment components.

For purposes of this definition, At-Risk Expenditure shall not include costs associated with the

Interconnection Studies.

Base Case shall have the meaning specified in Section 2.3.

Base Case Data shall mean the Base Case power flow, short circuit, and stability data bases used for the

Interconnection Studies by the System Operator, Interconnection Customer, Interconnecting Transmission

Owner, or any Affected Party as deemed appropriate by the System Operator in accordance with

applicable codes of conduct and confidentiality requirements.

Breach shall mean the failure of a Party to perform or observe any material term or condition of the

Standard Large Generator Interconnection Agreement.

Breaching Party shall mean a Party that is in Breach of the Standard Large Generator Interconnection

Agreement.

Calendar Day shall mean any day including Saturday, Sunday or a Federal Holiday.

Capacity Capability Interconnection Standard (“CC Interconnection Standard”) shall mean the

criteria required to permit the Interconnection Customer to interconnect in a manner that avoids any

significant adverse effect on the reliability, stability, and operability of the New England Transmission

System, including protecting against the degradation of transfer capability for interfaces affected by the

Generating Facility, and in a manner that ensures intra-zonal deliverability by avoidance of the redispatch

of other Capacity Network Resources, as detailed in the ISO New England Planning Procedures.

Capacity Network Resource (“CNR”) shall mean that portion of a Generating Facility that is

interconnected to the Administered Transmission System under the Capacity Capability Interconnection

Standard.

Capacity Network Resource Capability (“CNR Capability”) shall mean: (i) in the case of a

Generating Facility that is a New Generating Capacity Resource pursuant to Section III.13.1 of the Tariff

or an Existing Generating Capacity Resource that is increasing its capability pursuant to Section

III.13.1.2.2.5 of the Tariff, the highest megawatt amount of the Capacity Supply Obligation obtained by

the Generating Facility in accordance with Section III.13 of the Tariff, and, if applicable, as specified in a

filing by the System Operator with the Commission in accordance with Section III.13.8.2 of the Tariff, or

(ii) in the case of a Generating Facility that meets the criteria under Section 5.2.3 of this LGIP, the total

megawatt amount determined pursuant to the hierarchy established in Section 5.2.3. The CNR Capability

shall not exceed the maximum net megawatt electrical output of the Generating Facility at the Point of

Interconnection at an ambient temperature at or above 90 degrees F for Summer and at or above 20

degrees F for Winter. Where the Generating Facility includes multiple production devices, the CNR

Capability shall not exceed the aggregate maximum net megawatt electrical output of the Generating

Facility at the Point of Interconnection at an ambient temperature at or above 90 degrees F for Summer

and at or above 20 degrees F for Winter.

Capacity Network Resource Group Study (“CNR Group Study”) shall mean the study performed by

the System Operator under Section III.13.1.1.2.3 of the Tariff to determine which resources qualify to

participate in a Forward Capacity Auction.

Capacity Network Resource Interconnection Service (“CNR Interconnection Service”) shall mean

the Interconnection Service selected by the Interconnection Customer to interconnect its Large Generating

Facility with the Administered Transmission System in accordance with the Capacity Capability

Interconnection Standard. An Interconnection Customer’s CNR Interconnection Service shall be for the

megawatt amount of CNR Capability. CNR Interconnection Service does not in and of itself convey

transmission service.

Clustering shall mean the process whereby a group of Interconnection Requests is studied together for

the purpose of conducting the Interconnection System Impact Study.

Commercial Operation shall mean the status of a Generating Facility that has commenced generating

electricity for sale, excluding electricity generated during Trial Operation.

Commercial Operation Date of a unit shall mean the date on which the Generating Facility commences

Commercial Operation as agreed to by the Parties pursuant to Appendix E to the Standard Large

Generator Interconnection Agreement.

Confidential Information shall mean any confidential, proprietary or trade secret information of a plan,

specification, pattern, procedure, design, device, list, concept, policy or compilation relating to the present

or planned business of a Party, which is designated as confidential by the Party supplying the information,

whether conveyed orally, electronically, in writing, through inspection, or otherwise. Confidential

Information shall include, but not be limited to, information that is confidential pursuant to the ISO New

England Information Policy.

Default shall mean the failure of a Breaching Party to cure its Breach in accordance with Article 17 of the

Standard Large Generator Interconnection Agreement.

Dispute Resolution shall mean the procedure for resolution of a dispute between the Parties in which

they will first attempt to resolve the dispute on an informal basis.

Distribution System shall mean the Interconnecting Transmission Owner’s facilities and equipment used

to transmit electricity to ultimate usage points such as homes and industries directly from nearby

generators or from interchanges with higher voltage transmission networks which transport bulk power

over longer distances. The voltage levels at which distribution systems operate differ among areas.

Distribution Upgrades shall mean the additions, modifications, and upgrades to the Interconnecting

Transmission Owner’s Distribution System at or beyond the Point of Interconnection to facilitate

interconnection of the Generating Facility and render the transmission service necessary to effect

Interconnection Customer’s wholesale sale of electricity in interstate commerce. Distribution Upgrades

do not include Interconnection Facilities.

Effective Date shall mean the date on which the Standard Large Generator Interconnection Agreement

becomes effective upon execution by the Parties subject to acceptance by the Commission or if filed

unexecuted, upon the date specified by the Commission.

Emergency Condition shall mean a condition or situation: (1) that in the judgment of the Party making

the claim is likely to endanger life or property; or (2) that, in the case of the Interconnecting Transmission

Owner, is likely (as determined in a non-discriminatory manner) to cause a material adverse effect on the

security of, or damage to the New England Transmission System, Interconnecting Transmission Owner’s

Interconnection Facilities or any Affected System to which the New England Transmission System is

directly connected; or (3) that, in the case of Interconnection Customer, is likely (as determined in a non-

discriminatory manner) to cause a material adverse effect on the security of, or damage to, the Generating

Facility or Interconnection Customer’s Interconnection Facilities. System restoration and black start shall

be considered Emergency Conditions; provided that Interconnection Customer is not obligated by the

Standard Large Generator Interconnection Agreement to possess black start capability.

Engineering & Procurement (“E&P”) Agreement shall mean an agreement that authorizes the

Interconnection Customer, Interconnecting Transmission Owner and any other Affected Party to begin

engineering and procurement of long lead-time items necessary for the establishment of the

interconnection in order to advance the implementation of the Interconnection Request.

Environmental Law shall mean Applicable Laws or Regulations relating to pollution or protection of the

environment or natural resources.

Federal Power Act shall mean the Federal Power Act, as amended, 16 U.S.C. §§ 791a et seq.

Force Majeure shall mean any act of God, labor disturbance, act of the public enemy, war, insurrection,

riot, fire, storm or flood, explosion, breakage or accident to machinery or equipment, any order,

regulation or restriction imposed by governmental, military or lawfully established civilian authorities, or

any other cause beyond a Party’s control. A Force Majeure event does not include acts of negligence or

intentional wrongdoing by the Party claiming Force Majeure.

Generating Facility shall mean Interconnection Customer’s device for the production of electricity

identified in the Interconnection Request, but shall not include the Interconnection Customer’s

Interconnection Facilities.

Governmental Authority shall mean any federal, state, local or other governmental regulatory or

administrative agency, court, commission, department, board, or other governmental subdivision,

legislature, rulemaking board, tribunal, or other governmental authority having jurisdiction over the

Parties, their respective facilities, or the respective services they provide, and exercising or entitled to

exercise any administrative, executive, police, or taxing authority or power; provided, however, that such

term does not include the System Operator, Interconnection Customer, Interconnecting Transmission

Owner, or any Affiliate thereof.

Hazardous Substances shall mean any chemicals, materials or substances defined as or included in the

definition of “hazardous substances,” “hazardous wastes,” “hazardous materials,” “hazardous

constituents,” “restricted hazardous materials,” “extremely hazardous substances,” “toxic substances,”

“radioactive substances,” “contaminants,” “pollutants,” “toxic pollutants” or words of similar meaning

and regulatory effect under any applicable Environmental Law, or any other chemical, material or

substance, exposure to which is prohibited, limited or regulated by any applicable Environmental Law.

Initial Synchronization Date shall mean the date upon which the Generating Facility is initially

synchronized and upon which Trial Operation begins.

In-Service Date shall mean the date upon which the Interconnection Customer reasonably expects it will

be ready to begin use of the Interconnecting Transmission Owner’s Interconnection Facilities to obtain

back feed power.

Interconnecting Transmission Owner shall mean a Transmission Owner that owns, leases or otherwise

possesses an interest in the portion of the Administered Transmission System at the Point of

Interconnection and shall be a Party to the Standard Large Generator Interconnection Agreement. The

term Interconnecting Transmission Owner shall not be read to include the System Operator.

Interconnecting Transmission Owner’s Interconnection Facilities shall mean all facilities and

equipment owned, controlled, or operated by the Interconnecting Transmission Owner from the Point of

Change of Ownership to the Point of Interconnection as identified in Appendix A to the Standard Large

Generator Interconnection Agreement, including any modifications, additions or upgrades to such

facilities and equipment. Interconnecting Transmission Owner’s Interconnection Facilities are sole use

facilities and shall not include Distribution Upgrades, Stand Alone Network Upgrades or Network

Upgrades.

Interconnection Customer shall mean any entity, including a transmission owner or its Affiliates or

subsidiaries, that interconnects or proposes to interconnect its Generating Facility with the Administered

Transmission System under the Standard Large Generator Interconnection Procedures.

Interconnection Customer’s Interconnection Facilities shall mean all facilities and equipment, as

identified in Appendix A of the Standard Large Generator Interconnection Agreement, that are located

between the Generating Facility and the Point of Change of Ownership, including any modification,

addition, or upgrades to such facilities and equipment necessary to physically and electrically interconnect

the Generating Facility to the Administered Transmission System. Interconnection Customer’s

Interconnection Facilities are sole use facilities.

Interconnection Facilities shall mean the Interconnecting Transmission Owner’s Interconnection

Facilities and the Interconnection Customer’s Interconnection Facilities. Collectively, Interconnection

Facilities include all facilities and equipment between the Generating Facility and the Point of

Interconnection, including any modification, additions or upgrades that are necessary to physically and

electrically interconnect the Generating Facility to the Administered Transmission System.

Interconnection Facilities are sole use facilities and shall not include Distribution Upgrades, Stand Alone

Network Upgrades or Network Upgrades.

Interconnection Facilities Study shall mean a study conducted by the System Operator, Interconnecting

Transmission Owner, or a third party consultant for the Interconnection Customer to determine a list of

facilities (including Interconnecting Transmission Owner’s Interconnection Facilities and Network

Upgrades as identified in the Interconnection System Impact Study), the cost of those facilities, and the

time required to interconnect the Generating Facility with the Administered Transmission System. The

scope of the study is defined in Section 8 of the Standard Large Generator Interconnection Procedures.

Interconnection Facilities Study Agreement shall mean the form of agreement contained in Appendix 4

of the Standard Large Generator Interconnection Procedures for conducting the Interconnection Facilities

Study.

Interconnection Feasibility Study shall mean a preliminary evaluation of the system impact and cost of

interconnecting the Generating Facility to the Administered Transmission System, the scope of which is

described in Section 6 of the Standard Large Generator Interconnection Procedures. The Interconnection

Customer has the option to request either that the Interconnection Feasibility Study be completed as a

separate and distinct study, or as part of the Interconnection System Impact Study. If the Interconnection

Customer requests that the Interconnection Feasibility Study be completed as part of the Interconnection

System Impact Study, Section 6 shall be performed as the first step of the Interconnection System Impact

Study, and shall be regarded as part of the Interconnection System Impact Study. When the requirements

of Section 6 are performed as part of the Interconnection System Impact Study, the Interconnection

Customer shall be responsible only for the deposit requirements of the Interconnection System Impact

Study, and there shall be only one final report, which will include the results of both Section 6 and

Section 7.

Interconnection Feasibility Study Agreement shall mean the form of agreement contained in Appendix

2 of the Standard Large Generator Interconnection Procedures for conducting the Interconnection

Feasibility Study.

Interconnection Request shall mean an Interconnection Customer’s request, in the form of Appendix 1

to the Standard Large Generator Interconnection Procedures, in accordance with the Tariff, to: (i)

interconnect a new Generating Facility to the Administered Transmission System as either a CNR or a

NR; (ii) increase the energy capability or capacity capability of an existing Generation Facility; (iii) make

a Material Modification to the design or operating characteristics of an existing Generating Facility,

including its Interconnection Facilities, that is interconnected with the Administered Transmission

System; (iv) commence participation in the wholesale markets by an existing Generating Facility that is

interconnected with the Administered Transmission System; or (v) change from NR Interconnection

Service to CNR Interconnection Service for all or part of a Generating Facility’s capability.

Interconnection Request shall not include: (i) a retail customer interconnecting a new Generating Facility

that will produce electric energy to be consumed only on the retail customer’s site; (ii) a request to

interconnect a new Generating Facility to a distribution facility that is subject to the Tariff if the

Generating Facility will not be used to make wholesale sales of electricity in interstate commerce; or (iii)

a request to interconnect a Qualifying Facility (as defined by the Public Utility Regulatory Policies Act,

as amended by the Energy Policy Act of 2005 and the regulations thereto), where the Qualifying

Facility’s owner intent is to sell 100% of the Qualifying Facility’s output to its interconnected electric

utility.

Interconnection Service shall mean the service provided by the System Operator, and the

Interconnecting Transmission Owner, associated with interconnecting the Interconnection Customer’s

Generating Facility to the Administered Transmission System and enabling the receipt of electric energy

capability and/or capacity capability from the Generating Facility at the Point of Interconnection, pursuant

to the terms of the Standard Large Generator Interconnection Agreement and, if applicable, the Tariff.

Interconnection Study shall mean any of the following studies: the Interconnection Feasibility Study,

the Interconnection System Impact Study, the Interconnection Facilities Study and the Optional

Interconnection Study described in the Standard Large Generator Interconnection Procedures.

Interconnection Study shall not include a CNR Group Study.

Interconnection Study Agreement shall mean any of the following agreements: the Interconnection

Feasibility Study Agreement, the Interconnection System Impact Study Agreement, the Interconnection

Facilities Study Agreement, and the Optional Interconnection Study Agreement attached to the Standard

Large Generator Interconnection Procedures.

Interconnection System Impact Study shall mean an engineering study that evaluates the impact of the

proposed interconnection on the safety and reliability of the Administered Transmission System and any

other Affected System. The study shall identify and detail the system impacts that would result if the

Generating Facility were interconnected without project modifications or system modifications, focusing

on Adverse System Impacts, or to study potential impacts, including but not limited to those identified in

the Scoping Meeting as described in the Standard Large Generator Interconnection Procedures. If the

Interconnection Customer requests that the Interconnection Feasibility Study be completed as part of the

Interconnection System Impact Study, Section 6 shall be performed as the first step of the Interconnection

System Impact Study, and shall be regarded as part of the Interconnection System Impact Study. When

the requirements of Section 6 are performed as part of the Interconnection System Impact Study, the

Interconnection Customer shall be responsible only for the deposit requirements of the Interconnection

System Impact Study, and there shall be only one final report, which will include the results of both

Section 6 and Section 7.

Interconnection System Impact Study Agreement shall mean the form of agreement contained in

Appendix 3 of the Standard Large Generator Interconnection Procedures for conducting the

Interconnection System Impact Study.

IRS shall mean the Internal Revenue Service.

Large Generating Facility shall mean a Generating Facility having a maximum gross capability at or

above zero degrees F of more than 20 MW.

Long Lead Time Generating Facility (“Long Lead Facility”) shall mean a Generating Facility with an

Interconnection Request for CNR Interconnection Service that has, as applicable, elected or requested

long lead time treatment and met the eligibility criteria and requirements specified in Section 3.2.3.

Loss shall mean any and all losses relating to injury to or death of any person or damage to property,

demand, suits, recoveries, costs and expenses, court costs, attorney fees, and all other obligations by or to

third parties, arising out of or resulting from another Party’s performance, or non-performance of its

obligations under the Standard Large Generator Interconnection Agreement on behalf of the Indemnifying

Party, except in cases of gross negligence or intentional wrongdoing by the Indemnifying Party.

Major Permits shall be as defined in Section III.13.1.1.2.2.2(a) of the Tariff.

Material Modification shall mean: (i) except as expressly provided in Section 4.4.1, those modifications

to the Interconnection Request, including any of the technical data provided by the Interconnection

Customer in Attachment A to the Interconnection Request or to the interconnection configuration,

requested by the Interconnection Customer, that either require significant additional study of the same

Interconnection Request and could substantially change the interconnection design, or have a material

impact on the cost or timing of any Interconnection Studies or upgrades associated with an

Interconnection Request with a later queue priority date; (ii) a change to the design or operating

characteristics of an existing Generating Facility, including its Interconnection Facilities, that is

interconnected with the Administered Transmission System that may have a significant adverse effect on

the reliability or operating characteristics of the New England Transmission System; (iii) a delay to the

Commercial Operation Date, In-Service Date, or Initial Synchronization Date of greater than three (3)

years where the reason for delay is unrelated to construction schedules or permitting which delay is

beyond the Interconnection Customer’s control; (iv) except as provided in Section 3.2.3.4, a withdrawal

of a request for Long Lead Facility treatment; or (v) except as provided in Section 3.2.3.6, an election to

participate in an earlier Forward Capacity Auction than originally anticipated.

Metering Equipment shall mean all metering equipment installed or to be installed at the Generating

Facility pursuant to the Standard Large Generator Interconnection Agreement at the metering points,

including but not limited to instrument transformers, MWh-meters, data acquisition equipment,

transducers, remote terminal unit, communications equipment, phone lines, and fiber optics.

Network Capability Interconnection Standard (“NC Interconnection Standard”) shall mean the

minimum criteria required to permit the Interconnection Customer to interconnect in a manner that avoids

any significant adverse effect on the reliability, stability, and operability of the New England

Transmission System, including protecting against the degradation of transfer capability for interfaces

affected by the Generating Facility, as detailed in the ISO New England Planning Procedures.

Network Resource (“NR”) shall mean the portion of a Generating Facility that is interconnected to the

Administered Transmission System under the Network Capability Interconnection Standard.

Network Resource Capability (“NR Capability”) shall mean the maximum gross and net megawatt

electrical output of the Generating Facility at the Point of Interconnection at an ambient temperature at or

above 50 degrees F for Summer and at or above 0 degrees F for Winter. Where the Generating Facility

includes multiple energy production devices, the NR Capability shall be the aggregate maximum gross

and net megawatt electrical output of the Generating Facility at the Point of Interconnection at an ambient

temperature at or above 50 degrees F for Summer and at or above 0 degrees F for Winter. The NR

Capability shall be equal to or greater than the CNR Capability. In the case of a Generating Facility that

meets the criteria under Section 5.2.4 of this LGIP, the NR Capability shall mean the total megawatt

amount determined pursuant to Section 5.2.4.

Network Resource Interconnection Service (“NR Interconnection Service”) shall mean the

Interconnection Service selected by the Interconnection Customer to interconnect its Generating Facility

to the Administered Transmission System in accordance with the Network Capability Interconnection

Standard. An Interconnection Customer’s NR Interconnection Service shall be solely for the megawatt

amount of the NR Capability. NR Interconnection Service in and of itself does not convey transmission

service.

Network Upgrades shall mean the additions, modifications, and upgrades to the New England

Transmission System required at or beyond the Point of Interconnection to accommodate the

interconnection of the Large Generating Facility to the Administered Transmission System.

Notice of Dispute shall mean a written notice of a dispute or claim that arises out of or in connection with

the Standard Large Generator Interconnection Agreement or its performance.

Optional Interconnection Study shall mean a sensitivity analysis based on assumptions specified by the

Interconnection Customer in the Optional Interconnection Study Agreement.

Optional Interconnection Study Agreement shall mean the form of agreement contained in Appendix 5

of the Standard Large Generator Interconnection Procedures for conducting the Optional Interconnection

Study.

Party shall mean the System Operator, Interconnection Customer and Interconnecting Transmission

Owner or any combination of the above.

Point of Change of Ownership shall mean the point, as set forth in Appendix A to the Standard Large

Generator Interconnection Agreement, where the Interconnection Customer’s Interconnection Facilities

connect to the Interconnecting Transmission Owner’s Interconnection Facilities.

Point of Interconnection shall mean the point, as set forth in Appendix A to the Standard Large

Generator Interconnection Agreement, where the Interconnection Facilities connect to the Administered


Queue Position shall mean the order of a valid request in the New England Control Area, relative to all

other pending requests in the New England Control Area, that is established based upon the date and time

of receipt of such request by the System Operator. Requests are comprised of Interconnection Requests,

requests for Elective Transmission Upgrades, requests for transmission service and notification of

requests for interconnection to other electric systems, as notified by the other electric systems, that impact

the Administered Transmission System. For purposes of this LGIP, references to a “higher-queued”

Interconnection Request shall mean one that has been received by System Operator (and placed in queue

order) earlier than another Interconnection Request, which is referred to as “lower-queued.”

Reasonable Efforts shall mean, with respect to an action required to be attempted or taken by a Party

under the Standard Large Generator Interconnection Agreement, efforts that are timely and consistent

with Good Utility Practice and are otherwise substantially equivalent to those a Party would use to protect

its own interests.

Scoping Meeting shall mean the meeting between representatives of the System Operator,

Interconnection Customer, Interconnecting Transmission Owner, or any Affected Party as deemed

appropriate by the System Operator in accordance with applicable codes of conduct and confidentiality

requirements, conducted for the purpose of discussing alternative interconnection options, to exchange

information including any transmission data and earlier study evaluations that would be reasonably

expected to impact such interconnection options, to analyze such information, and to determine the

potential feasible Points of Interconnection.

Site Control shall mean documentation reasonably demonstrating: (a) that the Interconnection Customer

is the owner in fee simple of the real property for which new interconnection is sought; (b) that the

Interconnection Customer holds a valid written leasehold interest in the real property for which new

interconnection is sought; (c) that the Interconnection Customer holds a valid written option to purchase

or leasehold property for which new interconnection is sought; (d) that the Interconnection Customer

holds a duly executed written contract to purchase or leasehold the real property for which new

interconnection is sought; or (e) that the Interconnection Customer has filed applications for required

permits to site on federal or state property.

Stand Alone Network Upgrades shall mean Network Upgrades that an Interconnection Customer may

construct without affecting day-to-day operations of the New England Transmission System during their

construction. The System Operator, Interconnection Customer, Interconnecting Transmission Owner, and

any Affected Party as deemed appropriate by the System Operator in accordance with applicable codes of

conduct and confidentiality requirements, must agree as to what constitutes Stand Alone Network

Upgrades and identify them in Appendix A to the Standard Large Generator Interconnection Agreement.

Standard Large Generator Interconnection Agreement (“LGIA”) shall mean the form of

interconnection agreement applicable to an Interconnection Request pertaining to a Large Generating

Facility, that is included in this Schedule 22 to the Tariff.

Standard Large Generator Interconnection Procedures (“LGIP”) shall mean the interconnection

procedures applicable to an Interconnection Request pertaining to a Large Generating Facility that are

included in this Schedule 22 to the Tariff.

System Protection Facilities shall mean the equipment, including necessary signal protection

communications equipment, required to protect (1) the New England Transmission System from faults or

other electrical disturbances occurring at the Generating Facility and (2) the Generating Facility from

faults or other electrical system disturbances occurring on the New England Transmission System or on

other delivery systems or other generating systems to which the New England Transmission System is

directly connected.

Trial Operation shall mean the period during which Interconnection Customer is engaged in on-site test

operations and commissioning of the Generating Facility prior to Commercial Operation.

SECTION 2. SCOPE, APPLICATION AND TIME REQUIREMENTS.

2.1 Application of Standard Large Generator Interconnection Procedures.

The LGIP and LGIA shall apply to Interconnection Requests pertaining to Large Generating Facilities.

Except as expressly provided in the LGIP and LGIA, nothing in the LGIP or LGIA shall be construed to

limit the authority or obligations that the Interconnecting Transmission Owner or System Operator, as

applicable, has with regard to ISO New England Operating Documents.

2.2. Comparability.

The System Operator shall receive, process and analyze all Interconnection Requests in a timely manner

as set forth in this LGIP. The System Operator and Interconnecting Transmission Owner will use the

same Reasonable Efforts in processing and analyzing Interconnection Requests from all Interconnection

Customers, whether the Generating Facilities are owned by the Interconnecting Transmission Owner, its

subsidiaries or Affiliates, or others.

2.3 Base Case Data.

System Operator, Interconnecting Transmission Owner, and any Affected Party as deemed appropriate by

the System Operator in accordance with applicable codes of conduct and confidentiality requirements,

shall provide Base Case power flow, short circuit and stability databases, including all underlying

assumptions, and contingency lists upon request to any third party consultant retained by the

Interconnection Customer or to any non-market affiliate of the Interconnection Customer. The

recipient(s) of such information shall be subject to the confidentiality provisions of Section 13.1 and the

ISO New England Information Policy as well as any other applicable requirement under Applicable Laws

and Regulations regulating disclosure or confidentiality of such information. System Operator is

permitted to require that the third party consultant or non-market affiliate sign a confidentiality agreement

before the release of information governed by Section 13.1 or the ISO New England Information Policy,

or the release of any other information that is commercially sensitive or Critical Energy Infrastructure

Information. To the extent that any applicable information is not covered by any applicable

confidentiality/disclosure requirements, such information may be provided directly to the Interconnection

Customer. Such databases and lists, hereinafter referred to as Base Cases, shall include all generation

projects and transmission projects, including merchant transmission projects that are proposed for the

New England Transmission System, for which a transmission expansion plan has been submitted and

approved by the applicable authority. The Interconnection Customer, where applicable, shall provide

Base Case Data to the Interconnecting Transmission Owner and System Operator to facilitate required

Interconnection Studies.

2.4 No Applicability to Transmission Service.

Nothing in this LGIP shall constitute a request for, nor the provision of, any service except for

Interconnection Service, including, but not limited to, transmission delivery service, local delivery

service, distribution service, capacity service, energy service or Ancillary Services under any applicable

tariff, and does not convey any right to deliver electricity to any specific customer or Point of Delivery.

2.5 Time Requirements.

Parties that must perform a specific obligation under a provision of the Standard Large Generator

Interconnection Procedure or Standard Large Generator Interconnection Agreement within a specified

time period shall use Reasonable Efforts to complete such obligation within the applicable time period. A

Party may, in the exercise of reasonable discretion and within the time period set forth by the applicable

procedure or agreement, request that the relevant Party consent to a mutually agreeable alternative time

schedule, such consent not to be unreasonably withheld.

SECTION 3. INTERCONNECTION REQUESTS.

3.1 General.

To initiate an Interconnection Request, an Interconnection Customer must comply with all of the

requirements set forth in Section 3.3.1. The Interconnection Customer shall submit a separate

Interconnection Request for each site and may submit multiple Interconnection Requests for a single site.

The Interconnection Customer must comply with the requirements specified in Section 3.3.1 for each

Interconnection Request even when more than one request is submitted for a single site.

Within three (3) Business Days after its receipt of a valid Interconnection Request, System Operator shall

submit a copy of the Interconnection Request to Interconnecting Transmission Owner.

At Interconnection Customer’s option, System Operator, Interconnection Customer, Interconnecting

Transmission Owner, and any Affected Party as deemed appropriate by the System Operator in

accordance with applicable codes of conduct and confidentiality requirements, will identify alternative

Point(s) of Interconnection and configurations at the Scoping Meeting to evaluate in this process and

attempt to eliminate alternatives in a reasonable fashion given resources and information available.

Interconnection Customer will select the definitive Point(s) of Interconnection to be studied no later than

the execution of the Interconnection Feasibility Study Agreement, or the Interconnection System Impact

Study Agreement if the Interconnection Customer elects not to pursue the Interconnection Feasibility

Study.

3.2 Type of Interconnection Services and Long Lead Time Generating Facility Treatment

At the time the Interconnection Request is submitted, the Interconnection Customer must request either

CNR Interconnection Service or NR Interconnection Service, as described in Sections 3.2.1 and 3.2.2

below. An Interconnection Customer that meets the requirements to obtain CNR Interconnection Service

shall obtain NR Interconnection Service up to the NR Capability upon completion of all requirements for

NR Interconnection Service, including all necessary upgrades. Upon completion of all requirements for

the CNR Interconnection Service, the Interconnection Customer shall also receive CNR Interconnection

Service for CNR Capability. An Interconnection Customer that meets the requirements to obtain NR

Interconnection Service shall receive NR Interconnection Service for the Interconnection Customer’s NR

Capability. At the time the Interconnection Request is submitted, the Interconnection Customer may also

request Long Lead Facility treatment in accordance with Section 3.2.3.

3.2.1 Capacity Network Resource Interconnection Service

3.2.1.1 The Product.

The System Operator must conduct the necessary studies in conjunction with the Interconnecting

Transmission Owner, and with other Affected Parties as appropriate and in accordance with applicable

codes of conduct and confidentiality requirements, and the Interconnecting Transmission Owner and

other Affected Parties as appropriate must construct the Network Upgrades needed to interconnect the

Large Generating Facility in a manner comparable to that in which CNRs are interconnected under the

CC Interconnection Standard. CNR Interconnection Service allows the Interconnection Customer’s Large

Generating Facility to be designated as a CNR, and to participate in the New England Markets, in

accordance with Market Rule 1, Section III of the Tariff, up to the CNR Capability or as otherwise

provided in the Tariff, on the same basis as existing CNRs, and to be studied as a CNR on the assumption

that such a designation will occur.

3.2.1.2 The Studies.

All Interconnection Studies for CNR Interconnection Service shall assure that the Interconnection

Customer’s Large Generating Facility satisfies the minimum characteristics required to interconnect in a

manner that avoids any significant adverse effect on the reliability, stability, and operability of the New

England Transmission System, including protecting against the degradation of transfer capability for

interfaces affected by the unit. The CNR Group Study for CNR Interconnection Service shall assure that

the Interconnection Customer’s Large Generating Facility can be interconnected in a manner that ensures

intra-zonal deliverability by avoidance of the redispatch of other CNRs, in accordance with the CC

Interconnection Standard and as detailed in the ISO New England Planning Procedures. The System

Operator, in coordination with the Interconnecting Transmission Owner, may also study the New England

Transmission System under non-peak load conditions. However, upon request by the Interconnection

Customer, the System Operator and as appropriate the Interconnecting Transmission Owner must explain

in writing to the Interconnection Customer why the study of non-peak load conditions is required for

reliability purposes.

3.2.1.3 Milestones for CNR Interconnection Service.

In addition to the requirements set forth in this LGIP, an Interconnection Customer with an

Interconnection Request for CNR Interconnection Service shall complete the following milestones prior

to receiving CNR Interconnection Service for the CNR Capability, such milestones to be specified in

Appendix B of the LGIA, as either completed or to be completed: (i) submit the necessary requests for

participation in the Forward Capacity Auction associated with the Generating Facility’s requested

Commercial Operation Date (except as modified pursuant to Sections 3.2.3 or 4.4 of this LGIP), in

accordance with the provisions of Section III.13 of the Tariff; (ii) participate in a CNR Group Study for

the Forward Capacity Auction associated with the requested Generating Facility’s Commercial Operation

Date; (iii) qualify and receive a Capacity Supply Obligation in accordance with Section III.13 of the

Tariff; and (iv) complete a re-study of the applicable Interconnection Study to determine the cost

responsibility for facilities and upgrades necessary to accommodate the Interconnection Request based on

the results of the Forward Capacity Auction or Reconfiguration Auction or bilateral transaction through

which the Interconnection Customer received a Capacity Supply Obligation. With respect to (iv) above,

if an Interconnection Study has been completed, the completed Interconnection Study shall be subject to

re-study, in accordance with the re-study provisions in this LGIP. If an Interconnection Study Agreement

has been executed, the Interconnection Study associated with the Interconnection Study Agreement shall

include the necessary analysis that would otherwise have been performed in a re-study. If an LGIA has

been either executed or filed with the Commission in unexecuted form, then the last Interconnection

Study completed for the Interconnection Customer under this LGIP shall be subject to re-study. The

Appendices to the LGIA shall be amended (pursuant to Article 30 of the LGIA) to reflect CNR Capability

and the results of the re-study.

3.2.2 Network Resource Interconnection Service

3.2.2.1 The Product.

The System Operator must conduct the necessary studies in conjunction with the Interconnecting

Transmission Owner, and with other Affected Parties as appropriate and in accordance with applicable

codes of conduct and confidentiality requirements, and the Interconnecting Transmission Owner and

other Affected Parties as appropriate must construct the Network Upgrades needed to interconnect the

Large Generating Facility in a manner comparable to that in which Network Resources are interconnected

under the NC Interconnection Standard. NR Interconnection Service allows the Interconnection

Customer’s Large Generating Facility to participate in the New England Markets, in accordance with the

provisions of Market Rule 1, Section III of the Tariff, up to the gross and net NR Capability or as

otherwise provided in Market Rule 1, Section III of the Tariff, on the same basis as other Network

Resources. Notwithstanding the above, the portion of a Large Generating Facility that has been

designated as a Network Resource interconnected under the NC Interconnection Standard cannot be a

capacity resource under Section III.13 of the Tariff, except pursuant to a new Interconnection Request for

CNR Interconnection Service.

3.2.2.2 The Studies.

The Interconnection Studies for an Network Resource shall assure that the Interconnection Customer’s

Large Generating Facility satisfies the minimum characteristics required to interconnect in a manner that

avoids any significant adverse effect on reliability, stability, and operability of the New England

Transmission System, including protecting against the degradation of transfer capability for interfaces

affected by the unit, in accordance with the NC Interconnection Standard and as detailed in the ISO New

England Planning Procedures. The System Operator, in coordination with the Interconnecting

Transmission Owner, may also study the New England Transmission System under non-peak load

conditions. However, upon request by the Interconnection Customer, the System Operator and as

appropriate the Interconnecting Transmission Owner must explain in writing to the Interconnection

Customer why the study of non-peak load conditions is required for reliability purposes.

3.2.2.3 Milestones for NR Interconnection Service.

An Interconnection Customer with an Interconnection Request for NR Interconnection Service shall

complete the requirements in this LGIP prior to receiving NR Interconnection Service.

3.2.3 Long Lead Time Generating Facility Treatment

3.2.3.1 Treatment of Long Lead Facilities.

Long Lead Facilities receive the treatment described herein in connection with the associated request of

the Interconnection Customer for CNR Interconnection Service for its Generating Facility. Long Lead

Facility treatment provides for the Interconnection Customer’s Generating Facility, after the completion

of the Interconnection System Impact Study, to be modeled in the Base Cases for the next CNR Group

Study to determine whether the Long Lead Facility would have qualified to participate in the Forward

Capacity Auction associated with that CNR Group Study, in accordance with Section III.13.1.2 of the

Tariff, but for its development cycle (which shall include development of required transmission

upgrades). If the Long Lead Facility is deemed to qualify, the Long Lead Facility shall be included in the

re-study pursuant to Section 3.2.1.3(iv) in order to determine the facilities and upgrades that would be

necessary in order to accommodate the Interconnection Request of the Long Lead Facility, and for which

costs the Interconnection Customer must be responsible. In order to maintain Long Lead Facility status,

the Interconnection Customer must commit to the completion of these facilities and upgrades in time to

allow the Long Lead Facility to achieve its Commercial Operation Date by the start of the associated

Capacity Commitment Period. In addition, the Long Lead Facility will be treated as if it cleared as a New

Generating Capacity Resource for the sole purpose of inclusion in the CNR Group Studies for the

Forward Capacity Auctions that precede the Forward Capacity Auction for the Capacity Commitment

Period by which the Long Lead Facility is expected to have achieved Commercial Operation. If an

earlier-queued Generating Facility obtains a Capacity Supply Obligation in a Forward Capacity Auction

prior to or simultaneous with the Forward Capacity Auction in which the Long Lead Facility obtains a

Capacity Supply Obligation, the Long Lead Facility will be re-studied in order to determine whether any

additional facilities and upgrades to those identified prior to the CNR Group Study must be completed, at

the Interconnection Customer’s cost, prior to its Commercial Operation Date. A Long Lead Facility’s

cost responsibility for the facilities necessary to accommodate the Interconnection Request shall not be

impacted by a Generating Facility with a Queue Position lower than the Long Lead Facility that clears in

a Forward Capacity Auction, in accordance with Section III.13.2 of the Tariff, prior to the clearance of

the Long Lead Facility.

3.2.3.2 Request for Long Lead Facility Treatment.

An Interconnection Customer requesting CNR Interconnection Service for its proposed Generating

Facility, which the Interconnection Customer projects to have a development cycle that would not be

completed until after the beginning of the Capacity Commitment Period associated with the next Forward

Capacity Auction (after the election for the Long Lead Facility is made) may elect or request Long Lead

Facility treatment in the following manner:

(a) An Interconnection Customer proposing a Generating Facility with a requested Summer

net electrical output of 100 MW or more at or above 90 degrees F may elect Long Lead Facility

treatment at the time the Interconnection Request is submitted, together with the critical path

schedule and deposits required in Section 3.2.3.3.

(b) An Interconnection Customer proposing a Generating Facility with a requested Summer

net electrical output under 100 MW at or above 90 degrees F may request Long Lead Facility

treatment by submitting a written request to the System Operator for its review and approval,

explaining why the Generating Facility cannot achieve Commercial Operation by the beginning

of the Capacity Commitment Period associated with the next Forward Capacity Auction (after the

election for Long Lead Facility treatment is made), together with the critical path schedule and

deposits required in Section 3.2.3.3. In reviewing the request, the System Operator shall evaluate

the feasibility of the Generating Facility achieving Commercial Operation to meet an earlier

Capacity Commitment Period based on the information provided in the request and the critical

path schedule submitted pursuant to Section 3.2.3.3, in a manner similar to that performed under

Section III.13.3.2 of the Tariff. Within forty-five (45) Business Days after its receipt of the

request for Long Lead Facility treatment, the System Operator shall notify the Interconnection

Customer in writing whether the request has been granted or denied. If the System Operator

determines that the Generating Facility can achieve a Commercial Operation Date prior to the

beginning of the Capacity Commitment Period associated with the next Forward Capacity

Auction, the Interconnection Customer’s request shall be denied. The dispute resolution

provisions of this LGIP are not available for disputes or claims associated with the ISO’s

determination to deny an Interconnection Customer’s request for Long Lead Facility Treatment.

(c) An Interconnection Customer that did not request Long Lead Facility treatment at the

time the Interconnection Request was submitted, may thereafter submit a request for treatment as

a Long Lead Facility, together with the critical path schedule and deposits required in Section

3.2.3.3 and, if applicable, a request for an extension of the Commercial Operation Date specified

in the Interconnection Request in accordance with Sections 4.4.4 and 4.4.5. A request for Long

Lead Facility treatment that is submitted after the initial Interconnection Request will not be

eligible to participate in any Forward Capacity Auction prior to the Forward Capacity Auction

associated with the extended Commercial Operation Date. The Long Lead Facility will be

modeled in the Base Cases for the CNR Study Group associated with the near term Forward

Capacity Auction unless that CNR Study Group is underway, in which case the Long Lead

Facility will be modeled in the next CNR Study Group.

3.2.3.3 Critical Path Schedule and Deposits for Long Lead Facility Treatment.

At the time an Interconnection Customer submits an election or request for Long Lead Facility treatment,

the Interconnection Customer must submit, together with the request:

(1) Critical Path Schedule. A critical path schedule, in writing, for the Long Lead Facility

(with a development cycle that would not be completed until after the beginning of the Capacity

Commitment Period associated with the next Forward Capacity Auction (after the election for the

Long Lead Facility is made)) that meets the requirements set forth in Section III.13.1.1.2.2.2 of

the Tariff. The Interconnection Customer must submit annually, in writing, an updated critical

path schedule to the System Operator by the closing deadline of each New Capacity Show of

Interest Submission Window that precedes the Forward Capacity Auction associated with the

Capacity Commitment Period by which the Long Lead Facility is expected to have achieved

Commercial Operation, prior to the inclusion of the Long Lead Facility in the Base Case for the

CNR Group Study associated with the corresponding New Capacity Show of Interest Submission

Window. With its annual update, for each critical path schedule milestone achieved since the

submission of the previous critical path schedule update, the Interconnection Customer must

include in the critical path update documentation demonstrating that the milestone has been

achieved by the date indicated and as otherwise described in the critical path schedule.

(2) Long Lead Facility Deposits.

(a) Deposits. In addition to the deposits required elsewhere in this LGIP, at the time of its

request for Long Lead Facility treatment, in accordance with Section 3.2.3.3, and by each

deadline for which a New Generating Capacity Resource is required to provide financial

assurance under Section III.13.1.9.1 of the Tariff, the Interconnection Customer must provide a

separate deposit in the amount of 0.25*(Forward Capacity Auction Starting Price/2)*requested

summer net capacity. For each calculation of the deposit, the System Operator shall use the

Forward Capacity Auction Starting Price in effect for the upcoming Forward Capacity Auction at

the time of that calculation, pursuant to Section III.13.2.4 of the Tariff. The total amount of

deposits shall not exceed the Non-Commercial Capacity Financial Assurance Amount that the

Long Lead Facility would be required to provide if cleared in the upcoming Forward Capacity

Auction, in accordance with Section III.13.1.9.1 of the Tariff. The Long Lead Facility deposits

will be fully refunded (with interest to be calculated in accordance with Section 3.6) (i) if the

Interconnection Customer withdraws the Interconnection Request, pursuant to Section 3.6, within

thirty (30) Calendar Days of the Scoping Meeting or of the completion of the System Impact

Study (including restudy of the System Impact Study), pursuant to Section 7, or (ii) once the

Long Lead Facility clears in a Forward Capacity Auction.

(b) Reductions. Ten (10) percent of the Long Lead Facility deposits collected pursuant to

Section 3.2.3.3(2)(a) shall be non-refundable if the Interconnection Customer withdraws its

Interconnection Request (except as provided in Section 3.2.3.3(2)(a)) after the Long Lead Facility

fails to qualify or qualifies and fails to clear in the Forward Capacity Auction that follows the first

Forward Capacity Auction for which it could qualify based on the Commercial Operation Date

specified in the initial critical path schedule for the Long Lead Facility. An additional five (5)

percent of the Long Lead Facility deposits collected pursuant to Section 3.2.3.3(2)(a) shall be

non-refundable if the Interconnection Customer withdraws its Interconnection Request (except as

provided in Section 3.2.3.3(2)(a)) following each subsequent Forward Capacity Auction in which

the Long Lead Facility fails to qualify or qualifies and fails to clear such Forward Capacity

Auction, not to exceed the maximum period allowed under Sections 3.3.1, 4.4.4 and 4.4.5. The

non-refundable portions of the deposits shall be credited to the revenue requirements under

Schedule 1 of Section IV of the Tariff.

3.2.3.4 Withdrawal and Refunds After Expenditures for Upgrades.

An Interconnection Customer that provides documentation in the critical path schedule update to be

submitted in accordance with Section 3.2.3.3(1), showing expenditures of the required amounts for

upgrades identified in the Interconnection Studies for the Long Lead Facility, may submit a withdrawal of

the Interconnection Request for the Long Lead Facility, in accordance with Section 3.6, at any time up to

thirty (30) Calendar Days, after failure to clear in any Forward Capacity Auction. In such instance, the

Interconnection Customer shall receive a refund from the System Operator of the Long Lead Facility

deposits (with interest to be calculated in accordance with Section 3.6) as adjusted pursuant to 3.2.3.3(2),

if appropriate, and from the Interconnecting Transmission Owner a refund of the payments for the

upgrades that exceed the costs incurred by the Interconnecting Transmission Owner. If the

Interconnection Customer withdraws only its election or request for Long Lead Facility treatment, such

withdrawal will be considered a Material Modification and the Long Lead Facility will lose its Queue

Position unless its withdrawal occurs within one of the thirty (30)-day periods described in Section

3.2.3.3(2) of this LGIP.

3.2.3.5 Additional Requirements to Maintain Long Lead Facility Treatment.

An Interconnection Customer with a Long Lead Facility must begin payment as required by the

transmission expenditure schedule for the transmission upgrade costs that have been identified in the

pertinent Interconnection Studies. The Interconnection Request for CNR Interconnection Service shall be

deemed withdrawn under Section 3.6 if the Interconnection Customer fails to comply with the

requirements for Long Lead Facility treatment, including the milestones specified in Section 3.2.1.4. In

this circumstance, the conditions specified in Appendix A of the LGIA for a Large Generating Facility

that had an Interconnection Request of a Queue Position lower than the Long Lead Facility, but cleared in

a Forward Capacity Auction prior to the Long Lead Facility, shall be removed.

3.2.3.6 Participation in Earlier Forward Capacity Auctions.

An Interconnection Customer with a Long Lead Facility may, without loss of Queue Position, elect to

participate in an earlier Forward Capacity Auction than originally anticipated, but only if the election to

accelerate is made to the System Operator in writing within thirty (30) Calendar Days of the Scoping

Meeting or within thirty (30) Calendar Days of the completion of the System Impact Study (but before the

Long Lead Facility and the results of the associated System Impact Study are incorporated into the Base

Cases). Otherwise, such an election shall be considered a Material Modification.

3.3 Valid Interconnection Request.

3.3.1 Initiating an Interconnection Request.

To initiate an Interconnection Request, Interconnection Customer must submit all of the following to the

System Operator: (i) an initial deposit of $50,000, (ii) a completed application in the form of Appendix 1,

(iii) all information and deposits required under Section 3.2, and (iv) in the case of a request for CNR

Interconnection Service, demonstration of Site Control or, in the case of a request for NR Interconnection

Service, demonstration of Site Control or a posting of an additional deposit of $10,000. Interconnection

Customer does not need to demonstrate Site Control where the Interconnection Request is for a

modification to the Interconnection Customer’s existing Large Generating Facility and the

Interconnection Customer has certified in the Interconnection Request that it has Site Control and that the

modification proposed in the Interconnection Request does not require additional real property. The

portions of the deposit of $50,000 that have not been applied as provided in this Section 3.3.1 shall be

refundable if (i) the Interconnection Customer withdraws the Interconnection Request, pursuant to

Section 3.6, within ten (10) Business Days of the Scoping Meeting, or (ii) if the Interconnection Customer

executes an LGIA. Otherwise, any unused balance of the deposit of $50,000 shall be non-refundable and

applied on a pro-rata basis to offset costs incurred by Interconnection Customers with lower Queue

Positions that are subject to re-study, as determined by the System Operator in accordance with the

provisions of this LGIP, as a result of the withdrawal of an Interconnection Request with a higher Queue

Position.

The deposit of $50,000 shall be applied toward the costs incurred by the System Operator associated with

the Interconnection Request and Long Lead Facility treatment, as well as, the costs of the Interconnection

Feasibility Study and/or the Interconnection System Impact Study, including the cost of developing the

study agreements and their attachments, and the cost of developing the LGIA.

If, in the case of a request for NR Interconnection Service, the Interconnection Customer demonstrates

Site Control within the cure period specified in Section 3.3.3 after submitting its Interconnection Request,

the additional deposit of $10,000 shall be refundable; otherwise, that deposit shall be applied as provided

in Section 3.1, including, toward the costs of any Interconnection Studies pursuant to the Interconnection

Request, the cost of developing the study agreement(s) and associated attachment(s), and the cost of

developing the LGIA.

The expected Initial Synchronization Date of the new Large Generating Facility, of the increase in

capacity of the existing Generating Facility, or of the implementation of the Material Modification to the

existing Generating Facility shall not exceed seven (7) years from the date the Interconnection Request is

received by the System Operator, unless the Interconnection

Customer demonstrates that such time required to actively engineer, permit and construct the new Large

Generating Facility or increase in capacity of the existing Generating Facility or implement the Material

Modification to the existing Generating Facility will take longer than the seven year period. Upon such

demonstration, the Initial Synchronization Date may succeed the date the Interconnection Request is

received by the System Operator by a period of greater than seven (7) years so long as the Interconnection

Customer, System Operator, and Interconnecting Transmission Owner agree,; such agreement shall not be

unreasonably withheld.

3.3.2 Acknowledgment of Interconnection Request.

System Operator shall acknowledge receipt of the Interconnection Request within five (5) Business Days

of receipt of the request and attach a copy of the received Interconnection Request to the

acknowledgement. With the System Operator’s acknowledgement of a valid Interconnection Request, the

System Operator shall provide to the Interconnection Customer an Interconnection Feasibility Study

Agreement in the form of Appendix 2 or an Interconnection System Impact Study Agreement in the form

of Appendix 3.

3.3.3 Deficiencies in Interconnection Request.

An Interconnection Request will not be considered to be a valid request until all items in Section 3.3.1

have been received by the System Operator. If an Interconnection Request fails to meet the requirements

set forth in Section 3.3.1, the System Operator shall notify the Interconnection Customer within five (5)

Business Days of receipt of the initial Interconnection Request of the reasons for such failure and that the

Interconnection Request does not constitute a valid request. Interconnection Customer shall provide the

System Operator the additional requested information needed to constitute a valid request within ten (10)

Business Days after receipt of such notice. Failure by Interconnection Customer to comply with this

Section 3.3.3 shall be treated in accordance with Section 3.6.

3.3.4 Scoping Meeting.

Within ten (10) Business Days after receipt of a valid Interconnection Request, System Operator shall

establish a date agreeable to Interconnection Customer, Interconnecting Transmission Owner, and any

Affected Party as deemed appropriate by the System Operator in accordance with applicable codes of

conduct and confidentiality requirements, for a Scoping Meeting, and such date shall be no later than

thirty (30) Calendar Days from receipt of the valid Interconnection Request, unless otherwise mutually

agreed upon by the Parties.

The purpose of the Scoping Meeting shall be (i) to discuss the estimated timeline for completing all

applicable Interconnection Studies, and alternative interconnection options, (ii) to exchange pertinent

information including any transmission data that would reasonably be expected to impact such

interconnection options, (iii) to analyze such information, (iv) to determine the potential feasible Points of

Interconnection, and (v) to discuss any other information necessary to facilitate the administration of the

Interconnection Procedures. If a PSCAD model is required, the Parties shall discuss this at the Scoping

Meeting.

The Parties will bring to the meeting such technical data, including, but not limited to: (i) general facility

loadings, (ii) general instability issues, (iii) information regarding general short circuit issues, (iv) general

voltage issues, and (v) general reliability issues as may be reasonably required to accomplish the purpose

of the meeting. The Parties will also bring to the meeting personnel and other resources as may be

reasonably required to accomplish the purpose of the meeting in the time allocated for the meeting. On

the basis of the meeting, Interconnection Customer shall designate its Point of Interconnection, pursuant

to Section 6.1, and one or more available alternative Point(s) of Interconnection. The duration of the

meeting shall be sufficient to accomplish its purpose.

Within five (5) Business Days following the Scoping Meeting Interconnection Customer shall notify the

System Operator, in writing, (i) whether it wants the Interconnection Feasibility Study to be completed as

a separate and distinct study or as part of the Interconnection System Impact Study; and (ii) the Point(s) of

Interconnection and any reasonable alternative Point(s) of Interconnection for inclusion in the attachment

to the Interconnection Feasibility Study Agreement, or the Interconnection System Impact Study

Agreement if the Interconnection Customer elects not to pursue the Interconnection Feasibility Study.

3.4 OASIS Posting.

The System Operator will maintain on its OASIS a list of all Interconnection Requests in its Control

Area. The list will identify, for each Interconnection Request: (i) the maximum summer and winter

megawatt electrical output; (ii) the location by county and state; (iii) the station or transmission line or

lines where the interconnection will be made; (iv) the projected Initial Synchronization Date; (v) the

status of the Interconnection Request, including Queue Position; (vi) the type of Interconnection Service

being requested (i.e., CNR Interconnection Service or NR Interconnection Service); and (vii) the

availability of any studies related to the Interconnection Request; (viii) the date of the Interconnection

Request; (ix) the type of Generating Facility to be constructed (combined cycle, base load or combustion

turbine and fuel type); and (x) for Interconnection Requests that have not resulted in a completed

interconnection, an explanation as to why it was not completed. Except in the case of an Affiliate, the list

will not disclose the identity of the Interconnection Customer until the Interconnection Customer executes

an LGIA or requests that the System Operator and Interconnecting Transmission Owner jointly file an

unexecuted LGIA with the Commission. Before participating in a Scoping Meeting with an

Interconnection Customer that is also an Affiliate, the Interconnecting Transmission Owner shall post on

OASIS an advance notice of its intent to do so. The System Operator shall post to its OASIS site any

deviations from the study timelines set forth herein. Interconnection Study reports and Optional

Interconnection Study reports shall be posted to the System Operator’s OASIS site subsequent to the

meeting between the System Operator, Interconnecting Transmission Owner, and Interconnection

Customer to discuss the applicable study results. The System Operator shall also post any known

deviations in the Large Generating Facility’s Initial Synchronization Date.

3.5 Coordination with Affected Systems.

The System Operator will coordinate the conduct of any studies required to determine the impact of the

Interconnection Request on Affected Systems with Affected Parties and, if possible, include those results

(if available) in its applicable Interconnection Study within the time frame specified in this LGIP. The

System Operator will include such Affected Parties in all meetings held with the Interconnection

Customer as required by this LGIP. The Interconnection Customer will cooperate with the System

Operator and Interconnecting Transmission Owner in all matters related to the conduct of studies and the

determination of modifications to Affected Systems. The Interconnection Customer shall be responsible

for the costs associated with the studies or portions of studies associated with the Affected Systems.

Payment and refunds associated with the costs of such studies will be coordinated between the

Interconnection Customer and the Affected Party(ies).

The System Operator shall seek the cooperation of all Affected Parties in all matters related to the

conduct of studies and the determination of modifications to Affected Systems. Nothing in the foregoing

is intended to authorize the Interconnection Customer to receive interconnection, related facilities or other

services on an Affected System, and provision of such services must be handled through separate

arrangements with Affected Party(ies).

3.6 Withdrawal.

The Interconnection Customer may withdraw its Interconnection Request at any time by written notice of

such withdrawal to System Operator, which System Operator will transmit to Interconnecting

Transmission Owner and any Affected Parties. In addition, if the Interconnection Customer fails to

adhere to all requirements of this LGIP, except as provided in Section 13.5 (Disputes), the System

Operator shall deem the Interconnection Request to be withdrawn and shall provide written notice to the

Interconnection Customer of the deemed withdrawal and an explanation of the reasons for such deemed

withdrawal. Upon receipt of such written notice, if the Interconnection Customer wishes to dispute the

withdrawal notice, the Interconnection Customer shall have fifteen (15) Business Days, unless otherwise

provided elsewhere in this LGIP, in which to either respond with information or actions that cure the

deficiency or to notify the System Operator of its intent to pursue Dispute Resolution, and System

Operator shall notify Interconnecting Transmission Owner and any Affected Parties of the same.

Withdrawal shall result in the loss of the Interconnection Customer’s Queue Position. If an

Interconnection Customer disputes the withdrawal and loss of its Queue Position, then during Dispute

Resolution, the System Operator may eliminate the Interconnection Customer’s Interconnection Request

from the queue until such time that the outcome of Dispute Resolution would restore its Queue Position.

An Interconnection Customer that withdraws or is deemed to have withdrawn its Interconnection Request

shall pay to System Operator, Interconnecting Transmission Owner, and any Affected Parties all costs

prudently incurred with respect to that Interconnection Request prior to System Operator’s receipt of

notice described above. The Interconnection Customer must pay all monies due before it is allowed to

obtain any Interconnection Study data or results.

The System Operator shall update the OASIS Queue Position posting. Except as otherwise provided

elsewhere in this LGIP, the System Operator and the Interconnecting Transmission Owner shall arrange

to refund to the Interconnection Customer any portion of the Interconnection Customer’s deposit or study

payments that exceeds the costs incurred, including interest calculated in accordance with section

35.19a(a)(2) of the Commission’s regulations, or arrange to charge to the Interconnection Customer any

amount of such costs incurred that exceed the Interconnection Customer’s deposit or study payments,

including interest calculated in accordance with section 35.19a(a)(2) of the Commission’s regulations. In

the event of such withdrawal, System Operator, subject to the confidentiality provisions of Section 13.1

and the ISO New England Information Policy, as well as any other applicable requirement under

Applicable Laws and Regulations regulating the disclosure or confidentiality of such information, shall

provide, at Interconnection Customer’s request, all information developed for any completed study

conducted up to the date of withdrawal of the Interconnection Request.

SECTION 4. QUEUE POSITION.

4.1 General.

System Operator shall assign a Queue Position based upon the date and time of receipt of the valid

Interconnection Request; provided that, if the sole reason an Interconnection Request is not valid is the

lack of required information on the application form, and Interconnection Customer provides such

information in accordance with Section 3.3.3, then System Operator shall assign Interconnection

Customer a Queue Position based on the date the application form was originally filed. A Material

Modification pursuant to Section 4.4.2 shall be treated in accordance with Section 4.4.

Except as otherwise provided in this Section 4.4.1, the Queue Position of each Interconnection Request

will be used to determine: (i) the order of performing the Interconnection Studies; (ii) the order in which

CNR Interconnection Requests will be included in the CNR Group Study; and (iii) the cost responsibility

for the facilities and upgrades necessary to accommodate the Interconnection Request. A higher queued

Interconnection Request is one that has been placed “earlier” in the queue in relation to another

Interconnection Request that is lower queued.

Where a CNR Interconnection Request with a lower Queue Position submits a New Capacity Show of

Interest Form for qualification to participate in a particular Forward Capacity Auction for a Capacity

Commitment Period and another CNR Interconnection Request with a higher Queue Position does not

submit a New Capacity Show of Interest Form for qualification until a subsequent Forward Capacity

Auction, the CNR Interconnection Request with the lower Queue Position will be included in the CNR

Group Study prior to the CNR Interconnection Request with the higher Queue Position. The CNR Group

Study (to be conducted in accordance with Section III.13.1.1.2.3 of the Tariff) shall include all

Interconnection Requests for Capacity Network Resource Interconnection Service that have submitted a

New Capacity Show of Interest Form during the New Capacity Show of Interest Submission Window for

the purpose of qualification for participation in the same Forward Capacity Auction for a Capacity

Commitment Period, in accordance with Section III.13.1.1.2 of the Tariff, as well as Long Lead Facilities,

in accordance with Section 3.2.3. Participation in a CNR Group Study shall be a prerequisite for a

Generating Facility seeking to qualify as a New Generating Capacity Resource under Section III.13.1 of

the Tariff to obtain CNR Interconnection Service.

An Interconnection Customer with a CNR Interconnection Request for a Generating Facility that is

treated as a Conditional Qualified New Generating Capacity Resource, in accordance with Section

III.13.1.1.2.3(f) of the Tariff, may be responsible for the facilities and upgrades associated with an

overlapping CNR Interconnection Request having a higher Queue Position if the Conditional Qualified

New Generating Capacity Resource obtains a Capacity Supply Obligation through a Forward Capacity

Auction under Section III.13.2.5 of the Tariff.

An Interconnection Customer with a lower queued CNR Interconnection Request for a Large Generating

Facility that has achieved Commercial Operation and obtained a Capacity Supply Obligation through a

Forward Capacity Auction may be responsible for additional facilities and upgrades if the related higher

queued CNR Interconnection Request for a Long Lead Facility achieves Commercial Operation and

obtains a Capacity Supply Obligation through a Forward Capacity Auction. In such circumstance,

Appendix A to the LGIA for the lower queued CNR Interconnection Request shall specify the facilities

and upgrades for which the Interconnection Customer shall be responsible if the higher queued CNR

Interconnection Request for a Long Lead Facility achieves Commercial Operation and obtains a Capacity

Supply Obligation. System Operator may allocate the cost of the common upgrades for clustered

Interconnection Requests, pursuant to Section 4.2, without regard to Queue Position.

4.2 Clustering.

At the System Operator’s option, Interconnection Requests may be studied serially or in clusters for the

purpose of the Interconnection System Impact Study.

Clustering shall be implemented on the basis of Queue Position. If the System Operator elects to study

Interconnection Requests using Clustering, all Interconnection Requests received within a period not to

exceed one hundred and eighty (180) Calendar Days, hereinafter referred to as the “Queue Cluster

Window” shall be studied together. The deadline for completing all Interconnection System Impact

Studies for which an Interconnection System Impact Study Agreement has been executed during a Queue

Cluster Window shall be in accordance with Section 7.4, for all Interconnection Requests assigned to the

same Queue Cluster Window. The Queue Cluster Window shall have a fixed time interval based on fixed

annual opening and closing dates. Any changes to the established Queue Cluster Window interval and

opening or closing dates shall be announced with a posting on System Operator’s OASIS beginning at

least one hundred and eighty (180) Calendar Days in advance of the change and continuing thereafter

through the end date of the first Queue Cluster Window that is to be modified.

Clustering Interconnection System Impact Studies shall be conducted in such a manner to ensure the

efficient implementation of the applicable regional transmission expansion plan in light of the New

England Transmission System’s capabilities at the time of each study. The System Operator may study

an Interconnection Request separately to the extent warranted by Good Utility Practice based upon the

electrical remoteness of the proposed Large Generating Facility.

4.3 Transferability of Queue Position.

An Interconnection Customer may transfer its Queue Position to another entity only if such entity

acquires the specific Generating Facility identified in the Interconnection Request and the Point of

Interconnection does not change. The Interconnection Customer must notify the System Operator, in

writing, of any transfers of Queue Position and must provide the System Operator with the transferee’s

contact information, and System Operator shall notify Interconnecting Transmission Owner and any

Affected Parties of the same.

4.4 Modifications.

The Interconnection Customer shall submit to System Operator and Interconnecting Transmission Owner,

in writing, modifications to any information provided in the Interconnection Request, including its

attachments. The Interconnection Customer shall retain its Queue Position if the modifications are in

accordance with Sections 4.4.1 or 4.4.4, or are determined not to be Material Modifications pursuant to

Section 4.4.2. The System Operator will notify the Interconnecting Transmission Owner, and, when

System Operator deems it appropriate in accordance with applicable codes of conduct and confidentiality

requirements, it will notify any Affected Party of such modifications.

A request to: (1) increase the energy capability or capacity capability output of a Generating Facility

above that specified in an Interconnection Request, an existing Interconnection Agreement (whether

executed or filed in unexecuted form with the Commission), or as established pursuant to Section 5.2 of

this LGIP shall require a new Interconnection Request for the incremental increase and such

Interconnection Request will receive the lowest Queue Position available at that time for the purposes of

cost allocation and study analysis; and (2) change from NR Interconnection Service to CNR

Interconnection Service, at any time, shall require a new Interconnection Request for CNR

Interconnection Service and such Interconnection Request will receive the lowest Queue Position

available at that time for the purposes of cost allocation and study analysis. Notwithstanding the

foregoing, in the circumstance in which the Interconnection Customer seeking New Generating Capacity

Resource treatment for its Generating Facility (pursuant to Section III.13.1 of the Tariff) has offered into

a Forward Capacity Auction the full megawatt amount for which the CNR Interconnection Service was

requested in the original Interconnection Request (or as that amount has been modified in accordance

with Section 4.4.1(a)), but the entire amount did not clear in that Auction, no new Interconnection

Request will be required if the Interconnection Customer seeks to offer the uncleared amount in a

subsequent Forward Capacity Auction for which the associated Capacity Commitment Period begins less

than seven (7) years (or the years agreed to pursuant to Section 3.3.1 or Section 4.4.5) from the date of the

original Interconnection Request.

During the course of the Interconnection Studies, either the System Operator, Interconnection Customer,

Interconnecting Transmission Owner, or any Affected Party as deemed appropriate by the System

Operator in accordance with applicable codes of conduct and confidentiality requirements, may identify

changes to the planned interconnection that may improve the costs and benefits (including reliability) of

the interconnection, and the ability of the proposed change to accommodate the Interconnection Request.

To the extent the identified changes are acceptable to the Parties, such acceptance not to be unreasonably

withheld, System Operator and the Interconnecting Transmission Owner shall modify the Point of

Interconnection and/or configuration in accordance with such changes and proceed with any re-studies

necessary to do so in accordance with Section 6.4, Section 7.6 and Section 8.5 as applicable and

Interconnection Customer shall retain its Queue Position.

4.4.1 Prior to the return of the executed Interconnection System Impact Study Agreement to System

Operator, modifications permitted under this Section shall include specifically: (a) a decrease of up to 60

percent of electrical output (MW) of the proposed project; (b) modifying the technical parameters

associated with the Large Generating Facility technology or the Large Generating Facility step-up

transformer impedance characteristics; and (c) modifying the interconnection configuration.

4.4.2 Prior to making any modification other than those specifically permitted by Sections 4.4.1 and

4.4.4, Interconnection Customer may first request that the System Operator and Interconnecting

Transmission Owner evaluate whether such modification is a Material Modification. In response to

Interconnection Customer’s request, the System Operator in consultation with the Interconnecting

Transmission Owner, and in consultation with any Affected Party as deemed appropriate by the System

Operator in accordance with applicable codes of conduct and confidentiality requirements, shall evaluate,

at the Interconnection Customer’s cost, the proposed modifications prior to making them and the System

Operator will inform the Interconnection Customer in writing of whether the modifications would

constitute a Material Modification. Any change to the Point of Interconnection, except those deemed

acceptable under Sections 4.4.1, 6.1, 7.2 or so allowed elsewhere, shall constitute a Material

Modification. The Interconnection Customer may then withdraw the proposed modification or proceed

with a new Interconnection Request for such modification.

4.4.3 Upon receipt of Interconnection Customer’s request for modification that does not constitute a

Material Modification and therefore is permitted under this Section 4.4, the System Operator in

consultation with the Interconnecting Transmission Owner and in consultation with any Affected Party as

deemed appropriate by the System Operator in accordance with applicable codes of conduct and

confidentiality requirements, shall commence and perform any necessary additional studies as soon as

practicable, but in no event shall the System Operator, Interconnecting Transmission Owner, or Affected

Party commence such studies later than thirty (30) Calendar Days after receiving notice of

Interconnection Customer’s request. Any additional studies resulting from such modification shall be

done at Interconnection Customer’s cost.

4.4.4 Extensions of less than three (3) cumulative years in the Commercial Operation Date, In-Service

Date or Initial Synchronization Date of the Large Generating Facility to which the Interconnection

Request relates are not material and should be handled through construction sequencing, provided that the

extension(s) do not exceed seven (7) years from the date the Interconnection Request was received by the

System Operator.

4.4.5 Extensions of three (3) or more cumulative years in the Commercial Operation Date, In-Service

Date or Initial Synchronization Date of the Large Generating Facility to which the Interconnection

Request relates or any extension of a duration that results in the Initial Synchronization Date exceeding

the date the Interconnection Request was received by the System Operator by seven (7) or more years is a

Material Modification unless the Interconnection Customer demonstrates to the System Operator due

diligence, including At-Risk Expenditures, in pursuit of permitting, licensing and construction of the

Large Generating Facility to meet the Commercial Operation Date, In-Service Date or Initial

Synchronization Date provided in the Interconnection Request. Such demonstration shall be based on

evidence to be provided by the Interconnection Customer of accomplishments in permitting, licensing,

and construction in an effort to meet the Commercial Operation Date, In-Service Date or Initial

Synchronization Date provided in this Interconnection Request. Such evidence may include filed

documents, records of public hearings, governmental agency findings, documentation of actual

construction progress or documentation acceptable to the System Operator showing At-Risk Expenditure

made previously, including the previous four (4) months. If the evidence demonstrates that the

Interconnection Customer did not undertake reasonable efforts to meet the Commercial Operation Date,

In-Service Date or Initial Synchronization Date specified in the Interconnection Request, or demonstrates

that reasonable efforts were not undertaken until four (4) months prior to the request for extension, the

request for extension shall constitute a Material Modification. The Interconnection Customer may then

withdraw the proposed Material Modification or proceed with a new Interconnection Request for such

modification.

SECTION 5. PROCEDURES FOR TRANSITION.

5.1 Queue Position for Pending Requests.

5.1.1 Any Interconnection Customer assigned a Queue Position prior to February 1, 2009, shall retain

that Queue Position subject to Section 4.4 of the LGIP.

5.1.1.1 If an Interconnection Study Agreement has not been executed prior to February 1, 2009, then

such Interconnection Study, and any subsequent Interconnection Studies, shall be processed in accordance

with the version of this LGIP in effect on February 1, 2009 (or as revised thereafter).

5.1.1.2 If an Interconnection Study Agreement has been executed prior to February 1, 2009, such

Interconnection Study shall be completed in accordance with the terms of such agreement

5.1.2 Transition Period. To the extent necessary, the System Operator, Interconnection Customers with

an outstanding Interconnection Request (i.e., an Interconnection Request for which an LGIA has neither

been executed nor submitted to the Commission for approval prior to February 1, 2009), Interconnecting

Transmission Owner and any other Affected Parties, shall transition to proceeding under the version of

the LGIP in effect as of February 1, 2009 (or as revised thereafter) within a reasonable period of time not

to exceed sixty (60) Calendar Days. The use of the term “outstanding Interconnection Request” herein

shall mean any Interconnection Request, on February 1, 2009: (i) that has been submitted, together with

the required deposit and attachments, but not yet accepted by the System Operator; (ii) where the related

LGIA has not yet been submitted to the Commission for approval in executed or unexecuted form, (iii)

where the relevant Interconnection Study Agreements have not yet been executed, or (iv) where any of

the relevant Interconnection Studies are in process but not yet completed. Any Interconnection Customer

with an outstanding request as of the effective date of this LGIP may request a reasonable extension of

any deadline, otherwise applicable, if necessary to avoid undue hardship or prejudice to its

Interconnection Request. A reasonable extension, not to exceed sixty (60) Calendar Days, shall be

granted by the System Operator to the extent consistent with the intent and process provided for under

this LGIP.

5.1.3 One-Time Election for CNR Interconnection Service at Queue Position Assigned Prior to

February 1, 2009.

An Interconnection Customer with an outstanding Interconnection Request will be eligible to make a one-

time election to be considered for CNR Interconnection Service at the Queue Position assigned prior to

February 1, 2009. The Interconnection Customer’s one-time election must be made by the end of the

New Generating Capacity Show of Interest Submission Window for the fourth Forward Capacity

Auction. The Interconnection Customer’s one-time election may also include a request for Long Lead

Facility Treatment, which shall be subject to review pursuant to Section 3.2.3, and, if applicable, a request

for a change of the Commercial Operation Date, in accordance with Sections 4.4.4 and 4.4.5.

Interconnection Customers requesting CNR Interconnection Service will be required to comply with the

requirements for CNR Interconnection Service set forth in Section 3.2.1. Interconnection Customers

requesting CNR Interconnection Service that have not received a completed Interconnection System

Impact Study may request a preliminary, non-binding, analysis of potential upgrades that may be

necessary for the fourth Forward Capacity Auction – the prompt or near-term auction – pursuant to

Sections 6.3 or 7.3, whichever is applicable.

5.2 Grandfathering.

5.2.1 An Interconnection Customer’s Generating Facility that is interconnected pursuant to an

Interconnection Agreement executed or submitted to the Commission for approval prior to February 1,

2009, will maintain its status as a Network Resource with Network Resource Interconnection Service

eligible to participate in the New England Markets, in accordance with the requirements of Market Rule

1, Section III of the Tariff, up to the megawatt amount specified in the Interconnection Agreement,

subject to the Interconnection Customer satisfying all requirements set forth in the Interconnection

Agreement and this LGIP. If the Generating Facility does not meet the criteria set forth in Section 5.2.3

of this LGIP, the Interconnection Customer will be eligible to make a one-time election, pursuant to

Section 5.1.3, for Capacity Network Resource treatment without submitting a new Interconnection

Request; however, the Interconnection Customer will be required to comply with the requirements for

CNR Interconnection Service set forth in Section 3.2.1. Upon completion of the requirements to obtain

CNR Interconnection Service, the Interconnection Customer’s Interconnection Agreement shall be

amended to conform to the LGIA in Appendix 6 of this LGIP.

5.2.2 An Interconnection Customer’s Generating Facility governed by an Interconnection Agreement

either executed or filed with the Commission in unexecuted form prior to August 1, 2008, shall maintain

the Queue Position assigned as of August 1, 2008, and be eligible to participate in the New England

Markets, in accordance with the requirements in Market Rule 1, Section III of the Tariff, as in effect as of

August 1, 2008, so long as the Interconnection Customer complies with all of the requirements specified

in the Interconnection Agreement, including achieving the milestones associated with At-Risk

Expenditures, subject to Section 4.4 of this LGIP.

5.2.3 All resources that are treated as Existing Generating Capacity Resources in the fourth Forward

Capacity Auction pursuant to Section III.13 of the Tariff shall receive treatment as a CNR and obtain

CNR Interconnection Service, in accordance with this LGIP, up to the CNR Capability of the resource.

The grandfathered CNR Capability for these resources shall be equal to the megawatt amount established

pursuant to the following hierarchy:

(a) First, the megawatt amount specified in an Interconnection Agreement (whether executed or filed in

unexecuted form with the Commission).

(b) Second, in the absence of an Interconnection Agreement with a specified megawatt amount, the

megawatt amount specified in an approval pursuant to Section I.3.9 of the Tariff (or its predecessor

provision).

(c) Third, in the absence of an Interconnection Agreement and an approval pursuant to Section I.3.9 of

the Tariff (or its predecessor provision) with a specified megawatt amount, as determined by the System

Operator based on documented historic capability of the Generating Facility.

Where a resource has both an Interconnection Agreement and an approval pursuant to Section I.3.9 of the

Tariff (or its predecessor provision), the lower megawatt amount will govern until the resource completes

the applicable process(es) under the Tariff for obtaining the higher megawatt amount. The absence of an

Interconnection Agreement or an approval pursuant to Section I.3.9 of the Tariff (or its predecessor

provision) specifying a megawatt amount shall be confirmed by an affidavit executed by a corporate

officer of the resource attesting that the resource does not have an Interconnection Agreement and/or an

approval pursuant to Section I.3.9 of the Tariff (or its predecessor provision) that specifies a megawatt

amount.

Where the governing document (as determined by the hierarchy set forth in Section 5.2.3) specifies a

megawatt amount at an ambient temperature consistent with the definition of CNR Capability, the

grandfathered CNR Capability shall be equal to that amount.

Where the governing document (as determined by the hierarchy set forth in Section 5.2.3) does not

specify an ambient temperature, the megawatt amount will be deemed to be at the value consistent with

the definition of CNR Capability.

Where the implementation of this Section 5.2.3 results in a CNR Capability that is different than

previously had been identified, the revised CNR Capability will be applied commencing with the next

Forward Capacity Auction qualification process (after the revised CNR Capability value is identified),

which is initiated by the closing deadline of the Show of Interest Submission Window in accordance with

Section III.13 of the Tariff. The revised CNR Capability will continue to govern until the resource

completes the applicable process(es) for obtaining the higher megawatt amount.

5.2.4 All resources that are treated as Existing Generating Capacity Resources in the fourth Forward

Capacity Auction pursuant to Section III.13 of the Tariff shall receive treatment as a NR and obtain NR

Interconnection Service, in accordance with this LGIP, up to the NR Capability of the resource. The

grandfathered NR Capability shall be determined pursuant to the hierarchy set forth in Section 5.2.3.

Where the governing document (as determined by the hierarchy set forth in Section 5.2.3) of a resource

for which a temperature-adjustment curve is used for the claimed capability verification, as set forth in the

ISO New England Manuals, specifies a megawatt amount at an ambient temperature, the grandfathered

NR Capability shall be equal to a temperature-adjusted value consistent with the definition of NR

Capability.

Where the governing document (as determined by the hierarchy set forth in Section 5.2.3) does not

specify an ambient temperature, the megawatt amount will be deemed to be at the value consistent with

the definition of NR Capability.

5.3 New System Operator or Interconnecting Transmission Owner.

If the System Operator transfers operational control of the New England Transmission System to a

successor System Operator during the period when an Interconnection Request is pending, the System

Operator shall transfer to the successor System Operator any amount of the deposit or payment with

interest thereon that exceeds the cost that it incurred to evaluate the request for interconnection. Any

difference between such net amount and the deposit or payment required by this LGIP shall be paid by or

refunded to the Interconnection Customer, as appropriate. The System Operator shall coordinate with the

successor System Operator to complete any Interconnection Study, as appropriate, that the System

Operator has begun but has not completed.

If the Interconnecting Transmission Owner transfers ownership of its transmission facilities to a successor

transmission owner during the period when an Interconnection Request is pending, and System Operator

in conjunction with Interconnecting Transmission Owner has tendered a draft LGIA to the

Interconnection Customer but the Interconnection Customer has not either executed the LGIA or

requested the filing of an unexecuted LGIA with the Commission, unless otherwise provided, the

Interconnection Customer must complete negotiations with the successor transmission owner.

SECTION 6. INTERCONNECTION FEASIBILITY STUDY.

6.1 Interconnection Feasibility Study Agreement.

The Interconnection Customer has the option to request either that the Interconnection Feasibility Study

be completed as a separate and distinct study under this Section 6, or as part of the Interconnection

System Impact Study under Section 7. If the Interconnection Customer requests that the Interconnection

Feasibility Study be completed as part of the Interconnection System Impact Study, Section 6 shall be

performed as the first step of the Interconnection System Impact Study, and shall be regarded as part of

the Interconnection System Impact Study. When the requirements of Section 6 are performed as part of

the Interconnection System Impact Study, the Interconnection Customer shall be responsible only for the

deposit requirements of the Interconnection System Impact Study, and the System Operator shall be

responsible for generating only one final report, which will include the results of both Section 6 and

Section 7.

Within five (5) Business Days following the System Operator’s and Interconnecting Transmission

Owner’s receipt from the Interconnection Customer of its designation of the Point(s) of Interconnection

and of the type of study to be performed pursuant to Section 3.3.4, System Operator shall tender to

Interconnection Customer the Interconnection Feasibility Study Agreement, which includes a good faith

estimate of the cost for completing the Interconnection Feasibility Study. The Interconnection Feasibility

Study Agreement shall specify that Interconnection Customer is responsible for the actual cost of the

Interconnection Feasibility Study, including the cost of developing the study agreement and its

attachment(s). No later than thirty (30) Calendar Days after its receipt of the Interconnection Feasibility

Study Agreement, (a) the Interconnection Customer shall execute and deliver the agreement to System

Operator and the Interconnecting Transmission Owner, (b) the Interconnection Customer shall also

deliver the refundable deposit for the Interconnection Feasibility Study to the System Operator, and (c)

the technical data called for in Appendix 1, Attachment B. The deposit for the study shall be 100 percent

of the estimated cost of the study. The deposit shall be applied toward the cost of the Interconnection

Feasibility Study, including the cost of developing the study agreement and its attachment(s). Any

difference between the study deposit and the actual cost of the Interconnection Feasibility Study shall be

paid by or refunded to the Interconnection Customer, except as otherwise provided in Section 13.3. In

accordance with Section 13.3, the System Operator and/or the Interconnecting Transmission Owner shall

issue to the Interconnection Customer an invoice for the costs of the Interconnection Feasibility Study

that have been incurred by the System Operator and/or the Interconnecting Transmission Owner on the

Interconnection Feasibility Study, including the development of the study agreement and its

attachment(s). The Interconnection Customer shall pay the invoiced amounts, to the extent such amounts

are greater than the initial deposit, within thirty (30) Calendar Days of receipt of invoice. The System

Operator shall continue to hold any amounts on deposit until settlement of the final invoice with the

Interconnection Customer and the Interconnecting Transmission Owner.

On or before the return of the executed Interconnection Feasibility Study Agreement to the System

Operator and Interconnecting Transmission Owner, the Interconnection Customer shall provide the

technical data called for in Appendix 1, Attachment B. If the Interconnection Customer does not provide

all such technical data when it delivers the Interconnection Feasibility Study Agreement, the System

Operator shall notify the Interconnection Customer of the deficiency within five (5) Business Days of the

receipt of the executed Interconnection Feasibility Study Agreement and the Interconnection Customer

shall cure the deficiency within ten (10) Business Days of receipt of the notice, provided, however, such

deficiency does not include failure to deliver the executed Interconnection Feasibility Study Agreement or

deposit.

If the Interconnection Feasibility Study uncovers any unexpected result(s) not contemplated during the

Scoping Meeting, a substitute Point of Interconnection identified by the System Operator, Interconnection

Customer, Interconnecting Transmission Owner, or any Affected Party as deemed appropriate by the

System Operator in accordance with applicable codes of conduct and confidentiality requirements, and

acceptable to the Parties, such acceptance not to be unreasonably withheld, will be substituted for the

designated Point of Interconnection specified above without loss of Queue Position, and re-studies shall

be completed pursuant to Section 6.4 as applicable. For the purpose of this Section 6.1, if the Parties

cannot agree on the substituted Point of Interconnection, then Interconnection Customer may direct that

one of the alternatives as specified in the Interconnection Feasibility Study Agreement, as specified

pursuant to Section 3.3.4, shall be the substitute.

6.2 Scope of Interconnection Feasibility Study.

The Interconnection Feasibility Study shall preliminarily evaluate the feasibility of the proposed

interconnection to the Administered Transmission System with available data and information. The

Interconnection Feasibility Study does not require detailed model development.

The Interconnection Feasibility Study will consider the base case as well as all generating facilities (and

with respect to (iii), any identified Network Upgrades) that, on the date the Interconnection Feasibility

Study is commenced: (i) are directly interconnected to the New England Transmission System; (ii) are

interconnected to Affected Systems and may have an impact on the Interconnection Request; (iii) have a

pending higher queued Interconnection Request to interconnect to the New England Transmission

System; and (iv) have no Queue Position but have executed an LGIA or requested that an unexecuted

LGIA be filed with the Commission. An Interconnection Customer with a CNR Interconnection Request

may also request that the Interconnection Feasibility Study include a preliminary, non-binding, analysis to

identify potential upgrades that may be necessary for the Interconnection Customer’s Generating Facility

to qualify for participation in a Forward Capacity Auction under Section III.13 of the Tariff, based on a

limited set of assumptions to be specified by the Interconnection Customer and reflected in Attachment A

to the Interconnection Feasibility Study Agreement. The Interconnection Feasibility Study will consist of

a power flow, including thermal analysis and voltage analysis, and short circuit analysis. The

Interconnection Feasibility Study report will provide (i) a list of facilities, and a non-binding good faith

estimate of cost responsibility; (ii) a non-binding good faith estimated time to construct; (iii) a protection

assessment to determine the required Interconnection Facilities; and may provide (iv) an evaluation of the

siting of Interconnection Facilities and Network Upgrades; and (v) identification of the likely permitting

and siting process including easements and environmental work. To the extent the Interconnection

Customer requested a preliminary analysis as described in this Section 6.2, the Interconnection Feasibility

Study report will also provide a list of potential upgrades that may be necessary for the Interconnection

Customer’s Generating Facility to qualify for participation in a Forward Capacity Auction under Section

III.13 of the Tariff.

6.3 Interconnection Feasibility Study Procedures.

The System Operator in coordination with Interconnecting Transmission Owner shall utilize existing

studies to the extent practicable when it performs the study. The System Operator and Interconnecting

Transmission Owner shall use Reasonable Efforts to complete the Interconnection Feasibility Study no

later than forty-five (45) Calendar Days after System Operator and Interconnecting Transmission Owner

receive the fully executed Interconnection Feasibility Study Agreement, study deposit and required

technical data in accordance with Section 6.1. At the request of the Interconnection Customer or at any

time the System Operator or the Interconnecting Transmission Owner determines that it will not meet the

required time frame for completing the Interconnection Feasibility Study, the System Operator shall

notify the Interconnection Customer as to the schedule status of the Interconnection Feasibility Study. If

the System Operator is unable to complete the Interconnection Feasibility Study within that time period,

the System Operator shall notify the Interconnection Customer and provide an estimated completion date

with an explanation of the reasons why additional time is required. Upon request, the System Operator

with input from the Interconnecting Transmission Owner shall provide all supporting documentation,

workpapers and relevant pre-Interconnection Request and post-Interconnection Request power flow and

short circuit databases for the Interconnection Feasibility Study to any third party consultant retained by

the Interconnection Customer or to any non-market affiliate of the Interconnection Customer. The

recipient(s) of such information shall be subject to the confidentiality provisions of Section 13.1 and the

ISO New England Information Policy, as well as any other applicable requirement under Applicable

Laws and Regulations regulating the disclosure or confidentiality of such information. To the extent that

any applicable information is not covered by any applicable confidentiality/disclosure requirements, such

information may be provided directly to the Interconnection Customer.

6.3.1 Meeting with Parties.

Within ten (10) Business Days of providing an Interconnection Feasibility Study report to the

Interconnection Customer, the System Operator will convene a meeting of the Interconnecting

Transmission Owner, Interconnection Customer, and any Affected Party as deemed appropriate by the

System Operator in accordance with applicable codes of conduct and confidentiality requirements to

discuss the results of the Interconnection Feasibility Study.

6.4 Re-Study.

If re-study of the Interconnection Feasibility Study is required due to (i) a higher queued project dropping

out of the queue, (ii) a modification of a higher queued project subject to Section 4.4, (iii) a re-designation

of the Point of Interconnection pursuant to Section 6.1, (iv) a re-assessment of the upgrade responsibilities

of a Generating Facility after it receives a Capacity Supply Obligation in accordance with Section III.13

of the Tariff, or (v) a modification to a transmission project included in the Base Case, the System

Operator shall notify the Interconnection Customer and Interconnecting Transmission Owner in writing.

Each re-study shall be conducted serially based on the Queue Position of each Interconnection Customer,

and each re-study shall take not longer than sixty (60) Calendar Days from the date the re-study

commences. Any cost of re-study shall be borne by the Interconnection Customer being re-studied. If the

original Interconnection Feasibility Study is complete and the final invoice has been issued, the re-study

shall be performed under a new Interconnection Feasibility Study Agreement.

The Interconnection Customer shall have the option to waive the re-study and elect to have the re-study

performed as part of its Interconnection System Impact Study. The Interconnection Customer shall

provide written notice of the waiver and election of moving directly to the Interconnection System Impact

Study within five (5) Business Days of receiving notice from the System Operator of the required re-

study.

SECTION 7. INTERCONNECTION SYSTEM IMPACT STUDY.

7.1 Interconnection System Impact Study Agreement.

If the Interconnection Customer did not request that the Interconnection Feasibility Study be completed as

a separate and distinct study, Section 6 shall be performed as the first step of the Interconnection System

Impact Study, and shall be regarded as part of the Interconnection System Impact Study. When the

requirements of Section 6 are performed as part of the Interconnection System Impact Study, the


System Impact Study, and the System Operator shall be responsible for generating only one final report,

which will include the results of both Section 6 and Section 7.

Within five (5) Business Days following the Interconnection Feasibility Study results meeting, or

subsequent to the Scoping Meeting within five (5) Business Days following the receipt of designation of

the Point(s) of Interconnection and type of study to be performed pursuant to Section 3.3.4, if the

Interconnection Customer did not request that the Interconnection Feasibility Study be completed as a

separate and distinct study, the System Operator and Interconnecting Transmission Owner shall provide

to Interconnection Customer the Interconnection System Impact Study Agreement, which includes a non-

binding good faith estimate of the cost and timeframe for completing the Interconnection System Impact

Study. The Interconnection System Impact Study Agreement shall provide that the Interconnection

Customer shall compensate the System Operator and Interconnecting Transmission Owner for the actual

cost of the Interconnection System Impact Study, including the cost of developing the study agreement

and its attachment(s) and the cost of developing the LGIA.

7.2 Execution of Interconnection System Impact Study Agreement.

The Interconnection Customer shall execute the Interconnection System Impact Study Agreement and

deliver the executed Interconnection System Impact Study Agreement to the System Operator no later

than thirty (30) Calendar Days after its receipt along with a demonstration of Site Control and the

technical data called for in Appendix 1, Attachment A, and the Interconnection Customer shall also

deliver simultaneously a refundable deposit. An Interconnection Customer does not need to demonstrate

Site Control where the Interconnection Request is for a modification to the Interconnection Customer’s

existing Large Generating Facility and the Interconnection Customer has certified in the Interconnection

Request that it has Site Control and that the modification proposed in the Interconnection Request does

not require additional real property. The deposit for the study shall be: (i) the greater of 100 percent of

the estimated cost of the study or $250,000; or (ii) the lower of 100 percent of the estimated costs of the

study or $50,000, if the Interconnection Customer can provide: (1) evidence of applications for all Major

Permits, as defined in Section III.13.1.1.2.2.2(a) of the Tariff, required in support of the Interconnection

Request or written certification that Major Permits are not required, or (2) evidence acceptable to the

System Operator of At-Risk Expenditures (excluding Interconnection Study costs) totaling at least the

amounts of money described in (i) above; or (iii) the lower of 100 percent of the estimated costs of the

study or $50,000, if the Interconnection Request is for a modification to an existing Large Generating

Facility that does not increase the energy capability or capacity capability of the Large Generating

Facility.

The deposit shall be applied toward the cost of the Interconnection System Impact Study, including the

cost of developing the study agreement and its attachment(s) and the cost of developing the LGIA. Any

difference between the study deposit and the actual cost of the Interconnection System Impact Study shall

be paid by or refunded to the Interconnection Customer, except as otherwise provided in Section 13.3. In


issue to the Interconnection Customer an invoice for the costs of Interconnection System Impact Study

that have been incurred by the System Operator and/or the Interconnecting Transmission Owner for the

System Impact Study, including the study agreement and its attachment(s) and the LGIA. If the

Interconnection Customer elects the deposit described in (ii) above, the System Operator and the

Interconnecting Transmission Owner may, in the exercise of reasonable discretion, invoice the

Interconnection Customer on a monthly basis for the work to be conducted on the Interconnection System

Impact Study on each month. The Interconnection Customer shall pay the invoiced amounts, to the extent

such amounts are greater than the initial deposit, within thirty (30) Calendar Days of receipt of invoice.

The System Operator shall continue to hold the amounts on deposit until settlement of the final invoice

with the Interconnection Customer and the Interconnecting Transmission Owner.

On or before the return of the executed Interconnection System Impact Study Agreement to the System

Operator and Interconnecting Transmission Owner, the Interconnection Customer shall provide the

technical data called for in Appendix 1, Attachment A; provided that if a PSCAD model was determined

to be needed at the Scoping Meeting, then the Interconnection Customer shall have ninety (90) Calendar

Days from the execution of the System Impact Study Agreement to provide the PSCAD model.

If the Interconnection Customer does not provide all such technical data when it delivers the

Interconnection System Impact Study Agreement, the System Operator shall notify the Interconnection

Customer of the deficiency within five (5) Business Days of the receipt of the executed Interconnection

System Impact Study Agreement and the Interconnection Customer shall cure the deficiency within ten

(10) Business Days of receipt of the notice, provided, however, such deficiency does not include failure to

deliver the executed Interconnection System Impact Study Agreement or deposit.

If the Interconnection System Impact Study uncovers any unexpected result(s) not contemplated during

the Scoping Meeting or the Interconnection Feasibility Study, a substitute Point of Interconnection

identified by the System Operator, Interconnection Customer, Interconnecting Transmission Owner, or

any Affected Party as deemed appropriate by the System Operator in accordance with applicable codes of

conduct and confidentiality requirements, and acceptable to each Party, such acceptance not to be

unreasonably withheld, will be substituted for the designated Point of Interconnection specified above

without loss of Queue Position, and re-studies shall be completed pursuant to Section 7.6 as applicable.

For the purpose of this Section 7.2, if the Parties cannot agree on the substituted Point of Interconnection,

then Interconnection Customer may direct that one of the alternatives as specified in the Interconnection

Feasibility Study Agreement or Interconnection System Impact Study depending on whether

Interconnection Customer requested that the Interconnection Feasibility Study be completed as a separate

and distinct study or as part of the Interconnection System Impact Study, as specified pursuant to Section

3.3.4, shall be the substitute.

7.3 Scope of Interconnection System Impact Study.

The Interconnection System Impact Study shall evaluate the impact of the proposed interconnection on

the reliability and operation of the New England Transmission System. The Interconnection System

Impact Study will consider the base case as well as all generating facilities (and with respect to (iii)

below, any identified Network Upgrades associated with such higher queued interconnection) that, on the

date the Interconnection System Impact Study is commenced: (i) are directly interconnected to the New

England Transmission System; (ii) are interconnected to Affected Systems and may have an impact on

the Interconnection Request; (iii) have a pending higher queued Interconnection Request to interconnect

to the New England Transmission System; and (iv) have no Queue Position but have executed an LGIA

or requested that an unexecuted LGIA be filed with the Commission. An Interconnection Customer with

a CNR Interconnection Request that elected to waive the Interconnection Feasibility Study may also

request that the Interconnection System Impact Study include a preliminary, non-binding, analysis to

identify potential upgrades that may be necessary for the Interconnection Customer’s Generating Facility

to qualify for participation in a Forward Capacity Auction under Section III.13 of the Tariff, based on a

limited set of assumptions to be specified by the Interconnection Customer and reflected in Attachment A

to the Interconnection System Impact Study Agreement.

The Interconnection System Impact Study will consist of a short circuit analysis, a stability analysis, a

power flow analysis, including thermal analysis and voltage analysis, a system protection analysis and

any other analyses that are deemed necessary by the System Operator in consultation with the

Interconnecting Transmission Owner. The Interconnection System Impact Study report will state the

assumptions upon which it is based, state the results of the analyses, and provide the requirements or

potential impediments to providing the requested interconnection service, including a preliminary

indication of the cost and length of time that would be necessary to correct any problems identified in

those analyses and implement the interconnection. The Interconnection System Impact Study report will

provide (i) a list of facilities that are required as a result of the Interconnection Request and a non-binding

good faith estimate of cost responsibility; (ii) a non-binding good faith estimated time to construct; (iii) a

protection assessment to determine the required protection upgrades; and may provide (iv) an evaluation

of the siting of the Interconnection Facilities and Network Upgrades; and (v) identification of the likely

permitting and siting process including easements and environment work. To the extent the

Interconnection Customer requested a preliminary analysis as described in this Section 7.3, the

Interconnection System Impact Study report will also provide a list of potential upgrades that may be

necessary for the Interconnection Customer’s Generating Facility to qualify for participation in a Forward

Capacity Auction under Section III.13 of the Tariff.

7.4 Interconnection System Impact Study Procedures.

The System Operator shall coordinate the Interconnection System Impact Study with the Interconnecting

Transmission Owner, and with any Affected Party as deemed appropriate by the System Operator in

accordance with applicable codes of conduct and confidentiality requirements, that is affected by the

Interconnection Request pursuant to Section 3.5 above. The System Operator and Interconnecting

Transmission Owner shall utilize existing studies to the extent practicable when it performs the study.

The System Operator and Interconnecting Transmission Owner shall use Reasonable Efforts to complete

the Interconnection System Impact Study within ninety (90) Calendar Days after the receipt of the

Interconnection System Impact Study Agreement, study deposit, demonstration of Site Control, if Site

Control is required, and required technical data in accordance with Section 7.2. If System Operator or

Interconnecting Transmission Owner uses Clustering, the System Operator and Interconnecting

Transmission Owner shall use Reasonable Efforts to deliver a completed Interconnection System Impact

Study within ninety (90) Calendar Days after the close of the Queue Cluster Window.

At the request of the Interconnection Customer or at any time the System Operator or Interconnecting

Transmission Owner determines that it will not meet the required time frame for completing the

Interconnection System Impact Study, the System Operator shall notify the Interconnection Customer as

to the schedule status of the Interconnection System Impact Study. If the System Operator and

Interconnecting Transmission Owner are unable to complete the Interconnection System Impact Study

within the time period, the System Operator shall notify the Interconnection Customer and provide an

estimated completion date with an explanation of the reasons why additional time is required. Upon

request, the System Operator and Interconnecting Transmission Owner shall provide all supporting

documentation, workpapers and relevant pre-Interconnection Request and post-Interconnection Request

power flow, short circuit and stability databases for the Interconnection System Impact Study to any third

party consultant retained by the Interconnection Customer or to any non-market affiliate of the

Interconnection Customer. The recipient(s) of such information shall be subject to the confidentiality

provisions of Section 13.1 and the ISO New England Information Policy, as well as any other applicable

requirement under Applicable Laws and Regulations regulating the disclosure or confidentiality of such

information. To the extent that any applicable information is not covered by any applicable

confidentiality/ disclosure requirements, such information may be provided directly to the Interconnection

Customer.

7.5 Meeting with Parties.

Within ten (10) Business Days of providing an Interconnection System Impact Study report to

Interconnection Customer, the System Operator shall convene a meeting of the Interconnecting


System Operator in accordance with applicable codes of conduct and confidentiality requirements, to

discuss the results of the Interconnection System Impact Study.

Within five (5) Business Days following the study results meeting, the Interconnection Customer shall

provide to the System Operator written notice that it will either pursue the Interconnection Facilities

Study or waive the Interconnection Facilities Study and elect an expedited interconnection. If the

Interconnection Customer waives the Facilities Study, it shall commit to the following milestones in the

LGIA: (i) Siting approval for the Generating Facility and Interconnection Facilities; (ii) Engineering of

Interconnection Facilities approved by Interconnecting Transmission Owner; (iii) Ordering of long lead

time material for Interconnection Facilities and system upgrades; (iv) Initial Synchronization Date; and

(v) Commercial Operation Date.

Within thirty (30) Calendar Days of the Interconnection Customer receiving the Interconnection System

Impact Study report, the Interconnection Customer shall provide written comments on the report or

written notice that it has no comments on the report. The System Operator shall issue a final

Interconnection System Impact Study report within fifteen (15) Business Days of receiving the

Interconnection Customer’s comments or promptly upon receiving the Interconnection Customer’s notice

that it will not provide comments.

7.6 Re-Study.

If re-study of the Interconnection System Impact Study is required due to (i) a higher queued project

dropping out of the queue, (ii) a modification of a higher queued project subject to Section 4.4, (iii) re-

designation of the Point of Interconnection pursuant to Section 7.2, (iv) a re-assessment of the upgrade

responsibilities of a Generating Facility after it receives a Capacity Supply Obligation in accordance with

Section III.13 of the Tariff, or (v) a modification to a transmission project included in the Base Case, the

System Operator shall notify the Interconnection Customer and Interconnecting Transmission Owner in

writing.

Each re-study shall be conducted serially based on the Queue Position of each Interconnection Customer,

and each re-study shall take no longer than sixty (60) Calendar Days from the date the re-study

commences. Any cost of re-study shall be borne by the Interconnection Customer being re-studied. If the

original Interconnection System Impact Study is complete and the final invoice has been issued, the re-

study shall be performed under a new Interconnection System Impact Study Agreement.

7.7 Operational Readiness.

The System Operator shall, as close to the Interconnection Customer’s actual Synchronization Date as

reasonably possible, ensure that current stability analyses, power flow analyses, and any other analyses

deemed necessary by the System Operator, are performed or reviewed, as deemed appropriate by the

System Operator, and to develop or update procedures to address the operation of the New England

Transmission System with the addition of the Interconnection Customer’s Generating Facility. The

operational analysis will also include tests of system performance with selected facilities out of service.

Such studies shall be performed at the expense of the Interconnection Customer.

The System Operator is not obligated to perform the operational analyses described in this Section 7.7 if,

in the exercise of reasonable discretion, the System Operator in consultation with Interconnecting

Transmission Owner determines that interconnection of the Interconnection Customer’s Generating

Facility to the Administered Transmission System is remote and speculative.

SECTION 8. INTERCONNECTION FACILITIES STUDY.

8.1 Interconnection Facilities Study Agreement.

The Interconnection Customer may waive the Interconnection Facilities Study and instead elect expedited

interconnection, which means that the Interconnection Customer may enter into E&P Agreements under

Section 9 if it had not already done so, and shall enter into an LGIA in accordance with the requirements

specified in Section 11.

If the Interconnection Customer waives the Interconnection Facilities Study, the Interconnection

Customer, subject to the specific terms of the E&P Agreements, assumes all risks and shall pay all costs

associated with equipment, engineering, procurement and construction work covered by the

Interconnection Facilities Study as described in Section 8.2 below.

The System Operator shall provide to the Interconnection Customer an Interconnection Facilities Study

Agreement in the form of Appendix 4 to this LGIP simultaneously with the delivery of the

Interconnection System Impact Study to the Interconnection Customer.

The Interconnection Facilities Study Agreement shall provide that the Interconnection Customer shall

compensate the System Operator and Interconnecting Transmission Owner for the actual cost of the

Interconnection Facilities Study, including the cost of developing the study agreement and its

attachment(s) and the cost of developing the LGIA. Within three (3) Business Days following the

Interconnection System Impact Study results meeting, the System Operator and Interconnecting

Transmission Owner shall provide to Interconnection Customer a non-binding good faith estimate of the

cost for completing the Interconnection Facilities Study in accordance with requirements specified in

Section 8.3. The Interconnection Customer shall execute the Interconnection Facilities Study Agreement

and deliver the executed Interconnection Facilities Study Agreement to the System Operator within thirty

(30) Calendar Days after its receipt, together with the required technical data and the refundable deposit

for the Interconnection Facilities Study. In accordance with Section 8.3, the Interconnection Customer

shall specify in Attachment A to the Interconnection Facilities Study Agreement whether it wants no

more than a +/- 20 percent or a +/- 10 percent good faith cost estimate contained in the report. The

deposit for the study shall be either: (i) the greater of twenty-five percent of the estimated cost of the

study or $250,000; or (ii) the greater of 100 percent of one month’s estimated study cost or $100,000, if

the Interconnection Customer can provide: (1) evidence of applications for all Major Permits, as defined

in Section III.13.1.1.2.2.2 of the Tariff, required in support of the Interconnection Request, or provide

certification that Major Permits are not required or (2) evidence acceptable to the System Operator of At-

Risk Expenditures (excluding Interconnection Study costs) totaling at least the amounts of money in (i)

above, not including the same At-Risk Expenditures demonstrated with the Interconnection System

Impact Study Agreement, if applicable; or (iii) the greater of 100 percent of one month’s estimated study

cost or $100,000, if the Interconnection Request is for a modification to an existing Large Generating

Facility that does not increase the energy capability or capacity capability of the Large Generating

Facility.

Any difference between the study deposit and the actual cost of the Interconnection Facilities Study shall

be paid by or refunded to the Interconnection Customer, except as otherwise provided in Section 13.3. In


issue to the Interconnection Customer an invoice for the cost of the Interconnection Facilities Studies that

have been incurred by the System Operator and/or the Interconnecting Transmission Owner for the

Interconnection Facilities Study, the study agreement and its attachment(s) and the LGIA. The System

Operator and the Interconnecting Transmission Owner may, in the exercise of reasonable discretion,

invoice the Interconnection Customer on a monthly basis for the work to be conducted on the

Interconnection Facilities Study each month. The Interconnection Customer shall pay the invoiced

amounts, to the extent such amounts are greater than the initial deposit, within thirty (30) Calendar Days

of receipt of invoice. The System Operator shall continue to hold the amounts on deposit until settlement

of the final invoice with the Interconnection Customer and the Interconnecting Transmission Owner.

8.2 Scope of Interconnection Facilities Study.

The Interconnection Facilities Study shall specify and estimate the cost of the equipment, engineering,

procurement and construction work needed to implement the conclusions of the Interconnection System

Impact Study in accordance with Good Utility Practice to physically and electrically connect the

Interconnection Facility to the Administered Transmission System. The Interconnection Facilities Study

shall also identify the electrical switching configuration of the connection equipment, including, without

limitation: the transformer, switchgear, meters, and other station equipment; the nature and estimated

cost of any Interconnecting Transmission Owner’s Interconnection Facilities and Network Upgrades

necessary to accomplish the interconnection; and an estimate of the time required to complete the

construction and installation of such facilities. The scope and cost of the Interconnection Facilities Study

shall include completion of any engineering work limited to what is reasonably required to (i) estimate

such aforementioned cost to the accuracy specified by the Interconnection Customer pursuant to Section

8.3, (ii) identify, configurations of required facilities and (iii) identify time requirements for construction

and installation of required facilities.

8.3 Interconnection Facilities Study Procedures.

The System Operator shall coordinate the Interconnection Facilities Study with Interconnecting

Transmission Owner, and any Affected Party as deemed appropriate by the System Operator in

accordance with applicable codes of conduct and confidentiality requirements, pursuant to Section 3.5

above. The System Operator and Interconnecting Transmission Owner shall utilize existing studies to the

extent practicable in performing the Interconnection Facilities Study. The System Operator and

Interconnecting Transmission Owner shall use Reasonable Efforts to complete the study and the System

Operator shall issue a draft Interconnection Facilities Study report to the Interconnection Customer,

Interconnecting Transmission Owner, and any Affected Party as deemed appropriate by the System

Operator in accordance with applicable codes of conduct and confidentiality requirements, within the

following number of days after receipt of an executed Interconnection Facilities Study Agreement: ninety

(90) Calendar Days, with no more than a +/- 20 percent good faith cost estimate contained in the report;

or one hundred eighty (180) Calendar Days, if the Interconnection Customer requests a +/- 10 percent

good faith cost estimate. Such cost estimates either individually or in the aggregate will be provided in

the final study report.

At the request of the Interconnection Customer or at any time the System Operator or Interconnecting

Transmission Owner determines that it will not meet the required time frame for completing the

Interconnection Facilities Study, System Operator shall notify the Interconnection Customer, and any

Affected Party as deemed appropriate by the System Operator in accordance with applicable codes of

conduct and confidentiality requirements, as to the schedule status of the Interconnection Facilities Study.

If the System Operator is unable to complete the Interconnection Facilities Study and issue a draft

Interconnection Facilities Study report within the time required, the System Operator shall notify the

Interconnection Customer, Interconnecting Transmission Owner and any Affected Party as deemed


requirements, and provide an estimated completion date and an explanation of the reasons why additional

time is required.

The Interconnection Customer and appropriate Affected Parties may, within thirty (30) Calendar Days

after receipt of the draft report, provide written comments to the System Operator and Interconnecting

Transmission Owner, which the System Operator shall include in the final report. The System Operator

shall issue the final Interconnection Facilities Study report within fifteen (15) Business Days of receiving

the Interconnection Customer’s comments or promptly upon receiving Interconnection Customer’s

statement that it will not provide comments. The System Operator may reasonably extend such fifteen-

day period upon notice to the Interconnection Customer if the Interconnection Customer’s comments

require the System Operator or Interconnecting Transmission Owner to perform additional analyses or

make other significant modifications prior to the issuance of the final Interconnection Facilities Report.

Upon request, the System Operator and Interconnecting Transmission Owner shall provide the

Interconnection Customer and any Affected Party as deemed appropriate by the System Operator in

accordance with applicable codes of conduct and confidentiality requirements, or any third party

consultant retained by the Interconnection Customer or to any non-market affiliate of the Interconnection

Customer supporting documentation, with workpapers, and databases or data developed in the preparation

of the Interconnection Facilities Study. The recipient(s) of such information shall be subject to the

confidentiality provisions of Section 13.1 and the ISO New England Information Policy, as well as any

other applicable requirement under Applicable Laws and Regulations regulating the disclosure or

confidentiality of such information. To the extent that any applicable information is not covered by any

applicable confidentiality/ disclosure requirements, such information may be provided directly to the

Interconnection Customer.


Within ten (10) Business Days of providing a draft Interconnection Facilities Study report to

Interconnection Customer, the System Operator will convene a meeting of the Interconnecting


System Operator in accordance with applicable codes of conduct and confidentiality requirements to

discuss the results of the Interconnection Facilities Study.

8.5 Re-Study.

If re-study of the Interconnection Facilities Study is required due to (i) a higher queued project dropping

out of the queue, (ii) a modification of a higher queued project subject to Section 4.4, (iii) a re-assessment

of the upgrade responsibilities of a Generating Facility after it receives a Capacity Supply Obligation in

accordance with Section III.13 of the Tariff, or (iv) a modification to a transmission project included in

the Base Case, the System Operator shall so notify The Interconnection Customer and Interconnecting

Transmission Owner in writing. Each re-study shall be conducted serially based on the Queue Position of

each Interconnection Customer, and each re-study shall take no longer than sixty (60) Calendar Days

from the date the re-study commences. Any cost of re-study shall be borne by the Interconnection

Customer being re-studied. If the original Interconnection Facilities Study is complete and the final

invoice has been issued, the re-study shall be performed under a new Interconnection Facilities Study

Agreement.

SECTION 9. ENGINEERING & PROCUREMENT (“E&P”) AGREEMENT.

Prior to executing an LGIA, an Interconnection Customer may request, in order to advance the

implementation of its interconnection, and the Interconnecting Transmission Owner and any Affected

Party shall offer the Interconnection Customer, an E&P Agreement that authorizes the Interconnecting

Transmission Owner and any Affected Party to begin engineering and procurement of long lead-time

items necessary for the establishment of the interconnection. However, the Interconnecting Transmission

Owner or any Affected Party shall not be obligated to offer an E&P Agreement if the Interconnection

Customer is in Dispute Resolution as a result of an allegation that the Interconnection Customer has failed

to meet any milestones or comply with any prerequisites specified in other parts of the LGIP. The E&P

Agreement is an optional procedure and it will not alter the Interconnection Customer’s Queue Position or

Initial Synchronization Date. The E&P Agreement shall provide for the Interconnection Customer to pay

the cost of all activities authorized by the Interconnection Customer, including a deposit of 100 percent of

the estimated engineering and study costs, and to make advance payments or provide other satisfactory

security for such costs.

The Interconnection Customer shall pay the cost of such authorized activities and any cancellation costs

for equipment that is already ordered for its interconnection, which cannot be mitigated as hereafter

described, whether or not such items or equipment later become unnecessary. If the Interconnection

Customer withdraws its application for interconnection or an E&P Agreement is terminated by any Party,

to the extent the equipment ordered can be canceled under reasonable terms, the Interconnection

Customer shall be obligated to pay the associated cancellation costs. To the extent that the equipment

cannot be reasonably canceled, the Interconnecting Transmission Owner or the Affected Party that is a

party to an E&P Agreement may elect: (i) to take title to the equipment, in which event the

Interconnecting Transmission Owner or relevant Affected Party shall refund the Interconnection

Customer any amounts paid by the Interconnection Customer for such equipment and shall pay the cost of

delivery of such equipment, or (ii) to transfer title to and deliver such equipment to the Interconnection

Customer, in which event the Interconnection Customer shall pay any unpaid balance and cost of delivery

of such equipment.

SECTION 10. OPTIONAL INTERCONNECTION STUDY.

10.1 Optional Interconnection Study Agreement.

On or after the date when the Interconnection Customer receives Interconnection System Impact Study

report and no later than five (5) Business Days after the study results meeting to review the report, the

Interconnection Customer may request in writing, and the System Operator in coordination with the

Interconnecting Transmission Owner shall perform, an Optional Interconnection Study. The request shall

describe the assumptions that the Interconnection Customer wishes the System Operator to study within

the scope described in Section 10.2. Within five (5) Business Days after receipt of a request for an

Optional Interconnection Study, the System Operator shall provide to the Interconnecting Transmission

Owner and the Interconnection Customer an Optional Interconnection Study Agreement in the form of

Appendix 5.

The Optional Interconnection Study Agreement shall: (i) specify the technical data that the

Interconnection Customer must provide for each phase of the Optional Interconnection Study, (ii) specify

the Interconnection Customer’s assumptions as to which Interconnection Requests with earlier queue

priority dates will be excluded from the Optional Interconnection Study case, and (iii) specify the System

Operator’s and Interconnecting Transmission Owner’s estimate of the cost of the Optional

Interconnection Study. To the extent known by the System Operator, such estimate shall include any

costs expected to be incurred by any Affected System whose participation is necessary to complete the

Optional Interconnection Study. The Optional Interconnection Study Agreement shall specify that

Interconnection Customer is responsible for the actual cost of the Optional Interconnection Study,

including the cost of developing the study agreement and its attachment(s). Notwithstanding the above,

the System Operator and Interconnecting Transmission Owner shall not be required as a result of an

Optional Interconnection Study request to conduct any additional Interconnection Studies with respect to

any other Interconnection Request.

The Interconnection Customer shall execute the Optional Interconnection Study Agreement within ten

(10) Business Days of receipt and deliver the Optional Interconnection Study Agreement, the required

technical data and the refundable deposit for the Optional Interconnection Study to the System Operator.

The deposit for the study shall be 100 percent of the estimated cost of the study. Any difference between

the study deposit and the actual cost of the Optional Interconnection Study shall be paid by or refunded to

the Interconnection Customer, except as otherwise provided in Section 13.3. In accordance with Section

13.3, the System Operator and/or the Interconnecting Transmission Owner shall issue to the

Interconnection Customer an invoice for the costs of the Optional Interconnection Study that have been

incurred by the System Operator and/or the Interconnecting Transmission Owner for the Optional

Interconnection Study and the study agreement and its attachments(s). The Interconnection Customer

shall pay the invoiced amounts, to the extent such amounts are greater than the initial deposit, within

thirty (30) Calendar Days of receipt of invoice. The System Operator shall continue to hold the amounts

on deposits until settlement of the final invoice with the Interconnection Customer and the

Interconnecting Transmission Owner.

10.2 Scope of Optional Interconnection Study.

The Optional Interconnection Study will consist of a sensitivity analysis based on the assumptions

specified by the Interconnection Customer in the Optional Interconnection Study Agreement. The

Optional Interconnection Study will also identify the Interconnecting Transmission Owner’s

Interconnection Facilities and the Network Upgrades, and the estimated cost thereof, that may be required

to provide transmission service or Interconnection Service based upon the results of the Optional

Interconnection Study. The System Operator shall use Reasonable Efforts to coordinate the study with

any Affected Systems that may be affected by the types of Interconnection Services that are being

studied. The System Operator and Interconnecting Transmission Owner shall utilize existing studies to

the extent practicable in conducting the Optional Interconnection Study.

The Optional Interconnection Study will consist of a short circuit analysis, a stability analysis, a power

flow analysis, including thermal analysis and voltage analysis, a system protection analysis, and any other

analyses that are deemed necessary by the System Operator in consultation with the Interconnecting

Transmission Owner.

10.3 Optional Interconnection Study Procedures.

The executed Optional Interconnection Study Agreement, the prepayment, and technical and other data

called for therein must be provided to the System Operator and Interconnecting Transmission Owner

within ten (10) Business Days of the Interconnection Customer receipt of the Optional Interconnection

Study Agreement. The System Operator and Interconnecting Transmission Owner shall use Reasonable

Efforts to complete the Optional Interconnection Study within a mutually agreed-upon time period

specified within the Optional Interconnection Study Agreement. If the System Operator and

Interconnecting Transmission Owner are unable to complete the Optional Interconnection Study within

such time period, the System Operator shall notify the Interconnection Customer and provide an

estimated completion date and an explanation of the reasons why additional time is required. Upon

request, the System Operator and Interconnecting Transmission Owner shall provide the Interconnection

Customer supporting documentation and workpapers and databases or data developed in the preparation

of the Optional Interconnection Study to any third party consultant retained by the Interconnection

Customer or to any non-market affiliate of the Interconnection Customer. The recipient(s) of such

information shall be subject to the confidentiality provisions of Section 13.1 and the ISO New England

Information Policy, as well as any other applicable requirement under Applicable Laws and Regulations

regulating the disclosure or confidentiality of such information. To the extent that any applicable

information is not covered by any applicable confidentiality/disclosure requirements, such information

may be provided directly to the Interconnection Customer.


Within ten (10) Business Days of providing an Optional Interconnection Study report to Interconnection

Customer, System Operator will convene a meeting of the Interconnecting Transmission Owner,

Interconnection Customer, and any Affected Party as deemed appropriate by the System Operator in

accordance with applicable codes of conduct and confidentiality requirements to discuss the results of the

Optional Interconnection Study.

10.5 Interconnection Agreement Developed Based on Optional Interconnection Study.

If the LGIA for a Large Generating Facility is based on the results of an Optional Interconnection Study,

the LGIA shall reflect the conditions studied and any obligations that may involve: (i) additional studies if

such conditions change, (ii) operational limits, or (iii) financial support for transmission upgrades.

SECTION 11. STANDARD LARGE GENERATOR INTERCONNECTION AGREEMENT

(LGIA).

11.1 Tender.

Interconnection Customer shall tender comments or provide notice, in writing, to the System Operator

and Interconnecting Transmission Owner that the Interconnection Customer has no comments on the draft

Interconnection Facilities Study report or on the draft Interconnection System Impact Study report if the

Interconnection Customer waived the Interconnection Facilities Study, within thirty (30) Calendar Days

of receipt of the report. Except as provided in the E&P Agreement or any mutual agreement by the

entities that would be Parties to the LGIA, the System Operator shall initiate the development of the

LGIA process within fifteen (15) Calendar Days after the comments are submitted or waived, by

tendering to the Interconnection Customer a draft LGIA, together with draft appendices completed by the

System Operator, in conjunction with the Interconnecting Transmission Owner to the extent practicable.

The draft LGIA shall be in the form of the System Operator’s Commission-approved standard form LGIA

which is in Appendix 6 to Schedule 22. The Interconnection Customer shall return the Interconnection

Customer specific information required to complete the form of LGIA, including the appendices, in

Appendix 6 of Schedule 22 that the Interconnection Customer is willing to execute within thirty (30)

Calendar Days after receipt of the draft from the System Operator.

11.2 Negotiation.

Notwithstanding Section 11.1, at the request of the Interconnection Customer the System Operator and

Interconnecting Transmission Owner shall begin negotiations with the Interconnection Customer

concerning the appendices to the LGIA at any time after the Interconnection Facilities Study is complete

or after the Interconnection System Impact Study is complete if the Interconnection Customer intends to

waive the Interconnection Facilities Study. The System Operator, Interconnection Customer, and

Interconnecting Transmission Owner shall negotiate concerning any disputed provisions of the

appendices to the draft LGIA for not more than sixty (60) Calendar Days after tender by the System

Operator of the draft LGIA pursuant to Section 11. If the Interconnection Customer determines that

negotiations are at an impasse, it may request termination of the negotiations at any time after tender of

the draft LGIA pursuant to Section 11.1 and request submission of the unexecuted LGIA with the

Commission or initiate Dispute Resolution procedures pursuant to Section 13.5. If the Interconnection

Customer requests termination of the negotiations, but within sixty (60) Calendar Days thereafter fails to

request either the filing of the unexecuted LGIA or initiate Dispute Resolution, it shall be deemed to have

withdrawn its Interconnection Request. Unless otherwise agreed by the Parties, if the Interconnection

Customer has not executed the LGIA, requested filing of an unexecuted LGIA, or initiated Dispute

Resolution procedures pursuant to Section 13.5 within sixty (60) Calendar Days of tender of by the

System Operator of the draft LGIA pursuant to Section 11.1, it shall be deemed to have withdrawn its

Interconnection Request. The System Operator and Interconnecting Transmission Owner shall provide to

the Interconnection Customer a final LGIA within fifteen (15) Business Days after the mutually agreed

completion of the negotiation process.

11.3 Evidence to be Provided by Interconnection Customer; Execution and Filing of LGIA.

11.3.1 Evidence to be Provided by Interconnection Customer.

11.3.1.1 Site Control. Within fifteen (15) Business Days after receipt of the final LGIA, the

Interconnection Customer shall provide (A) to the System Operator, reasonable evidence of continued

Site Control, or (B) to the Interconnecting Transmission Owner, posting of $250,000, non-refundable

additional security, which shall be applied toward future construction costs. Interconnection Customer

does not need to demonstrate Site Control where the Interconnection Request is for a modification to the

Interconnection Customer’s existing Large Generating Facility and the Interconnection Customer has

certified in the Interconnection Request that it has Site Control and that the modification proposed in the

Interconnection Request does not require additional real property.

11.3.1.2 Development Milestones. Within fifteen (15) Business Days after receipt of the final LGIA,

the Interconnection Customer also shall provide to the System Operator reasonable evidence that one or

more of the following milestones in the development of the Large Generating Facility, to be elected by

the Interconnection Customer, has been achieved: (i) the execution of a contract for the supply or

transportation of fuel to the Large Generating Facility; (ii) the execution of a contract for the supply of

cooling water to the Large Generating Facility; (iii) execution of a contract for the engineering for,

procurement of major equipment for, or construction of, the Large Generating Facility; (iv) execution of a

contract for the sale of electric energy or capacity from the Large Generating Facility; (v) application for

an air, water, or land use permit.

At the same time, the Interconnection Customer shall commit to a schedule for the payment of upgrades

identified in the Interconnection Studies or an E&P Agreement and either: (A) provide evidence of

approvals for all Major Permits, as defined in Section III.13.1.1.2.2.2(a) of the Tariff, or (B) provide a

refundable deposit to the Interconnecting Transmission Owner, at execution of the LGIA, of 20 percent of

the total costs for the Interconnection Facilities and other upgrades identified in the Interconnection

Studies or an E&P Agreement, unless the Interconnecting Transmission Owner’s expenditure schedule

for the Interconnection Facilities and other upgrades calls for an initial payment of greater than 20 percent

of the total upgrade costs, in which case the scheduled initial payment must instead be made at time of

LGIA execution. If the Interconnection Customer selects option (B) above, it shall also commit in the

LGIA to the achievement of: (i) milestones for the completion of Major Permit approvals, and (ii) in the

case of a CNR Interconnection Request, milestones to align the LGIA with the fulfillment of terms

outlined in Section III.13 of the Tariff for participation in the Forward Capacity Market.

11.3.2 Execution and Filing of LGIA. Within fifteen (15) Business Days after receipt of the final

LGIA, the Interconnection Customer shall either: (i) execute three (3) originals of the tendered LGIA and

return one to the System Operator and one to the Interconnecting Transmission Owner; or (ii) request in

writing that the System Operator and Interconnecting Transmission Owner jointly file with the

Commission an LGIA in unexecuted form. As soon as practicable, but not later than ten (10) Business

Days after receiving either the executed originals of the tendered LGIA (if it does not conform with a

Commission-approved standard form of interconnection agreement) or the request to file an unexecuted

LGIA, the System Operator and Interconnecting Transmission Owner, in accordance with Section 11.3.3

or Section 11.3.4, as appropriate , shall jointly file the LGIA with the Commission, together with its

explanation of any matters as to which the System Operator, Interconnection Customer or Interconnecting

Transmission Owner disagree and support for the costs that the Interconnecting Transmission Owner

proposes to charge to the Interconnection Customer under the LGIA. An unexecuted LGIA should

contain terms and conditions deemed appropriate by the System Operator and Interconnecting

Transmission Owner for the Interconnection Request. If the Parties agree to proceed with design,

procurement, and construction of facilities and upgrades under the agreed-upon terms of the unexecuted

LGIA, they may proceed pending Commission action.

With respect to the interconnection of an Interconnection Customer under Schedule 22, the LGIA shall be

a three-party agreement among the Interconnecting Transmission Owner, the System Operator and the

Interconnection Customer. If Interconnecting Transmission Owner, System Operator and Interconnection

Customer agree to the terms and conditions of a specific LGIA, or any amendments to such an LGIA,

then the System Operator and Interconnecting Transmission Owner shall jointly file the executed LGIA,

or amendment thereto, with the Commission under Section 205 of the Federal Power Act. To the extent

the Interconnecting Transmission Owner, System Operator and Interconnection Customer cannot agree to

proposed variations from the standard form of LGIA in Appendix 6 or cannot otherwise agree to the

terms and conditions of the LGIA for such Large Generating Unit, or any amendments to such an LGIA,

then the System Operator and Interconnecting Transmission Owner shall jointly file an unexecuted LGIA,

or amendment thereto, with the Commission under Section 205 of the Federal Power Act and shall

identify the areas of disagreement in such filing, provided that, in the event of disagreement on terms and

conditions of the LGIA related to the costs of upgrades to such Interconnecting Transmission Owner’s

transmission facilities, the anticipated schedule for the construction of such upgrades, any financial

obligations of the Interconnecting Transmission Owner, and any provisions related to physical impacts of

the interconnection on the Interconnecting Transmission Owner’s transmission facilities or other assets,

then the standard applicable under Section 205 of the Federal Power Act shall apply only to the

Interconnecting Transmission Owner’s position on such terms and conditions.

11.3.3 The Interconnecting Transmission Owner, acting on its own or jointly with the System Operator,

may initiate a filing to amend this LGIP and the standard form of LGIA in Appendix 6 under Section 205

of the Federal Power Act and shall include in such filing the views of System Operator, provided that the

standard applicable under Section 205 of the Federal Power Act shall apply only to the Interconnecting

Transmission Owner’s position on any financial obligations of the Interconnecting Transmission Owner

or the Interconnection Customer(s), and any provisions related to physical impacts of the interconnection

on the Interconnecting Transmission Owner’s transmission facilities or other assets.

11.4 Commencement of Interconnection Activities.

If the Interconnection Customer executes the final LGIA, the System Operator, Interconnection Customer

and Interconnecting Transmission Owner shall perform their respective obligations in accordance with the

terms of the LGIA, subject to modification by the Commission. Upon submission of an unexecuted

LGIA, the System Operator, Interconnection Customer and Interconnecting Transmission Owner shall

promptly comply with the unexecuted LGIA, subject to modification by the Commission.

SECTION 12. CONSTRUCTION OF INTERCONNECTING TRANSMISSION OWNER

INTERCONNECTION FACILITIES AND NETWORK UPGRADES.

12.1 Schedule.

The Interconnection Customer, Interconnecting Transmission Owner and any other Affected Party shall

negotiate in good faith concerning a schedule for the construction of the Interconnecting Transmission

Owner’s Interconnection Facilities and the Network Upgrades.

12.2 Construction Sequencing.

12.2.1 General. In general, the Initial Synchronization Date of an Interconnection Customer seeking

interconnection to the Administered Transmission System will determine the sequence of construction of

Network Upgrades.

12.2.2 Advance Construction of Network Upgrades that are an Obligation of an Entity other than

the Interconnection Customer. An Interconnection Customer with an executed or unexecuted, but filed

with the Commission, LGIA, in order to maintain its Initial Synchronization Date, may request that the

Interconnecting Transmission Owner or appropriate Affected Party advance to the extent necessary the

completion of Network Upgrades that: (i) were assumed in the Interconnection Studies for such

Interconnection Customer, (ii) are necessary to support such Initial Synchronization Date, and (iii) would

otherwise not be completed, pursuant to a contractual obligation of an entity other than the

Interconnection Customer that is seeking interconnection to the Administered Transmission System, in

time to support such Initial Synchronization Date. Upon such request, the Interconnecting Transmission

Owner or appropriate Affected Party will use Reasonable Efforts to advance the construction of such

Network Upgrades to accommodate such request; provided that the Interconnection Customer commits to

pay the Interconnecting Transmission Owner or appropriate Affected Party; (i) any associated expediting

costs and (ii) the cost of such Network Upgrades.

The Interconnecting Transmission Owner or appropriate Affected Party will refund to the Interconnection

Customer both the expediting costs and the cost of Network Upgrades, in accordance with Article 11.4 of

the LGIA. Consequently, the entity with a contractual obligation to construct such Network Upgrades

shall be obligated to pay only that portion of the costs of the Network Upgrades that the Interconnecting

Transmission Owner or appropriate Affected Party has not refunded to the Interconnection Customer.

Payment by that entity with a contractual obligation to construct such Network Upgrades shall be due on

the date that it would have been due had there been no request for advance construction. The

Interconnecting Transmission Owner or appropriate Affected Party shall forward to the Interconnection

Customer the amount paid by the entity with a contractual obligation to construct the Network Upgrades

as payment in full for the outstanding balance owed to the Interconnection Customer. The

Interconnecting Transmission Owner or appropriate Affected Party then shall refund to that entity the

amount that it paid for the Network Upgrades, in accordance with Article 11.4 of the LGIA.

12.2.3 Advancing Construction of Network Upgrades that are Part of the Regional System Plan of

the System Operator. An Interconnection Customer with an LGIA, in order to maintain its Initial

Synchronization Date, may request that Interconnecting Transmission Owner or appropriate Affected

Party advance to the extent necessary the completion of Network Upgrades that: (i) are necessary to

support such Initial Synchronization Date and (ii) would otherwise not be completed, pursuant to the

Regional System Plan, in time to support such Initial Synchronization Date. Upon such request, the

Interconnecting Transmission Owner or appropriate Affected Party will use Reasonable Efforts to

advance the construction of such Network Upgrades to accommodate such request; provided that the

Interconnection Customer commits to pay the Interconnecting Transmission Owner or appropriate

Affected Party any associated expediting costs.

12.2.4 Amended Interconnection System Impact Study. An Interconnection System Impact Study

will be amended to determine the facilities necessary to support the requested Initial Synchronization

Date. This amended study will include those transmission and Large Generating Facilities that are

expected to be in service on or before the requested Initial Synchronization Date. The LGIA will also be

amended to reflect the results of the Amended Interconnection System Impact Study and any changes in

obligations, including financial support, of the Parties.

SECTION 13. MISCELLANEOUS.

13.1 Confidentiality.

Confidential Information shall include, without limitation, all information treated as confidential under

the ISO New England Information Policy, all information obtained from third parties under

confidentiality agreements, all information relating to a Party’s technology, research and development,

business affairs, and pricing, and any information supplied by any of the Parties to the others prior to the

execution of an LGIA.

Information is Confidential Information only if it is clearly designated or marked in writing as

confidential on the face of the document, or, if the information is conveyed orally or by inspection, if the

Party providing the information orally informs the Party receiving the information that the information is

confidential.

If requested by any Party, the other Party(ies) shall provide in writing, the basis for asserting that the

information referred to in this Article warrants confidential treatment, and the requesting Party may

disclose such writing to the appropriate Governmental Authority. Each Party shall be responsible for the

costs associated with affording confidential treatment to its information.

13.1.1 Scope. Confidential Information shall not include information that the receiving Party can

demonstrate: (1) is generally available to the public other than as a result of a disclosure by the receiving

Party; (2) was in the lawful possession of the receiving Party on a non-confidential basis before receiving

it from the disclosing Party; (3) was supplied to the receiving Party without restriction by a third party,

who, to the knowledge of the receiving Party after due inquiry, was under no obligation to the disclosing

Party to keep such information confidential; (4) was independently developed by the receiving Party

without reference to Confidential Information of the disclosing Party; (5) is, or becomes, publicly known,

through no wrongful act or omission of the receiving Party or Breach of the LGIA; or (6) is required, in

accordance with Section 13.1.6, Order of Disclosure, to be disclosed by any Governmental Authority or is

otherwise required to be disclosed by law or subpoena, or is necessary in any legal proceeding

establishing rights and obligations under the LGIA. Information designated as Confidential Information

will no longer be deemed confidential if the Party that designated the information as confidential notifies

the other Parties that it no longer is confidential.

13.1.2 Release of Confidential Information. A Party shall not release or disclose Confidential

Information to any other person, except to its Affiliates (limited by the Standards of Conduct

requirements), employees, consultants, or to parties who may be or considering providing financing to or

equity participation with Interconnection Customer, or to potential purchasers or assignees of

Interconnection Customer, on a need-to-know basis in connection with these procedures, unless such

person has first been advised of the confidentiality provisions of this Section 13.1 and has agreed to

comply with such provisions. Notwithstanding the foregoing, a Party providing Confidential Information

to any person shall remain primarily responsible for any release of Confidential Information in

contravention of this Section 13.1.

13.1.3 Rights. Each Party retains all rights, title, and interest in the Confidential Information that each

Party discloses to the other Party(ies). The disclosure by each Party to the other Party(ies) of Confidential

Information shall not be deemed a waiver by any Party or any other person or entity of the right to protect

the Confidential Information from public disclosure.

13.1.4 No Warranties. By providing Confidential Information, a Party does not make any warranties or

representations as to its accuracy or completeness. In addition, by supplying Confidential Information, a

Party does not obligate itself to provide any particular information or Confidential Information to the

other Party(ies) nor to enter into any further agreements or proceed with any other relationship or joint

venture.

13.1.5 Standard of Care. Each Party shall use at least the same standard of care to protect Confidential

Information it receives as it uses to protect its own Confidential Information from unauthorized

disclosure, publication or dissemination. Each Party may use Confidential Information solely to fulfill its

obligations to the other Party(ies) under these procedures or its regulatory requirements.

13.1.6 Order of Disclosure. If a court or a Government Authority or entity with the right, power, and

apparent authority to do so requests or requires a Party, by subpoena, oral deposition, interrogatories,

requests for production of documents, administrative order, or otherwise, to disclose Confidential

Information, that Party shall provide the other Party(ies) with prompt notice of such request(s) or

requirement(s) so that the other Party(ies) may seek an appropriate protective order or waive compliance

with the terms of the LGIA. Notwithstanding the absence of a protective order or waiver, the Party may

disclose such Confidential Information which, in the opinion of its counsel, the Party is legally compelled

to disclose. Each Party will use Reasonable Efforts to obtain reliable assurance that confidential

treatment will be accorded any Confidential Information so furnished.

13.1.7 Remedies. The Parties agree that monetary damages would be inadequate to compensate a Party

for the other Party’s(ies’) Breach of its obligations under this Section 13.1. Each Party accordingly agrees

that the other Party(ies) shall be entitled to equitable relief, by way of injunction or otherwise, if the first

Party Breaches or threatens to Breach its obligations under this Section 13.1, which equitable relief shall

be granted without bond or proof of damages, and the receiving Party shall not plead in defense that there

would be an adequate remedy at law. Such remedy shall not be deemed an exclusive remedy for the

Breach of this Section 13.1, but shall be in addition to all other remedies available at law or in equity.

The Parties further acknowledge and agree that the covenants contained herein are necessary for the

protection of legitimate business interests and are reasonable in scope. No Party, however, shall be liable

for indirect, incidental, or consequential or punitive damages of any nature or kind resulting from or

arising in connection with this Section 13.1.

13.1.8 Disclosure to the Commission, its Staff, or a State. Notwithstanding anything in this Section

13.1 to the contrary, and pursuant to 18 CFR section 1b.20, if the Commission or its staff, during the

course of an investigation or otherwise, requests information from one of the Parties that is otherwise

required to be maintained in confidence pursuant to the LGIP, the Party shall provide the requested

information to the Commission or its staff, within the time provided for in the request for information. In

providing the information to the Commission or its staff, the Party must, consistent with 18 CFR. section

388.112, request that the information be treated as confidential and non-public by the Commission and its

staff and that the information be withheld from public disclosure. Parties are prohibited from notifying

the other Party(ies) prior to the release of the Confidential Information to the Commission or its staff.

The Party shall notify the other Party(ies) to the LGIA when its is notified by the Commission or its staff

that a request to release Confidential Information has been received by the Commission, at which time

any of the Parties may respond before such information would be made public, pursuant to 18 CFR

section 388.112. Requests from a state regulatory body conducting a confidential investigation shall be

treated in a similar manner, consistent with applicable state rules, regulations and Section 13.1.

13.1.9 Subject to the exception in Section 13.1.8, any information that a Party claims is competitively

sensitive, commercial or financial information (“Confidential Information”) shall not be disclosed by the

other Party(ies) to any person not employed or retained by the other Party(ies), except to the extent

disclosure is (i) required by law; (ii) reasonably deemed by the disclosing Party to be required to be

disclosed in connection with a dispute between or among the Parties, or the defense of litigation or

dispute; (iii) otherwise permitted by consent of the other Party(ies), such consent not to be unreasonably

withheld; or (iv) necessary to fulfill its obligations under this LGIP or as a transmission service provider

or a Control Area operator including disclosing the Confidential Information to an RTO or ISO or to a

subregional, regional or national reliability organization or planning group. The Party asserting

confidentiality shall notify the other Party(ies) in writing of the information it claims is confidential.

Prior to any disclosures of the other Party’s(ies’) Confidential Information under this subparagraph, or if

any third party or Governmental Authority makes any request or demand for any of the information

described in this subparagraph, the disclosing Party agrees to promptly notify the other Party(ies) in

writing and agrees to assert confidentiality and cooperate with the other Party(ies) in seeking to protect

the Confidential Information from public disclosure by confidentiality agreement, protective order or

other reasonable measures.

13.1.10 This provision shall not apply to any information that was or is hereafter in the public domain

(except as a result of a Breach of this provision).

13.1.11 The System Operator and Interconnecting Transmission Owner shall, at Interconnection

Customer’s election, destroy, in a confidential manner, or return the Confidential Information provided at

the time when Confidential Information is no longer needed.

13.2 Delegation of Responsibility.

The System Operator and Interconnecting Transmission Owner, or any Affected Party may use the

services of subcontractors as it deems appropriate to perform its obligations under this LGIP. The Party

using the services of a subcontractor shall remain primarily liable to the Interconnection Customer for the

performance of such subcontractors and compliance with its obligations of this LGIP. The subcontractor

shall keep all information provided confidential and shall use such information solely for the performance

of such obligation for which it was provided and no other purpose.

13.3 Obligation for Study Costs.

The System Operator and the Interconnecting Transmission Owner shall charge, and the Interconnection

Customer shall pay, the actual costs of the Interconnection Studies. Any difference between the study

deposit and the actual cost of the applicable Interconnection Study shall be paid by or refunded, except as

otherwise provided herein, to the Interconnection Customer or offset against the cost of any future

Interconnection Studies associated with the applicable Interconnection Request prior to beginning of any

such future Interconnection Studies. Any invoices for Interconnection Studies shall include a detailed and

itemized accounting of the cost of each Interconnection Study. The Interconnection Customer shall pay

any such undisputed costs within thirty (30) Calendar Days of receipt of an invoice therefore. The

System Operator and Interconnecting Transmission Owner shall not be obligated to perform or continue

to perform any studies unless the Interconnection Customer has paid all undisputed amounts in

compliance herewith.

13.4 Third Parties Conducting Studies.

If (i) at the time of the signing of an Interconnection Study Agreement there is disagreement as to the

estimated time to complete an Interconnection Study, (ii) the Interconnection Customer receives notice

pursuant to Sections 6.3, 7.4 or 8.3 that the System Operator or Interconnecting Transmission Owner will

not complete an Interconnection Study within the applicable timeframe for such Interconnection Study, or

(iii) the Interconnection Customer receives neither the Interconnection Study nor a notice under Sections

6.3, 7.4 or 8.3 within the applicable timeframe for such Interconnection Study, then the Interconnection

Customer may request, which request will not be unreasonably denied, that the System Operator and

Interconnecting Transmission Owner utilize a third party consultant reasonably acceptable to the System

Operator, Interconnection Customer, Interconnecting Transmission Owner and any appropriate Affected

Party, to perform such Interconnection Study under the direction of the System Operator or

Interconnecting Transmission Owner as applicable. At other times, System Operator or Interconnecting

Transmission Owner may also utilize a third party consultant to perform such Interconnection Study,

either in response to a general request of the Interconnection Customer, or on its own volition.

In all cases, use of a third party consultant shall be in accord with Article 26 of the LGIA (Subcontractors)

and limited to situations where the System Operator or Interconnecting Transmission Owner determines

that doing so will help maintain or accelerate the study process for the Interconnection Customer’s

pending Interconnection Request and not interfere with the System Operator and Interconnecting

Transmission Owner’s progress on Interconnection Studies for other pending Interconnection Requests.

In cases where the Interconnection Customer requests use of a third party consultant to perform such

Interconnection Study, the Interconnection Customer, System Operator and Interconnecting Transmission

Owner shall negotiate all of the pertinent terms and conditions, including reimbursement arrangements

and the estimated study completion date and study review deadline. The System Operator and

Interconnecting Transmission Owner shall convey all workpapers, data bases, study results and all other

supporting documentation prepared to date with respect to the Interconnection Request as soon as soon as

practicable upon the Interconnection Customer’s request subject to the confidentiality provision in

Section 13.1 and the ISO New England Information Policy, as well as any other applicable requirement

under Applicable Laws and Regulations regulating the disclosure or confidentiality of such information.

In any case, such third party contract may be entered into with the System Operator, Interconnection

Customer, or Interconnecting Transmission Owner at the System Operator and Interconnecting

Transmission Owner’s discretion. In the case of (iii) the Interconnection Customer maintains its right to

submit a claim to Dispute Resolution to recover the costs of such third party study. Such third party

consultant shall be required to comply with this LGIP, Article 26 of the LGIA (Subcontractors), and the

relevant Tariff procedures and protocols as would apply if the System Operator and Interconnecting

Transmission Owner were to conduct the Interconnection Study and shall use the information provided to

it solely for purposes of performing such services and for no other purposes.

The System Operator and Interconnecting Transmission Owner shall cooperate with such third party

consultant and Interconnection Customer to complete and issue the Interconnection Study in the shortest

reasonable time.

13.5 Disputes.

13.5.1 Submission. In the event a Party has a dispute, or asserts a claim, that arises out of or in

connection with the LGIA, the LGIP, or their performance, such Party (the “Disputing Party”) shall

provide the other Party(ies) with written notice of the dispute or claim (“Notice of Dispute”). Such

dispute or claim shall be referred to a designated senior representative of each Party for resolution on an

informal basis as promptly as practicable after receipt of the Notice of Dispute by the other Party(ies). In

the event the designated representatives are unable to resolve the claim or dispute through unassisted or

assisted negotiations within thirty (30) Calendar Days of the other Party’s(ies’) receipt of the Notice of

Dispute, such claim or dispute may, upon mutual agreement of the Parties, be submitted to arbitration and

resolved in accordance with the arbitration procedures set forth below. In the event the Parties do not

agree to submit such claim or dispute to arbitration, after thirty (30) Calendar Days, then (i) in the case of

disputes arising out of or in conjunction with the LGIA, the System Operator and Interconnecting

Transmission Owner shall jointly file an unexecuted LGIA, or amendment thereto, with the Commission

in accordance with Section 11.3.4, or (ii) in the case of disputes arising out of or in connection with any

other matter regarding the administration of the LGIP, the System Operator may terminate the

Interconnection Request and the Interconnection Customer may seek relief pursuant to Section 206 of the

Federal Power Act. Each Party may exercise whatever rights and remedies it may have in equity or at law

consistent with the terms of this Schedule 22.

13.5.2 External Arbitration Procedures. Any arbitration initiated under these procedures shall be

conducted before a single neutral arbitrator appointed by the Parties. If the Parties fail to agree upon a

single arbitrator within ten (10) Calendar Days of the submission of the dispute to arbitration, each Party

shall choose one arbitrator who shall sit on a three-member arbitration panel. The arbitrator so chosen by

the System Operator shall chair the arbitration panel. In either case, the arbitrators shall be

knowledgeable in electric utility matters, including electric transmission and bulk power issues, and shall

not have any current or past substantial business or financial relationships with any party to the arbitration

(except prior arbitration). The arbitrator(s) shall provide each of the Parties an opportunity to be heard

and, except as otherwise provided herein, shall conduct the arbitration in accordance with the Commercial

Arbitration Rules of the American Arbitration Association (“Arbitration Rules”) and any applicable

Commission regulations or RTO rules; provided, however, in the event of a conflict between the

Arbitration Rules and the terms of this Section 13, the terms of this Section 13 shall prevail.

13.5.3 Arbitration Decisions. Unless otherwise agreed by the Parties, the arbitrator(s) shall render a

decision within ninety (90) Calendar Days of appointment and shall notify the Parties in writing of such

decision and the reasons for such decision. The arbitrator(s) shall be authorized only to interpret and

apply the provisions of the LGIA and LGIP and shall have no power to modify or change any provision

of the LGIA and LGIP in any manner. The decision of the arbitrator(s) shall be final and binding upon

the Parties, and judgment on the award may be entered in any court having jurisdiction. The decision of

the arbitrator(s) may be appealed solely on the grounds that the conduct of the arbitrator(s), or the

decision itself, violated the standards set forth in the Federal Arbitration Act or the Administrative

Dispute Resolution Act. The final decision of the arbitrator must also be filed with the Commission if it

affects jurisdictional rates, terms and conditions of service, Interconnection Facilities, or Network

Upgrades.

13.5.4 Costs. Each Party shall be responsible for its own costs incurred during the arbitration process

and for the following costs, if applicable: (1) the cost of the arbitrator chosen by the Party to sit on the

three-member panel and one-third of any associated arbitration costs; or (2) one-third the cost of the

single arbitrator jointly chosen by the Parties and one-third of any associated arbitration costs.

13.6 Local Furnishing Bonds.

13.6.1 Facilities Financed by Local Furnishing Bonds. This provision is applicable only to

interconnections associated with facilities financed for the local furnishing of electric energy with tax-

exempt bonds, as described in Section 142(f) of the Internal Revenue Code ("local furnishing bonds").

Notwithstanding any other provision of this LGIA and LGIP, the Interconnecting Transmission Owner

shall not be required to provide Interconnection Service to the Interconnection Customer pursuant to this

LGIA and LGIP if the provision of such Interconnection Service would jeopardize the tax-exempt status

of any local furnishing bond(s) used to finance the Interconnecting Transmission Owner’s facilities that

would be used in providing such Interconnection Service.

13.6.2 Alternative Procedures for Requesting Interconnection Service. If the Interconnecting

Transmission Owner determines that the provision of Interconnection Service requested by the

Interconnection Customer would jeopardize the tax-exempt status of any local furnishing bond(s) used to

finance its facilities that would be used in providing such Interconnection Service, it shall advise the

Interconnection Customer within thirty (30) Calendar Days of receiving notice of the Interconnection

Request. The Interconnection Customer thereafter may renew its Interconnection Request using the

process specified in the Tariff.

APPENDICES TO LGIP

APPENDIX 1 INTERCONNECTION REQUEST

APPENDIX 2 INTERCONNECTION FEASIBILITY STUDY AGREEMENT

APPENDIX 3 INTERCONNECTION SYSTEM IMPACT STUDY AGREEMENT

APPENDIX 4 INTERCONNECTION FACILITIES STUDY AGREEMENT

APPENDIX 5 OPTIONAL INTERCONNECTION STUDY AGREEMENT

APPENDIX 6 LARGE GENERATOR INTERCONNECTION AGREEMENT

APPENDIX 1

INTERCONNECTION REQUEST

The undersigned Interconnection Customer submits this request to interconnect its Large

Generating Facility to the Administered Transmission System under Schedule 22 - Large

Generator Interconnection Procedures (“LGIP”) of the ISO New England Inc. Open Access

Transmission Tariff (the “Tariff”). Capitalized terms have the meanings specified in the Tariff.

PROJECT INFORMATION

Proposed Project Name:

1. This Interconnection Request is for (check one):

__________ A proposed new Large Generating Facility

__________ An increase in the generating capacity or a modification that has the potential to be

a Material Modification of an existing Generating Facility

__________ Commencement of participation in the wholesale markets by an existing Generating

Facility

__________ A change from Network Resource Interconnection Service to Capacity Network

Resource Interconnection Service

2. The types of Interconnection Service requested:

__________ Network Resource Interconnection Service (energy capability only)

__________ Capacity Network Resource Interconnection Service (energy capability and capacity

capability)

If Capacity Network Resource Interconnection Service, does Interconnection

Customer request Long Lead Facility treatment? Check: ____Yes or ___ No

If yes, provide, together with this Interconnection Request, the Long Lead Facility

deposit and other required information as specified in Section 3.2.3 of the LGIP,

including (if the Large Generating Facility will be less than 100 MW) a justification

for Long Lead Facility treatment.

3. This Interconnection Customer requests (check one, selection is not required as part of the

initial Interconnection Request):

__________ A Feasibility Study to be completed as a separate and distinct study

__________ A System Impact Study with the Feasibility Study to be performed as the first step

of the study

(The Interconnection Customer shall select either option and may revise any earlier

selection up to within five (5) Business Days following the Scoping Meeting.)

4. The Interconnection Customer shall provide the following information:

Address or Location of the Facility (including Town/City, County and State):

_____________________________________________________________________________________

_____________________________________________________________________________________

_____________________________________________________________________________________

Approximate location of the proposed Point of Interconnection (information is not required as part

of the initial Interconnection Request):

_____________________________________________________________________________________

Type of Generating Facility to be Constructed:

Generating Facility Fuel Type:

_

Generating Facility Capacity (MW):

Maximum Net MW

Electrical Output

Maximum Gross

MW Electrical

Output

At or above 90 degrees F




General description of the equipment configuration (# of units and GSUs):

_____________________________________________________________________________________

____________________________________________________________________________________

Requested Commercial Operations Date:

Requested Initial Synchronization Date:

Requested In Service Date:

Evidence of Site Control (check one):

__________ If for Capacity Network Resource Interconnection Service, Site Control is provided

herewith, as required.

__________ If for Network Resource Interconnection Service: (Check one)

___ Is provided herewith

___ In lieu of evidence of Site Control, a $10,000 deposit is provided herewith

(refundable within the cure period as described in Section 3.3.3 of the LGIP).

__________ Site Control is not provided because the proposed modification is to the

Interconnection Customer’s existing Large Generating Facility and, by checking

this option, the Interconnection Customer certifies that it has Site Control and that

the proposed modification does not require additional real property.

The technical data specified within the applicable attachment to this form (check one):

__________ Is included with the submittal of this Interconnection Request form

__________ Will be provided on or before the execution and return of the Feasibility Study

Agreement (Attachment B) or the System Impact Study Agreement (Attachment A),

as applicable

The ISO will post the Project Information on the ISO web site under “New Interconnections” and

OASIS.

CUSTOMER INFORMATION

Company Name:_____________________________________________________________________

ISO Customer ID# (If available):_______________________________________________________

(Interconnection Customer)

Company Address: PO Box No.:

____________________________________________________________

Street Address:____________________________________________________

City, State ZIP:

Company Representative: Name: ____________________________________________________

Title: ___________________________________________________

Company Representative’s Company and Address (if different from above):

Company Name:

PO Box No.:

Street Address:

City, State ZIP:

Phone: __________________ FAX: ___________________ email:___________________________

This Interconnection Request is submitted by:

Authorized Signature:_________________________________________________________________

Name (type or print):_________________________________________________________________

Title:______________________________________________________________________________

Date:_______________________________________________________________________________

In order for an Interconnection Request to be considered a valid request, it must:

(a) Be accompanied by a deposit of $50,000.00, which may be refundable in accordance with Section

3.3.1 of the LGIP;

(b) For Capacity Network Resource Interconnection Service, include documentation

demonstrating Site Control. If for Network Resource Interconnection Service, demonstrate Site

Control or post an additional deposit of $10,000.00. If the Interconnection Customer with an

Interconnection Request for Network Resource Interconnection Service demonstrates Site Control

within the cure period specified in Section 3.3.1 of the LGIP, the additional deposit of $10,000.00

shall be refundable (An Interconnection Customer does not need to demonstrate Site Control for

an Interconnection Request for a modification to its existing Large Generating Facility where the

Interconnection Customer has certified that it has Site Control and that the proposed modification

does not require additional real property);

(c) Include a detailed map (2 copies), such as a map of the quality produced by the U.S. Geological

Survey, which clearly indicates the site of the new facility and pertinent surrounding structures;

and

(d) Include all information required on the Interconnection Request form; and

(e) Include the deposit and all information required for Long Lead Facility treatment, if such

treatment is requested in accordance with Section 3.2.3 of the LGIP.

Attachment A (page 1) To Appendix 1

Interconnection Request Technical Data Required For

Interconnection System Impact Study

The technical data required below must be submitted no later than the date of execution of the

System Impact Study Agreement pursuant to Section 7.2 of the LGIP.

LARGE GENERATING FACILITY DATA

UNIT RATINGS

Kva F Voltage

Power Factor

Speed (RPM) Connection (e.g. Wye) _____

Short Circuit Ratio Frequency, Hertz _____

Stator Amperes at Rated Kva Field Volts _____

Max Turbine MW F

GREATEST UNIT RATING AT AMBIENT TEMPERATURE OF 90 o

OR ABOVE

Gross Unit Rating (MW) Gross Lagging (MVAR)

Net Unit Rating (MW) Gross Leading (MVAR)

Station Service (MW) Station Service (MVAR)

Temperature (oF)

GREATEST UNIT RATING AT AMBIENT TEMPERATURE OF 50o

OR ABOVE




Temperature (oF)




GREATEST UNIT RATING AT AMBIENT TEMPERATURE OF 20oOR ABOVE




Temperature (o F)

GREATEST UNIT RATING AT AMBIENT TEMPERATURE OF 0o

OR ABOVE




Temperature (oF)

COMBINED TURBINE-GENERATOR-EXCITER INERTIA DATA

Inertia Constant, H = kW sec/kVA

Moment-of-Inertia, WR2 = lb. ft.2

REACTANCE DATA (PER UNIT-RATED KVA)

DIRECT AXIS QUADRATURE AXIS

Synchronous – saturated Xdv Xqv

Synchronous – unsaturated Xdi Xqi

Transient – saturated X’dv X’qv

Transient – unsaturated X’di X’qi

Subtransient – saturated X”dv X”qv

Subtransient – unsaturated X”di X”qi

Negative Sequence – saturated X2v

Negative Sequence – unsaturated X2i

Zero Sequence – saturated X0v

Zero Sequence – unsaturated X0i

Leakage Reactance Xlm



Interconnection System Impact Study FIELD TIME CONSTANT DATA (SEC)

Open Circuit T’qo T’do

Three-Phase Short Circuit Transient T’d3 T’q

Line to Line Short Circuit Transient T’d2

Line to Neutral Short Circuit Transient T’d1

Short Circuit Subtransient T”d T”q

Open Circuit Subtransient T”do T”qo

ARMATURE TIME CONSTANT DATA (SEC)

Three Phase Short Circuit Ta3

Line to Line Short Circuit Ta2

Line to Neutral Short Circuit Ta1

NOTE: If requested information is not applicable, indicate by marking “N/A.”

Attachment A (page 4)

To Appendix 1

Interconnection Request

Technical Data Required For


MW CAPABILITY AND PLANT CONFIGURATION


ARMATURE WINDING RESISTANCE DATA (PER UNIT)

Positive R1

Negative R2

Zero R0

Rotor Short Time Thermal Capacity I2t =

Field Current at Rated kVA, Armature Voltage and PF = amps

Field Current at Rated kVA and Armature Voltage, 0 PF amps

Three Phase Armature Winding Capacitance = microfarad

Field Winding Resistance = ohms C

Armature Winding Resistance (Per Phase) = ohms C

CURVES

Provide Saturation, Vee, Reactive Capability, Capacity Temperature Correction curves. Designate

normal and emergency Hydrogen Pressure operating range for multiple curves.


To Appendix 1




GENERATOR STEP-UP TRANSFORMER DATA RATINGS

Capacity Self-cooled/Maximum Nameplate

/ Kva

Voltage Ratio Generator side/System side/Tertiary

/ kV

Winding Connections Generator side/System Side/Tertiary (Delta or Wye)

/

Fixed Taps Available

Present Tap Setting

IMPEDANCE

Positive Z1 (on self-cooled kVA rating) % X/R

Zero Z0 (on self-cooled kVA rating) % X/R


To Appendix 1




EXCITATION SYSTEM DATA

Identify appropriate IEEE model block diagram of excitation system and power system stabilizer (“PSS”)

for computer representation in power system stability simulations and the corresponding excitation

system and PSS constants for use in the model.

GOVERNOR SYSTEM DATA

Identify appropriate IEEE model block diagram of governor system for computer representation in power

system stability simulations and the corresponding governor system constants for use in the model.

WIND GENERATORS

Number of generators to be interconnected pursuant to

this Interconnection Request: ______

Elevation: _____________ _____ Single Phase _____ Three Phase

Inverter manufacturer, model name, number, and version:

List of adjustable set points for the protective equipment or software:

For all generator types: A completed fully functioning, non-proprietary or non-confidential Siemens

PTI’s (“PSSE”) power flow model or other compatible formats, such as IEEE and General Electric

Company Power Systems Load Flow (“PSLF”) data sheet , must be supplied with this Attachment A. If

additional non-proprietary or non-confidential data sheets are more appropriate to the proposed device

then they shall be provided and discussed at Scoping Meeting.

A PSCAD model shall be provided pursuant to Section 7.2 of the LGIP if deemed required at the Scoping

Meeting.


To Appendix 1




INDUCTION GENERATORS:

(*) Field Volts:

(*) Field Amperes:

(*) Motoring Power (kW):

(*) Neutral Grounding Resistor (If Applicable):

(*) I22t or K (Heating Time Constant):

(*) Rotor Resistance:

(*) Stator Resistance:

(*) Stator Reactance:

(*) Rotor Reactance:

(*) Magnetizing Reactance:

(*) Short Circuit Reactance:

(*) Exciting Current:

(*) Temperature Rise:

(*) Frame Size:

(*) Design Letter:

(*) Reactive Power Required In Vars (No Load):

(*) Reactive Power Required In Vars (Full Load):

(*) Total Rotating Inertia, H: Per Unit on KVA Base

Note: Please consult System Operator prior to submitting the Interconnection Request to

determine if the information designated by (*) is required.

Applicant Signature

I hereby certify that, to the best of my knowledge, all the information provided in this Attachment A to

the Interconnection Request is true and accurate.

For Interconnection Customer:_____________________________Date:_________________________

Attachment B (page 1)

To Appendix 1



Interconnection Feasibility Study

The technical data required below must be submitted no later than the date of execution of the

Feasibility Study Agreement pursuant to Section 6.1 of the LGIP.


UNIT RATING

kVA F Phase to Phase Voltage, kV

Rated Power Factor

Speed (RPM) Connection (e.g. Wye) _____

Short Circuit Ratio Frequency, Hertz _____

Stator Amperes at Rated, kVA Field Volts _____

Max Turbine MW F

GREATEST UNIT RATING AT AMBIENT TEMPERATURE OF 50oF OR ABOVE




Temperature (oF)

DATA (PER UNIT-RATED KVA AND RATED VOLTAGE)

Saturated Reactance

Direct axis positive sequence X”dv

negative sequence X”2v ______

zero sequence X”0v

Resistance

Generator AC resistance Ra ______

negative sequence R2 ______

zero sequence R0 ______

Attachment B (page 2) To Appendix 1

Interconnection RequestTechnical Data Required For


Time Constant (seconds)

Three-phase short circuit armature time constant Ta3 _____

CURVES

Provide Saturation, Vee, Reactive Capability, Capacity Temperature Correction curves. Designate

normal and emergency Hydrogen Pressure operating range for multiple curves.

GENERATOR STEP-UP TRANSFORMER DATA RATINGS

Capacity Self-cooled/Maximum Nameplate

/ kVA

Voltage Ratio Generator side/System side/Tertiary

/ kV

Winding Connections Generator side/system side /Tertiary

(Delta or Wye)

/

Fixed Taps Available

Present Tap Setting

IMPEDANCE

For 2-Winding Transformers

Positive Z1 (on self-cooled kVA rating) % X/R

Zero Z0 (on self-cooled kVA rating) % X/R


To Appendix 1




IMPEDANCE

For 3-winding transformers

Positive Z1H-L (on self-cooled kVA rating) %, X/R

Z1H-T (on self-cooled kVA rating) %, X/R

Z1L-T (on self-cooled kVA rating) %, X/R

Zero Z0H-L (on self-cooled kVA rating) %, X/R

Z0H-T (on self-cooled kVA rating) %, X/R

Z0L-T (on self-cooled kVA rating) %, X/R

FEEDER IMPEDANCE (Per Unit)

From GSU to Point of Interconnection

Positive R1 + j X1 on 100 MVA base

Zero R0 + j X0 on 100 MVA base

WIND GENERATORS

Number of generators to be interconnected pursuant to this Interconnection Request: ________

Elevation:________________________Single Phase________________Three Phase

Inverter manufacturer, model name, number, and version:

List of adjustable setpoints for the protective equipment or software:


To Appendix 1




For all generator types: A completed fully functioning, non-proprietary or non-confidential Siemens

PTI’s (“PSSE”) power flow model or other compatible formats, such as IEEE and General Electric

Company Power Systems Load Flow (“PSLF”) data sheet, must be supplied with this Attachment B. If

additional non-proprietary or non-confidential data sheets are more appropriate to the proposed device

then they shall be provided and discussed at Scoping Meeting.

Applicant Signature

I hereby certify that, to the best of my knowledge, all the information provided in this Attachment B to

the Interconnection Request is true and accurate.

For Interconnection Customer:___________________________Date:___________________________

APPENDIX 2

INTERCONNECTION FEASIBILITY STUDY AGREEMENT

THIS AGREEMENT is made and entered into this _____ day of __________, 20__ by and

between __________, a __________ organized and existing under the laws of the State of __________

(“Interconnection Customer,”) and ISO New England Inc., a non-stock corporation existing under the

laws of the State of Delaware (“System Operator”), and __________, a __________ organized and

existing under the laws of the State of __________ (“Interconnecting Transmission Owner”).

Interconnection Customer, System Operator, and Interconnecting Transmission Owner may be referred to

as a “Party,” or collectively as the “Parties.”

RECITALS

WHEREAS, Interconnection Customer is proposing to develop a Large Generating Facility or

generating capacity addition to an existing Generating Facility consistent with the Interconnection

Request submitted by the Interconnection Customer dated __________; and

WHEREAS, Interconnection Customer desires to interconnect the Large Generating Facility to

the Administered Transmission System; and

WHEREAS, Interconnection Customer has requested System Operator and Interconnecting

Transmission Owner to perform an Interconnection Feasibility Study to assess the feasibility of

interconnecting the proposed Large Generating Facility to the Administered Transmission System, and

any Affected Systems.

NOW, THEREFORE, in consideration of and subject to the mutual covenants contained herein

the Parties agree as follows:

1.0 When used in this Agreement, with initial capitalization, the terms specified shall have

the meanings indicated in the Commission-approved Large Generator Interconnection

Procedures (“LGIP”), or in the other provisions of the ISO New England Inc.

Transmission, Markets and Services Tariff (the “Tariff”).

2.0 Interconnection Customer elects and System Operator shall cause to be performed an

Interconnection Feasibility Study consistent with Section 6.0 of the LGIP in accordance

with the Tariff.

3.0 The scope of the Interconnection Feasibility Study shall be subject to the assumptions set

forth in Attachment A to this Agreement.

4.0 The Interconnection Feasibility Study shall be based on the technical information

provided by Interconnection Customer in Attachment B to the Interconnection Request,

as may be modified as the result of the Scoping Meeting. System Operator and

Interconnecting Transmission Owner reserve the right to request additional technical

information from Interconnection Customer as may reasonably become necessary

consistent with Good Utility Practice during the course of the Interconnection Feasibility

Study and as designated in accordance with Section 3.3.4 of the LGIP. If, after the

designation of the Point of Interconnection pursuant to Section 3.3.4 of the LGIP,

Interconnection Customer modifies its Interconnection Request pursuant to Section 4.4,

the time to complete the Interconnection Feasibility Study may be extended.

5.0 The Interconnection Feasibility Study report shall provide the following information:

- preliminary identification of any circuit breaker or other facility short circuit

capability limits exceeded as a result of the interconnection;

- preliminary identification of any thermal overload of any transmission facility or

system voltage limit violations resulting from the interconnection;

- initial review of grounding requirements and electric system protection;

- preliminary description and non-binding estimated cost of facilities required to

interconnect the Large Generating Facility to the New England Transmission

System and to address the identified short circuit and power flow issues; and

- to the extent the Interconnection Customer requested a preliminary analysis as

described in this Section 6.2 of the LGIP, the report will also provide a list of

potential upgrades that may be necessary for the Interconnection Customer’s

Generating Facility to qualify for participation in a Forward Capacity Auction

under Section III.13 of the Tariff.

In accordance with the LGIP, in performing the Interconnection Feasibility

Study, System Operator and Interconnecting Transmission Owner shall

coordinate with each other and Affected Parties, and shall receive and

incorporate input from such entities into its study, and shall provide copies of the

final study report to such entities.

6.0 The Interconnection Customer is providing herewith a deposit equal to 100 percent of the

estimated cost of the study. The deposit shall be applied toward the cost of the

Interconnection Feasibility Study and the development of this Interconnection Feasibility

Study Agreement and its attachment(s). Interconnecting Transmission Owner’s and

System Operator’s good faith estimate for the time of completion of the Interconnection

Feasibility Study Agreement is [insert date].

The total estimated cost of the performance of the Interconnection Feasibility Study

consists of $_____ which is comprised of the System Operator’s estimated cost of

$_____ and the Interconnecting Transmission Owner’s estimated cost of $_____.

Any difference between the deposit and the actual cost of the Interconnection Feasibility

Study shall be paid by or refunded to the Interconnection Customer, as appropriate.

Upon receipt of the Interconnection Feasibility Study System Operator and

Interconnecting Transmission Owner shall charge and the Interconnection Customer shall

pay the actual costs of the Interconnection Feasibility Study.

Interconnection Customer shall pay any invoiced amounts within thirty (30) Calendar Days of

receipt of the invoice.

7.0 Miscellaneous.

7.1 Accuracy of Information. Except as a Party (“Providing Party”) may otherwise specify in

writing when it provides information to the other Parties under this Agreement, the

Providing Party represents and warrants that, to the best of its knowledge, the information

it provides to the other Parties shall be accurate and complete as of the date the

information is provided. The Providing Party shall promptly provide the other Parties

with any additional information needed to update information previously provided.

7.2 Disclaimer of Warranty. In preparing and/or participating in the Interconnection

Feasibility Study, as applicable, each Party and any subcontractor consultants employed

by it shall have to rely on information provided by the Providing Party, and possibly by

third parties, and may not have control over the accuracy of such information.

Accordingly, beyond the commitment to use Reasonable Efforts in preparing and/or

participating in the Interconnection Feasibility Study (including, but not limited to,

exercise of Good Utility Practice in verifying the accuracy of information provided for or

used in the Interconnection Feasibility Study), as applicable, no Party nor any

subcontractor consultant employed by it makes any warranties, express or implied,

whether arising by operation of law, course of performance or dealing, custom, usage in

the trade or profession, or otherwise, including without limitation implied warranties of

merchantability and fitness for a particular purpose, with regard to the accuracy of the

information considered in conducting the Interconnection Feasibility Study, the content

of the Interconnection Feasibility Study, or the conclusions of the Interconnection

Feasibility Study. Interconnection Customer acknowledges that it has not relied on any

representations or warranties not specifically set forth herein and that no such

representations or warranties have formed the basis of its bargain hereunder.

7.3 Force Majeure, Liability and Indemnification.

7.3.1 Force Majeure. Neither System Operator, Interconnecting Transmission Owner

nor an Interconnection Customer will be considered in default as to any

obligation under this Agreement if prevented from fulfilling the obligation due to

an event of Force Majeure; provided that no event of Force Majeure affecting

any entity shall excuse that entity from making any payment that it is obligated to

make hereunder. However, an entity whose performance under this Agreement

is hindered by an event of Force Majeure shall make all reasonable efforts to

perform its obligations under this Agreement, and shall promptly notify the

System Operator, the Interconnecting Transmission Owner or the Interconnection

Customer, whichever is appropriate, of the commencement and end of each event

of Force Majeure.

7.3.2 Liability. System Operator shall not be liable for money damages or other

compensation to the Interconnection Customer for action or omissions by System

Operator in performing its obligations under this Agreement, except to the extent

such act or omission by System Operator is found to result from its gross

negligence or willful misconduct. Interconnecting Transmission Owner shall not

be liable for money damages or other compensation to the Interconnection

Customer for action or omissions by Interconnecting Transmission Owner in

performing its obligations under this Agreement, except to the extent such act or

omission by Interconnecting Transmission Owner is found to result from its

gross negligence or willful misconduct. To the extent the Interconnection

Customer has claims against System Operator or Interconnecting Transmission

Owner, the Interconnection Customer may only look to the assets of System

Operator or Interconnecting Transmission Owner (as the case may be) for the

enforcement of such claims and may not seek to enforce any claims against the

directors, members, shareholders, officers, employees or agents of System

Operator or Interconnecting Transmission Owner or Affiliate of either who, the

Interconnection Customer acknowledges and agrees, have no personal or other

liability for obligations of System Operator or an Interconnecting Transmission

Owner by reason of their status as directors, members, shareholders, officers,

employees or agents of System Operator or an Interconnecting Transmission

Owner or Affiliate of either. In no event shall System Operator, Interconnecting

Transmission Owner or Interconnection Customer be liable for any incidental,

consequential, multiple or punitive damages, loss of revenues or profits,

attorneys fees or costs arising out of, or connected in any way with the

performance or non-performance under this Agreement. Notwithstanding the

foregoing, nothing in this section shall diminish an Interconnection Customer’s

obligations under the Indemnification section below.

7.3.3 Indemnification. Interconnection Customer shall at all times indemnify, defend,

and save harmless System Operator and the Interconnecting Transmission Owner

and their respective directors, officers, members, employees and agents from any

and all damages, losses, claims and liabilities (“Losses”) by or to third parties

arising out of or resulting from the performance by System Operator or

Interconnecting Transmission Owner under this Agreement, any bankruptcy

filings made by the Interconnection Customer, or the actions or omissions of the

Interconnection Customer in connection with this Agreement, except in the case

of System Operator, to the extent such Losses arise from the gross negligence or

willful misconduct by System Operator or its directors, officers, members,

employees or agents, and, in the case of Interconnecting Transmission Owner, to

the extent such Losses arise from the gross negligence or willful misconduct by

Interconnecting Transmission Owner or its directors, officers, members,

employees or agents. The amount of any indemnity payment hereunder shall be

reduced (including, without limitation, retroactively) by any insurance proceeds

or other amounts actually recovered by the indemnified party in respect of the

indemnified action, claim, demand, cost, damage or liability. The obligations of

Interconnection Customer to indemnify System Operator and Interconnecting

Transmission Owner shall be several, and not joint or joint and several. The

liability provisions of the Transmission Operating Agreement or other applicable

operating agreements shall apply to the relationship between the System Operator

and the Interconnecting Transmission Owner.

7.4 Third-Party Beneficiaries. Without limitation of Sections 7.2 and 7.3 of this Agreement,

the Parties agree that subcontractor consultants hired by them to conduct, participate in,

or review, or to assist in the conducting, participating in, or reviewing of, an

Interconnection Feasibility Study shall be deemed third party beneficiaries of Sections

7.2 and 7.3.

7.5 Term and Termination. This Agreement shall be effective from the date hereof and

unless earlier terminated in accordance with this Section 7.5, shall continue in effect for a

term of one year or until the Interconnection Feasibility Study is completed. This

Agreement shall automatically terminate upon the withdrawal of Interconnection Request

under Section 3.6 of the LGIP. The System Operator or the Interconnecting

Transmission Owner may terminate this Agreement fifteen (15) days after providing

written notice to the Interconnection Customer that it has breached one of its obligations

hereunder, if the breach has not been cured within such fifteen (15) day period.

7.6 Governing Law. This Agreement shall be governed by and construed in accordance with

the laws of the state where the Point of Interconnection is located without regard to any

choice of laws provisions.

7.7 Severability. In the event that any part of this Agreement is deemed as a matter of law to

be unenforceable or null and void, such unenforceable or void part shall be deemed

severable from this Agreement and the Agreement shall continue in full force and effect

as if each part was not contained herein.

7.8 Counterparts. This Agreement may be executed in counterparts, and each counterpart

shall have the same force and effect as the original instrument.

7.9 Amendment. No amendment, modification or waiver of any term hereof shall be

effective unless set forth in writing and signed by the Parties hereto.

7.10 Survival. All warranties, limitations of liability and confidentiality provisions provided

herein shall survive the expiration or termination hereof.

7.11 Independent Contractor. Each of the Parties shall at all times be deemed to be an

independent contractor of the other Parties, and none of its employees or the employees

of its subcontractors shall be considered to be employees of the other Parties as a result of

this Agreement.

7.12 No Implied Waivers. The failure of a Party to insist upon or enforce strict performance

of any of the provisions of this Agreement shall not be construed as a waiver or

relinquishment to any extent of such Party’s right to insist or rely on any such provision,

rights and remedies in that or any other instance; rather, the same shall be and remain in

full force and effect.

7.13 Successors and Assigns. This Agreement may not be assigned, by operation of law or

otherwise, without the prior written consent of the other Parties hereto, such consent not

to be unreasonably withheld. Notwithstanding the foregoing, this Agreement, and each

and every term and condition hereof, shall be binding upon and inure to the benefit of the

Parties hereto and their respective successors and assigns, to the extent the same are

authorized hereunder.

7.14 Due Authorization. Each Party to this Agreement represents and warrants that it has full

power and authority to enter into this Agreement and to perform its obligations

hereunder, that execution of this Agreement will not violate any other agreement with a

third party, and that the person signing this Agreement on its behalf has been properly

authorized and empowered to enter into this Agreement.

IN WITNESS WHEREOF, the Parties have caused this Agreement to be duly executed by their

duly authorized officers or agents on the day and year first above written.

System Operator Interconnecting Transmission Owner

By: By:

Title: Title:

Date: Date:

[Insert name of Interconnection Customer]

By:

Title:

Date:

Attachment A to

Appendix 2

Interconnection Feasibility

Study Agreement

ASSUMPTIONS USED IN CONDUCTING THE

INTERCONNECTION FEASIBILITY STUDY

The Interconnection Feasibility Study will be based upon the information set forth in the

Interconnection Request and agreed upon in the Scoping Meeting held on __________:

Designation of Point of Interconnection and configuration to be studied.

Designation of alternative Point(s) of Interconnection and configuration.

[Above assumptions to be completed by Interconnection Customer and other assumptions to be

provided by Interconnection Customer, System Operator, and Interconnecting Transmission Owner]

APPENDIX 3

INTERCONNECTION SYSTEM IMPACT STUDY AGREEMENT








RECITALS





the Administered Transmission System;

WHEREAS, System Operator and Interconnecting Transmission Owner have completed an

Interconnection Feasibility Study (the “Feasibility Study”) and provided the results of said study to the

Interconnection Customer, or Interconnection Customer has requested that the Feasibility Study be

completed as part of the System Impact Study pursuant to Section 6.1 of the LGIP, or in the other

provisions of the ISO New England Inc. Transmission, Markets and Services Tariff (the “Tariff”)(This

recital is to be omitted if Interconnection Customer has elected to forego the Interconnection Feasibility

Study); and


Transmission Owner to perform an Interconnection System Impact Study to assess the impact of

interconnecting the Large Generating Facility to the Administered Transmission System, and any

Affected Systems.


the Parties agreed as follows:



Procedure (“LGIP”).

2.0 Interconnection Customer elects and System Operator and Interconnecting Transmission

Owner shall cause to be performed an Interconnection System Impact Study consistent

with Section 7.0 of the LGIP in accordance with the Tariff.

3.0 The scope of the Interconnection System Impact Study shall be subject to the

assumptions set forth in Attachment A to this Agreement.

4.0 The Interconnection System Impact Study will be based upon the results of the

Interconnection Feasibility Study, whether performed separately or as part of the

Interconnection System Impact Study, and the technical information provided by

Interconnection Customer in Attachment A to the Interconnection Request, subject to any

modifications in accordance with Section 4.4 of the LGIP. System Operator and

Interconnecting Transmission Owner reserve the right to request additional technical

information from Interconnection Customer as may reasonably become necessary

consistent with Good Utility Practice during the course of the Interconnection System

Impact Study. If Interconnection Customer modifies its designated Point of

Interconnection, Interconnection Request, or the technical information provided therein is

modified, the time to complete the Interconnection System Impact Study may be

extended.

5.0 The Interconnection System Impact Study report shall provide the following information:

- identification of any circuit breaker or other facility short circuit capability limits

exceeded as a result of the interconnection;

- identification of any thermal overload of any transmission facility or system

voltage limit violations resulting from the interconnection;

- initial review of grounding requirements and electric system protection;

- identification of any instability or inadequately damped response to system

disturbances resulting from the interconnection;

- description and non-binding, good faith estimated cost of facilities required to

interconnect the Large Generating Facility to the Administered Transmission

System and to address the identified short circuit, instability, and power flow

issues; and

- to the extent the Interconnection Customer requested a preliminary analysis as

described in this Section 7.4 of the LGIP, the report will also provide a list of

potential upgrades that may be necessary for the Interconnection Customer’s

Generating Facility to qualify for participation in a Forward Capacity Auction

under Section III.13 of the Tariff.

6.0 The Interconnection Customer is providing herewith a deposit equal to:

i. the greater of 100 percent of the estimated cost of the Interconnection

System Impact Study or $250,000;

or

ii. the lower of 100 percent of the estimated cost of the Interconnection

System Impact Study or $50,000, if the Interconnection Customer is

providing herewith either:

(a) evidence of applications for all Major Permits, as defined in Section

III.13.1.1.2.2.2(a) of the Tariff, required in support of the

Interconnection Request, or provide certification that Major Permits

are not required or

(b) evidence acceptable to the System Operator of At-Risk Expenditures

(excluding study cots) totaling at least the amounts of money

described in (i) above.

or

iii the lower of 100 percent of the estimated costs of the study or $50,000 if

the Interconnection Request is for a modification to an existing Large

Generating Facility that does not increase the energy capability or

capacity capability of the Large Generating Facility.

The deposit shall be applied toward the cost of the Interconnection System Impact Study

and the development of this Interconnection System Impact Study Agreement and its

attachment(s) and the LGIA. Interconnecting Transmission Owner’s and System

Operator’s good faith estimate for the time of completion of the Interconnection System

Impact Study is [insert date].

The total estimated cost of the performance of the Interconnection System Impact Study



Any difference between the deposit and the actual cost of the Interconnection System

Impact Study shall be paid by or refunded to the Interconnection Customer, as

appropriate.

Upon receipt of the Interconnection System Impact Study, System Operator and

Interconnecting Transmission Owner shall charge and the Interconnection Customer shall

pay the actual costs of the Interconnection System Impact Study.

System Operator and Interconnecting Transmission Owner may, in the exercise of

reasonable discretion, invoice the Interconnection Customer on a monthly basis for the

work to be conducted on the Interconnection System Impact Study each month.

Interconnection Customer shall pay any invoiced amounts within thirty (30) Calendar

Days of receipt of the invoice.

In accordance with the LGIP, in performing the Interconnection System Impact Study,

System Operator and Interconnecting Transmission Owner shall coordinate with Affected

Parties, shall receive and incorporate input from such entities into its study, and shall

provide copies of the final study report to such entities.

7.0 Miscellaneous.







7.2 Disclaimer of Warranty. In preparing and/or participating in the Interconnection System

Impact Study, as applicable, each Party and any subcontractor consultants employed by it

shall have to rely on information provided by the Providing Party, and possibly by third

parties, and may not have control over the accuracy of such information. Accordingly,

beyond the commitment to use Reasonable Efforts in preparing and/or participating in the

Interconnection System Impact Study (including, but not limited to, exercise of Good

Utility Practice in verifying the accuracy of information provided for or used in the

Interconnection System Impact Study), as applicable, no Party nor any subcontractor

consultant employed by it makes any warranties, express or implied, whether arising by

operation of law, course of performance or dealing, custom, usage in the trade or

profession, or otherwise, including without limitation implied warranties of


information considered in conducting the Interconnection System Impact Study, the

content of the Interconnection System Impact Study, or the conclusions of the

Interconnection System Impact Study. Interconnection Customer acknowledges that it

has not relied on any representations or warranties not specifically set forth herein and

that no such representations or warranties have formed the basis of its bargain hereunder.












of Force Majeure.


















liability for obligations of System Operator or Interconnecting Transmission


employees or agents of System Operator or Interconnecting Transmission Owner

or Affiliate of either. In no event shall System Operator, an Interconnecting

Transmission Owner or any Interconnection Customer be liable for any

incidental, consequential, multiple or punitive damages, loss of revenues or

profits, attorneys fees or costs arising out of, or connected in any way with the





and save harmless System Operator and the Interconnecting Transmission

Owners and their respective directors, officers, members, employees and agents

from any and all damages, losses, claims and liabilities (“Losses”) by or to third

parties arising out of or resulting from the performance by System Operator or














Transmission Owners shall be several, and not joint or joint and several. The






or review, or to assist in the conducting, participating in, or reviewing of, an

Interconnection System Impact Study shall be deemed third party beneficiaries of

Sections 7.2 and 7.3.



term of one year or until the Interconnection System Impact Study is completed. This






















this Agreement.

















IN WITNESS THEREOF, the Parties have caused this Agreement to be duly executed by their



By: By:

Title: Title:

Date: Date:


By:

Title:

Date:

Attachment A

To Appendix 3

Interconnection System Impact

Study Agreement

ASSUMPTIONS USED IN CONDUCTING THE

INTERCONNECTION SYSTEM IMPACT STUDY

The Interconnection System Impact Study will be based upon the results of the Interconnection

Feasibility Study, whether performed separately or as part of the Interconnection System Impact Study,

subject to any modifications in accordance with Section 4.4 of the LGIP, and the following assumptions:

Designation of Point of Interconnection and configuration to be studied.

Designation of alternative Point(s) of Interconnection and configuration.

[Above assumptions to be completed by Interconnection Customer and other assumptions to be

provided by Interconnection Customer, System Operator, and Interconnecting Transmission Owner]

APPENDIX 4

INTERCONNECTION FACILITIES STUDY AGREEMENT








RECITALS



Request submitted by the Interconnection Customer dated ; and


the Administered Transmission System; and

WHEREAS, System Operator and Interconnecting Transmission Owner have completed an

Interconnection System Impact Study (the “System Impact Study”) and provided the results of said study

to the Interconnection Customer; and


Transmission Owner to perform an Interconnection Facilities Study to specify and estimate the cost of the

equipment, engineering, procurement and construction work needed to implement the conclusions of the

Interconnection System Impact Study in accordance with Good Utility Practice to physically and

electrically connect the Large Generating Facility to the Administered Transmission System.


the Parties agreed as follows:





2.0 Interconnection Customer elects and System Operator shall cause an Interconnection

Facilities Study consistent with Section 8.0 of the LGIP to be performed in accordance

with the Tariff.

3.0 The scope of the Interconnection Facilities Study shall be subject to the assumptions set

forth in Attachment A and the data provided in Attachment B to this Agreement.

4.0 The Interconnection Facilities Study report (i) shall provide a description, estimated cost

of (consistent with Attachment A), and schedule for required facilities to interconnect the

Large Generating Facility to the Administered Transmission System and (ii) shall address

the short circuit, instability, and power flow issues identified in the Interconnection

System Impact Study.

5.0 The Interconnection Customer is providing herewith a deposit equal to:

i. the greater of 25 percent of the estimated cost of the Interconnection

Facilities Study or $250,000;

or

ii. the greater of 100 percent of the estimated monthly cost of the

Interconnection Facilities Study Agreement or $100,000, if the

Interconnection Customer can provide either:

(a) evidence of application for all Major Permits, as defined

in Section III.13.1.1.2.2.2(a) of the Tariff, required in

support of the Interconnection Request, or provide

certification that Major Permits are not required or

(b) evidence acceptable to the System Operator of At-Risk

Expenditures (excluding Interconnection Study costs)

totaling at least the amount of the money in (i) above,

not including the At-Risk Expenditures demonstrated

with the Interconnection System Impact Study

Agreement, if applicable.

or

iii. the greater of 100 percent of one month’s estimated study cost or

$100,000, if the Interconnection Request is for a modification to

an existing Large Generating Facility that does not increase the

energy capability or capacity capability of the Large Generating

Facility.

The deposit shall be applied toward the cost of the Interconnection Facilities Study and

the development of this Interconnection Facilities Study Agreement and its attachment(s)

and the LGIA. The time for completion of the Interconnection Facilities Study is

specified in Attachment A.

The total estimated cost of the performance of the Interconnection Facilities Study



Any difference between the deposit and the actual cost of the Interconnection Facilities

Study shall be paid by or refunded to the Interconnection Customer, as appropriate.

Upon receipt of the Interconnection Facilities Study, System Operator and

Interconnecting Transmission Owner shall charge and Interconnection Customer shall

pay the actual costs of the Interconnection Facilities Study. System Operator and

Interconnecting Transmission Owner may, in the exercise of reasonable discretion,

invoice the Interconnection Customer on a monthly basis for the work to be conducted on

the Interconnection Facilities Study each month. Interconnection Customer shall pay any

invoiced amounts within thirty (30) Calendar Days of receipt of the invoice.

In accordance with the LGIP, in performing the Interconnection Facilities Study,

Interconnecting Transmission Owner and System Operator shall coordinate with Affected

Parties, shall receive and incorporate input from such entities into its study, and shall


6.0 Miscellaneous.

6.1 Accuracy of Information. Except as a Party (“Providing Party”) may otherwise

specify in writing when it provides information to the other Parties under this

Agreement, the Providing Party represents and warrants that, to the best of its

knowledge, the information it provides to the other Parties shall be accurate and

complete as of the date the information is provided. The Providing Party shall

promptly provide the other Parties with any additional information needed to update

information previously provided.

6.2 Disclaimer of Warranty. In preparing and/or participating in the Interconnection

Facilities Study, as applicable, each Party and any subcontractor consultants employed by

it shall have to rely on information provided by the Providing Party, and possibly by third

parties, and may not have control over the accuracy of such information. Accordingly,

beyond the commitment to use Reasonable Efforts in preparing and/or participating in the

Interconnection Facilities Study (including, but not limited to, exercise of Good Utility

Practice in verifying the accuracy of information provided for or used in the

Interconnection Facilities Study), as applicable, no Party nor any subcontractor consultant

employed by it makes any warranties, express or implied, whether arising by operation of

law, course of performance or dealing, custom, usage in the trade or profession, or

otherwise, including without limitation implied warranties of merchantability and fitness

for a particular purpose, with regard to the accuracy of the information considered in

conducting the Interconnection Facilities Study, the content of the Interconnection

Facilities Study, or the conclusions of the Interconnection Facilities Study.

Interconnection Customer acknowledges that it has not relied on any representations or

warranties not specifically set forth herein and that no such representations or warranties

have formed the basis of its bargain hereunder.












of Force Majeure.





















or Affiliate of either. In no event shall System Operator, Interconnecting





























6.4 Third-Party Beneficiaries. Without limiting Sections 7.2 and 7.3 of this Agreement, the

Parties agree that subcontractor consultants hired by them to conduct, participate in,

review, or to assist in the conducting, participating in, or reviewing of, an Interconnection

Facilities Study shall be deemed third party beneficiaries of Sections 7.2 and 7.3.



term of one year or until the Interconnection Facilities Study is completed. This






















this Agreement.




















By: By:

Title: Title:

Date: Date:


By:

Title:

Date:

Attachment A

To Appendix 4

Interconnection Facilities

Study Agreement

INTERCONNECTION CUSTOMER SCHEDULE ELECTION FOR CONDUCTING THE

INTERCONNECTION FACILITIES STUDY

Interconnection Customer elects (check one):

+/- 20 percent cost estimate contained in the Interconnection Facilities Study report.

+/- 10 percent cost estimate contained in the Interconnection Facilities Study report.

Interconnecting Transmission Owner and System Operator shall use Reasonable Efforts to

complete the study and issue a draft Interconnection Facilities Study report to the Interconnection

Customer within the following number of days after of receipt of an executed copy of this Interconnection

Facilities Study Agreement:

- ninety (90) Calendar Days with no more than a +/- 20 percent cost estimate contained in

the report, or

- one hundred eighty (180) Calendar Days with no more than a +/- 10 percent cost estimate

contained in the report.


Appendix 4


Study Agreement

DATA FORM TO BE PROVIDED BY INTERCONNECTION CUSTOMER

WITH THE

INTERCONNECTION FACILITIES STUDY AGREEMENT

Provide location plan and simplified one-line diagram of the plant and station facilities. For staged

projects, please indicate future generation, transmission circuits, etc.

One set of metering is required for each generation connection to the new ring bus or existing New

England Transmission System station. Number of generation connections:

On the one line indicate the generation capacity attached at each metering location. (Maximum load on

Current Transformer/Power Transformer (“CT/PT”))

On the one line indicate the location of auxiliary power. (Minimum load on CT/PT) Amps

Will an alternate source of auxiliary power be available during CT/PT maintenance?

Yes _____ No _____

Will a transfer bus on the generation side of the metering require that each meter set be designed for the

total plant generation? Yes _____ No _____

(Please indicate on one line).

What type of control system or Power Line Carrier (“PLC”) will be located at the Interconnection

Customer’s Large Generating Facility?

What protocol does the control system or PLC use?

Please provide a 7.5-minute quadrangle of the site. Sketch the plant, station, transmission line, and

property line.


Appendix 4


Study Agreement

Physical dimensions of the proposed interconnection station:

Bus length from generation to interconnection station:

Line length from interconnection station to Interconnecting Transmission Owner’s transmission line.

Tower number observed in the field. (Painted on tower leg)*

Number of third party easements required for transmission lines*:

* To be completed in coordination with System Operator and Interconnecting Transmission Owner.

Is the Large Generating Facility in Interconnecting Transmission Owner’s service area?

Yes _____ No _____ Local provider:

Please provide proposed schedule dates:

Begin Construction Date:

Generator step-up transformer Date:

Receives back feed power Date

Generation Testing Date:

Commercial Operation Date:

APPENDIX 5

OPTIONAL INTERCONNECTION STUDY AGREEMENT

THIS AGREEMENT is made and entered into this _____day of __________, 20___by and







RECITALS




WHEREAS, Interconnection Customer is proposing to establish an interconnection to the

Administered Transmission System; and

WHEREAS, Interconnection Customer has submitted to System Operator an Interconnection

Request; and

WHEREAS, on or after the date when the Interconnection Customer receives the Interconnection

System Impact Study results, Interconnection Customer has further requested that the System Operator

and Interconnecting Transmission Owner prepare an Optional Interconnection Study.


the Parties agree as follows:





2.0 Interconnection Customer elects and System Operator shall cause an Optional

Interconnection Study consistent with Section 10.0 of the LGIP to be performed in

accordance with the Tariff.

3.0 The scope of the Optional Interconnection Study shall be subject to the assumptions set

forth in Attachment A to this Agreement.

4.0 The Optional Interconnection Study shall be performed solely for informational purposes.

5.0 The Optional Interconnection Study report shall provide a sensitivity analysis based on

the assumptions specified by the Interconnection Customer in Attachment A to this

Agreement. The Optional Interconnection Study will identify Interconnecting

Transmission Owner’s Interconnection Facilities and the Network Upgrades, and the

estimated cost thereof, that may be required to provide transmission service or

Interconnection Service based upon the assumptions specified by the Interconnection

Customer in Attachment A.

In accordance with the LGIP, in performing the Optional Interconnection Study, the

System Operator shall coordinate with Interconnecting Transmission Owner and Affected

Parties, and shall receive and incorporate input from such entities into its study, and shall


6.0 The Interconnection Customer is providing herewith a deposit equal to 100 percent of the

estimated cost of the study. Interconnecting Transmission Owner’s and System

Operator’s good faith estimate for the time of completion of the Optional Interconnection

Study is [insert date].

The total estimated cost of the performance of the Optional Interconnection Study



Any difference between the initial payment and the actual cost of the study shall be paid

by or refunded to the Interconnection Customer, as appropriate. Upon receipt of the

Optional Interconnection Study, System Operator and Interconnecting Transmission

Owner shall charge and the Interconnection Customer shall pay the actual costs of the

Optional Interconnection Study. Interconnection Customer shall pay any invoiced

amounts within thirty (30) Calendar Days of receipt of invoice.

7.0 Miscellaneous.







7.2 Disclaimer of Warranty. In preparing and/or participating in the Optional

Interconnection Study, as applicable, each Party and any subcontractor consultants

employed by it shall have to rely on information provided by the Providing Party, and

possibly by third parties, and may not have control over the accuracy of such information.

Accordingly, beyond the commitment to use Reasonable Efforts in preparing and/or

participating in the Optional Interconnection Study (including, but not limited to, exercise

of Good Utility Practice in verifying the accuracy of information provided for or used in

the Optional Interconnection Study), as applicable, no Party nor any subcontractor

consultant employed by it makes any warranties, express or implied, whether arising by

operation of law, course of performance or dealing, custom, usage in the trade or

profession, or otherwise, including without limitation implied warranties of


information considered in conducting the Optional Interconnection Study, the content of

the Optional Interconnection Study, or the conclusions of the Optional Interconnection

Study. Interconnection Customer acknowledges that it has not relied on any

representations or warranties not specifically set forth herein and that no such

representations or warranties have formed the basis of its bargain hereunder.












of Force Majeure.





















or Affiliate of either. In no event shall System Operator, Interconnecting












Interconnecting Transmission Owners under this Agreement, any bankruptcy



of System Operator, to the extent such Losses arise from gross negligence or
















or review, or to assist in the conducting, participating in, or reviewing of, an Optional

Interconnection Study shall be deemed third party beneficiaries of Sections 7.2 and 7.3.



term of one year or until the Optional Interconnection Study is completed. This







the laws of the state where the Point of Interconnection is located, without regard to any















this Agreement.




rights and remedies in that or any other instances; rather, the same shall be and remain in
















By: By:

Title: Title:

Date: Date:


By:

Title:

Date:

Attachment A

Appendix 5

Optional Interconnection

Study Agreement

ASSUMPTIONS USED IN CONDUCTING

THE OPTIONAL INTERCONNECTION STUDY

[To be completed by Interconnection Customer consistent with Section 10 of the LGIP.]

APPENDIX 6

LARGE GENERATOR INTERCONNECTION

AGREEMENT

TABLE OF CONTENTS

Article 1 Definitions

Article 2 Effective Date, Term and Termination

Article 3 Regulatory Filings

Article 4 Scope of Service

Article 5 Interconnection Facilities Engineering, Procurement, and Construction

Article 6 Testing and Inspection

Article 7 Metering

Article 8 Communications

Article 9 Operations

Article 10 Maintenance

Article 11 Performance Obligation

Article 12 Invoice

Article 13 Emergencies

Article 14 Regulatory Requirements and Governing Law

Article 15 Notices

Article 16 Force Majeure

Article 17 Default

Article 18 Indemnity, Consequential Damages and Insurance

Article 19 Assignment

Article 20 Severability

Article 21 Comparability

Article 22 Confidentiality

Article 23 Environmental Releases

Article 24 Information Requirements

Article 25 Information Access and Audit Rights

Article 26 Subcontractors

Article 27 Disputes

Article 28 Representations, Warranties and Covenants

Article 29 Omitted

Article 30 Miscellaneous

THIS STANDARD LARGE GENERATOR INTERCONNECTION AGREEMENT

(“Agreement”) is made and entered into this ____ day of ________ 20__, by and between

________________, a ________________ organized and existing under the laws of the

State/Commonwealth of ________________ (“Interconnection Customer” with a Large Generating

Facility), ISO New England Inc., a non-stock corporation organized and existing under the laws of the

State of Delaware (“System Operator”), and ________________, a ________________ organized and

existing under the laws of the State/Commonwealth of ________________ (“Interconnecting

Transmission Owner”). Under this Agreement the Interconnection Customer, System Operator, and

Interconnecting Transmission Owner each may be referred to as a “Party” or collectively as the “Parties.”

RECITALS

WHEREAS, System Operator is the central dispatching agency provided for under the

Transmission Operating Agreement (“TOA”) which has responsibility for the operation of the New

England Control Area from the System Operator control center and the administration of the Tariff; and

WHEREAS, Interconnecting Transmission Owner is the owner or possessor of an interest in the

Administered Transmission System; and

WHEREAS, Interconnection Customer intends to own, lease and/or control and operate the

Generating Facility identified as a Large Generating Facility in Appendix C to this Agreement; and

WHEREAS, System Operator, Interconnection Customer and Interconnecting Transmission

Owner have agreed to enter into this Agreement for the purpose of interconnecting the Large Generating

Facility to the Administered Transmission System.

NOW, THEREFORE, in consideration of and subject to the mutual covenants contained herein,

it is agreed:

When used in this Standard Large Generator Interconnection Agreement, terms with initial

capitalization that are not defined in Article 1 shall have the meanings specified in the Article in which

they are used.

ARTICLE 1. DEFINITIONS

The definitions contained in this Article 1 and those definitions embedded in an Article of this

Agreement are intended to apply in the context of the generator interconnection process provided for in

Schedule 22 (and its appendices). To the extent that the definitions herein are different than those

contained in Section I.2.2 of the Tariff, the definitions provided below shall control only for purposes of

generator interconnections under Schedule 22. Capitalized terms in Schedule 22 that are not defined in

this Article 1 shall have the meanings specified in Section I.2.2 of the Tariff.

Administered Transmission System shall mean the PTF, the Non-PTF, and distribution

facilities that are subject to the Tariff.

Adverse System Impact shall mean any significant negative effects on the stability, reliability or

operating characteristics of the electric system.

Affected Party shall mean the entity that owns, operates or controls an Affected System, or any

other entity that otherwise may be a necessary party to the interconnection process.

Affected System shall mean any electric system that is within the Control Area, including, but

not limited to, generator owned transmission facilities, or any other electric system that is not within the

Control Area that may be affected by the proposed interconnection.

Affiliate shall mean, with respect to a corporation, partnership or other entity, each such other

corporation, partnership or other entity that directly or indirectly, through one or more intermediaries,

controls, is controlled by, or is under common control with, such corporation, partnership or other entity.

Applicable Laws and Regulations shall mean all duly promulgated applicable federal, state and

local laws, regulations, rules, ordinances, codes, decrees, judgments, directives, or judicial or

administrative orders, permits and other duly authorized actions of any Governmental Authority.

Applicable Reliability Council shall mean the reliability council applicable to the New England


Applicable Reliability Standards shall mean the requirements and guidelines of NERC, the

NPCC and the New England Control Area, including publicly available local reliability requirements of

Interconnecting Transmission Owners or other Affected Parties.

At-Risk Expenditure shall mean money expended for the development of the Generating

Facility that cannot be recouped if the Interconnection Customer were to withdraw the Interconnection

Request for the Generating Facility. At-Risk Expenditure may include, but is not limited to, money

expended on: (i) costs of federal, state, local, regional and town permits, (ii) Site Control, (iii) site-

specific design and surveys, (iv) construction activities, and (v) non-refundable deposits for major

equipment components. For purposes of this definition, At-Risk Expenditure shall not include costs

associated with the Interconnection Studies.

Base Case shall have the meaning specified in Section 2.3 of the Large Generator

Interconnection Procedures (“LGIP”).

Base Case Data shall mean the Base Case power flow, short circuit, and stability data bases used

for the Interconnection Studies by the System Operator, Interconnection Customer, Interconnecting

Transmission Owner, or any Affected Party as deemed appropriate by the System Operator in accordance

with applicable codes of conduct and confidentiality requirements.

Breach shall mean the failure of a Party to perform or observe any material term or condition of

the Standard Large Generator Interconnection Agreement.

Breaching Party shall mean a Party that is in Breach of the Standard Large Generator

Interconnection Agreement.

Calendar Day shall mean any day including Saturday, Sunday or a Federal Holiday.

Capacity Capability Interconnection Standard (“CC Interconnection Standard”) shall mean

the criteria required to permit the Interconnection Customer to interconnect in a manner that avoids any



Generating Facility, and in a manner that ensures intra-zonal deliverability by avoidance of the redispatch

of other Capacity Network Resources, as detailed in the ISO New England Planning Procedures.

Capacity Network Resource (“CNR”) shall mean that portion of a Generating Facility that is

interconnected to the Administered Transmission System under the Capacity Capability Interconnection

Standard.

Capacity Network Resource Capability (“CNR Capability”) shall mean: (i) in the case of a

Generating Facility that is a New Generating Capacity Resource pursuant to Section III.13.1 of the Tariff

or an Existing Generating Capacity Resource that is increasing its capability pursuant to Section

III.13.1.2.2.5 of the Tariff, the highest megawatt amount of the Capacity Supply Obligation obtained by

the Generating Facility in accordance with Section III.13 of the Tariff, and, if applicable, as specified in a

filing by the System Operator with the Commission in accordance with Section III.13.8.2 of the Tariff, or

(ii) in the case of a Generating Facility that meets the criteria under Section 5.2.3 of this LGIP, the total

megawatt amount determined pursuant to the hierarchy established in Section 5.2.3. CNR Capability

shall not exceed the maximum net megawatt electrical output of the Generating Facility at the Point of

Interconnection at an ambient temperature at or above 90 degrees F for Summer and at or above 20

degrees F for Winter. Where the Generating Facility includes multiple production devices, the CNR

Capability shall not exceed the aggregate maximum net megawatt electrical output of the Generating

Facility at the Point of Interconnection at an ambient temperature at or above 90 degrees F for Summer

and at or above 20 degrees F for Winter.

Capacity Network Resource Group Study (“CNR Group Study”) shall mean the study

performed by the System Operator under Section III.13.1.1.2.3 of the Tariff to determine which resources

qualify to participate in a Forward Capacity Auction.

Capacity Network Resource Interconnection Service (“CNR Interconnection Service”) shall

mean the Interconnection Service selected by the Interconnection Customer to interconnect its Large

Generating Facility with the Administered Transmission System in accordance with the Capacity

Capability Interconnection Standard. An Interconnection Customer’s CNR Interconnection Service shall

be for the megawatt amount of CNR Capability. CNR Interconnection Service does not in and of itself

convey transmission service.

Clustering shall mean the process whereby a group of Interconnection Requests is studied

together for the purpose of conducting the Interconnection System Impact Study.

Commercial Operation shall mean the status of a Generating Facility that has commenced

generating electricity for sale, excluding electricity generated during Trial Operation.

Commercial Operation Date of a unit shall mean the date on which the Generating Facility

commences Commercial Operation as agreed to by the Parties pursuant to Appendix E to the Standard

Large Generator Interconnection Agreement.

Confidential Information shall mean any confidential, proprietary or trade secret information of

a plan, specification, pattern, procedure, design, device, list, concept, policy or compilation relating to the

present or planned business of a Party, which is designated as confidential by the Party supplying the

information, whether conveyed orally, electronically, in writing, through inspection, or otherwise.

Confidential Information shall include, but not be limited to, information that is confidential pursuant to

the ISO New England Information Policy.

Default shall mean the failure of a Breaching Party to cure its Breach in accordance with Article

17 of the Standard Large Generator Interconnection Agreement.

Dispute Resolution shall mean the procedure for resolution of a dispute between the Parties in

which they will first attempt to resolve the dispute on an informal basis.

Distribution System shall mean the Interconnecting Transmission Owner’s facilities and

equipment used to transmit electricity to ultimate usage points such as homes and industries directly from

nearby generators or from interchanges with higher voltage transmission networks which transport bulk

power over longer distances. The voltage levels at which distribution systems operate differ among areas.

Distribution Upgrades shall mean the additions, modifications, and upgrades to Interconnecting

Transmission Owner’s Distribution System at or beyond the Point of Interconnection to facilitate

interconnection of the Generating Facility and render the transmission service necessary to effect

Interconnection Customer’s wholesale sale of electricity in interstate commerce. Distribution Upgrades

do not include Interconnection Facilities.

Effective Date shall mean the date on which the Standard Large Generator Interconnection

Agreement becomes effective upon execution by the Parties subject to acceptance by the Commission or

if filed unexecuted, upon the date specified by the Commission.

Emergency Condition shall mean a condition or situation: (1) that in the judgment of the Party

making the claim is likely to endanger life or property; or (2) that, in the case of the Interconnecting

Transmission Owner, is likely (as determined in a non-discriminatory manner) to cause a material adverse

effect on the security of, or damage to the New England Transmission System, Interconnecting

Transmission Owner’s Interconnection Facilities or any Affected System to which the New England

Transmission System is directly connected; or (3) that, in the case of Interconnection Customer, is likely

(as determined in a non-discriminatory manner) to cause a material adverse effect on the security of, or

damage to, the Generating Facility or Interconnection Customer’s Interconnection Facilities. System

restoration and black start shall be considered Emergency Conditions; provided that Interconnection

Customer is not obligated by the Standard Large Generator Interconnection Agreement to possess black

start capability.

Engineering & Procurement (“E&P”) Agreement shall mean an agreement that authorizes the

Interconnection Customer, Interconnecting Transmission Owner and any other Affected Party to begin

engineering and procurement of long lead-time items necessary for the establishment of the

interconnection in order to advance the implementation of the Interconnection Request.

Environmental Law shall mean Applicable Laws or Regulations relating to pollution or

protection of the environment or natural resources.

Federal Power Act shall mean the Federal Power Act, as amended, 16 U.S.C. §§ 791a et seq.

Force Majeure shall mean any act of God, labor disturbance, act of the public enemy, war,

insurrection, riot, fire, storm or flood, explosion, breakage or accident to machinery or equipment, any

order, regulation or restriction imposed by governmental, military or lawfully established civilian

authorities, or any other cause beyond a Party’s control. A Force Majeure event does not include acts of

negligence or intentional wrongdoing by the Party claiming Force Majeure.

Generating Facility shall mean Interconnection Customer’s device for the production of

electricity identified in the Interconnection Request, but shall not include the Interconnection Customer’s

Interconnection Facilities.

Governmental Authority shall mean any federal, state, local or other governmental regulatory or

administrative agency, court, commission, department, board, or other governmental subdivision,

legislature, rulemaking board, tribunal, or other governmental authority having jurisdiction over the

Parties, their respective facilities, or the respective services they provide, and exercising or entitled to

exercise any administrative, executive, police, or taxing authority or power; provided, however, that such

term does not include the System Operator, Interconnection Customer, Interconnecting Transmission

Owner, or any Affiliate thereof.

Hazardous Substances shall mean any chemicals, materials or substances defined as or included

in the definition of “hazardous substances,” “hazardous wastes,” “hazardous materials,” “hazardous

constituents,” “restricted hazardous materials,” “extremely hazardous substances,” “toxic substances,”

“radioactive substances,” “contaminants,” “pollutants,” “toxic pollutants” or words of similar meaning

and regulatory effect under any applicable Environmental Law, or any other chemical, material or

substance, exposure to which is prohibited, limited or regulated by any applicable Environmental Law.

Initial Synchronization Date shall mean the date upon which the Generating Facility is initially

synchronized and upon which Trial Operation begins.

In-Service Date shall mean the date upon which the Interconnection Customer reasonably

expects it will be ready to begin use of the Interconnecting Transmission Owner’s Interconnection

Facilities to obtain back feed power.

Interconnecting Transmission Owner shall mean a Transmission Owner that owns, leases or

otherwise possesses an interest in the portion of the Administered Transmission System at the Point of

Interconnection and shall be a Party to the Standard Large Generator Interconnection Agreement. The

term Interconnecting Transmission Owner shall not be read to include the System Operator.

Interconnecting Transmission Owner’s Interconnection Facilities shall mean all facilities and

equipment owned, controlled, or operated by Interconnecting Transmission Owner from the Point of

Change of Ownership to the Point of Interconnection as identified in Appendix A to the Standard Large

Generator Interconnection Agreement, including any modifications, additions or upgrades to such

facilities and equipment. Interconnecting Transmission Owner’s Interconnection Facilities are sole use

facilities and shall not include Distribution Upgrades, Stand Alone Network Upgrades or Network

Upgrades.

Interconnection Customer shall mean any entity, including a transmission owner or its

Affiliates or subsidiaries, that interconnects or proposes to interconnect its Generating Facility with the

Administered Transmission System under the Standard Large Generator Interconnection Procedures.

Interconnection Customer’s Interconnection Facilities shall mean all facilities and equipment,

as identified in Appendix A of the Standard Large Generator Interconnection Agreement, that are located

between the Generating Facility and the Point of Change of Ownership, including any modification,

addition, or upgrades to such facilities and equipment necessary to physically and electrically interconnect

the Generating Facility to the Administered Transmission System. Interconnection Customer’s

Interconnection Facilities are sole use facilities.

Interconnection Facilities shall mean the Interconnecting Transmission Owner’s Interconnection

Facilities and the Interconnection Customer’s Interconnection Facilities. Collectively, Interconnection

Facilities include all facilities and equipment between the Generating Facility and the Point of

Interconnection, including any modification, additions or upgrades that are necessary to physically and

electrically interconnect the Generating Facility to the Administered Transmission System.

Interconnection Facilities are sole use facilities and shall not include Distribution Upgrades, Stand Alone

Network Upgrades or Network Upgrades.

Interconnection Facilities Study shall mean a study conducted by the System Operator,

Interconnecting Transmission Owner, or a third party consultant for the Interconnection Customer to

determine a list of facilities (including Interconnecting Transmission Owner’s Interconnection Facilities

and Network Upgrades as identified in the Interconnection System Impact Study), the cost of those

facilities, and the time required to interconnect the Generating Facility with the Administered

Transmission System. The scope of the study is defined in Section 8 of the Standard Large Generator

Interconnection Procedures.

Interconnection Facilities Study Agreement shall mean the form of agreement contained in


Interconnection Facilities Study.

Interconnection Feasibility Study shall mean a preliminary evaluation of the system impact and

cost of interconnecting the Generating Facility to the Administered Transmission System, the scope of

which is described in Section 6 of the Standard Large Generator Interconnection Procedures. The

Interconnection Customer has the option to request either that the Interconnection Feasibility Study be

completed as a separate and distinct study, or as part of the Interconnection System Impact Study. If the

Interconnection Customer requests that the Interconnection Feasibility Study be completed as part of the

Interconnection System Impact Study, Section 6 shall be performed as the first step of the Interconnection

System Impact Study, and shall be regarded as part of the Interconnection System Impact Study. When

the requirements of Section 6 are performed as part of the Interconnection System Impact Study, the


System Impact Study, and there shall be only one final report, which will include the results of both

Section 6 and Section 7.

Interconnection Feasibility Study Agreement shall mean the form of agreement contained in


Interconnection Feasibility Study.

Interconnection Request (a) shall mean an Interconnection Customer’s request, in the form of

Appendix 1 to the Standard Large Generator Interconnection Procedures, in accordance with the Tariff,

to: (i) interconnect a new Generating Facility to the Administered Transmission System as either a CNR

or a NR; (ii) increase the energy capability or capacity capability of an existing Generating Facility; (iii)

make a Material Modification to the design or operating characteristics of an existing Generating Facility,

including its Interconnection Facilities, that is interconnected with the Administered Transmission

System; (iv) commence participation in the wholesale markets by an existing Generating Facility that is

interconnected with the Administered Transmission System; or (v) change from NR Interconnection

Service to CNR Interconnection Service. Interconnection Request shall not include: (i) a retail customer

interconnecting a new Generating Facility that will produce electric energy to be consumed only on the

retail customer’s site; (ii) a request to interconnect a new Generating Facility to a distribution facility that

is subject to the Tariff if the Generating Facility will not be used to make wholesale sales of electricity in

interstate commerce; or (iii) a request to interconnect a Qualifying Facility (as defined by the Public

Utility Regulatory Policies Act, as amended by the Energy Policy Act of 2005 and the regulations

thereto), where the Qualifying Facility’s owner intent is to sell 100% of the Qualifying Facility’s output

to its interconnected electric utility.

Interconnection Service shall mean the service provided by System Operator and the

Interconnecting Transmission Owner, associated with interconnecting the Interconnection Customer’s

Generating Facility to the Administered Transmission System and enabling the receipt of electric energy

capability and/or capacity capability from the Generating Facility at the Point of Interconnection, pursuant

to the terms of the Standard Large Generator Interconnection Agreement and, if applicable, the Tariff.

Interconnection Study shall mean any of the following studies: the Interconnection Feasibility

Study, the Interconnection System Impact Study, the Interconnection Facilities Study and the Optional

Interconnection Study described in the Standard Large Generator Interconnection Procedures.

Interconnection Study shall not include a CNR Group Study.

Interconnection Study Agreement shall mean any of the following agreements: the

Interconnection Feasibility Study Agreement, the Interconnection System Impact Study Agreement, the

Interconnection Facilities Study Agreement, and the Optional Interconnection Study Agreement attached

to the Standard Large Generator Interconnection Procedures.

Interconnection System Impact Study shall mean an engineering study that evaluates the

impact of the proposed interconnection on the safety and reliability of the Administered Transmission

System and any other Affected System. The study shall identify and detail the system impacts that would

result if the Generating Facility were interconnected without project modifications or system

modifications, focusing on Adverse System Impacts, or to study potential impacts, including but not

limited to those identified in the Scoping Meeting as described in the Standard Large Generator

Interconnection Procedures. If the Interconnection Customer requests that the Interconnection Feasibility

Study be completed as part of the Interconnection System Impact Study, Section 6 shall be performed as

the first step of the Interconnection System Impact Study, and shall be regarded as part of the

Interconnection System Impact Study. When the requirements of Section 6 are performed as part of the

Interconnection System Impact Study, the Interconnection Customer shall be responsible only for the

deposit requirements of the Interconnection System Impact Study, and there shall be only one final report,

which will include the results of both Section 6 and Section 7.

Interconnection System Impact Study Agreement shall mean the form of agreement contained

in Appendix 3 of the Standard Large Generator Interconnection Procedures for conducting the

Interconnection System Impact Study.

IRS shall mean the Internal Revenue Service.

Large Generating Facility shall mean a Generating Facility having a maximum gross capability

at or above zero degrees F of more than 20 MW.

Long Lead Time Generating Facility (“Long Lead Facility”) shall mean a Generating Facility

with an Interconnection Request for CNR Interconnection Service that has, as applicable, elected or

requested long lead time treatment and met the eligibility criteria and requirements specified in Section

3.2.3 of the LGIP.

Loss shall mean any and all losses relating to injury to or death of any person or damage to

property, demand, suits, recoveries, costs and expenses, court costs, attorney fees, and all other

obligations by or to third parties, arising out of or resulting from another Party’s performance, or non-

performance of its obligations under the Standard Large Generator Interconnection Agreement on behalf

of the Indemnifying Party, except in cases of gross negligence or intentional wrongdoing by the

Indemnifying Party.

Major Permits shall be as defined in Section III.13.1.1.2.2.2(a) of the Tariff.

Material Modification shall mean (i) except as expressly provided in Section 4.4.1, those

modifications to the Interconnection Request, including any of the technical data provided by the

Interconnection Customer in Attachment A to the Interconnection Request or to the interconnection

configuration, requested by the Interconnection Customer that either require significant additional study

of the same Interconnection Request and could substantially change the interconnection design, or have a

material impact on the cost or timing of any Interconnection Studies or upgrades associated with an

Interconnection Request with a later queue priority date; (ii) a change to the design or operating

characteristics of an existing Generating Facility, including its Interconnection Facilities, that is

interconnected with the Administered Transmission System that may have a significant adverse effect on

the reliability or operating characteristics of the New England Transmission System; (iii) a delay to the

Commercial Operation Date, In-Service Date, or Initial Synchronization Date of greater than three (3)

years where the reason for delay is unrelated to construction schedules or permitting which delay is

beyond the Interconnection Customer’s control; or (iv) except as provided in Section 3.2.3.4 of the LGIP,

a withdrawal of a request for Long Lead Facility treatment; or (v) except as provided in Section 3.2.3.6 of

the LGIP, an election to participate in an earlier Forward Capacity Auction than originally anticipated.

Metering Equipment shall mean all metering equipment installed or to be installed at the

Generating Facility pursuant to the Standard Large Generator Interconnection Agreement at the metering

points, including but not limited to instrument transformers, MWh-meters, data acquisition equipment,

transducers, remote terminal unit, communications equipment, phone lines, and fiber optics.

Network Capability Interconnection Standard (“NC Interconnection Standard”) shall mean

the criteria required to permit the Interconnection Customer to interconnect in a manner that avoids any



Generating Facility, as detailed in the ISO New England Planning Procedures.

Network Resource (“NR”) shall mean the portion of a Generating Facility that is interconnected

to the Administered Transmission System under the Network Capability Interconnection Standard.

Network Resource Capability (“NR Capability”) shall mean the maximum gross and net

megawatt electrical output of the Generating Facility at the Point of Interconnection at an ambient

temperature at or above 50 degrees F for Summer and at or above 0 degrees F for Winter. Where the

Generating Facility includes multiple energy production devices, the NR Capability shall be the aggregate

maximum gross and net megawatt electrical output of the Generating Facility at the Point of

Interconnection at an ambient temperature at or above 50 degrees F for Summer and at or above 0 degrees

F for Winter. NR Capability shall be equal to or greater than the CNR Capability. In the case of a

Generating Facility that meets the criteria under Section 5.2.4 of this LGIP, the NR Capability shall equal

the total megawatt amount determined pursuant to Section 5.2.4.

Network Resource Interconnection Service (“NR Interconnection Service”) shall mean the

Interconnection Service selected by the Interconnection Customer to interconnect its Generating Facility

to the Administered Transmission System in accordance with the Network Capability Interconnection

Standard. An Interconnection Customer’s NR Interconnection Service shall be solely for the megawatt

amount of the NR Capability. NR Interconnection Service in and of itself does not convey transmission

service.

Network Upgrades shall mean the additions, modifications, and upgrades to the New England

Transmission System required at or beyond the Point of Interconnection to accommodate the

interconnection of the Large Generating Facility to the Administered Transmission System.

Notice of Dispute shall mean a written notice of a dispute or claim that arises out of or in

connection with the Standard Large Generator Interconnection Agreement or its performance.

Optional Interconnection Study shall mean a sensitivity analysis based on assumptions

specified by the Interconnection Customer in the Optional Interconnection Study Agreement.

Optional Interconnection Study Agreement shall mean the form of agreement contained in

Appendix 5 of the Standard Large Generator Interconnection Procedures for conducting the Optional

Interconnection Study.

Party shall mean the System Operator, Interconnection Customer and Interconnecting

Transmission Owner or any combination of the above.

Point of Change of Ownership shall mean the point, as set forth in Appendix A to the Standard

Large Generator Interconnection Agreement, where the Interconnection Customer’s Interconnection

Facilities connect to Interconnecting Transmission Owner’s Interconnection Facilities.

Point of Interconnection shall mean the point, as set forth in Appendix A to the Standard Large

Generator Interconnection Agreement, where the Interconnection Facilities connect to the Administered


Queue Position shall mean the order of a valid request in the New England Control Area, relative

to all other pending requests in the New England Control Area, that is established based upon the date and

time of receipt of such request by the System Operator. Requests are comprised of Interconnection

Requests, requests for Elective Transmission Upgrades, requests for transmission service and notification

of requests for interconnection to other electric systems, as notified by the other electric systems, that

impact the Administered Transmission System. For purposes of this LGIA, references to a “higher-

queued” Interconnection Request shall mean one that has been received by the System Operator (and

placed in queue order) earlier than another Interconnection Request, which is referred to as “lower-

queued.”

Reasonable Efforts shall mean, with respect to an action required to be attempted or taken by a

Party under the Standard Large Generator Interconnection Agreement, efforts that are timely and

consistent with Good Utility Practice and are otherwise substantially equivalent to those a Party would

use to protect its own interests.

Scoping Meeting shall mean the meeting between representatives of the System Operator,

Interconnection Customer, Interconnecting Transmission Owner, or any Affected Party as deemed


requirements, conducted for the purpose of discussing alternative interconnection options, to exchange

information including any transmission data and earlier study evaluations that would be reasonably

expected to impact such interconnection options, to analyze such information, and to determine the

potential feasible Points of Interconnection.

Site Control shall mean documentation reasonably demonstrating: (a) that the Interconnection

Customer is the owner in fee simple of the real property for which new interconnection is sought; (b) that

the Interconnection Customer holds a valid written leasehold interest in the real property for which new

interconnection is sought; (c) that the Interconnection Customer holds a valid written option to purchase

or leasehold property for which new interconnection is sought; (d) that the Interconnection Customer

holds a duly executed written contract to purchase or leasehold the real property for which new

interconnection is sought; or (e) that the Interconnection Customer has filed applications for required

permits to site on federal or state property.

Stand Alone Network Upgrades shall mean Network Upgrades that an Interconnection

Customer may construct without affecting day-to-day operations of the New England Transmission

System during their construction. The System Operator, Interconnection Customer, Interconnecting

Transmission Owner, and any Affected Party as deemed appropriate by System Operator in accordance

with applicable codes of conduct and confidentiality requirements, must agree as to what constitutes

Stand Alone Network Upgrades and identify them in Appendix A to the Standard Large Generator

Interconnection Agreement.

Standard Large Generator Interconnection Agreement (“LGIA”) shall mean the form of

interconnection agreement applicable to an Interconnection Request pertaining to a Large Generating

Facility, that is included in this Schedule 22 to the Tariff.

Standard Large Generator Interconnection Procedures (“LGIP”) shall mean the

interconnection procedures applicable to an Interconnection Request pertaining to a Large Generating

Facility that are included in this Schedule 22 to the Tariff.

System Protection Facilities shall mean the equipment, including necessary signal protection

communications equipment, required to protect (1) the New England Transmission System from faults or

other electrical disturbances occurring at the Generating Facility and (2) the Generating Facility from

faults or other electrical system disturbances occurring on the New England Transmission System or on

other delivery systems or other generating systems to which the New England Transmission System is

directly connected.

Trial Operation shall mean the period during which Interconnection Customer is engaged in on-

site test operations and commissioning of the Generating Facility prior to Commercial Operation.

ARTICLE 2. EFFECTIVE DATE, TERM AND TERMINATION

2.1 Effective Date. This LGIA shall become effective upon execution by the Parties subject to

acceptance by the Commission (if applicable), or if filed unexecuted, upon the date specified by

the Commission. System Operator and Interconnecting Transmission Owner, shall promptly and

jointly file this LGIA with the Commission upon execution in accordance with Section 11.3 of

the LGIP and Article 3.1, if required.

2.2 Term of Agreement. This LGIA, subject to the provisions of Article 2.3, and by mutual

agreement of the Parties, shall remain in effect for a period of _______ years from the Effective

Date (term to be specified in individual Agreement, but in no case should the term be less than ten

(10) years from the Effective Date or such other longer period as the Interconnection Customer

may request) and shall be automatically renewed for each successive one-year period thereafter.

2.3 Termination Procedures.

2.3.1 Written Notice. This LGIA may be terminated by the Interconnection Customer, subject

to continuing obligations of this LGIA and the Tariff, after giving the System Operator

and Interconnecting Transmission Owner ninety (90) Calendar Days advance written

notice, or by System Operator or Interconnecting Transmission Owner notifying the

Commission after a Generating Facility retires pursuant to the Tariff, provided that if an

Interconnection Customer exercises its right to terminate on ninety (90) Calendar Days,

any reconnection would be treated as a new interconnection request; or this LGIA may be

terminated by Interconnecting Transmission Owner or System Operator by notifying the

Commission after the Generating Facility permanently ceases Commercial Operation.

2.3.2 Default. Each Party may terminate this LGIA in accordance with Article 17.

Notwithstanding Articles 2.3.1 and 2.3.2, no termination shall become effective until the

Parties have complied with all Applicable Laws and Regulations applicable to such

termination, including the filing, if applicable, with the Commission of a notice of

termination of this LGIA, which notice has been accepted for filing by the Commission.

Termination of the LGIA shall not supersede or alter any requirements for deactivation or

retirement of a generating unit under ISO New England Operating Documents,

Applicable Reliability Standards, or successor documents.

2.4 Termination Costs. If a Party elects to terminate this LGIA pursuant to Article 2.3 above, each

Party shall pay all costs incurred (including any cancellation costs relating to orders or contracts

for Interconnection Facilities and equipment) or charges assessed by the other Party(ies), as of the

date of such Party’s(ies’) receipt of such notice of termination, that are the responsibility of such

Party(ies) under this LGIA. In the event of termination by a Party, all Parties shall use

commercially Reasonable Efforts to mitigate the costs, damages and charges arising as a

consequence of termination. Upon termination of this LGIA, unless otherwise ordered or

approved by the Commission:

2.4.1 With respect to any portion of the Interconnecting Transmission Owner’s Interconnection

Facilities, Network Upgrades, or Distribution Upgrades to the extent covered by this

LGIA, that have not yet been constructed or installed, the Interconnecting Transmission

Owner shall to the extent possible and with Interconnection Customer’s authorization

cancel any pending orders of, or return, any materials or equipment for, or contracts for

construction of, such facilities; provided that in the event Interconnection Customer elects

not to authorize such cancellation, Interconnection Customer shall assume all payment

obligations with respect to such materials, equipment, and contracts, and the

Interconnecting Transmission Owner shall deliver such material and equipment, and, if

necessary, and to the extent possible, assign such contracts, to Interconnection Customer

as soon as practicable, at Interconnection Customer’s expense. To the extent that

Interconnection Customer has already paid Interconnecting Transmission Owner for any

or all such costs of materials or equipment not taken by Interconnection Customer, either

(i) in the case of overpayment, Interconnecting Transmission Owner shall promptly

refund such amounts to Interconnection Customer, less any costs, including penalties

incurred by the Interconnecting Transmission Owner to cancel any pending orders of or

return such materials, equipment, or contracts, or (ii) in the case of underpayment,

Interconnection Customer shall promptly pay such amounts still due plus any costs,

including penalties incurred by Interconnecting Transmission Owner to cancel any

pending orders of or return such materials, equipment, or contracts.

If an Interconnection Customer terminates this LGIA, it shall be responsible for all costs

incurred in association with that Interconnection Customer’s interconnection, including

any cancellation costs relating to orders or contracts for Interconnection Facilities and

equipment, and other expenses including any Network Upgrades for which the

Interconnecting Transmission Owner has incurred expenses and has not been reimbursed

by the Interconnection Customer.

2.4.2 Interconnecting Transmission Owner may, at its option, retain any portion of such

materials, equipment, or facilities that Interconnection Customer chooses not to accept

delivery of, in which case Interconnecting Transmission Owner shall be responsible for

all costs associated with procuring such materials, equipment, or facilities.

2.4.3 With respect to any portion of the Interconnection Facilities, and any other facilities

already installed or constructed pursuant to the terms of this LGIA, Interconnection

Customer shall be responsible for all costs associated with the removal, relocation or

other disposition or retirement of such materials, equipment, or facilities.

2.5 Disconnection. Upon termination of this LGIA, Interconnection Service shall terminate and, the

Parties will take all appropriate steps to disconnect the Large Generating Facility from the

Interconnecting Transmission Owner’s Interconnection Facilities. All costs required to effectuate

such disconnection shall be borne by the terminating Party, unless such termination resulted from

a non-terminating Party’s Default of this LGIA or such non-terminating Party otherwise is

responsible for these costs under this LGIA.

2.6 Survival. This LGIA shall continue in effect after termination to the extent necessary to provide

for final billings and payments and for costs incurred hereunder, including billings and payments

pursuant to this LGIA; to permit the determination and enforcement of liability and

indemnification obligations arising from acts or events that occurred while this LGIA was in

effect; and to permit each Party to have access to the lands of the other Party(ies) pursuant to this

LGIA or other applicable agreements, to disconnect, remove or salvage its own facilities and

equipment.

ARTICLE 3. REGULATORY FILINGS

3.1 Filing. The System Operator and Interconnecting Transmission Owner shall jointly file this

LGIA (and any amendment hereto) with the appropriate Governmental Authority, if required, in

accordance with Section 11.3 of the LGIP. Interconnection Customer may request that any

information so provided be subject to the confidentiality provisions of Article 22. If the

Interconnection Customer has executed this LGIA, or any amendment thereto, the

Interconnection Customer shall reasonably cooperate with the System Operator and

Interconnecting Transmission Owner with respect to such filing and to provide any information

reasonably requested by the System Operator and/or the Interconnecting Transmission Owner

needed to comply with applicable regulatory requirements.

ARTICLE 4. SCOPE OF SERVICE

4.1 Interconnection Product Options. Interconnection Customer has selected the following

(checked) type(s) of Interconnection Service:

Check: ___ NR for NR Interconnection Service (NR Capability Only)

___ CNR for CNR Interconnection Service (CNR Capability and NR Capability)

4.1.1 Capacity Network Resource Interconnection Service (CNR Interconnection

Service).

4.1.1.1 The Product. The System Operator and Interconnecting Transmission Owner

must conduct the necessary studies and the Interconnecting Transmission Owner

and Affected Parties must construct the Network Upgrades needed to

interconnect the Large Generating Facility in a manner comparable to that in

which all other Capacity Network Resources are interconnected under the CNR

Interconnection Standard. CNR Interconnection Service allows the

Interconnection Customer’s Large Generating Facility to be designated as a

Capacity Network Resource, to participate in the New England Markets, in

accordance with Market Rule 1, Section III of the Tariff, up to the net CNR

Capability, or as otherwise provided in Market Rule 1, Section III of the Tariff,

on the same basis as all other existing Capacity Network Resources, and to be

studied as a Capacity Network Resource on the assumption that such a

designation will occur.

4.1.2 Network Resource Interconnection Service (NR Interconnection Service).

4.1.2.1 The Product. The System Operator and Interconnecting Transmission Owner

must conduct the necessary studies and Interconnecting Transmission Owner and

Affected Parties must construct the Network Upgrades needed to interconnect the

Large Generating Facility in a manner comparable to that in which all other

Network Resources are interconnected under the NC Interconnection Standard.

NC Interconnection Service allows the Interconnection Customer’s Large

Generating Facility to participate in the New England Markets, in accordance

with Market Rule 1, Section III of the Tariff, up to the gross and net NR

Capability or as otherwise provided in Market Rule l, Section III of the Tariff.

Notwithstanding the above, the portion of a Large Generating Facility that has

been designated as a Network Resource interconnected under the NC

Interconnection Standard cannot be a capacity resource under Section III.13 of

the Tariff, unless pursuant to a new Interconnection Request for CNR

Interconnection Service.

4.2 Provision of Service. System Operator and Interconnecting Transmission Owner shall provide

Interconnection Service for the Large Generating Facility at the Point of Interconnection.

4.3 Performance Standards. Each Party shall perform all of its obligations under this LGIA in

accordance with Applicable Laws and Regulations, the ISO New England Operating Documents,

Applicable Reliability Standards, or successor documents, and Good Utility Practice, and to the

extent a Party is required or prevented or limited in taking any action by such requirements and

standards, such Party shall not be deemed to be in Breach of this LGIA for its compliance

therewith. If such Party is the Interconnecting Transmission Owner, then that Party shall amend

the LGIA and System Operator, in conjunction with the Interconnecting Transmission Owner,

shall submit the amendment to the Commission for approval.

4.4 No Transmission Delivery Service. The execution of this LGIA does not constitute a request

for, nor the provision of, any service except for Interconnection Service, including, but not

limited to, transmission delivery service, local delivery service, distribution service, capacity

service, energy service, or Ancillary Services under any applicable tariff, and does not convey

any right to deliver electricity to any specific customer or Point of Delivery.

4.5 Transmission Delivery Service Implications. CNR Interconnection Service and NR

Interconnection Service allow the Interconnection Customer’s Large Generating Facility

to be designated by any Network Customer under the Tariff on the New England

Transmission System as a Capacity Network Resource or Network Resource, up to the

net CNR Capability or NR Capability, respectively, on the same basis as all other existing

Capacity Network Resources and Network Resources interconnected to the New England

Transmission System, and to be studied as a Capacity Network Resource or a Network

Resource on the assumption that such a designation will occur. Although CNR

Interconnection Service and NR Interconnection Service do not convey a reservation of

transmission service, any Network Customer can utilize its network service under the

Tariff to obtain delivery of capability from the Interconnection Customer’s Large

Generating Facility in the same manner as it accesses Capacity Network Resources and

Network Resources. A Large Generating Facility receiving CNR Interconnection Service

or NR Interconnection Service may also be used to provide Ancillary Services, in

accordance with the Tariff and Market Rule 1, after technical studies and/or periodic

analyses are performed with respect to the Large Generating Facility’s ability to provide

any applicable Ancillary Services, provided that such studies and analyses have been or

would be required in connection with the provision of such Ancillary Services by any

existing Capacity Network Resource or Network Resource. However, if an

Interconnection Customer’s Large Generating Facility has not been designated as a

Capacity Network Resource or as a Network Resource by any load, it cannot be required

to provide Ancillary Services except to the extent such requirements extend to all

Generating Facilities that are similarly situated.

CNR Interconnection Service and NR Interconnection Service do not necessarily provide

the Interconnection Customer with the capability to physically deliver the output of its

Large Generating Facility to any particular load on the New England Transmission

System without incurring congestion costs. In the event of transmission constraints on

the New England Transmission System, the Interconnection Customer’s Large

Generating Facility shall be subject to the applicable congestion management procedures

for the New England Transmission System in the same manner as other Capacity

Network Resources or Network Resources.

There is no requirement either at the time of study or interconnection, or at any point in

the future, that the Interconnection Customer’s Large Generating Facility be designated

as a Capacity Network Resource or as a Network Resource by a Network Service

Customer under the Tariff or that the Interconnection Customer identify a specific buyer

(or sink). To the extent a Network Customer does designate the Large Generating

Facility as either a Capacity Network Resource or a Network Resource, it must do so

pursuant to the Tariff.

Once an Interconnection Customer satisfies the requirements for obtaining CNR

Interconnection Service or NR Interconnection Service, as long as the Large Generating

Facility has not been deemed to be retired, any future transmission service request for

delivery from the Large Generating Facility on the New England Transmission System of

any amount of capacity capability and/or energy capability will not require that any

additional studies be performed or that any further upgrades associated with such Large

Generating Facility be undertaken, regardless of whether or not such Large Generating

Facility is ever designated by a Network Customer as a Capacity Network Resource or

Network Resource, and regardless of changes in ownership of the Large Generating

Facility. To the extent the Interconnection Customer enters into an arrangement for long-

term transmission service for deliveries from the Large Generating Facility outside the

New England Transmission System, or if the unit has been deemed to be retired, such

request may require additional studies and upgrades in order for Interconnecting

Transmission Owner to grant such request.

4.6 Interconnection Customer Provided Services. The services provided by Interconnection

Customer under this LGIA are set forth in Article 9.6 and Article 13.4. Interconnection Customer

shall be paid for such services in accordance with Article 11.6.

ARTICLE 5. INTERCONNECTION FACILITIES ENGINEERING,

PROCUREMENT, AND CONSTRUCTION

5.1 Options. Unless otherwise mutually agreed to between the Parties, Interconnection Customer

shall specify the In-Service Date, Initial Synchronization Date, and Commercial Operation Date

as specified in the Interconnection Request or as subsequently revised pursuant to Section 4.4 of

the LGIP; and select either Standard Option or Alternate Option set forth below for completion of

the Interconnecting Transmission Owner’s Interconnection Facilities and Network Upgrades as

set forth in Appendix A, and such dates and selected option shall be set forth in Appendix B

(Milestones). In accordance with Section 8 of the LGIP and unless otherwise mutually agreed,

the Alternate Option is not an available option if the Interconnection Customer waived the

Interconnection Facilities Study.

5.1.1 Standard Option. The Interconnecting Transmission Owner shall design, procure, and

construct the Interconnecting Transmission Owner’s Interconnection Facilities and

Network Upgrades, using Reasonable Efforts to complete the Interconnecting

Transmission Owner’s Interconnection Facilities and Network Upgrades by the dates set

forth in Appendix B (Milestones). The Interconnecting Transmission Owner shall not be

required to undertake any action which is inconsistent with its standard safety practices,

its material and equipment specifications, its design criteria and construction procedures,

its labor agreements, and Applicable Laws and Regulations. In the event the

Interconnecting Transmission Owner reasonably expects that it will not be able to

complete the Interconnecting Transmission Owner’s Interconnection Facilities and

Network Upgrades by the specified dates, the Interconnecting Transmission Owner shall

promptly provide written notice to the Interconnection Customer and shall undertake

Reasonable Efforts to meet the earliest dates thereafter.

5.1.2 Alternate Option. If the dates designated by Interconnection Customer are acceptable to

Interconnecting Transmission Owner, the Interconnecting Transmission Owner shall so

notify Interconnection Customer within thirty (30) Calendar Days, and shall assume

responsibility for the design, procurement and construction of the Interconnecting

Transmission Owner’s Interconnection Facilities by the designated dates.

If Interconnecting Transmission Owner subsequently fails to complete Interconnecting

Transmission Owner’s Interconnection Facilities by the In-Service Date, to the extent

necessary to provide back feed power; or fails to complete Network Upgrades by the

Initial Synchronization Date to the extent necessary to allow for Trial Operation at full

power output, unless other arrangements are made by the Parties for such Trial

Operation; or fails to complete the Network Upgrades by the Commercial Operation

Date, as such dates are reflected in Appendix B (Milestones); Interconnecting

Transmission Owner shall pay Interconnection Customer liquidated damages in

accordance with Article 5.3, Liquidated Damages, provided, however, the dates

designated by Interconnection Customer shall be extended day for day for each day that

the applicable System Operator refuses to grant clearances to install equipment.

5.1.3 Option to Build. If the dates designated by Interconnection Customer are not acceptable

to Interconnecting Transmission Owner, the Interconnecting Transmission Owner shall

so notify the Interconnection Customer within thirty (30) Calendar Days, and unless the

Parties agree otherwise, Interconnection Customer shall have the option to assume

responsibility for the design, procurement and construction of Interconnecting

Transmission Owner’s Interconnection Facilities and Stand Alone Network Upgrades on

the dates specified in Article 5.1.2. The System Operator, Interconnecting Transmission

Owner, Interconnection Customer, and any Affected Party as deemed appropriate by

System Operator in accordance with applicable codes of conduct and confidentiality

requirements must agree as to what constitutes Stand Alone Network Upgrades and

identify such Stand Alone Network Upgrades in Appendix A to the LGIA. Except for

Stand Alone Network Upgrades, Interconnection Customer shall have no right to

construct Network Upgrades under this option.

5.1.4 Negotiated Option. If the Interconnection Customer elects not to exercise its option

under Article 5.1.3 (Option to Build), Interconnection Customer shall so notify

Interconnecting Transmission Owner within thirty (30) Calendar Days, and the Parties

shall in good faith attempt to negotiate terms and conditions (including revision of the

specified dates and liquidated damages, the provision of incentives or the procurement

and construction of a portion of the Interconnecting Transmission Owner’s

Interconnection Facilities and Stand Alone Network Upgrades by Interconnection

Customer) pursuant to which Interconnecting Transmission Owner is responsible for the

design, procurement and construction of the Interconnecting Transmission Owner’s

Interconnection Facilities and Network Upgrades. If the Parties are unable to reach

agreement on such terms and conditions, Interconnecting Transmission Owner shall

assume responsibility for the design, procurement and construction of the Interconnecting

Transmission Owner’s Interconnection Facilities and Network Upgrades pursuant to

5.1.1 (Standard Option).

5.2 General Conditions Applicable to Option to Build. If Interconnection Customer assumes

responsibility for the design, procurement and construction of the Interconnecting Transmission

Owner’s Interconnection Facilities and Stand Alone Network Upgrades,

(1) the Interconnection Customer shall engineer, procure equipment, and construct the

Interconnecting Transmission Owner’s Interconnection Facilities and Stand Alone Network

Upgrades (or portions thereof) using Good Utility Practice and using standards and specifications

provided in advance by the Interconnecting Transmission Owner;

(2) Interconnection Customer’s engineering, procurement and construction of the


Upgrades shall comply with all requirements of law to which Interconnecting Transmission

Owner would be subject in the engineering, procurement or construction of the Interconnecting

Transmission Owner’s Interconnection Facilities and Stand Alone Network Upgrades;

(3) Interconnecting Transmission Owner shall review and approve the engineering design,

equipment acceptance tests, and the construction of the Interconnecting Transmission Owner’s

Interconnection Facilities and Stand Alone Network Upgrades;

(4) prior to commencement of construction, Interconnection Customer shall provide to

Interconnecting Transmission Owner a schedule for construction of the Interconnecting

Transmission Owner’s Interconnection Facilities and Stand Alone Network Upgrades, and shall

promptly respond to requests for information from Interconnecting Transmission Owner;

(5) at any time during construction, Interconnecting Transmission Owner shall have the right

to gain unrestricted access to the Interconnecting Transmission Owner’s Interconnection

Facilities and Stand Alone Network Upgrades and to conduct inspections of the same;

(6) at any time during construction, should any phase of the engineering, equipment

procurement, or construction of the Interconnecting Transmission Owner’s Interconnection

Facilities and Stand Alone Network Upgrades not meet the standards and specifications provided

by Interconnecting Transmission Owner, the Interconnection Customer shall be obligated to

remedy deficiencies in that portion of the Interconnecting Transmission Owner’s Interconnection

Facilities and Stand Alone Network Upgrades;

(7) the Interconnection Customer shall indemnify the Interconnecting Transmission Owner

for claims arising from the Interconnection Customer's construction of Interconnecting

Transmission Owner’s Interconnection Facilities and Stand Alone Network Upgrades under the

terms and procedures applicable to Article 18.1 (Indemnity);

(8) the Interconnection Customer shall transfer control of Interconnecting Transmission

Owner’s Interconnection Facilities and Stand Alone Network Upgrades to the Interconnecting

Transmission Owner;

(9) Unless Parties otherwise agree, Interconnection Customer shall transfer ownership of


Upgrades to Interconnecting Transmission Owner;

(10) Interconnecting Transmission Owner shall approve and accept for operation and

maintenance the Interconnecting Transmission Owner’s Interconnection Facilities and Stand

Alone Network Upgrades to the extent engineered, procured, and constructed in accordance with

this Article 5.2; and

(11) Interconnection Customer shall deliver to Interconnecting Transmission Owner “as built”

drawings, information, and any other documents that are reasonably required by Interconnecting

Transmission Owner to assure that the Interconnection Facilities and Stand Alone Network

Upgrades are built to the standards and specifications required by Interconnecting Transmission

Owner.

5.3 Liquidated Damages. The actual damages to the Interconnection Customer, in the event the

Interconnecting Transmission Owner’s Interconnection Facilities or Network Upgrades are not

completed by the dates designated by the Interconnection Customer and accepted by the

Interconnecting Transmission Owner pursuant to subparagraphs 5.1.2 or 5.1.4, above, may

include Interconnection Customer’s fixed operation and maintenance costs and lost opportunity

costs. Such actual damages are uncertain and impossible to determine at this time. Because of

such uncertainty, any liquidated damages paid by the Interconnecting Transmission Owner to the

Interconnection Customer in the event that Interconnecting Transmission Owner does not

complete any portion of the Interconnecting Transmission Owner’s Interconnection Facilities or

Network Upgrades by the applicable dates, shall be an amount equal to ½ of 1 percent per day of

the actual cost of the Interconnecting Transmission Owner’s Interconnection Facilities and

Network Upgrades, in the aggregate, for which Interconnecting Transmission Owner has assumed

responsibility to design, procure and construct.

However, in no event shall the total liquidated damages exceed 20 percent of the actual cost of

the Interconnecting Transmission Owner’s Interconnection Facilities and Network Upgrades for

which the Interconnecting Transmission Owner has assumed responsibility to design, procure,

and construct. The foregoing payments will be made by the Interconnecting Transmission Owner

to the Interconnection Customer as just compensation for the damages caused to the

Interconnection Customer, which actual damages are uncertain and impossible to determine at

this time, and as reasonable liquidated damages, but not as a penalty or a method to secure

performance of this LGIA. Liquidated damages, when the Parties agree to them, are the

exclusive remedy for the Interconnecting Transmission Owner’s failure to meet its schedule.

No liquidated damages shall be paid to Interconnection Customer if: (1) Interconnection

Customer is not ready to commence use of the Interconnecting Transmission Owner’s

Interconnection Facilities or Network Upgrades to take the delivery of power for the Large

Generating Facility's Trial Operation or to export power from the Large Generating Facility on

the specified dates, unless the Interconnection Customer would have been able to commence use

of the Interconnecting Transmission Owner’s Interconnection Facilities or Network Upgrades to

take the delivery of power for Large Generating Facility's Trial Operation or to export power

from the Large Generating Facility, but for Interconnecting Transmission Owner’s delay; (2) the

Interconnecting Transmission Owner’s failure to meet the specified dates is the result of the

action or inaction of the Interconnection Customer or any other Interconnection Customer who

has entered into an LGIA with the Interconnecting Transmission Owner or any cause beyond

Interconnecting Transmission Owner’s reasonable control or reasonable ability to cure, including,

but not limited to, actions by the System Operator that cause delays and/or delays in licensing,

permitting or consents where the Interconnecting Transmission Owner has pursued such licenses,

permits or consents in good faith; (3) the Interconnection Customer has assumed responsibility

for the design, procurement and construction of the Interconnecting Transmission Owner’s

Interconnection Facilities and Stand Alone Network Upgrades; or (4) the Parties have otherwise

agreed.

5.4 Power System Stabilizers. If a Power System Stabilizer is required to be installed on the Large

Generating Facility for the purpose of maintaining system stability, the Interconnection Customer

shall procure, install, maintain and operate Power System Stabilizers in accordance with the

guidelines and procedures established by the System Operator and Interconnecting Transmission

Owner, and consistent with the ISO New England Operating Documents, Applicable Reliability

Standards, or successor documents. The System Operator and Interconnecting Transmission

Owner reserve the right to reasonably establish minimum acceptable settings for any installed

Power System Stabilizers, subject to the design and operating limitations of the Large Generating

Facility. If the Large Generating Facility’s Power System Stabilizers are removed from service

or not capable of automatic operation, the Interconnection Customer shall immediately notify the

System Operator and Interconnecting Transmission Owner, or their designated representative.

The requirements of this paragraph shall not apply to non-synchronous power production

equipment.

5.5 Equipment Procurement. If responsibility for construction of the Interconnecting Transmission

Owner’s Interconnection Facilities or Network Upgrades is to be borne by the Interconnecting

Transmission Owner, then the Interconnecting Transmission Owner shall commence design of

the Interconnecting Transmission Owner’s Interconnection Facilities or Network Upgrades and

procure necessary equipment as soon as practicable after all of the following conditions are

satisfied, unless the Parties otherwise agree in writing:

5.5.1 The Interconnecting Transmission Owner has completed the Facilities Study pursuant to

the Facilities Study Agreement;

5.5.2 The Interconnecting Transmission Owner has received written authorization to proceed

with design and procurement from the Interconnection Customer by the date specified in

Appendix B (Milestones); and

5.5.3 The Interconnection Customer has provided security to the Interconnecting Transmission

Owner in accordance with Article 11.5 by the dates specified in Appendix B

(Milestones).

5.6 Construction Commencement. The Interconnecting Transmission Owner shall commence

construction of the Interconnecting Transmission Owner’s Interconnection Facilities and Network

Upgrades for which it is responsible as soon as practicable after the following additional

conditions are satisfied:

5.6.1 Approval of the appropriate Governmental Authority has been obtained for any facilities

requiring regulatory approval;

5.6.2 Necessary real property rights and rights-of-way have been obtained, to the extent

required for the construction of a discrete aspect of the Interconnecting Transmission

Owner’s Interconnection Facilities and Network Upgrades;

5.6.3 The Interconnecting Transmission Owner has received written authorization to proceed

with construction from the Interconnection Customer by the date specified in Appendix B

(Milestones); and

5.6.4 The Interconnection Customer has provided security to Interconnecting Transmission

Owner in accordance with Article 11.5 by the dates specified in Appendix B

(Milestones).

5.7 Work Progress. The Interconnection Customer and the Interconnecting Transmission Owner

shall keep each Party informed, by written quarterly progress reports, as to the progress of their

respective design, procurement and construction efforts in order to meet the dates specified in

Appendix B (Milestones). Any Party may also, at any other time, request a written progress

report from the other Parties. If, at any time, the Interconnection Customer determines that the

completion of the Interconnecting Transmission Owner’s Interconnection Facilities will not be

required until after the specified In-Service Date, the Interconnection Customer, upon the System

Operator’s approval that the change in the In-Service Date will not constitute a Material

Modification pursuant to Section 4.4 of the LGIP, will provide written notice to the

Interconnecting Transmission Owner of such later date upon which the completion of the

Interconnecting Transmission Owner’s Interconnection Facilities will be required.

5.8 Information Exchange. As soon as reasonably practicable after the Effective Date, the Parties

shall exchange information regarding the design and compatibility of the Parties’ Interconnection

Facilities and compatibility of the Interconnection Facilities with the New England Transmission

System, and shall work diligently and in good faith to make any necessary design changes.

5.9 Limited Operation. If any of the Interconnecting Transmission Owner’s Interconnection

Facilities or Network Upgrades are not reasonably expected to be completed prior to the

Commercial Operation Date of the Large Generating Facility, System Operator and the

Interconnecting Transmission Owner shall, upon the request and at the expense of

Interconnection Customer, perform operating studies on a timely basis to determine the extent to

which the Large Generating Facility and the Interconnection Customer’s Interconnection

Facilities may operate prior to the completion of the Interconnecting Transmission Owner’s

Interconnection Facilities or Network Upgrades consistent with Applicable Laws and

Regulations, Applicable Reliability Standards, Good Utility Practice, and this LGIA. System

Operator and Interconnecting Transmission Owner shall permit Interconnection Customer to

operate the Large Generating Facility and the Interconnection Customer’s Interconnection

Facilities in accordance with the results of such studies.

5.10 Interconnection Customer’s Interconnection Facilities (“ICIF”). Interconnection Customer

shall, at its expense, design, procure, construct, own and install the ICIF, as set forth in Appendix

A (Interconnection Facilities, Network Upgrades and Distribution Upgrades).

5.10.1 Large Generating Facility Specifications. Interconnection Customer shall submit

initial specifications for the ICIF, including System Protection Facilities, to

Interconnecting Transmission Owner at least one hundred eighty (180) Calendar Days

prior to the Initial Synchronization Date; and final specifications for review and comment

at least ninety (90) Calendar Days prior to the Initial Synchronization Date.

Interconnecting Transmission Owner shall review such specifications to ensure that the

ICIF are compatible with the technical specifications, operational control, and safety

requirements of the Interconnecting Transmission Owner and comment on such

specifications within thirty (30) Calendar Days of Interconnection Customer’s

submission. All specifications provided hereunder shall be deemed confidential.

5.10.2 Interconnecting Transmission Owner’s Review. Interconnecting Transmission

Owner’s review of Interconnection Customer’s final specifications shall not be construed

as confirming, endorsing, or providing a warranty as to the design, fitness, safety,

durability or reliability of the Large Generating Facility, or the ICIF. Interconnection

Customer shall make such changes to the ICIF as may reasonably be required by

Interconnecting Transmission Owner, in accordance with Good Utility Practice, to ensure

that the ICIF are compatible with the technical specifications, operational control, and

safety requirements of the Interconnecting Transmission Owner.

5.10.3 ICIF Construction. The ICIF shall be designed and constructed in accordance with

Good Utility Practice. Within one hundred twenty (120) Calendar Days after the

Commercial Operation Date, unless the Parties agree on another mutually acceptable

deadline, the Interconnection Customer shall deliver to the Interconnecting Transmission

Owner “as-built” drawings, information and documents for the ICIF, such as: a one-line

diagram, a site plan showing the Large Generating Facility and the ICIF, plan and

elevation drawings showing the layout of the ICIF, a relay functional diagram, relaying

AC and DC schematic wiring diagrams and relay settings for all facilities associated with

the Interconnection Customer’s step-up transformers, the facilities connecting the Large

Generating Facility to the step-up transformers and the ICIF, and the impedances

(determined by factory tests) for the associated step-up transformers and the Large

Generating Facilities. The Interconnection Customer shall provide Interconnecting

Transmission Owner specifications for the excitation system, automatic voltage regulator,

Large Generating Facility control and protection settings, transformer tap settings, and

communications, if applicable.

5.11 Interconnecting Transmission Owner’s Interconnection Facilities Construction. The

Interconnecting Transmission Owner’s Interconnection Facilities shall be designed and

constructed in accordance with Good Utility Practice. Upon request, within one hundred twenty

(120) Calendar Days after the Commercial Operation Date, unless the Parties agree on another

mutually acceptable deadline, the Interconnecting Transmission Owner shall deliver to the

Interconnection Customer the following “as-built” drawings, information and documents for the

Interconnecting Transmission Owner’s Interconnection Facilities. The appropriate drawings and

relay diagrams shall be included in Appendix A of this LGIA.

The System Operator will obtain operational control of the Interconnecting Transmission

Owner’s Interconnection Facilities and Stand Alone Network Upgrades upon completion of such

facilities pursuant to the TOA.

5.12 Access Rights. Upon reasonable notice and supervision by a Party, and subject to any required

or necessary regulatory approvals, a Party (“Granting Party”) shall furnish at the incremental cost

to another Party (“Access Party”) any rights of use, licenses, rights of way and easements with

respect to lands owned or controlled by the Granting Party, its agents if allowed under the

applicable agency agreement, that are necessary to enable the Access Party solely to obtain

ingress and egress to construct, operate, maintain, repair, test (or witness testing), inspect, replace

or remove facilities and equipment to: (i) interconnect the Large Generating Facility with the

Administered Transmission System; (ii) operate and maintain the Large Generating Facility, the

Interconnection Facilities and the New England Transmission System; and (iii) disconnect or

remove the Access Party’s facilities and equipment upon termination of this LGIA. In exercising

such licenses, rights of way and easements, the Access Party shall not unreasonably disrupt or

interfere with normal operation of the Granting Party’s business and shall adhere to the safety

rules and procedures established in advance, as may be changed from time to time, by the

Granting Party and provided to the Access Party.

5.13 Lands of Other Property Owners. If any part of the Interconnecting Transmission Owner’s

Interconnection Facilities and/or Network Upgrades is to be installed on property owned by

persons other than Interconnection Customer or Interconnecting Transmission Owner, the

Interconnecting Transmission Owner shall at Interconnection Customer’s expense use

Reasonable Efforts, including use of its eminent domain authority, and to the extent consistent

with state law, to procure from such persons any rights of use, licenses, rights of way and

easements that are necessary to construct, operate, maintain, test, inspect, replace or remove the

Interconnecting Transmission Owner’s Interconnection Facilities and/or Network Upgrades upon

such property. Notwithstanding the foregoing, the Interconnecting Transmission Owner shall not

be obligated to exercise eminent domain authority in a manner inconsistent with Applicable Laws

and Regulations or when an Interconnection Customer is authorized under Applicable Laws and

Regulations to exercise eminent domain on its own behalf.

5.14 Permits. System Operator, Interconnecting Transmission Owner and Interconnection Customer

shall cooperate with each other in good faith in obtaining all permits, licenses, and authorizations

that are necessary to accomplish the interconnection in compliance with Applicable Laws and

Regulations. With respect to this paragraph, Interconnecting Transmission Owner shall provide

permitting assistance to the Interconnection Customer comparable to that provided to the

Interconnecting Transmission Owner’s own, or an Affiliate’s generation.

5.15 Early Construction of Base Case Facilities. Interconnection Customer may request

Interconnecting Transmission Owner to construct, and Interconnecting Transmission Owner shall

construct, using Reasonable Efforts to accommodate Interconnection Customer’s In-Service Date,

all or any portion of any Network Upgrades required for Interconnection Customer to be

interconnected to the Administered Transmission System, which are included in the Base Case of

the Facilities Study for the Interconnection Customer, and which also are required to be

constructed for another Interconnection Customer, but where such construction is not scheduled

to be completed in time to achieve Interconnection Customer’s In-Service Date. The

Interconnection Customer shall reimburse the Interconnecting Transmission Owner for all costs

incurred related to early construction to the extent such costs are not recovered from other

Interconnection Customers included in the base case.

5.16 Suspension. Interconnection Customer reserves the right, upon written notice to Interconnecting

Transmission Owner and System Operator, to suspend at any time all work by Interconnecting

Transmission Owner associated with the construction and installation of Interconnecting

Transmission Owner’s Interconnection Facilities and/or Network Upgrades required under this

LGIA with the condition that the New England Transmission System shall be left in a safe and

reliable condition in accordance with Good Utility Practice and the System Operator’s and

Interconnecting Transmission Owner’s safety and reliability criteria. In such event,

Interconnection Customer shall be responsible for all reasonable and necessary costs which

Interconnecting Transmission Owner (i) has incurred pursuant to this LGIA prior to the

suspension and (ii) incurs in suspending such work, including any costs incurred to perform such

work as may be necessary to ensure the safety of persons and property and the integrity of the

New England Transmission System during such suspension and, if applicable, any costs incurred

in connection with the cancellation or suspension of material, equipment and labor contracts

which Interconnecting Transmission Owner cannot reasonably avoid; provided, however, that

prior to canceling or suspending any such material, equipment or labor contract, Interconnecting

Transmission Owner shall obtain Interconnection Customer’s authorization to do so.

Interconnecting Transmission Owner shall invoice Interconnection Customer for such costs

pursuant to Article 12 and shall use due diligence to minimize its costs. In the event

Interconnection Customer suspends work by Interconnecting Transmission Owner required under

this LGIA pursuant to this Article 5.16, and has not requested Interconnecting Transmission

Owner to recommence the work required under this LGIA on or before the expiration of three (3)

years following commencement of such suspension, this LGIA shall be deemed terminated. The

three-year period shall begin on the date the suspension is requested, or the date of the written

notice to Interconnecting Transmission Owner and System Operator, if no effective date is

specified. A suspension under this Article 5.16 does not automatically permit an extension of the

In-Service Date, the Initial Synchronization Date or the Commercial Operation Date. A request

for extension of such dates is subject to Section 4.4.5 of the LGIP. Notwithstanding the

extensions permitted under Section 4.4.5 of the LGIP, the three-year period shall in no way result

in an extension of the In-Service Date, the Initial Synchronization Date or the Commercial

Operation Date that exceeds seven (7) years from the date of the Interconnection Request;

otherwise, this LGIA shall be deemed terminated.

5.17 Taxes.

5.17.1 Payments Not Taxable. The Parties intend that all payments or property transfers made

by any Party for the installation of the Interconnecting Transmission Owner’s

Interconnection Facilities and the Network Upgrades shall be non-taxable, either as

contributions to capital, or as an advance, in accordance with the Internal Revenue Code

and any applicable state income tax laws and shall not be taxable as contributions in aid

of construction or otherwise under the Internal Revenue Code and any applicable state

income tax laws.

5.17.2 Representations and Covenants. In accordance with IRS Notice 2001-82 and IRS

Notice 88-129, Interconnection Customer represents and covenants that (i) ownership of

the electricity generated at the Large Generating Facility will pass to another party prior

to the transmission of the electricity on the New England Transmission System, (ii) for

income tax purposes, the amount of any payments and the cost of any property

transferred to the Interconnecting Transmission Owner for the Interconnecting

Transmission Owner’s Interconnection Facilities will be capitalized by Interconnection

Customer as an intangible asset and recovered using the straight-line method over a

useful life of twenty (20) years, and (iii) any portion of the Interconnecting Transmission

Owner’s Interconnection Facilities that is a “dual-use intertie,” within the meaning of IRS

Notice 88-129, is reasonably expected to carry only a de minimis amount of electricity in

the direction of the Large Generating Facility. For this purpose, “de minimis amount”

means no more than 5 percent of the total power flows in both directions, calculated in

accordance with the “5 percent test” set forth in IRS Notice 88-129. This is not intended

to be an exclusive list of the relevant conditions that must be met to conform to IRS

requirements for non-taxable treatment.

At Interconnecting Transmission Owner’s request, Interconnection Customer shall

provide Interconnecting Transmission Owner with a report from an independent engineer

confirming its representation in clause (iii), above. Interconnecting Transmission Owner

represents and covenants that the cost of the Interconnecting Transmission Owner’s

Interconnection Facilities paid for by Interconnection Customer will have no net effect on

the base upon which rates are determined.

5.17.3 Indemnification for the Cost Consequences of Current Tax Liability Imposed Upon

Interconnecting Transmission Owner. Notwithstanding Article 5.17.1, Interconnection

Customer shall protect, indemnify and hold harmless Interconnecting Transmission

Owner from the cost consequences of any current tax liability imposed against

Interconnecting Transmission Owner as the result of payments or property transfers made

by Interconnection Customer to Interconnecting Transmission Owner under this LGIA,

as well as any interest and penalties, other than interest and penalties attributable to any

delay caused by Interconnecting Transmission Owner.

The Interconnecting Transmission Owner shall not include a gross-up for the cost

consequences of any current tax liability in the amounts it charges Interconnection

Customer under this LGIA unless (i) Interconnecting Transmission Owner has

determined, in good faith, that the payments or property transfers made by

Interconnection Customer to Interconnecting Transmission Owner should be reported as

income subject to taxation or (ii) any Governmental Authority directs Interconnecting

Transmission Owner to report payments or property as income subject to taxation;

provided, however, that Interconnecting Transmission Owner may require

Interconnection Customer to provide security, in a form reasonably acceptable to

Interconnecting Transmission Owner (such as a parental guarantee or a letter of credit), in

an amount equal to the cost consequences of any current tax liability under this Article

5.17. Interconnection Customer shall reimburse Interconnecting Transmission Owner for

such costs on a fully grossed-up basis, in accordance with Article 5.17.4, within thirty

(30) Calendar Days of receiving written notification from Interconnecting Transmission

Owner of the amount due, including detail about how the amount was calculated.

The indemnification obligation shall terminate at the earlier of (1) the expiration of the

ten year testing period, and the applicable statute of limitation, as it may be extended by

the Interconnecting Transmission Owner upon request of the IRS, to keep these years

open for audit or adjustment, or (2) the occurrence of a subsequent taxable event and the

payment of any related indemnification obligations as contemplated by this Article 5.17.

5.17.4 Tax Gross-Up Amount. Interconnection Customer’s liability for the cost consequences

of any current tax liability under this Article 5.17 shall be calculated on a fully grossed-

up basis. Except as may otherwise be agreed to by the parties, this means that

Interconnection Customer will pay Interconnecting Transmission Owner, in addition to

the amount paid for the Interconnection Facilities and Network Upgrades, an amount

equal to (1) the current taxes imposed on Interconnecting Transmission Owner (“Current

Taxes”) on the excess of (a) the gross income realized by Interconnecting Transmission

Owner as a result of payments or property transfers made by Interconnection Customer to

Interconnecting Transmission Owner under this LGIA (without regard to any payments

under this Article 5.17) (the “Gross Income Amount”) over (b) the present value of future

tax deductions for depreciation that will be available as a result of such payments or

property transfers (the “Present Value Depreciation Amount”), plus (2) an additional

amount sufficient to permit the Interconnecting Transmission Owner to receive and

retain, after the payment of all Current Taxes, an amount equal to the net amount

described in clause (1).For this purpose, (i) Current Taxes shall be computed based on

Interconnecting Transmission Owner composite federal and state tax rates at the time the

payments or property transfers are received and Interconnecting Transmission Owner will

be treated as being subject to tax at the highest marginal rates in effect at that time (the

“Current Tax Rate”), and (ii) the Present Value Depreciation Amount shall be computed

by discounting Interconnecting Transmission Owner’s anticipated tax depreciation

deductions as a result of such payments or property transfers by Interconnecting

Transmission Owner current weighted average cost of capital. Thus, the formula for

calculating Interconnection Customer’s liability to Transmission Owner pursuant to this

Article 5.17.4 can be expressed as follows: (Current Tax Rate x (Gross Income Amount –

Present Value of Tax Depreciation))/(1-Current Tax Rate). Interconnection Customer’s

estimated tax liability in the event taxes are imposed shall be stated in Appendix A

(Interconnection Facilities, Network Upgrades and Distribution Upgrades).

5.17.5 Private Letter Ruling or Change or Clarification of Law. At Interconnection

Customer’s request and expense, Interconnecting Transmission Owner shall file with the

IRS a request for a private letter ruling as to whether any property transferred or sums

paid, or to be paid, by Interconnection Customer to Interconnecting Transmission Owner

under this LGIA are subject to federal income taxation. Interconnection Customer will

prepare the initial draft of the request for a private letter ruling, and will certify under

penalties of perjury that all facts represented in such request are true and accurate to the

best of Interconnection Customer’s knowledge. Interconnecting Transmission Owner

and Interconnection Customer shall cooperate in good faith with respect to the

submission of such request.

Interconnecting Transmission Owner shall keep Interconnection Customer fully informed

of the status of such request for a private letter ruling and shall execute either a privacy

act waiver or a limited power of attorney, in a form acceptable to the IRS, that authorizes

Interconnection Customer to participate in all discussions with the IRS regarding such

request for a private letter ruling. Interconnecting Transmission Owner shall allow

Interconnection Customer to attend all meetings with IRS officials about the request and

shall permit Interconnection Customer to prepare the initial drafts of any follow-up letters

in connection with the request.

5.17.6 Subsequent Taxable Events. If, within ten (10) years from the date on which the

relevant Interconnecting Transmission Owner’s Interconnection Facilities are placed in

service, (i) Interconnection Customer Breaches the covenant contained in Article 5.17.2,

(ii) a “disqualification event” occurs within the meaning of IRS Notice 88-129, or (iii)

this LGIA terminates and Interconnecting Transmission Owner retains ownership of the

Interconnection Facilities and Network Upgrades, the Interconnection Customer shall pay

a tax gross-up for the cost consequences of any current tax liability imposed on

Interconnecting Transmission Owner, calculated using the methodology described in

Article 5.17.4 and in accordance with IRS Notice 90-60.

5.17.7 Contests. In the event any Governmental Authority determines that Interconnecting

Transmission Owner’s receipt of payments or property constitutes income that is subject

to taxation, Interconnecting Transmission Owner shall notify Interconnection Customer,

in writing, within thirty (30) Calendar Days of receiving notification of such

determination by a Governmental Authority. Upon the timely written request by

Interconnection Customer and at Interconnection Customer’s sole expense,

Interconnecting Transmission Owner may appeal, protest, seek abatement of, or

otherwise oppose such determination. Upon Interconnection Customer’s written request

and sole expense, Interconnecting Transmission Owner may file a claim for refund with

respect to any taxes paid under this Article 5.17, whether or not it has received such a

determination. Interconnecting Transmission Owner reserves the right to make all

decisions with regard to the prosecution of such appeal, protest, abatement or other

contest, including the selection of counsel and compromise or settlement of the claim, but

Interconnecting Transmission Owner shall keep Interconnection Customer informed,

shall consider in good faith suggestions from Interconnection Customer about the

conduct of the contest, and shall reasonably permit Interconnection Customer or an

Interconnection Customer representative to attend contest proceedings.

Interconnection Customer shall pay to Interconnecting Transmission Owner on a periodic

basis, as invoiced by Interconnecting Transmission Owner, documented reasonable costs

of prosecuting such appeal, protest, abatement or other contest. At any time during the

contest, Interconnecting Transmission Owner may agree to a settlement either with

Interconnection Customer’s consent or after obtaining written advice from nationally-

recognized tax counsel, selected by Interconnecting Transmission Owner, but reasonably

acceptable to Interconnection Customer, that the proposed settlement represents a

reasonable settlement given the hazards of litigation. Interconnection Customer’s

obligation shall be based on the amount of the settlement agreed to by Interconnection

Customer, or if a higher amount, so much of the settlement that is supported by the

written advice from nationally recognized tax counsel selected under the terms of the

preceding sentence. The settlement amount shall be calculated on a fully grossed-up

basis to cover any related cost consequences of the current tax liability. Any settlement

without Interconnection Customer’s consent or such written advice will relieve

Interconnection Customer from any obligation to indemnify Interconnecting

Transmission Owner for the tax at issue in the contest.

5.17.8 Refund. In the event that (a) a private letter ruling is issued to Interconnecting

Transmission Owner which holds that any amount paid or the value of any property

transferred by Interconnection Customer to Interconnecting Transmission Owner under

the terms of this LGIA is not subject to federal income taxation, (b) any legislative

change or administrative announcement, notice, ruling or other determination makes it

reasonably clear to Interconnecting Transmission Owner in good faith that any amount

paid or the value of any property transferred by Interconnection Customer to

Interconnecting Transmission Owner under the terms of this LGIA is not taxable to

Interconnecting Transmission Owner, (c) any abatement, appeal, protest, or other contest

results in a determination that any payments or transfers made by Interconnection

Customer to Interconnecting Transmission Owner are not subject to federal income tax,

or (d) if Interconnecting Transmission Owner receives a refund from any taxing authority

for any overpayment of tax attributable to any payment or property transfer made by

Interconnection Customer to Interconnecting Transmission Owner pursuant to this LGIA,

Interconnecting Transmission Owner shall promptly refund to Interconnection Customer

the following:

(i) any payment made by Interconnection Customer under this Article 5.17

for taxes that is attributable to the amount determined to be non-taxable, together

with interest thereon,

(ii) interest on any amounts paid by Interconnection Customer to

Interconnecting Transmission Owner for such taxes which Interconnecting

Transmission Owner did not submit to the taxing authority, interest calculated in

accordance with the methodology set forth in the Commission’s regulations at 18

CFR §35.19a(a)(2)(iii) from the date payment was made by Interconnection

Customer to the date Interconnecting Transmission Owner refunds such payment

to Interconnection Customer, and

(iii) with respect to any such taxes paid by Interconnecting Transmission

Owner, any refund or credit Interconnecting Transmission Owner receives or to

which it may be entitled from any Governmental Authority, interest (or that

portion thereof attributable to the payment described in clause (i), above) owed to

the Interconnecting Transmission Owner for such overpayment of taxes

(including any reduction in interest otherwise payable by Interconnecting

Transmission Owner to any Governmental Authority resulting from an offset or

credit); provided, however, that Interconnecting Transmission Owner will remit

such amount promptly to Interconnection Customer only after and to the extent

that Interconnecting Transmission Owner has received a tax refund, credit or

offset from any Governmental Authority for any applicable overpayment of

income tax related to the Interconnecting Transmission Owner’s Interconnection

Facilities.

The intent of this provision is to leave Parties, to the extent practicable, in the event that

no taxes are due with respect to any payment for Interconnection Facilities and Network

Upgrades hereunder, in the same position they would have been in had no such tax

payments been made.

5.17.9 Taxes Other Than Income Taxes. Upon the timely request by Interconnection

Customer, and at Interconnection Customer’s sole expense, Interconnecting Transmission

Owner shall appeal, protest, seek abatement of, or otherwise contest any tax (other than

federal or state income tax) asserted or assessed against Interconnecting Transmission

Owner for which Interconnection Customer may be required to reimburse

Interconnecting Transmission Owner under the terms of this LGIA. Interconnection

Customer shall pay to Interconnecting Transmission Owner on a periodic basis, as

invoiced by Interconnecting Transmission Owner, Interconnecting Transmission Owner’s

documented reasonable costs of prosecuting such appeal, protest, abatement, or other

contest. Interconnection Customer and Interconnecting Transmission Owner shall

cooperate in good faith with respect to any such contest. Unless the payment of such

taxes is a prerequisite to an appeal or abatement or cannot be deferred, no amount shall

be payable by Interconnection Customer to Interconnecting Transmission Owner for such

taxes until they are assessed by a final, non-appealable order by any court or agency of

competent jurisdiction. In the event that a tax payment is withheld and ultimately due

and payable after appeal, Interconnection Customer will be responsible for all taxes,

interest and penalties, other than penalties attributable to any delay caused by


5.18 Tax Status. Each Party shall cooperate with the others to maintain the other Party’s(ies’) tax

status. Nothing in this LGIA is intended to adversely affect any Interconnecting Transmission

Owner’s tax-exempt status with respect to the issuance of bonds including, but not limited to,

Local Furnishing Bonds.

5.19 Modification.

5.19.1 General. Either Interconnection Customer or Interconnecting Transmission Owner may

undertake modifications to its facilities. If a Party plans to undertake a modification that

reasonably may be expected to affect the other Party’s facilities,the facilities of any

Affected Parties, or the New England Transmission System, that Party shall provide to

the other Parties and any Affected Party: (i) sufficient information regarding such

modification so that the other Party(ies) may evaluate the potential impact of such

modification prior to commencement of the work; and (ii) such information as may be

required by the ISO New England Operating Documents, Applicable Reliability

Standards, or successor documents. Such information shall be deemed to be confidential

hereunder and shall include information concerning the timing of such modifications and

whether such modifications are expected to interrupt the flow of electricity from the

Large Generating Facility. The Party desiring to perform such work shall provide the

relevant drawings, plans, and specifications to the other Party(ies) at least ninety (90)

Calendar Days in advance of the commencement of the work or such shorter period upon

which the Parties may agree, which agreement shall not unreasonably be withheld,

conditioned or delayed. Notwithstanding the foregoing, no Party shall be obligated to

proceed with a modification that would constitute a Material Modification and therefore

require an Interconnection Request under the LGIP, except as provided under and

pursuant to the LGIP.

In the case of Large Generating Facility or Interconnection Customer’s Interconnection

Facility modifications that do not require Interconnection Customer to submit an

Interconnection Request, Interconnecting Transmission Owner shall provide, within

thirty (30) Calendar Days (or such other time as the Parties may agree), an estimate of

any additional modifications to the New England Transmission System, Interconnecting

Transmission Owner’s Interconnection Facilities or Network Upgrades necessitated by

such Interconnection Customer modification and a good faith estimate of the costs

thereof.

5.19.2 Standards. Any additions, modifications, or replacements made to a Party’s facilities

shall be designed, constructed and operated in accordance with this LGIA and Good

Utility Practice.

5.19.3 Modification Costs. Interconnection Customer shall not be directly assigned for the

costs of any additions, modifications, or replacements that Interconnecting Transmission

Owner makes to the Interconnecting Transmission Owner’s Interconnection Facilities or

the New England Transmission System to facilitate the interconnection of a third party to

the Interconnecting Transmission Owner’s Interconnection Facilities or the New England

Transmission System, or to provide transmission service to a third party under the Tariff,

except as provided for under the Tariff or any other applicable tariff. Interconnection

Customer shall be responsible for the costs of any additions, modifications, or

replacements to the Large Generating Facility or Interconnection Customer’s

Interconnection Facilities that may be necessary to maintain or upgrade such

Interconnection Customer’s Interconnection Facilities consistent with Applicable Laws

and Regulations, Applicable Reliability Standards or Good Utility Practice.

ARTICLE 6. TESTING AND INSPECTION

6.1 Pre-Commercial Operation Date Testing and Modifications. Prior to the Commercial

Operation Date, the Interconnecting Transmission Owner shall test Interconnecting Transmission

Owner’s Interconnection Facilities and Network Upgrades and Interconnection Customer shall

test the Large Generating Facility and the Interconnection Customer’s Interconnection Facilities

to ensure their safe and reliable operation. Similar testing may be required after initial operation.

Each Party shall make any modifications to its facilities that are found to be necessary as a result

of such testing. Interconnection Customer shall bear the cost of all such testing and

modifications. Interconnection Customer shall generate test energy at the Large Generating

Facility only if it has arranged for the delivery of such test energy.

6.2 Post-Commercial Operation Date Testing and Modifications. Each Interconnection Customer

and Interconnecting Transmission Owner shall at its own expense perform routine inspection and

testing of its facilities and equipment in accordance with ISO New England Operating

Documents, Applicable Reliability Standards, or successor documents, as may be necessary to

ensure the continued interconnection of the Large Generating Facility to the Administered

Transmission System in a safe and reliable manner. The Interconnection Customer and

Interconnecting Transmission Owner each shall have the right, upon advance written notice, to

require reasonable additional testing of the other Party’s(ies’) facilities, at the requesting Party’s

expense, as may be in accordance with the ISO New England Operating Documents, Applicable

Reliability Standards, or successor documents. The System Operator shall also have the right to

require reasonable additional testing of the other Party’s (ies’) facilities in accordance with the

ISO New England Operating Documents, Applicable Reliability Standards, or successor

documents.

6.3 Right to Observe Testing. Each Party shall notify the System Operator and other Party(ies) in

advance of its performance of tests of its Interconnection Facilities. The other Party(ies) has the

right, at its own expense, to observe such testing.

6.4 Right to Inspect. Each Party shall have the right, but shall have no obligation to: (i) observe the

other Party’s(ies’) tests and/or inspection of any of its System Protection Facilities and other

protective equipment, including Power System Stabilizers; (ii) review the settings of the other

Party’s(ies’) System Protection Facilities and other protective equipment; and (iii) review the

other Party’s(ies’) maintenance records relative to the Interconnection Facilities, the System

Protection Facilities and other protective equipment. Each Party may exercise these rights from

time to time as it deems necessary upon reasonable notice to the other Parties. The exercise or

non-exercise by a Party of any such rights shall not be construed as an endorsement or

confirmation of any element or condition of the Interconnection Facilities or the System

Protection Facilities or other protective equipment or the operation thereof, or as a warranty as to

the fitness, safety, desirability, or reliability of same. Any information that a Party obtains

through the exercise of any of its rights under this Article 6.4 shall be governed by Article 22.

ARTICLE 7. METERING

7.1 General. Each Party shall comply with the ISO New England Operating Documents, Applicable

Reliability Standards, or successor documents, regarding metering. Interconnection Customer

shall bear all reasonable documented costs associated with the purchase, installation, operation,

testing and maintenance of the Metering Equipment. Unless the System Operator otherwise

agrees, the Interconnection Customer shall be responsible for installing and maintaining

compatible metering and communications equipment to accurately account for the capacity and

energy being transmitted under this Tariff and to communicate the information to the System

Operator. Unless otherwise agreed, such equipment shall remain the property of the


7.2 Check Meters. Interconnection Customer, at its option and expense, may install and operate, on

its premises and on its side of the Point of Interconnection, one or more check meters to check

Interconnecting Transmission Owner’s meters. Such check meters shall be for check purposes

only and shall not be used for the measurement of power flows for purposes of this LGIA, except

as provided in Article 7.4 below. The check meters shall be subject at all reasonable times to

inspection and examination by Interconnecting Transmission Owner or its designee. The

installation, operation and maintenance thereof shall be performed entirely by Interconnection

Customer in accordance with Good Utility Practice.

7.3 Standards. Interconnecting Transmission Owner shall install, calibrate, and test revenue quality

Metering Equipment in accordance with applicable ANSI standards and the ISO New England

Operating Documents, Applicable Reliability Standards, or successor documents.

7.4 Testing of Metering Equipment. Interconnecting Transmission Owner shall inspect and test all

Interconnecting Transmission Owner-owned Metering Equipment upon installation and thereafter

as specified in the ISO New England Operating Documents, Applicable Reliability Standards, or

successor documents. Interconnecting Transmission Owner shall give reasonable notice of the

time when any inspection or test shall take place, and Interconnection Customer may have

representatives present at the test or inspection. If at any time Metering Equipment is found to be

inaccurate or defective, it shall be adjusted, repaired or replaced at Interconnection Customer’s

expense, in order to provide accurate metering. If Metering Equipment fails to register, or if the

measurement made by Metering Equipment during a test varies by more than the values specified

within ISO New England Operating Documents, or successor documents, from the measurement

made by the standard meter used in the test, the Interconnecting Transmission Owner shall adjust

the measurements, in accordance with the ISO New England Operating Documents, Applicable

Reliability Standards, or successor documents.

7.5 Metering Data. At Interconnection Customer’s expense, metered data shall be telemetered to

one or more locations designated by System Operator and Interconnecting Transmission Owner.

The hourly integrated metering, established in accordance with ISO New England Operating

Documents, Applicable Reliability Standards, or successor documents, used to transmit Megawatt

hour (“MWh”) per hour data by electronic means and the Watt-hour meters equipped with

kilowatt-hour (“kwh”) or MWh registers to be read at month’s end shall be the official

measurement of the amount of energy delivered from the Large Generating Facility to the Point

of Interconnection. Instantaneous metering is required for all Generators in accordance with ISO

New England Operating Documents, Applicable Reliability Standards, or successor documents.

ARTICLE 8. COMMUNICATIONS

8.1 Interconnection Customer Obligations. Interconnection Customer shall maintain satisfactory

operating communications with the System Operator and Interconnecting Transmission Owner in

accordance with applicable provisions of ISO New England Operating Documents, Applicable


8.2 Remote Terminal Unit. Prior to the Initial Synchronization Date of the Large Generating

Facility, a Remote Terminal Unit, or equivalent data collection and transfer equipment acceptable

to the Parties, shall be installed by Interconnection Customer or Interconnecting Transmission

Owner at Interconnection Customer’s expense, to gather accumulated and instantaneous data to

be telemetered to the location(s) designated by System Operator and Interconnecting

Transmission Owner through use of a dedicated point-to-point data circuit(s). The

communication protocol for the data circuit(s) shall be specified by System Operator and

Interconnecting Transmission Owner. All information required by the ISO New England

Operating Documents, or successor documents, must be telemetered directly to the location(s)

specified by System Operator and Interconnecting Transmission Owner.

Each Party will promptly advise the other Party(ies) if it detects or otherwise learns of any

metering, telemetry or communications equipment errors or malfunctions that require the

attention and/or correction by the other Party(ies). The Party owning such equipment shall

correct such error or malfunction as soon as reasonably feasible.

8.3 No Annexation. Any and all equipment placed on the premises of a Party shall be and remain

the property of the Party providing such equipment regardless of the mode and manner of

annexation or attachment to real property, unless otherwise mutually agreed by the Parties.

ARTICLE 9. OPERATIONS

9.1 General. Each Party shall comply with applicable provisions of ISO New England Operating

Documents, Reliability Standards, or successor documents, regarding operations. Each Party

shall provide to the other Party(ies) all information that may reasonably be required by the other

Party(ies) to comply with Applicable Laws and Regulations and Applicable Reliability Standards.

9.2 Control Area Notification. Before Initial Synchronization Date, the Interconnection Customer

shall notify the System Operator and Interconnecting Transmission Owner in writing in

accordance with ISO New England Operating Documents, Reliability Standards, or successor

documents. If the Interconnection Customer elects to have the Large Generating Facility

dispatched and operated from a remote Control Area other than the Control Area in which the

Large Generating Facility is physically located, and if permitted to do so by the relevant

transmission tariffs and ISO New England Operating Documents, Reliability Standards, or

successor documents, all necessary arrangements, including but not limited to those set forth in

Article 7 and Article 8 of this LGIA, and remote Control Area generator interchange agreements,

if applicable, and the appropriate measures under such agreements, shall be executed and

implemented prior to the placement of the Large Generating Facility in the other Control Area for

dispatch and operations.

9.3 Interconnecting Transmission Owner and System Operator Obligations. Interconnecting

Transmission Owner and System Operator shall cause the Interconnecting Transmission Owner’s

Interconnection Facilities to be operated, maintained and controlled in a safe and reliable manner

and in accordance with this LGIA and ISO New England Operating Documents, Reliability

Standards, or successor documents. Interconnecting Transmission Owner or System Operator

may provide operating instructions to Interconnection Customer consistent with this LGIA, ISO

New England Operating Documents, Applicable Reliability Standards, or successor documents,

and Interconnecting Transmission Owner’s and System Operator’s operating protocols and

procedures as they may change from time to time. Interconnecting Transmission Owner and

System Operator will consider changes to their operating protocols and procedures proposed by

Interconnection Customer.

9.4 Interconnection Customer Obligations. Interconnection Customer shall at its own expense

operate, maintain and control the Large Generating Facility and the Interconnection Customer’s

Interconnection Facilities in a safe and reliable manner and in accordance with this LGIA and

ISO New England Operating Documents, Applicable Reliability Standards, or successor

documents.

9.5 Start-Up and Synchronization. The Interconnection Customer is responsible for the proper

start-up and synchronization of the Large Generating Facility to the New England Transmission

System in accordance with ISO New England Operating Documents, Applicable Reliability

Standards, or successor documents.

9.6 Reactive Power.

9.6.1 Power Factor Design Criteria. Interconnection Customer shall design the Large

Generating Facility and all generating units comprising the Large Generating Facility, as

applicable, to maintain a composite power delivery at continuous rated power output at

the Point of Interconnection at a power factor within the range of 0.95 leading to 0.95

lagging, unless the System Operator or Interconnecting Transmission Owner has

established different requirements that apply to all generators in the Control Area on a

comparable basis and in accordance with ISO New England Operating Documents,

Applicable Reliability Standards, or successor documents. The requirements of this

paragraph shall not apply to wind generators.

9.6.2 Voltage Schedules. Once the Interconnection Customer has synchronized the Large

Generating Facility to the New England Transmission System, Interconnection Customer

shall operate the Large Generating Facility at the direction of System Operator and

Interconnecting Transmission Owner in accordance with applicable provisions of the ISO

New England Operating Documents, Applicable Reliability Standards, or successor

documents, regarding voltage schedules in accordance with such requirements.

9.6.2.1 Voltage Regulators. The Interconnection Customer must keep and maintain a

voltage regulator on all generating units comprising a Large Generating Facility

in accordance with the ISO New England Operating Documents, Applicable

Reliability Standards, or successor documents. All Interconnection Customers

that have, or are required to have, automatic voltage regulation shall normally

operate the Large Generating Facility with its voltage regulators in automatic

operation.

It is the responsibility of the Interconnection Customer to maintain the voltage

regulator in good operating condition and promptly report to the System Operator

and Interconnecting Transmission Owner any problems that could cause

interference with its proper operation.

9.6.2.2 Governor Control. The Interconnection Customer is obligated to provide and

maintain a functioning governor on all generating units comprising the Large

Generating Facility in accordance with applicable provisions of the ISO New

England Operating Documents, Applicable Reliability Standards, or successor

documents.

9.6.2.3 System Protection. The Interconnection Customer shall install and maintain

protection systems in accordance with applicable provisions of the ISO New


documents.

9.6.3 Payment for Reactive Power.

Interconnection Customers shall be compensated for Reactive Power service in

accordance with Schedule 2 of the Section II of the Tariff.

9.7 Outages and Interruptions.

9.7.1 Outages.

9.7.1.1 Outage Authority and Coordination. The System Operator shall have the

authority to coordinate facility outages in accordance with the ISO New England


Each Party may in accordance with the ISO New England Operating Documents,

Applicable Reliability Standards, or successor documents, in coordination with

the other Party(ies), remove from service any of its respective Interconnection

Facilities or Network Upgrades that may impact the other Party’s(ies’) facilities

as necessary to perform maintenance or testing or to install or replace equipment,

subject to the oversight of System Operator in accordance with the ISO New


documents.

9.7.1.2 Outage Schedules. Outage scheduling, and any related compensation, shall be

in accordance with the applicable provisions of the ISO New England Operating

Documents, Applicable Reliability Standards, or successor documents.

9.7.2 Interruption of Service. In accordance with the ISO New England Operating

Documents, Applicable Reliability Standards, or successor documents, the System

Operator or Interconnecting Transmission Owner may require Interconnection Customer

to interrupt or reduce deliveries of electricity if such delivery of electricity could

adversely affect System Operator’s or Interconnecting Transmission Owner’s ability to

perform such activities as are necessary to safely and reliably operate and maintain the

New England Transmission System.

9.7.3 Under-Frequency and Over Frequency Conditions. Interconnection Customer shall

implement under-frequency and over-frequency relay set points for the Large Generating

Facility as required by the applicable provisions of ISO New England Operating

Documents, Applicable Reliability Standards, or successor documents. Large Generating

Facility response to frequency deviations of pre-determined magnitudes, both under-

frequency and over-frequency deviations, shall be studied and coordinated with System

Operator and Interconnecting Transmission Owner in accordance with ISO New England


9.7.4 System Protection and Other Control Requirements.

9.7.4.1 System Protection Facilities. Interconnection Customer shall, at its expense,

install, operate and maintain System Protection Facilities as a part of the Large

Generating Facility or the Interconnection Customer’s Interconnection Facilities

in accordance with the ISO New England Operating Documents, Applicable

Reliability Standards, or successor documents. Interconnecting Transmission

Owner shall install at Interconnection Customer’s expense, in accordance with

the ISO New England Operating Documents, Applicable Reliability Standards,

or successor documents, any System Protection Facilities that may be required on

the Interconnecting Transmission Owner Interconnection Facilities or the New

England Transmission System as a result of the interconnection of the Large

Generating Facility and the Interconnection Customer’s Interconnection

Facilities.

9.7.4.2 Each Party’s protection facilities shall be designed and coordinated with other

systems in accordance with the ISO New England Operating Documents,


9.7.4.3 Each Party shall be responsible for protection of its facilities consistent with the

ISO New England Operating Documents, Applicable Reliability Standards, or

successor documents.

9.7.4.4 Each Party’s protective relay design shall allow for tests required in Article 6.

9.7.4.5 Each Party will test, operate and maintain System Protection Facilities in

accordance with the ISO New England Operating Documents, Applicable


9.7.5 Requirements for Protection. In accordance with the ISO New England Operating

Documents, Applicable Reliability Standards, or successor documents, and compliance

with Good Utility Practice , Interconnection Customer shall provide, install, own, and

maintain relays, circuit breakers and all other devices necessary to remove any fault

contribution of the Large Generating Facility to any short circuit occurring on the New

England Transmission System not otherwise isolated by Interconnecting Transmission

Owner’s equipment, such that the removal of the fault contribution shall be coordinated

with the protective requirements of the New England Transmission System. Such

protective equipment shall include, without limitation, a disconnecting device or switch

with load-interrupting capability located between the Large Generating Facility and the

New England Transmission System at a site selected upon mutual agreement (not to be

unreasonably withheld, conditioned or delayed) of the Parties. Interconnection Customer

shall be responsible for protection of the Large Generating Facility and Interconnection

Customer’s other equipment from such conditions as negative sequence currents, over- or

under-frequency, sudden load rejection, over- or under-voltage, and generator loss-of-

field. Interconnection Customer shall be solely responsible to disconnect the Large

Generating Facility and Interconnection Customer’s other equipment if conditions on the

New England Transmission System could adversely affect the Large Generating Facility.

9.7.6 Power Quality. A Party’s facilities shall not cause excessive voltage flicker nor

introduce excessive distortion to the sinusoidal voltage or current waves as defined by

ANSI Standard C84.1-1989, in accordance with IEEE Standard 519, or any applicable

superseding electric industry standard.

9.8 Switching and Tagging Rules. Each Party shall provide the other Party(ies) with a copy of its

switching and tagging rules that are applicable to the other Party’s activities. Such switching and

tagging rules shall be developed on a non-discriminatory basis. The Parties shall comply with

applicable switching and tagging rules, as amended from time to time, in obtaining clearances for

work or for switching operations on equipment.

9.9 Use of Interconnection Facilities by Third Parties.

9.9.1 Purpose of Interconnection Facilities. Except as may be required by Applicable Laws

and Regulations, or as otherwise agreed to among the Parties, the Interconnection

Facilities shall be constructed for the sole purpose of interconnecting the Large

Generating Facility to the Administered Transmission System and shall be used for no

other purpose.

9.9.2 Third Party Users. If required by Applicable Laws and Regulations or if the Parties

mutually agree, such agreement not to be unreasonably withheld, to allow one or more

third parties to use the Interconnecting Transmission Owner’s Interconnection Facilities,

or any part thereof, Interconnection Customer will be entitled to compensation for the

capital expenses it incurred in connection with the Interconnection Facilities based upon

the pro rata use of the Interconnection Facilities by Interconnecting Transmission Owner,

all third party users, and Interconnection Customer, in accordance with Applicable Laws

and Regulations or upon some other mutually agreed-upon methodology. In addition,

cost responsibility for ongoing costs, including operation and maintenance costs

associated with the Interconnection Facilities, will be allocated between Interconnection

Customer and any third party users based upon the pro rata use of the Interconnection

Facilities by Interconnecting Transmission Owner, all third party users, and

Interconnection Customer, in accordance with Applicable Laws and Regulations or upon

some other mutually agreed-upon methodology. If the issue of such compensation or

allocation cannot be resolved through such negotiations, it shall be submitted to the

Commission for resolution.

9.10 Disturbance Analysis Data Exchange. The Parties will cooperate with one another in the

analysis of disturbances to either the Large Generating Facility or the New England Transmission

System by gathering and providing access to any information relating to any disturbance,

including information from oscillography, protective relay targets, breaker operations and

sequence of events records, and any disturbance information required by the ISO New England


ARTICLE 10. MAINTENANCE

10.1 Interconnecting Transmission Owner and Customer Obligations. Interconnecting

Transmission Owner and Interconnection Customer shall each maintain that portion of its

respective facilities that are part of the New England Transmission System and the

Interconnecting Transmission Owner’s Interconnection Facilities in a safe and reliable manner

and in accordance with the applicable provisions of the ISO New England Operating Documents,


10.2 Operating and Maintenance Expenses. Subject to the provisions herein addressing the use of

facilities by others, and except for operations and maintenance expenses associated with

modifications made for providing interconnection or transmission service to a third party and

such third party pays for such expenses, Interconnection Customer shall be responsible for all

reasonable expenses including overheads, associated with: (1) owning, operating, maintaining,

repairing, and replacing Interconnection Customer’s Interconnection Facilities; and (2) operation,

maintenance, repair and replacement of Interconnecting Transmission Owner’s Interconnection

Facilities, Stand Alone Network Upgrades, Network Upgrades and Distribution Upgrades.

ARTICLE 11. PERFORMANCE OBLIGATION

11.1 Interconnection Customer’s Interconnection Facilities. Interconnection Customer shall

design, procure, construct, install, own and/or control the Interconnection Customer’s

Interconnection Facilities described in Appendix A (Interconnection Facilities, Network

Upgrades and Distribution Upgrades) at its sole expense.

11.2 Interconnecting Transmission Owner’s Interconnection Facilities. Interconnecting

Transmission Owner shall design, procure, construct, install, own and/or control the

Interconnecting Transmission Owner’s Interconnection Facilities described in Appendix A

(Interconnection Facilities, Network Upgrades and Distribution Upgrades) at the sole expense of

the Interconnection Customer.

11.3 Network Upgrades and Distribution Upgrades. Interconnecting Transmission Owner shall

design, procure, construct, install, and own the Network Upgrades, and to the extent provided by

Article 5.1, Stand Alone Network Upgrades, and Distribution Upgrades described in Appendix A

(Interconnection Facilities, Network Upgrades and Distribution Upgrades). The Interconnection

Customer shall be responsible for all costs related to Distribution Upgrades. Unless the

Interconnecting Transmission Owner elects to fund the capital for the Network Upgrades, they

shall be solely funded by the Interconnection Customer.

11.4 Cost Allocation; Compensation; Rights; Affected Systems

11.4.1 Cost Allocation. Cost allocation of Generator Interconnection Related Upgrades shall be

in accordance with Schedule 11 of Section II of the Tariff.

11.4.2 Compensation. Any compensation due to the Interconnection Customer for increases in

transfer capability to the PTF resulting from its Generator Interconnection Related

Upgrade shall be determined in accordance with Sections II and III of the Tariff.

11.4.3 Rights. Notwithstanding any other provision of this LGIA, nothing herein shall be

construed as relinquishing or foreclosing any rights, including but not limited to firm

transmission rights, capacity rights, transmission congestion rights, or transmission

credits, that the Interconnection Customer shall be entitled to, now or in the future, under

any other agreement or tariff as a result of, or otherwise associated with, the transmission

capacity, if any, created by the Network Upgrades.

11.4.4 Special Provisions for Affected Systems. The Interconnection Customer shall enter into

separate related facilities agreements to address any upgrades to the Affected System(s)

that are necessary for safe and reliable interconnection of the Interconnection Customer’s

Generating Facility.

11.5 Provision of Security. At least thirty (30) Calendar Days prior to the commencement of the

procurement, installation, or construction of a discrete portion of an Interconnecting Transmission

Owner’s Interconnection Facilities, Network Upgrades, or Distribution Upgrades, Interconnection

Customer shall provide Interconnecting Transmission Owner a guarantee, a surety bond, letter of

credit or other form of security that is reasonably acceptable to Interconnecting Transmission

Owner in accordance with Section 7 of Schedule 11 of the Tariff. In addition:

11.5.1 The guarantee must be made by an entity that meets the creditworthiness requirements of

Interconnecting Transmission Owner, and contain terms and conditions that guarantee

payment of any amount that may be due from Interconnection Customer, up to an agreed-

to maximum amount.

11.5.2 The letter of credit must be issued by a financial institution reasonably acceptable to

Interconnecting Transmission Owner and must specify a reasonable expiration date.

11.5.3 The surety bond must be issued by an insurer reasonably acceptable to Interconnecting

Transmission Owner and must specify a reasonable expiration date.

11.6 Interconnection Customer Compensation. If System Operator or Interconnecting

Transmission Owner requests or directs Interconnection Customer to provide a service pursuant

to Articles 9.6.3 (Payment for Reactive Power), or 13.4.1 of this LGIA, Interconnection Customer

shall be compensated pursuant to the ISO New England Operating Documents, Applicable


11.6.1 Interconnection Customer Compensation for Actions During Emergency Condition.

Interconnection Customer shall be compensated for its provision of real and reactive

power and other Emergency Condition services that Interconnection Customer provides

to support the New England Transmission System during an Emergency Condition in

accordance with the ISO New England Operating Documents, Applicable Reliability


ARTICLE 12. INVOICE

12.1 General. Each Party shall submit to the other Party(ies), on a monthly basis, invoices of amounts

due for the preceding month. Each invoice shall state the month to which the invoice applies and

fully describe the services and equipment provided. The Parties may discharge mutual debts and

payment obligations due and owing to each other on the same date through netting, in which case

all amounts a Party owes to the other Party(ies) under this LGIA, including interest payments or

credits, shall be netted so that only the net amount remaining due shall be paid by the owing

Party.

12.2 Final Invoice. Within six months after completion of the construction of the Interconnecting

Transmission Owner’s Interconnection Facilities and the Network Upgrades, Interconnecting

Transmission Owner shall provide an invoice of the final cost of the construction of the

Interconnecting Transmission Owner’s Interconnection Facilities and the Network Upgrades and

shall set forth such costs in sufficient detail to enable Interconnection Customer to compare the

actual costs with the estimates and to ascertain deviations, if any, from the cost estimates.

Interconnecting Transmission Owner shall refund to Interconnection Customer any amount by

which the actual payment by Interconnection Customer for estimated costs exceeds the actual

costs of construction within thirty (30) Calendar Days of the issuance of such final construction

invoice. Interconnection Customer shall pay to Interconnecting Transmission Owner any amount

by which the actual payment by Interconnection Customer for estimated costs falls short of the

actual costs of construction within thirty (30) Calendar Days of the issuance of such final

construction invoice.

12.3 Payment. Invoices shall be rendered to the paying Party at the address specified in Appendix F.

The Party receiving the invoice shall pay the invoice within thirty (30) Calendar Days of receipt.

All payments shall be made in immediately available funds payable to the other Party, or by wire

transfer to a bank named and account designated by the invoicing Party. Payment of invoices by

any Party will not constitute a waiver of any rights or claims the other Party(ies) may have under

this LGIA.

12.4 Disputes. In the event of a billing dispute between Interconnecting Transmission Owner and

Interconnection Customer, Interconnecting Transmission Owner shall continue to provide

Interconnection Service under this LGIA as long as Interconnection Customer: (i) continues to

make all payments not in dispute; and (ii) pays to Interconnecting Transmission Owner or into an

independent escrow account the portion of the invoice in dispute, pending resolution of such

dispute. If Interconnection Customer fails to meet these two requirements for continuation of

service, then Interconnecting Transmission Owner may provide notice to Interconnection

Customer of a Default pursuant to Article 17. Within thirty (30) Calendar Days after the

resolution of the dispute, the Party that owes money to the other Party shall pay the amount due

with interest calculated in accord with the methodology set forth in the Commission’s

Regulations at 18 CFR § 35.19a(a)(2)(iii).

ARTICLE 13. EMERGENCIES

13.1 Obligations. Each Party shall comply with the Emergency Condition procedures of the System

Operator in accordance with the applicable provisions of the ISO New England Operating


13.2 Notice. Interconnecting Transmission Owner or System Operator as applicable shall notify

Interconnection Customer and System Operator or Interconnecting Transmission Owner as

applicable, promptly when it becomes aware of an Emergency Condition that affects the

Interconnecting Transmission Owner’s Interconnection Facilities or the New England

Transmission System that may reasonably be expected to affect Interconnection Customer’s

operation of the Large Generating Facility or the Interconnection Customer’s Interconnection

Facilities. Interconnection Customer shall notify Interconnecting Transmission Owner and

System Operator promptly when it becomes aware of an Emergency Condition that affects the

Large Generating Facility or the Interconnection Customer’s Interconnection Facilities that may

reasonably be expected to affect the New England Transmission System or the Interconnecting

Transmission Owner’s Interconnection Facilities. To the extent information is known, the

notification shall describe the Emergency Condition, the extent of the damage or deficiency, the

expected effect on the operation of Interconnection Customer’s or Interconnecting Transmission

Owner’s facilities and operations, its anticipated duration and the corrective action taken and/or to

be taken. The initial notice shall be followed as soon as practicable with written notice.

13.3 Immediate Action. Unless, in Interconnection Customer’s reasonable judgment, immediate

action is required, Interconnection Customer shall obtain the consent of Interconnecting

Transmission Owner and System Operator, such consent to not be unreasonably withheld, prior to

performing any manual switching operations at the Large Generating Facility or the

Interconnection Customer’s Interconnection Facilities in response to an Emergency Condition

either declared by the Interconnecting Transmission Owner or the System Operator or otherwise

regarding the New England Transmission System.

13.4 System Operator’s and Interconnecting Transmission Owner’s Authority.

13.4.1 General. System Operator or Interconnecting Transmission Owner may take whatever

actions or inactions with regard to the New England Transmission System or the

Interconnecting Transmission Owner’s Interconnection Facilities it deems necessary

during an Emergency Condition in order to (i) preserve public health and safety, (ii)

preserve the reliability of the New England Transmission System or Interconnecting

Transmission Owner’s Interconnection Facilities, (iii) limit or prevent damage, and (iv)

expedite restoration of service.

System Operator and Interconnecting Transmission Owner shall use Reasonable Efforts

to minimize the effect of such actions or inactions on the Large Generating Facility or the

Interconnection Customer’s Interconnection Facilities. System Operator and

Interconnecting Transmission Owner may, on the basis of technical considerations,

require the Large Generating Facility to mitigate an Emergency Condition by taking

actions necessary and limited in scope to remedy the Emergency Condition, including,

but not limited to, directing Interconnection Customer to shut-down, start-up, increase or

decrease the real or reactive power output of the Large Generating Facility; implementing

a reduction or disconnection pursuant to Article 13.4.2; directing the Interconnection

Customer to assist with black start (if available) or restoration efforts; or altering the

outage schedules of the Large Generating Facility and the Interconnection Customer’s

Interconnection Facilities. Interconnection Customer shall comply with all of System

Operator’s and Interconnecting Transmission Owner’s operating instructions concerning

Large Generating Facility real power and reactive power output within the

manufacturer’s design limitations of the Large Generating Facility’s equipment that is in

service and physically available for operation at the time, in compliance with Applicable

Laws and Regulations.

13.4.2 Reduction and Disconnection. System Operator and Interconnecting Transmission

Owner may reduce Interconnection Service or disconnect the Large Generating Facility

or the Interconnection Customer’s Interconnection Facilities when such reduction or

disconnection is necessary in accordance with the ISO New England Operating

Documents, Applicable Reliability Standards, or successor documents. These rights are

separate and distinct from any right of curtailment of the System Operator and

Interconnecting Transmission Owner pursuant to the Tariff. When the System Operator

and Interconnecting Transmission Owner can schedule the reduction or disconnection in

advance, System Operator and Interconnecting Transmission Owner shall notify

Interconnection Customer of the reasons, timing and expected duration of the reduction

or disconnection. System Operator and Interconnecting Transmission Owner shall

coordinate with the Interconnection Customer in accordance with the ISO New England

Operating Documents, Applicable Reliability Standards, or successor documents to

schedule the reduction or disconnection during periods of least impact to the

Interconnection Customer and the System Operator and Interconnecting Transmission

Owner. Any reduction or disconnection shall continue only for so long as reasonably

necessary in accordance with the ISO New England Operating Documents, Applicable

Reliability Standards, or successor documents. The Parties shall cooperate with each

other to restore the Large Generating Facility, the Interconnection Facilities, and the New

England Transmission System to their normal operating state as soon as practicable in

accordance with the ISO New England Operating Documents, Applicable Reliability


13.5 Interconnection Customer Authority. In accordance with the ISO New England Operating

Documents, Applicable Reliability Standards, or successor documents and the LGIA and the

LGIP, the Interconnection Customer may take whatever actions or inactions with regard to the

Large Generating Facility or the Interconnection Customer’s Interconnection Facilities during an

Emergency Condition in order to (i) preserve public health and safety, (ii) preserve the reliability

of the Large Generating Facility or the Interconnection Customer’s Interconnection Facilities, (iii)

limit or prevent damage, and (iv) expedite restoration of service. Interconnection Customer shall

use Reasonable Efforts to minimize the effect of such actions or inactions on the New England

Transmission System and the Interconnecting Transmission Owner’s Interconnection Facilities.

System Operator and Interconnecting Transmission Owner shall use Reasonable Efforts to assist

Interconnection Customer in such actions.

13.6 Limited Liability. Except as otherwise provided in Article 11.6.1 of this LGIA, a Party shall not

be liable to another Party for any action it takes in responding to an Emergency Condition so long

as such action is made in good faith and in accordance with the ISO New England Operating


ARTICLE 14. REGULATORY REQUIREMENTS AND GOVERNING LAW

14.1 Regulatory Requirements. Each Party’s obligations under this LGIA shall be subject to its

receipt of any required approval or certificate from one or more Governmental Authorities in the

form and substance satisfactory to the applying Party, or the Party making any required filings

with, or providing notice to, such Governmental Authorities, and the expiration of any time

period associated therewith. Each Party shall in good faith seek and use its Reasonable Efforts to

obtain such other approvals. Nothing in this LGIA shall require Interconnection Customer to take

any action that could result in its inability to obtain, or its loss of, status or exemption under the

Federal Power Act or the Public Utility Holding Company Act of 1935, as amended. To the

extent that a condition arises that could result in Interconnection Customer’s inability to obtain, or

its loss of, status or exemption under the Federal Power Act, the Public Utility Holding Company

Act of 1935, as amended, or the Public Utility Regulatory Policies Act of 1978, the Parties shall

engage in good faith negotiations to address the condition so that such result will not occur and so

that this LGIA can be performed.

14.2 Governing Law.

14.2.1 The validity, interpretation and performance of this LGIA and each of its provisions shall

be governed by the laws of the state where the Point of Interconnection is located,

without regard to its conflicts of law principles.

14.2.2 This LGIA is subject to all Applicable Laws and Regulations.

14.2.3 Each Party expressly reserves the right to seek changes in, appeal, or otherwise contest

any laws, orders, rules, or regulations of a Governmental Authority.

ARTICLE 15. NOTICES

15.1 General. Unless otherwise provided in this LGIA, any notice, demand or request required or

permitted to be given by a Party to another Party and any instrument required or permitted to be

tendered or delivered by a Party in writing to another Party shall be effective when delivered and

may be so given, tendered or delivered, by recognized national courier, or by depositing the same

with the United States Postal Service with postage prepaid, for delivery by certified or registered

mail, addressed to the Party, or personally delivered to the Party, at the address set out in

Appendix F (Addresses for Delivery of Notices and Billings).

A Party may change the notice information in this LGIA by giving five (5) Business Days written

notice prior to the effective date of the change.

15.2 Billings and Payments. Billings and payments shall be sent to the addresses set out in Appendix

F.

15.3 Alternative Forms of Notice. Any notice or request required or permitted to be given by a Party

to another Party and not required by this Agreement to be given in writing may be so given by

telephone, facsimile or email to the telephone numbers and email addresses set out in Appendix

F.

15.4 Operations and Maintenance Notice. Each Party shall notify the other Party(ies) in writing of

the identity of the person(s) that it designates as the point(s) of contact with respect to the

implementation of Articles 9 and 10.

ARTICLE 16. FORCE MAJEURE

16.1 Force Majeure.

16.1.1 Economic hardship is not considered a Force Majeure event.

16.1.2 A Party shall not be considered to be in Default with respect to any obligation hereunder

(including obligations under Article 4), other than the obligation to pay money when due,

if prevented from fulfilling such obligation by Force Majeure. A Party unable to fulfill

any obligation hereunder (other than an obligation to pay money when due) by reason of

Force Majeure shall give notice and the full particulars of such Force Majeure to the

other Party(ies) in writing or by telephone as soon as reasonably possible after the

occurrence of the cause relied upon. Telephone notices given pursuant to this Article

shall be confirmed in writing as soon as reasonably possible and shall specifically state

full particulars of the Force Majeure, the time and date when the Force Majeure occurred

and when the Force Majeure is reasonably expected to cease. The Party affected shall

exercise due diligence to remove such disability with reasonable dispatch, but shall not be

required to accede or agree to any provision not satisfactory to it in order to settle and

terminate a strike or other labor disturbance.

ARTICLE 17. DEFAULT

17.1 Default.

17.1.1 General. No Breach shall exist where such failure to discharge an obligation (other than

the payment of money) is the result of Force Majeure as defined in this LGIA or the

result of an act or omission of the other Party(ies). Upon a Breach, the non-Breaching

Party shall give written notice of such Breach to the breaching Party. Except as provided

in Article 17.1.2, the Breaching Party shall have thirty (30) Calendar Days from receipt

of the Breach notice within which to cure such Breach; provided however, if such Breach

is not capable of cure within thirty (30) Calendar Days, the Breaching Party shall

commence such cure within thirty (30) Calendar Days after notice and continuously and

diligently complete such cure within ninety (90) Calendar Days from receipt of the

Breach notice; and, if cured within such time, the Breach specified in such notice shall

cease to exist.

17.1.2 Right to Terminate. If a Breach is not cured as provided in this Article, or if a Breach is

not capable of being cured within the period provided for herein, the non-Breaching

Party(ies) shall have the right to terminate this LGIA by written notice at any time until

cure occurs, and be relieved of any further obligation hereunder and, whether or not those

Parties terminate this LGIA, to recover from the Breaching Party all amounts due

hereunder, plus all other damages and remedies to which they are entitled at law or in

equity. The provisions of this Article will survive termination of this LGIA.

ARTICLE 18. INDEMNITY, CONSEQUENTIAL DAMAGES AND INSURANCE

Notwithstanding any other provision of this Agreement, the liability, indemnification and

insurance provisions of the Transmission Operating Agreement (“TOA”) or other applicable

operating agreements shall apply to the relationship between the System Operator and the

Interconnecting Transmission Owner and the liability, indemnification and insurance provisions

of the Tariff apply to the relationship between the System Operator and the Interconnection

Customer and between the Interconnecting Transmission Owner and the Interconnection

Customer.

18.1 Indemnity. Each Party shall at all times indemnify, defend, and save the other Party(ies)

harmless from any and all damages, losses, claims, including claims and actions relating to injury

to or death of any person or damage to property, demand, suits, recoveries, costs and expenses,

court costs, attorney fees, and all other obligations by or to third parties, arising out of or resulting

from the other Party’s(ies’) action or inactions of their obligations under this LGIA on behalf of

the Indemnifying Party, except in cases of gross negligence or intentional wrongdoing by an

indemnified Party.

18.1.1 Indemnified Person. If an Indemnified Person is entitled to indemnification under this

Article 18 as a result of a claim by a third party, and the Indemnifying Party fails, after

notice and reasonable opportunity to proceed under Article 18.1, to assume the defense of

such claim, such Indemnified Person may at the expense of the Indemnifying Party

contest, settle or consent to the entry of any judgment with respect to, or pay in full, such

claim.

18.1.2 Indemnifying Party. If an Indemnifying Party is obligated to indemnify and hold any

Indemnified Person harmless under this Article 18, the amount owing to the Indemnified

Person shall be the amount of such Indemnified Person’s actual Loss, net of any

insurance or other recovery.

18.1.3 Indemnity Procedures. Promptly after receipt by an Indemnified Person of any claim or

notice of the commencement of any action or administrative or legal proceeding or

investigation as to which the indemnity provided for in Article 18.1 may apply, the

Indemnified Person shall notify the Indemnifying Party of such fact. Any failure of or

delay in such notification shall not affect a Party’s indemnification obligation unless such

failure or delay is materially prejudicial to the Indemnifying Party.

The Indemnifying Party shall have the right to assume the defense thereof with counsel

designated by such Indemnifying Party and reasonably satisfactory to the Indemnified

Person. If the defendants in any such action include one or more Indemnified Persons

and the Indemnifying Party and if the Indemnified Person reasonably concludes that there

may be legal defenses available to it and/or other Indemnified Persons which are different

from or additional to those available to the Indemnifying Party, the Indemnified Person

shall have the right to select separate counsel to assert such legal defenses and to

otherwise participate in the defense of such action on its own behalf. In such instances,

the Indemnifying Party shall only be required to pay the fees and expenses of one

additional attorney to represent an Indemnified Person or Indemnified Persons having

such differing or additional legal defenses.

The Indemnified Person shall be entitled, at its expense, to participate in any such action,

suit or proceeding, the defense of which has been assumed by the Indemnifying Party.

Notwithstanding the foregoing, the Indemnifying Party (i) shall not be entitled to assume

and control the defense of any such action, suit or proceedings if and to the extent that, in

the opinion of the Indemnified Person and its counsel, such action, suit or proceeding

involves the potential imposition of criminal liability on the Indemnified Person, or there

exists a conflict or adversity of interest between the Indemnified Person and the

Indemnifying Party, in which event the Indemnifying Party shall pay the reasonable

expenses of the Indemnified Person, and (ii) shall not settle or consent to the entry of any

judgment in any action, suit or proceeding without the consent of the Indemnified Person,

which shall not be reasonably withheld, conditioned or delayed.

18.2 Consequential Damages. Other than the Liquidated Damages heretofore described, in no event

shall a Party be liable under any provision of this LGIA for any losses, damages, costs or

expenses for any special, indirect, incidental, consequential, or punitive damages, including but

not limited to loss of profit or revenue, loss of the use of equipment, cost of capital, cost of

temporary equipment or services, whether based in whole or in part in contract, in tort, including

negligence, strict liability, or any other theory of liability; provided, however, that damages for

which a Party may be liable to the other Party under another agreement will not be considered to

be special, indirect, incidental, or consequential damages hereunder.

18.3 Insurance. The Interconnecting Transmission Owner and the Interconnection Customer shall, at

their own expense, maintain in force throughout the period of this LGIA, and until released by the

other Party(ies), the following minimum insurance coverages, with insurers authorized to do

business in the state where the Point of Interconnection is located:

18.3.1 Employers’ Liability and Workers’ Compensation Insurance providing statutory benefits

in accordance with the laws and regulations of the state in which the Point of

Interconnection is located.

18.3.2 Commercial General Liability Insurance including premises and operations, personal

injury, broad form property damage, broad form blanket contractual liability coverage

(including coverage for the contractual indemnification) products and completed

operations coverage, coverage for explosion, collapse and underground hazards,

independent contractors coverage, coverage for pollution to the extent normally available

and punitive damages to the extent normally available and a cross liability endorsement,

with minimum limits of One Million Dollars ($1,000,000) per occurrence/One Million

Dollars ($1,000,000) aggregate combined single limit for personal injury, bodily injury,

including death, and property damage.

18.3.3 Comprehensive Automobile Liability Insurance for coverage of owned and non-owned

and hired vehicles, trailers or semi-trailers designed for travel on public roads, with a

minimum, combined single limit of One Million Dollars ($1,000,000) per occurrence for

bodily injury, including death, and property damage.

18.3.4 Excess Public Liability Insurance over and above the Employers’ Liability Commercial

General Liability and Comprehensive Automobile Liability Insurance coverage, with a

minimum combined single limit of Twenty Million Dollars ($20,000,000) per

occurrence/Twenty Million Dollars ($20,000,000) aggregate.

18.3.5 The Commercial General Liability Insurance, Comprehensive Automobile Insurance and

Excess Public Liability Insurance policies shall name the other Party(ies), its parent,

associated and Affiliate companies and their respective directors, officers, agents,

servants and employees (“Other Party Group”) as additional insured. All policies shall

contain provisions whereby the insurers waive all rights of subrogation in accordance

with the provisions of this LGIA against the Other Party Group and provide thirty (30)

Calendar Days advance written notice to the Other Party Group prior to anniversary date

of cancellation or any material change in coverage or condition.

18.3.6 The Commercial General Liability Insurance, Comprehensive Automobile Liability

Insurance and Excess Public Liability Insurance policies shall contain provisions that

specify that the policies are primary and shall apply to such extent without consideration

for other policies separately carried and shall state that each insured is provided coverage

as though a separate policy had been issued to each, except the insurer’s liability shall not

be increased beyond the amount for which the insurer would have been liable had only

one insured been covered. Each Party shall be responsible for its respective deductibles

or retentions.

18.3.7 The Commercial General Liability Insurance, Comprehensive Automobile Liability

Insurance and Excess Public Liability Insurance policies, if written on a Claims First

Made Basis, shall be maintained in full force and effect for two (2) years after

termination of this LGIA, which coverage may be in the form of tail coverage or

extended reporting period coverage if agreed by the Parties.

18.3.8 The requirements contained herein as to the types and limits of all insurance to be

maintained by the Parties are not intended to and shall not in any manner, limit or qualify

the liabilities and obligations assumed by the Parties under this LGIA.

18.3.9 Within ten (10) days following execution of this LGIA, and as soon as practicable after

the end of each fiscal year or at the renewal of the insurance policy and in any event

within ninety (90) days thereafter, each Party shall provide certification of all insurance

required in this LGIA, executed by each insurer or by an authorized representative of

each insurer.

18.3.10 Notwithstanding the foregoing, each Party may self-insure to meet the minimum

insurance requirements of Articles 18.3.2 through 18.3.8 to the extent it maintains a

self-insurance program, provided that such Party’s senior secured debt is rated at

investment grade, or better, by Standard & Poor’s and that its self-insurance program

meets the minimum insurance requirements of Articles 18.3.2 through 18.3.8. For any

period of time that a Party’s senior secured debt is unrated by Standard & Poor’s or is

rated at less than investment grade by Standard & Poor’s, such Party shall comply with

the insurance requirements applicable to it under Articles 18.3.2 through 18.3.9. In the

event that a Party is permitted to self-insure pursuant to this Article, it shall notify the

other Party(ies) that it meets the requirements to self-insure and that its self-insurance

program meets the minimum insurance requirements in a manner consistent with that

specified in Article 18.3.9.

18.3.11 The Parties agree to report to each other in writing as soon as practical all accidents or

occurrences resulting in injuries to any person, including death, and any property

damage arising out of this LGIA.

ARTICLE 19. ASSIGNMENT

19.1 Assignment. This LGIA may be assigned by any Party only with the written consent of the other

Parties; provided that the Parties may assign this LGIA without the consent of the other Parties to

any Affiliate of the assigning Party with an equal or greater credit rating and with the legal

authority and operational ability to satisfy the obligations of the assigning Party under this LGIA;

and provided further that the Interconnection Customer shall have the right to assign this LGIA,

without the consent of the Interconnecting Transmission Owner or System Operator, for collateral

security purposes to aid in providing financing for the Large Generating Facility, provided that

the Interconnection Customer will promptly notify the Interconnecting Transmission Owner and

System Operator of any such assignment. Any financing arrangement entered into by the

Interconnection Customer pursuant to this Article will provide that prior to or upon the exercise

of the secured party’s, trustee’s or mortgagee’s assignment rights pursuant to said arrangement,

the secured creditor, the trustee or mortgagee will notify the Interconnecting Transmission Owner

and System Operator of the date and particulars of any such exercise of assignment right(s),

including providing the Interconnecting Transmission Owner with proof that it meets the

requirements of Articles 11.5 and 18.3. Any attempted assignment that violates this Article is

void and ineffective. Any assignment under this LGIA shall not relieve a Party of its obligations,

nor shall a Party’s obligations be enlarged, in whole or in part, by reason thereof. Where

required, consent to assignment will not be unreasonably withheld, conditioned or delayed.

ARTICLE 20. SEVERABILITY

20.1 Severability. If any provision in this LGIA is finally determined to be invalid, void or

unenforceable by any court or other Governmental Authority having jurisdiction, such

determination shall not invalidate, void or make unenforceable any other provision, agreement or

covenant of this LGIA; provided that if the Interconnection Customer (or any third party, but only

if such third party is not acting at the direction of the Interconnecting Transmission Owner) seeks

and obtains such a final determination with respect to any provision of the Alternate Option

(Article 5.1.2), or the Negotiated Option (Article 5.1.4), then none of these provisions shall

thereafter have any force or effect and the Parties’ rights and obligations shall be governed solely

by the Standard Option (Article 5.1.1).

ARTICLE 21. COMPARABILITY

21.1 Comparability. The Parties will comply with all applicable comparability and code of conduct

laws, rules and regulations, as amended from time to time.

ARTICLE 22. CONFIDENTIALITY

22.1 Confidentiality. Confidential Information shall include, without limitation, all information

governed by the ISO New England Information Policy, all information obtained from third

parties under confidentiality agreements, all information relating to a Party’s technology, research

and development, business affairs, and pricing, and any information supplied by a Party to

another prior to the execution of this LGIA.

Information is Confidential Information only if it is clearly designated or marked in writing as

confidential on the face of the document, or, if the information is conveyed orally or by

inspection, if the Party providing the information orally informs the Party receiving the

information that the information is confidential.

If requested by a Party, the other Party(ies) shall provide, in writing, the basis for asserting that

the information referred to in this Article warrants confidential treatment, and the requesting

Party may disclose such writing to the appropriate Governmental Authority. Each Party shall be

responsible for the costs associated with affording confidential treatment to its information.

22.1.1 Term. During the term of this LGIA, and for a period of three (3) years after the

expiration or termination of this LGIA, except as otherwise provided in this Article 22,

each Party shall hold in confidence and shall not disclose to any person Confidential

Information.

22.1.2 Scope. Confidential Information shall not include information that the receiving Party

can demonstrate: (1) is generally available to the public other than as a result of a

disclosure by the receiving Party; (2) was in the lawful possession of the receiving Party

on a non-confidential basis before receiving it from the disclosing Party; (3) was supplied

to the receiving Party without restriction by a third party, who, to the knowledge of the

receiving Party after due inquiry, was under no obligation to the disclosing Party to keep

such information confidential; (4) was independently developed by the receiving Party

without reference to Confidential Information of the disclosing Party; (5) is, or becomes,

publicly known, through no wrongful act or omission of the receiving Party or Breach of

this LGIA; or (6) is required, in accordance with Article 22.1.7 of the LGIA, Order of

Disclosure, to be disclosed by any Governmental Authority or is otherwise required to be

disclosed by law or subpoena, or is necessary in any legal proceeding establishing rights

and obligations under this LGIA. Information designated as Confidential Information will

no longer be deemed confidential if the Party that designated the information as

confidential notifies the other Party(ies) that it no longer is confidential.

22.1.3 Release of Confidential Information. A Party shall not release or disclose Confidential

Information to any other person, except to its Affiliates (limited by the Standards of

Conduct requirements), subcontractors, employees, consultants, or to parties who may be

or are considering providing financing to or equity participation with Interconnection

Customer, or to potential purchasers or assignees of Interconnection Customer, on a

need-to-know basis in connection with this LGIA, unless such person has first been

advised of the confidentiality provisions of this Article 22 and has agreed to comply with

such provisions. Notwithstanding the foregoing, a Party providing Confidential

Information to any person shall remain primarily responsible for any release of

Confidential Information in contravention of this Article 22.

22.1.4 Rights. Each Party retains all rights, title, and interest in the Confidential Information

that each Party discloses to the other Party(ies). The disclosure by each Party to the other

Party(ies) of Confidential Information shall not be deemed a waiver by a Party or any

other person or entity of the right to protect the Confidential Information from public

disclosure.

22.1.5 No Warranties. By providing Confidential Information, a Party does not make any

warranties or representations as to its accuracy or completeness. In addition, by

supplying Confidential Information, a Party does not obligate itself to provide any

particular information or Confidential Information to the other Party(ies) nor to enter into

any further agreements or proceed with any other relationship or joint venture.

22.1.6 Standard of Care. Each Party shall use at least the same standard of care to protect

Confidential Information it receives as it uses to protect its own Confidential Information

from unauthorized disclosure, publication or dissemination. Each Party may use

Confidential Information solely to fulfill its obligations to the other Party(ies) under this

LGIA or its regulatory requirements.

22.1.7 Order of Disclosure. If a court or a Governmental Authority or entity with the right,

power, and apparent authority to do so requests or requires a Party, by subpoena, oral

deposition, interrogatories, requests for production of documents, administrative order, or

otherwise, to disclose Confidential Information, that Party shall provide the other

Party(ies) with prompt notice of such request(s) or requirement(s) so that the other

Party(ies) may seek an appropriate protective order or waive compliance with the terms

of this LGIA. Notwithstanding the absence of a protective order or waiver, the Party may

disclose such Confidential Information which, in the opinion of its counsel, the Party is

legally compelled to disclose. Each Party will use Reasonable Efforts to obtain reliable

assurance that confidential treatment will be accorded any Confidential Information so

furnished.

22.1.8 Termination of Agreement. Upon termination of this LGIA for any reason, each Party

shall, within ten (10) Calendar Days of receipt of a written request from the other

Party(ies), use Reasonable Efforts to destroy, erase, or delete (with such destruction,

erasure, and deletion certified in writing to the other Party(ies)) or return to the other

Party(ies), without retaining copies thereof, any and all written or electronic Confidential

Information received from the other Party(ies).

22.1.9 Remedies. The Parties agree that monetary damages would be inadequate to compensate

a Party for the other Party’s(ies’) Breach of its obligations under this Article 22. Each

Party accordingly agrees that the other Party(ies) shall be entitled to equitable relief, by

way of injunction or otherwise, if the first Party Breaches or threatens to Breach its

obligations under this Article 22, which equitable relief shall be granted without bond or

proof of damages, and the receiving Parties shall not plead in defense that there would be

an adequate remedy at law. Such remedy shall not be deemed an exclusive remedy for

the Breach of this Article 22, but shall be in addition to all other remedies available at law

or in equity. The Parties further acknowledge and agree that the covenants contained

herein are necessary for the protection of legitimate business interests and are reasonable

in scope. No Party, however, shall be liable for indirect, incidental, or consequential or

punitive damages of any nature or kind resulting from or arising in connection with this

Article 22.

22.1.10 Disclosure to the Commission, its Staff, or a State. Notwithstanding anything in this

Article 22 to the contrary, and pursuant to 18 CFR. section 1b.20, if the Commission or

its staff, during the course of an investigation or otherwise, requests information from

one of the Parties that is otherwise required to be maintained in confidence pursuant to

this LGIA, the Party shall provide the requested information to the Commission or its

staff, within the time provided for in the request for information. In providing the

information to the Commission or its staff, the Party must, consistent with 18 CFR

section 388.112, request that the information be treated as confidential and non-public

by the Commission and its staff and that the information be withheld from public

disclosure. Parties are prohibited from notifying the other Party(ies) to this LGIA prior

to the release of the Confidential Information to the Commission or its staff. The Party

shall notify the other Party(ies) to the LGIA when it is notified by the Commission or

its staff that a request to release Confidential Information has been received by the

Commission, at which time any of the Parties may respond before such information

would be made public, pursuant to 18 CFR section 388.112. Requests from a state

regulatory body conducting a confidential investigation shall be treated in a similar

manner if consistent with the applicable state rules and regulations.

22.1.11 Subject to the exception in Article 22.1.10, any information that a Party claims is

competitively sensitive, commercial or financial information under this LGIA

(“Confidential Information”) shall not be disclosed by the other Party(ies) to any

person not employed or retained by the other Party(ies), except to the extent disclosure

is (i) required by law; (ii) reasonably deemed by the disclosing Party to be required to

be disclosed in connection with a dispute between or among the Parties, or the defense

of litigation or dispute; (iii) otherwise permitted by consent of the other Party(ies), such

consent not to be unreasonably withheld; or (iv) necessary to fulfill its obligations

under this LGIA or as a transmission service provider or a Control Area operator

including disclosing the Confidential Information to an RTO or ISO or to a regional or

national reliability organization. The Party asserting confidentiality shall notify the

other Party(ies) in writing of the information it claims is confidential. Prior to any

disclosures of the other Parties’ Confidential Information under this subparagraph, or if

any third party or Governmental Authority makes any request or demand for any of the

information described in this subparagraph, the disclosing Party agrees to promptly

notify the other Party(ies) in writing and agrees to assert confidentiality and cooperate

with the other Party(ies) in seeking to protect the Confidential Information from public

disclosure by confidentiality agreement, protective order or other reasonable measures.

ARTICLE 23. ENVIRONMENTAL RELEASES

23.1 Each Party shall notify the other Party(ies), first orally and then in writing, of the release of any

Hazardous Substances, any asbestos or lead abatement activities, or any type of remediation

activities related to the Large Generating Facility or the Interconnection Facilities, each of which

may reasonably be expected to affect the other Party(ies). The notifying Party shall: (i) provide

the notice as soon as practicable, provided such Party makes a good faith effort to provide the

notice no later than twenty-four (24) hours after such Party becomes aware of the occurrence; and

(ii) promptly furnish to the other Party(ies) copies of any publicly available reports filed with any

Governmental Authorities addressing such events.

ARTICLE 24. INFORMATION REQUIREMENTS

24.1 Information Acquisition. Subject to any applicable confidentiality restrictions, including, but

not limited to, codes of conduct, each Party shall submit specific information regarding the

electrical characteristics of their respective facilities to each other as described below and in

accordance with Applicable Reliability Standards.

24.2 Information Submission by System Operator and Interconnecting Transmission Owner.

The initial information submission by System Operator and Interconnecting Transmission Owner

shall occur no later than one hundred eighty (180) Calendar Days prior to the Initial

Synchronization Date and shall include information necessary to allow the Interconnection

Customer to select equipment and meet any system protection and stability requirements, unless

otherwise mutually agreed to by the Parties. On a monthly basis Interconnecting Transmission

Owner shall provide Interconnection Customer a status report on the construction and installation

of Interconnecting Transmission Owner’s Interconnection Facilities and Network Upgrades,

including, but not limited to, the following information: (1) progress to date; (2) a description of

the activities since the last report; (3) a description of the action items for the next period; and (4)

the delivery status of equipment ordered.

24.3 Updated Information Submission by Interconnection Customer. The updated information

submission by the Interconnection Customer, including manufacturer information, shall occur no

later than one hundred eighty (180) Calendar Days prior to the Initial Synchronization Date.

Interconnection Customer shall submit a completed copy of the Large Generating Facility data

requirements contained in Appendix 1 to the LGIP. It shall also include any additional

information provided to Interconnecting Transmission Owner and System Operator for the

Interconnection Feasibility Study, Interconnection System Impact Study and Interconnection

Facilities Study. Information in this submission shall be the most current Large Generating

Facility design or expected performance data. Information submitted for stability models shall be

compatible with Interconnecting Transmission Owner and System Operator standard models. If

there is no compatible model, the Interconnection Customer will work with a consultant mutually

agreed to by the Parties to develop and supply a standard model and associated information.

If the Interconnection Customer’s data is different from what was originally provided to

Interconnecting Transmission Owner pursuant to the Interconnection Study Agreement between

Interconnecting Transmission Owner and Interconnection Customer, then the System Operator

will review it and conduct appropriate studies, as needed, at the Interconnection Customer’s cost,

to determine the impact on the New England Transmission System based on the actual data

submitted pursuant to this Article 24.3. The Interconnection Customer shall not begin Trial

Operation until such studies are completed.

24.4 Information Supplementation. Prior to the Commercial Operation Date, the Parties shall

supplement their information submissions described above in this Article 24 with any and all “as-

built” Large Generating Facility information and “as-tested” performance information that differs

from the initial submissions or, alternatively, written confirmation that no such differences exist.

The Interconnection Customer shall conduct tests on the Large Generating Facility as required by

Good Utility Practice such as an open circuit “step voltage” test on the Large Generating Facility

to verify proper operation of the Large Generating Facility’s automatic voltage regulator.

Unless otherwise agreed, the test conditions shall include: (1) Large Generating Facility at

synchronous speed; (2) automatic voltage regulator on and in voltage control mode; and (3) a five

percent change in Large Generating Facility terminal voltage initiated by a change in the voltage

regulators reference voltage. Interconnection Customer shall provide validated test recordings

showing the responses of Large Generating Facility terminal and field voltages. In the event that

direct recordings of these voltages is impractical, recordings of other voltages or currents that

mirror the response of the Large Generating Facility’s terminal or field voltage are acceptable if

information necessary to translate these alternate quantities to actual Large Generating Facility

terminal or field voltages is provided. Large Generating Facility testing shall be conducted and

results provided to the Interconnecting Transmission Owner for each individual generating unit in

a station.

The Interconnection Customer shall provide the Interconnecting Transmission Owner and System

Operator with any information changes due to proposed equipment replacement, repair, or

adjustment. Interconnecting Transmission Owner shall provide the Interconnection Customer

and System Operator with any information changes due to proposed equipment replacement,

repair or adjustment in the directly connected substation or any adjacent Interconnecting

Transmission Owner-owned substation that may affect the Interconnection Customer’s

Interconnection Facilities equipment ratings, protection or operating requirements. The Parties

shall provide such information in accordance with Article 5.19 of this Agreement.

ARTICLE 25. INFORMATION ACCESS AND AUDIT RIGHTS

25.1 Information Access. Each Party (the “disclosing Party”) shall make available to the other

Parties information that is in the possession of the disclosing Party and is necessary in order for

the other Party(ies) to: (i) verify the costs incurred by the disclosing Party for which the other

Party(ies) are responsible under this LGIA; and (ii) carry out its obligations and responsibilities

under this LGIA. The Parties shall not use such information for purposes other than those set

forth in this Article 25.1 and to enforce their rights under this LGIA.

25.2 Reporting of Non-Force Majeure Events. Each Party (the “notifying Party”) shall notify the

other Party(ies) when the notifying Party becomes aware of its inability to comply with the

provisions of this LGIA for a reason other than a Force Majeure event. The Parties agree to

cooperate with each other and provide necessary information regarding such inability to comply,

including the date, duration, reason for the inability to comply, and corrective actions taken or

planned to be taken with respect to such inability to comply. Notwithstanding the foregoing,

notification, cooperation or information provided under this Article shall not entitle the Party

receiving such notification to allege a cause for anticipatory Breach of this LGIA.

25.3 Audit Rights. Subject to the requirements of confidentiality under Article 22 of this LGIA, each

Party shall have the right, during normal business hours, and upon prior reasonable notice to the

other Party(ies), to audit at its own expense the other Party’s(ies’) accounts and records pertaining

to a Party’s performance or a Party’s satisfaction of obligations under this LGIA. Such audit

rights shall include audits of the other Party’s(ies’) costs, calculation of invoiced amounts, the

efforts to allocate responsibility for the provision of reactive support to the New England

Transmission System, the efforts to allocate responsibility for interruption or reduction of

generation on the New England Transmission System, and each Party’s actions in an Emergency

Condition. Any audit authorized by this Article shall be performed at the offices where such

accounts and records are maintained and shall be limited to those portions of such accounts and

records that relate to each Party’s performance and satisfaction of obligations under this LGIA.

Each Party shall keep such accounts and records for a period equivalent to the audit rights periods

described in Article 25.4.

25.4 Audit Rights Periods.

25.4.1 Audit Rights Period for Construction-Related Accounts and Records. Accounts and

records related to the design, engineering, procurement, and construction of

Interconnecting Transmission Owner’s Interconnection Facilities and Network Upgrades

shall be subject to audit for a period of twenty-four (24) months following

Interconnecting Transmission Owner’s issuance of a final invoice in accordance with

Article 12.2.

25.4.2 Audit Rights Period for All Other Accounts and Records. Accounts and records

related to a Party’s performance or satisfaction of all obligations under this LGIA other

than those described in Article 25.4.1 shall be subject to audit as follows: (i) for an audit

relating to cost obligations, the applicable audit rights period shall be twenty-four (24)

months after the auditing Party’s receipt of an invoice giving rise to such cost obligations;

and (ii) for an audit relating to all other obligations, the applicable audit rights period

shall be twenty-four (24) months after the event for which the audit is sought.

25.5 Audit Results. If an audit by a Party determines that an overpayment or an underpayment has

occurred, a notice of such overpayment or underpayment shall be given to the other Party(ies)

together with those records from the audit which support such determination.

ARTICLE 26. SUBCONTRACTORS

26.1 General. Nothing in this LGIA shall prevent a Party from utilizing the services of any

subcontractor as it deems appropriate to perform its obligations under this LGIA; provided,

however, that each Party shall require its subcontractors to comply with all applicable terms and

conditions of this LGIA in providing such services and each Party shall remain primarily liable to

the other Party(ies) for the performance of such subcontractor.

26.2 Responsibility of Principal. The creation of any subcontract relationship shall not relieve the

hiring Party of any of its obligations under this LGIA. The hiring Party shall be fully responsible

to the other Party(ies) for the acts or omissions of any subcontractor the hiring Party hires as if no

subcontract had been made; provided, however, that in no event shall the Interconnecting

Transmission Owner be liable for the actions or inactions of the Interconnection Customer or its

subcontractors with respect to obligations of the Interconnection Customer under Article 5 of this

LGIA. Any applicable obligation imposed by this LGIA upon the hiring Party shall be equally

binding upon, and shall be construed as having application to, any subcontractor of such Party.

26.3 No Limitation by Insurance. The obligations under this Article 26 will not be limited in any

way by any limitation of subcontractor’s insurance.

ARTICLE 27. DISPUTES

27.1 Submission. In the event a Party has a dispute, or asserts a claim, that arises out of or in

connection with this LGIA or its performance, such Party (the “disputing Party”) shall provide

the other Party(ies) with written notice of the dispute or claim (“Notice of Dispute”). Such

dispute or claim shall be referred to a designated senior representative of each Party for resolution

on an informal basis as promptly as practicable after receipt of the Notice of Dispute by the other

Party(ies). In the event the designated representatives are unable to resolve the claim or dispute

through unassisted or assisted negotiations within thirty (30) Calendar Days of the other

Party’s(ies’) receipt of the Notice of Dispute, such claim or dispute may, upon mutual agreement

of the Parties, be submitted to arbitration and resolved in accordance with the arbitration

procedures set forth below. In the event the Parties do not agree to submit such claim or dispute

to arbitration, each Party may exercise whatever rights and remedies it may have in equity or at

law consistent with the terms of this LGIA.

27.2 External Arbitration Procedures. Any arbitration initiated under this LGIA shall be conducted

before a single neutral arbitrator appointed by the Parties. If the Parties fail to agree upon a single

arbitrator within ten (10) Calendar Days of the submission of the dispute to arbitration, each Party

shall choose one arbitrator who shall sit on a three-member arbitration panel. The arbitrator so

chosen by the System Operator shall chair the arbitration panel. In either case, the arbitrators

shall be knowledgeable in electric utility matters, including electric transmission and bulk power

issues, and shall not have any current or past substantial business or financial relationships with

any party to the arbitration (except prior arbitration). The arbitrator(s) shall provide each of the

Parties an opportunity to be heard and, except as otherwise provided herein, shall conduct the

arbitration in accordance with the Commercial Arbitration Rules of the American Arbitration

Association (“Arbitration Rules”) and any applicable Commission regulations or RTO rules;

provided, however, in the event of a conflict between the Arbitration Rules and the terms of this

Article 27, the terms of this Article 27 shall prevail

27.3 Arbitration Decisions. Unless otherwise agreed by the Parties, the arbitrator(s) shall render a

decision within ninety (90) Calendar Days of appointment and shall notify the Parties in writing

of such decision and the reasons therefore. The arbitrator(s) shall be authorized only to interpret

and apply the provisions of this LGIA and shall have no power to modify or change any provision

of this Agreement in any manner. The decision of the arbitrator(s) shall be final and binding

upon the Parties, and judgment on the award may be entered in any court having jurisdiction.

The decision of the arbitrator(s) may be appealed solely on the grounds that the conduct of the

arbitrator(s), or the decision itself, violated the standards set forth in the Federal Arbitration Act

or the Administrative Dispute Resolution Act. The final decision of the arbitrator must also be

filed with the Commission if it affects jurisdictional rates, terms and conditions of service,

Interconnection Facilities, or Network Upgrades.

27.4 Costs. Each Party shall be responsible for its own costs incurred during the arbitration process

and for the following costs, if applicable: (1) the cost of the arbitrator chosen by the Party to sit

on the three member panel; or (2) a pro rata share of the cost of a single arbitrator chosen by the

Parties.

ARTICLE 28. REPRESENTATIONS, WARRANTIES AND COVENANTS

28.1 General. Each Party makes the following representations, warranties and covenants:

28.1.1 Good Standing. Such Party is duly organized, validly existing and in good standing

under the laws of the state in which it is organized, formed, or incorporated, as

applicable; that it is qualified to do business in the state or states in which the Large

Generating Facility, Interconnection Facilities and Network Upgrades owned by such

Party, as applicable, are located; and that it has the corporate power and authority to own

its properties, to carry on its business as now being conducted and to enter into this LGIA

and carry out the transactions contemplated hereby and perform and carry out all

covenants and obligations on its part to be performed under and pursuant to this LGIA.

28.1.2 Authority. Such Party has the right, power and authority to enter into this LGIA, to

become a Party hereto and to perform its obligations hereunder. This LGIA is a legal,

valid and binding obligation of such Party, enforceable against such Party in accordance

with its terms, except as the enforceability thereof may be limited by applicable

bankruptcy, insolvency, reorganization or other similar laws affecting creditors’ rights

generally and by general equitable principles (regardless of whether enforceability is

sought in a proceeding in equity or at law).

28.1.3 No Conflict. The execution, delivery and performance of this LGIA does not violate or

conflict with the organizational or formation documents, or bylaws or operating

agreement, of such Party, or any judgment, license, permit, order, material agreement or

instrument applicable to or binding upon such Party or any of its assets.

28.1.4 Consent and Approval. Such Party has sought or obtained, or, in accordance with this

LGIA will seek or obtain, each consent, approval, authorization, order, or acceptance by

any Governmental Authority in connection with the execution, delivery and performance

of this LGIA, and it will provide to any Governmental Authority notice of any actions

under this LGIA that are required by Applicable Laws and Regulations.

ARTICLE 29. [OMITTED]

ARTICLE 30. MISCELLANEOUS

30.1 Binding Effect. This LGIA and the rights and obligations hereof shall be binding upon and shall

inure to the benefit of the successors and assigns of the Parties hereto.

30.2 Conflicts. In the event of a conflict between the body of this LGIA and any attachment,

appendices or exhibits hereto, the terms and provisions of the body of this LGIA shall prevail and

be deemed the final intent of the Parties.

30.3 Rules of Interpretation. This LGIA, unless a clear contrary intention appears, shall be

construed and interpreted as follows: (1) the singular number includes the plural number and vice

versa; (2) reference to any person includes such person’s successors and assigns but, in the case

of a Party, only if such successors and assigns are permitted by this LGIA, and reference to a

person in a particular capacity excludes such person in any other capacity or individually; (3)

reference to any agreement (including this LGIA), document, instrument or tariff means such

agreement, document, instrument, or tariff as amended or modified and in effect from time to

time in accordance with the terms thereof and, if applicable, the terms hereof; (4) reference to any

Applicable Laws and Regulations means such Applicable Laws and Regulations as amended,

modified, codified, or reenacted, in whole or in part, and in effect from time to time, including, if

applicable, rules and regulations promulgated thereunder; (5) unless expressly stated otherwise,

reference to any Article, Section or Appendix means such Article of this LGIA or such Appendix

of this LGIA, or such Section of the LGIP or such Appendix of the LGIP, as the case may be; (6)

“hereunder”, “hereof”, “herein”, “hereto” and words of similar import shall be deemed references

to this LGIA as a whole and not to any particular Article or other provision hereof or thereof; (7)

“including” (and with correlative meaning “include”) means including without limiting the

generality of any description preceding such term; and (8) relative to the determination of any

period of time, “from” means “from and including”, “to” means “to but excluding” and “through”

means “through and including”.

30.4 Entire Agreement. Except for the ISO New England Operating Documents, Applicable

Reliability Standards, or successor documents, this LGIA, including all Appendices and

Schedules attached hereto, constitutes the entire agreement between the Parties with reference to

the subject matter hereof, and supersedes all prior and contemporaneous understandings or

agreements, oral or written, between the Parties with respect to the subject matter of this LGIA.

Except for the ISO New England Operating Documents, Applicable Reliability Standards, any

applicable tariffs, related facilities agreements, or successor documents, there are no other

agreements, representations, warranties, or covenants which constitute any part of the

consideration for, or any condition to, any Party’s compliance with its obligations under this

LGIA.

30.5 No Third Party Beneficiaries. This LGIA is not intended to and does not create rights,

remedies, or benefits of any character whatsoever in favor of any persons, corporations,

associations, or entities other than the Parties, and the obligations herein assumed are solely for

the use and benefit of the Parties, their successors in interest and, where permitted, their assigns.

30.6 Waiver. The failure of a Party to this LGIA to insist, on any occasion, upon strict performance

of any provision of this LGIA will not be considered a waiver of any obligation, right, or duty of,

or imposed upon, such Party.

Any waiver at any time by a Party of its rights with respect to this LGIA shall not be deemed a

continuing waiver or a waiver with respect to any other failure to comply with any other

obligation, right, or duty of this LGIA. Termination or Default of this LGIA for any reason by

the Interconnection Customer shall not constitute a waiver of the Interconnection Customer’s

legal rights to obtain an interconnection from the Interconnecting Transmission Owner. Any

waiver of this LGIA shall, if requested, be provided in writing.

30.7 Headings. The descriptive headings of the various Articles of this LGIA have been inserted for

convenience of reference only and are of no significance in the interpretation or construction of

this LGIA.

30.8 Multiple Counterparts. This LGIA may be executed in two or more counterparts, each of

which is deemed an original but all constitute one and the same instrument.

30.9 Amendment. The Parties may by mutual agreement amend this LGIA by a written instrument

duly executed by the Parties.

30.10 Modification by the Parties. The Parties may by mutual agreement amend the Appendices to

this LGIA by a written instrument duly executed by all of the Parties. Such amendment shall

become effective and a part of this LGIA upon satisfaction of all Applicable Laws and

Regulations.

30.11 Reservation of Rights. Consistent with Section 11.3 of the LGIP, Interconnecting Transmission

Owner and System Operator shall have the right to make unilateral filings with the Commission

to modify this LGIA with respect to any rates, terms and conditions, charges, classifications of

service, rule or regulation under section 205 or any other applicable provision of the Federal

Power Act and the Commission’s rules and regulations thereunder, and Interconnection Customer

shall have the right to make a unilateral filing with the Commission to modify this LGIA pursuant

to section 206 or any other applicable provision of the Federal Power Act and the Commission’s

rules and regulations thereunder; provided that each Party shall have the right to protest any such

filing by the other Parties and to participate fully in any proceeding before the Commission in

which such modifications may be considered. In the event of disagreement on terms and

conditions of the LGIA related to the costs of upgrades to such Interconnecting Transmission

Owner’s transmission facilities, the anticipated schedule for the construction of such upgrades,

any financial obligations of Interconnecting Transmission Owner, and any provisions related to

physical impacts of the interconnection on Interconnecting Transmission Owner’s transmission

facilities or other assets, then the standard applicable under Section 205 of the Federal Power Act

shall apply only to Interconnecting Transmission Owner’s position on such terms and conditions.

Nothing in this LGIA shall limit the rights of the Parties or of the Commission under sections 205

or 206 of the Federal Power Act and the Commission’s rules and regulations thereunder, except

to the extent that the Parties otherwise mutually agree as provided herein.

30.12 No Partnership. This LGIA shall not be interpreted or construed to create an association, joint

venture, agency relationship, or partnership between the Parties or to impose any partnership

obligation or partnership liability upon any Party. No Party shall have any right, power or

authority to enter into any agreement or undertaking for, or act on behalf of, or to act as or be an

agent or representative of, or to otherwise bind, the other Parties.

IN WITNESS WHEREOF, the Parties have executed this LGIA in triplicate originals, each of

which shall constitute and be an original effective Agreement between the Parties.

ISO New England Inc. (System Operator)

By:

Title:

Date:

[Insert Name of] (Interconnecting Transmission Owner)

By:

Title:

Date:

[Insert name of] (Interconnection Customer)

By:

Title:

Date:

APPENDICES TO LGIA

Appendix A Interconnection Facilities, Network Upgrades and Distribution Upgrades

Appendix B Milestones

Appendix C Interconnection Details

Appendix D Security Arrangements Details

Appendix E Commercial Operation Date

Appendix F Addresses for Delivery of Notices and Billings

Appendix G Interconnection Requirements for a Wind Generating Plant

APPENDIX A TO LGIA

Interconnection Facilities, Network Upgrades and Distribution Upgrades

1. Interconnection Facilities:

a. Point of Interconnection and Point of Change of Ownership. The Point of

Interconnection shall be at the point where [insert description of location]. See Appendix

A-[insert], which drawing is attached hereto and made part hereof.

The Point of Change of Ownership shall be at the point where [insert description of location].

See Appendix A – [insert], which drawing is attached hereto and made part hereof.

If not located at the Point of Interconnection, the metering point(s) shall be located at: [insert

location].

b. Interconnection Customer’s Interconnection Facilities (including metering

equipment). The Interconnection Customer shall construct [insert Interconnection

Customer’s Interconnection Facilities]. See Appendix A-[insert].

c. Interconnecting Transmission Owner’s Interconnection Facilities (including

metering equipment). The Interconnecting Transmission Owner shall construct [insert

Interconnecting Transmission Owner’s Interconnection Facilities]. See Appendix –

[insert].

2. Network Upgrades:

a. Stand Alone Network Upgrades. [insert Stand Alone Network Upgrades].

b. Other Network Upgrades. [insert Other Network Upgrades].

3. Distribution Upgrades. [insert Distribution Upgrades]

4. Affected System Upgrades. [insert Affected System Upgrades]

5. Contingency Upgrades List:

a. Long Lead Facility-Related Upgrades. The Interconnection Customer’s Large

Generating Facility is associated with a Long Lead Facility, in accordance with Section 3.2.3 of

the LGIP. Pursuant to Section 4.1 of the LGIP, the Interconnection Customer shall be responsible

for the following upgrades in the event that the Long Lead Facility achieves Commercial

Operation and obtains a Capacity Supply Obligation in accordance with Section III.13.1 of the

Tariff:

[insert list of upgrades]

If the Interconnection Customer fails to cause these upgrades to be in-service prior to the

commencement of the Long Lead Facility’s Capacity Commitment Period, the

Interconnection Customer shall be deemed to be in Breach of this LGIA in accordance

with Article 17.1, and the System Operator will initiate all necessary steps to terminate

this LGIA, in accordance with Article 2.3.

b. Other Contingency Upgrades. [e.g., list of upgrades associated with higher queued

Interconnection Requests with LGIAs prior to this LGIA and any other contingency upgrades that

the Parties may deem necessary for the interconnection of the Large Generating Facility.]

6. Post-Forward Capacity Auction Re-study Upgrade Obligations. [insert any change in upgrade

obligations that result from re-study conducted post receiving a Capacity Supply Obligation

through a Forward Capacity Auction.]

APPENDIX B TO LGIA

Milestones

1. Selected Option Pursuant to Article 5.1: Interconnection Customer selects the [insert].

Options as described in Articles 5.1.[insert], 5.1.[insert], and 5.1.[insert ] shall not apply to this

LGIA.

2. Milestones and Other Requirements for all Large Generating Facilities: The description and

entries listed in the following table establish the required Milestones in accordance with the

provisions of the LGIP and this LGIA. The referenced section of the LGIP or article of the LGIA

should be reviewed by each Party to understand the requirements of each milestone.

Item

No.

Milestone Description Responsible Party Date LGIP/LGIA

Reference

1 Provide evidence of

continued Site Control to

System Operator, or

$250,000 non-refundable

deposit to Interconnecting

Transmission Owner

Interconnection

Customer

Within 15 BD of

final LGIA receipt

§ 11.3.1.1 of LGIP

2 Provide evidence of one or

more milestones specified in

§ 11.3 of LGIP

Interconnection

Customer

Within 15 BD of

final LGIA receipt

§ 11.3.1.2 of LGIP

3 Commit to a schedule for

payment of upgrades

Interconnection

Customer

Within 15 BD of

final LGIA receipt

§ 11.3.1.2 of LGIP

4 Provide either (1) evidence

of Major Permits or (2)

refundable deposit to

Interconnecting

Transmission Owner

Interconnection

Customer

If (1) Within 15

BD of final LGIA

receipt or if (2) At

time of LGIA

execution

§ 11.3.1.2 of LGIP

5 Provide certificate of

insurance

Interconnection

Customer and

Interconnecting

Within 10

Calendar Days of

execution of LGIA

§ 18.3.9 of LGIA

Transmission

Owner

6 Provide siting approval for

Generating Facility and

Interconnection Facilities to

Interconnecting

Transmission Owner

Interconnection

Customer

As may be agreed

to by the Parties

§ 7.5 of LGIP

7A Receive Governmental

Authority approval for any

facilities requiring regulatory

approval

Interconnection

Customer and/or

Interconnecting

Transmission

Owner

If needed, as may

be agreed to by the

Parties

§ 5.6.1 of LGIA

7B Obtain necessary real

property rights and rights-of-

way for the construction of a

discrete aspect of the

Interconnecting

Transmission Owner’s


and Network Upgrades

Interconnection

Customer and/or

Interconnecting

Transmission

Owner

If needed, as may

be agreed to by the

Parties

§ 5.6.2 of LGIA

7C Provide to Interconnecting

Transmission Owner written

authorization to proceed with

design, equipment

procurement and

construction

Interconnection

Customer

As may be agreed

to by the Parties

§ 5.5.2 and § 5.6.3

of LGIA

7D Provide quarterly written

progress reports

Interconnection

Customer and

Interconnecting

Transmission

Owner

15 Calendar Days

after the end of

each quarter

beginning the

quarter that

includes the date

for Milestone 7C

§ 5.7 of LGIA

and ending when

the entire Large

Generating

Facility and all

required

Interconnection

Facilities and

Network Upgrades

are in place

8 Provision of Security to

Interconnecting

Transmission Owner

pursuant to Section 11.5 of

LGIA

Interconnection

Customer

At least 30

Calendar Days

prior to design,

procurement and

construction

§§ 5.5.3 and 5.6.4

of LGIA

9 Provision of Security

Associated with Tax

Liability to Interconnecting

Transmission Owner

pursuant to Section 5.17.3 of

LGIA

Interconnection

Customer

As may be agreed

to by the Parties

§ 5.17.3 of LGIA

10 Commit to the ordering of

long lead time material for


and Network Upgrades

Interconnection

Customer

As may be agreed

to by the Parties

§ 7.5 of LGIP

11A Provide initial design,

engineering and specification

for Interconnection

Customer’s Interconnection

Facilities to Interconnecting

Transmission Owner

Interconnection

Customer

180 Calendar Days

prior to Initial

Synchronization

Date

§ 5.10.1 of LGIA

§ 7.5 of LGIP

11B Provide comments on initial

design, engineering and

specification for

Interconnecting

Transmission

Owner

Within 30

Calendar Days of

receipt

§ 5.10.1 of LGIA

§ 7.5 of LGIP

Interconnection Customer’s


12A Provide final design,

engineering and specification

for Interconnection


Facilities to Interconnecting

Transmission Owner

Interconnection

Customer

90 Calendar Days

prior to Initial

Synchronization

Date

§ 5.10.1 of LGIA

§ 7.5 of LGIP

12B Provide comments on final

design, engineering and

specification for

Interconnection Customer’s


Interconnecting

Transmission

Owner

Within 30

Calendar Days of

receipt

§ 5.10.1 of LGIA

§ 7.5 of LGIP

13 Deliver to Transmission

Owner “as built” drawings,

information and documents

regarding Interconnection


Facilities

Interconnection

Customer

Within 120

Calendar Days of

Commercial

Operation date

§ 5.10.3 of LGIA

14 Provide protective relay

settings to Interconnecting

Transmission Owner for

coordination and verification

Interconnection

Customer

At least 90

Calendar Days

prior to Initial

Synchronization

Date

§§ 5.10.1 of LGIA

15 Commencement of

construction of


Interconnecting

Transmission

Owner

As may be agreed

to by the Parties

§ 5.6 of LGIA

16 Submit updated data “as

purchased” Interconnection

Customer

No later than 180

Calendar Days

prior to Initial

Synchronization

Date

§ 24.3 of LGIA

17 In Service Date Interconnection Same as § 3.3.1 and 4.4.5

Customer Interconnection

Request unless

subsequently

modified

of LGIP, § 5.1 of

LGIA

18 Initial Synchronization Date Interconnection

Customer

Same as

Interconnection

Request unless

subsequently

modified

§ 3.3.1, 4.4.4,

4.4.5, and 7.5 of

LGIP

19 Submit supplemental and/or

updated data – “as built/as-

tested”

Interconnection

Customer

Prior to

Commercial

Operation Date

§ 24.4 of LGIA

20 Commercial Operation Date Interconnection

Customer

Same as

Interconnection

Request unless

subsequently

modified

§ 3.3.1, 4.4.4,

4.4.5, and 7.5 of

LGIP

21 Deliver to Interconnection

Customer “as built”

drawings, information and

documents regarding

Interconnecting

Transmission Owner’s


Interconnecting

Transmission

Owner

If requested,

within 120

Calendar Days

after Commercial

Operation Date

§ 5.11 of LGIA

22 Provide Interconnection

Customer final cost invoices

Interconnecting

Transmission

Owner

Within 6 months

of completion of

construction of

Interconnecting

Transmission

Owner

Interconnection

Facilities and

Network Upgrades

§ 12.2 of LGIA

3. Milestones Applicable Solely for CNR Interconnection Service and Long Lead Facility

Treatment. In addition to the Milestones above, the following Milestones apply to

Interconnection Customers requesting CNR Interconnection Service and/or Long Lead Facility

Treatment:

Item

No.

Milestone Description Responsible Party Date LGIP/LGIA

Reference

1 If Long Lead Facility, all dates by which

Critical Path Schedule upgrades will be

submitted to System Operator (end date

for New Capacity Show of Interest

Submission)

Interconnection

Customer

§ 3.2.3 of LGIP

2 If Long Lead Facility, dates by which

Long Lead Facility Deposits will be

provided to System Operator (each

deadline for which New Generating

Capacity Resource would be required to

provide financial assurance under §

III.13.1.9 of the Tariff)

Interconnection

Customer

§ 3.2.3 of LGIP

3 If Long Lead Facility, Capacity

Commitment Period (not to exceed the

Commercial Operation Date)

Interconnection

Customer

§ 1 and 3.2 of LGIP

4 Submit necessary requests for

participation in the Forward Capacity

Auction associated with the Generating

Facility’s requested Commercial

Operation Date, in accordance with

Section III.13 of the Tariff

Interconnection

Customer

§ 3.2.1.3 of LGIP

5 Participate in a CNR Group Study Interconnection

Customer

§ 3.2.1.3 of LGIP

6 Qualify and receive a Capacity Supply Interconnection § 3.2.1.3 of LGIP

Obligation in accordance with Section

III.13 of the Tariff

Customer

7 Complete a re-study of the applicable

Interconnection Study to determine the

cost responsibility for facilities and

upgrades necessary to accommodate the

Interconnection Request based on the

results of the Forward Capacity Auction or

Reconfiguration Auction or bilateral

transaction through which the

Interconnection Customer received a

Capacity Supply Obligation

System Operator § 3.2.1.3 of LGIP

APPENDIX C TO LGIA

Interconnection Details

1. Description of Interconnection:

Interconnection Customer shall install a [insert] MW facility, rated at [insert]MW gross and [insert] MW

net, with all studies performed at or below these outputs. The Generating Facility is comprised of [insert]

units in a [insert description of facility type - combined cycle, wind farm, etc.] rated at: [insert] MW each,

and will located at [insert location].

The Large Generating Facility shall receive:

Network Resource Interconnection Service for the NR Capability at a level not to exceed

[insert gross and net] MW for Summer, and [insert gross and net] MW for Winter.

Capacity Network Resource Interconnection Service for: (i) the NR Capability at a level

not to exceed [insert gross and net at or above 50 degrees F] MW for Summer and

[insert gross and net at or above 0 degrees F] MW for Winter; and (ii) the CNR

Capability at [insert net] MW for Summer and [insert net] MW for Winter, which shall

not exceed [insert the maximum net MW electrical output of the Generating Facility at an

ambient temperature at or above 90 degrees F for summer and at or above 20 degrees F

for winter.] The CNR Capability shall be the highest amount of the Capacity Supply

Obligation obtained by the Generating Facility in accordance with Section III.13 of the

Tariff and, if applicable, as specified in filings by the System Operator with the

Commission pursuant to Section III.13 of the Tariff.

2. Detailed Description of Generating Facility and Generator Step-Up Transformer, if

applicable:

Generator Data

Number of Generators

Manufacturer

Model

Designation of Generator(s)

Excitation System Manufacturer

Excitation System Model

Voltage Regulator Manufacturer

Voltage Regulator Model

Generator Ratings

Greatest Unit Gross and Net MW Output at

Ambient Temperature at or above 90 Degrees F






Ambient Temperature at or above zero Degrees

F

Station Service Load For Each Unit

Overexcited Reactive Power at Rated MVA and

Rated Power Factor

Underexcited Reactive Power at Rated MVA

and Rated Power Factor

Generator Short Circuit and Stability Data

Generator MVA rating

Generator AC Resistance

Subtransient Reactance (saturated)

Subtransient Reactance (unsaturated)

Transient Reactance (saturated)

Negative sequence reactance

Transformer Data

Number of units

Self Cooled Rating

Maximum Rating

Winding Connection (LV/LV/HV)

Fixed Taps

Z1 primary to secondary at self cooled rating

Z1 primary to tertiary at self cooled rating

Z1 secondary to tertiary at self cooled rating

Positive Sequence X/R ratio primary to

secondary

Z0 primary to secondary at self cooled rating

Z0 primary to tertiary at self cooled rating

Z0 secondary to tertiary at self cooled rating

Zero Sequence X/R ratio primary to tertiary

3. Other Description of Interconnection Plan and Facilities:

[Insert any other description relating to the Generating Facility, including, but not limited to switchyard,

protection equipment, step-up transformer to the extent not described in Appendix A.]

APPENDIX D TO LGIA

Security Arrangements Details

Infrastructure security of the New England Transmission System equipment and operations and control

hardware and software is essential to ensure day-to-day New England Transmission System reliability

and operational security. The Commission will expect System Operator, Interconnecting Transmission

Owners, market participants, and Interconnection Customers interconnected to the New England

Transmission System to comply with the recommendations offered by the Critical Infrastructure

Protection Committee and, eventually, best practice recommendations from NERC. All public utilities

will be expected to meet basic standards for system infrastructure and operational security, including

physical, operational, and cyber-security practices.

APPENDIX E TO LGIA

Commercial Operation Date

This Appendix E is a part of the LGIA between System Operator Interconnecting, Transmission Owner

and Interconnection Customer.

[Date]

[Interconnecting Transmission Owner; Address]

[to be supplied]

Generator Interconnections

Transmission Planning Department

ISO New England Inc.

One Sullivan Road

Holyoke, MA 01040-2841

Re: _____________ Large Generating Facility

Dear _______________:

On [Date] [Interconnection Customer] has completed Trial Operation of Unit No. ___. This letter

confirms that [Interconnection Customer] commenced commercial operation of Unit No. ___ at the Large

Generating Facility, effective as of [Date plus one day].

Thank you.

[Signature]

[Interconnection Customer Representative]

APPENDIX F TO LGIA

Addresses for Delivery of Notices and Billings Notices:

System Operator:




One Sullivan Road


With copy to:

Billing Department


One Sullivan Road


Interconnecting Transmission Owner:

[To be supplied.]

Interconnection Customer:

[To be supplied.]

Billings and Payments:

System Operator:




One Sullivan Road


With copy to:

Billing Department


One Sullivan Road



[To be supplied.]


[To be supplied.]

Alternative Forms of Delivery of Notices (telephone, facsimile or email):

System Operator:

Facsimile: (413) 540-4203

E-mail: [email protected]

With copy to:

Facsimile: (413) 535-4024

E-mail: [email protected]


[To be supplied.]


[To be supplied.]

DUNS Numbers:

Interconnection Customer: [To be supplied]

Interconnecting Transmission Owner: [To be supplied]

APPENDIX G TO LGIA

Interconnection Requirements For A Wind Generating Plant

Appendix G sets forth requirements and provisions specific to a wind generating plant. All other

requirements of this LGIA continue to apply to wind generating plant interconnections.

A. Technical Standards Applicable to a Wind Generating Plant

i. Low Voltage Ride-Through (LVRT) Capability

A wind generating plant shall be able to remain online during voltage disturbances up to

the time periods and associated voltage levels set forth in the standard below. The LVRT standard

provides for a transition period standard and a post-transition period standard.

Transition Period LVRT Standard

The transition period standard applies to wind generating plants subject to FERC Order 661 that

have either: (i) interconnection agreements signed and filed with the Commission, filed with the

Commission in unexecuted form, or filed with the Commission as non-conforming agreements between

January 1, 2006 and December 31, 2006, with a scheduled in-service date no later than December 31,

2007, or (ii) wind generating turbines subject to a wind turbine procurement contract executed prior to

December 31, 2005, for delivery through 2007.

1. Wind generating plants are required to remain in-service during three-phase faults with

normal clearing (which is a time period of approximately 4 – 9 cycles) and single line to

ground faults with delayed clearing, and subsequent post-fault voltage recovery to

prefault voltage unless clearing the fault effectively disconnects the generator from the

system. The clearing time requirement for a three-phase fault will be specific to the wind

generating plant substation location, as determined by and documented by the System

Operator and Interconnecting Transmission Owner. The maximum clearing time the

wind generating plant shall be required to withstand for a three-phase fault shall be 9

cycles at a voltage as low as 0.15 p.u., as measured at the high side of the wind

generating plant step-up transformer (i.e. the transformer that steps the voltage up to the

transmission interconnection voltage or “GSU”), after which, if the fault remains

following the location-specific normal clearing time for three-phase faults, the wind

generating plant may disconnect from the transmission system.

2. This requirement does not apply to faults that would occur between the wind generator

terminals and the high side of the GSU or to faults that would result in a voltage lower

than 0.15 per unit on the high side of the GSU serving the facility.

3. Wind generating plants may be tripped after the fault period if this action is intended as

part of a special protection system.

4. Wind generating plants may meet the LVRT requirements of this standard by the

performance of the generators or by installing additional equipment (e.g., Static VAr

Compensator, etc.) within the wind generating plant or by a combination of generator

performance and additional equipment.

5. Existing individual wind generator units that are, or have been, interconnected to the

network at the same location at the effective date of the Appendix G LVRT. Standard are

exempt from meeting the Appendix G LVRT Standard for the remaining life of the

existing generation equipment. Existing individual wind generator units that are replaced

are required to meet the Appendix G LVRT Standard.

Post-transition Period LVRT Standard

All wind generating plants subject to FERC Order No. 661 and not covered by the transition

period described above must meet the following requirements:

1. Wind generating plants are required to remain in-service during three-phase faults with

normal clearing (which is a time period of approximately 4 – 9 cycles) and single line to

ground faults with delayed clearing, and subsequent post-fault voltage recovery to

prefault voltage unless clearing the fault effectively disconnects the generator from the

system. The clearing time requirement for a three-phase fault will be specific to the wind

generating plant substation location, as determined by and documented by the System

Operator and Interconnecting Transmission Owner. The maximum clearing time the

wind generating plant shall be required to withstand for a three-phase fault shall be 9

cycles after which, if the fault remains following the location-specific normal clearing

time for three-phase faults, the wind generating plant may disconnect from the

transmission system. A wind generating plant shall remain interconnected during such a

fault on the transmission system for a voltage level as low as zero volts, as measured at

the high voltage side of the wind GSU.

2. This requirement does not apply to faults that would occur between the wind generator

terminals and the high side of the GSU.

3. Wind generating plants may be tripped after the fault period if this action is intended as

part of a special protection system.

4. Wind generating plants may meet the LVRT requirements of this standard by the

performance of the generators or by installing additional equipment (e.g., Static VAr

Compensator) within the wind generating plant or by a combination of generator

performance and additional equipment.

5. Existing individual wind generator units that are, or have been, interconnected to the

network at the same location at the effective date of the Appendix G LVRT Standard are

exempt from meeting the Appendix G LVRT Standard for the remaining life of the

existing generation equipment. Existing individual wind generator units that are replaced

are required to meet the Appendix G LVRT Standard.

ii. Power Factor Design Criteria (Reactive Power)

A wind generating plant shall maintain a power factor within the range of 0.95 leading to

0.95 lagging, measured at the Point of Interconnection as defined in this LGIA, if the Interconnection

System Impact Study shows that such a requirement is necessary to ensure safety or reliability. The

power factor range standard can be met by using, for example, power electronics designed to supply this

level of reactive capability (taking into account any limitations due to voltage level, real power output,

etc.) or fixed and switched capacitors if agreed to by the System Operator and Interconnecting

Transmission Owner, or a combination of the two. The Interconnection Customer shall not disable power

factor equipment while the wind generating plant is in operation. Wind generating plants shall also be

able to provide sufficient dynamic voltage support in lieu of the power system stabilizer and automatic

voltage regulation at the generator excitation system if the Interconnection System Impact Study shows

this to be required for system safety or reliability.

iii. Supervisory Control and Data Acquisition (SCADA) Capability

The wind generating plant shall provide SCADA capability to transmit data and receive

instructions from the System Operator and Local Control Center to protect system reliability. The System

Operator, Interconnecting Transmission Owner and the wind generating plant Interconnection Customer

shall determine what SCADA information is essential for the proposed wind generating plant, taking into

account the size of the plant and its characteristics, location, and importance in maintaining generation

resource adequacy and transmission system reliability in its area.

APPENDIX 7

INTERCONNECTION PROCEDURES FOR WIND GENERATION

Appendix 7 sets forth procedures specific to a wind generating plant. All other requirements of

this LGIP continue to apply to wind generating plant interconnections.

A. Special Procedures Applicable to Wind Generating Plants

The wind generating plant Interconnection Customer, in completing the Interconnection Request

required by Section 3.3 of this LGIP, may provide to the System Operator a set of preliminary electrical

design specifications depicting the wind generating plant as a single equivalent generator. Upon

satisfying these and other applicable Interconnection Request conditions, the wind generating plant may

enter the queue and receive the base case data as provided for in this LGIP.

No later than six months after submitting an Interconnection Request completed in this manner,

the wind generating plant Interconnection Customer must submit completed detailed electrical design

specifications and other data (including collector system layout data) needed to allow the System

Operator to complete the Interconnection System Impact Study.

Appendix 2-3

Northeast Power Coordinating

Council Reliability Reference

Directory #1

Design and Operation of the

Bulk Power System

NPCC

Regional Reliability Reference Directory # 1

Design and Operation of the Bulk Power System

Task Force on Coordination of Planning Revision Review Record:

December 01, 2009

Adopted by the Members of the Northeast Power Coordinating Council, Inc., on December 01, 2009 based on recommendation by the Reliability Coordinating Committee, in accordance with Section VIII of the NPCC Amended and Restated Bylaws dated July 24, 2007 as amended to date.

Revision History

Version Date Action Change Tracking (New,

Errata or Revisions)

0 New

1 4/20/2012 Errata changes in Appendix

B and Appendix E.

Errata

Table of Contents

1.0 Introduction............................................................................................................................................. 5

1.1 Title - Design and Operation of the Bulk Power System .................................................................. 51.2 Directory Number 1.............................................................................................................................. 51.3 Objective .............................................................................................................................................. 51.4 Effective Date – December 01,2009..................................................................................................... 51.5 Background .......................................................................................................................................... 61.6 Applicability......................................................................................................................................... 61.6.1 Functional Entities................................................................................................................................ 6

2.0 Terms Defined in this Directory ............................................................................................................ 6

3.0 NERC ERO Reliability Standard Requirements ................................................................................. 6

3.1 EOP-001-0 - Emergency Operations Planning..................................................................................... 6

4.0 NPCC regional Reliability Standards Requirements .............................................................................. 7

5.0 NPCC Full Member, More Stringent Criteria......................................................................................... 7

5.1 General Requirements .......................................................................................................................... 75.1.1 Design Criteria............................................................................................................................ 75.1.2 Operating Criteria ....................................................................................................................... 85.1.3 Data Exchange Requirements for Modeling and System Analysis............................................. 9

5.2 Resource Adequacy – Design Criteria.................................................................................................. 95.3 Resource Adequacy – Operating Criteria ........................................................................................... 105.4 Transmission Design Criteria ............................................................................................................. 10

5.4.1 Stability Assessment ................................................................................................................. 105.4.2 Steady State Assessment........................................................................................................... 115.4.3 Fault Current Assessment ......................................................................................................... 12

5.5 Transmission Operating Criteria ........................................................................................................ 125.5.1 Normal Transfers ...................................................................................................................... 125.5.2 Emergency Transfers ................................................................................................................ 145.5.3 Post Contingency Operation ..................................................................................................... 155.5.4 Operation under High Risk Conditions..................................................................................... 15

5.6 Extreme Contingency Assessment ..................................................................................................... 155.7 Extreme System Conditions Assessment ........................................................................................... 17

Appendix A - Definition of Terms........................................................................................................................ 1

Appendix B - Guidelines and Procedures for NPCC Area Transmission Reviews ......................................... 1

Appendix C - Procedure for Testing and Analysis of Extreme Contingencies ................................................ 1

Appendix D - Guidelines for Area Review of Resource Adequacy ................................................................... 1

Appendix E - Guidelines for Requesting Exclusions to Sections 5.4.1 (B) and 5.5.1 (B) of NPCC Directory

#1 – Design and Operation of the Bulk Power System.......................................................................................... 1

Appendix F – Procedure for Operational Planning Coordination.................................................................... 1

Procedure for Operational Planning Coordination – Attachment A ................................................................... 1

Procedure for Operational Planning Coordination – Attachment B ................................................................... 1Procedure for Operational Planning Coordination - Attachment C.................................................................... 1

Appendix G - Procedures for Inter Reliability Coordinator Area Voltage Control ....................................... 1

1.0 Introduction

1.1 Title - Design and Operation of the Bulk Power System

1.2 Directory Number 1

1.3 Objective

The objective of these criteria is to provide a “design-based approach” to ensure the bulk power system is designed and operated to a level of reliability such that the loss of a major portion of the system, or unintentional separation of a major portion of the system, will not result from any design contingencies

referenced in Sections 5.4.1 and 5.4.2. In NPCC the technique for assuring the reliability of the bulk power system is to require that it be designed and operated to withstand representative contingencies as specified in this Directory. Analyses of simulations of these contingencies include assessment of the potential for widespread cascading outages due to overloads, instability or voltage collapse. Loss of small portions of a system (such as radial portions) may be tolerated provided these do not jeopardize the reliability of the remaining bulk power system.

Criteria described in this document are to be used in the design and operation of the bulk power system. These criteria are applicable to all entities which are part of or make use of the bulk power system.

The characteristics of a reliable bulk power system include adequate resources and transmission to reliably meet projected customer electricity demand and energy requirements as prescribed in this document and include:

a. Consideration of a balanced relationship among the fuel type, capacity, physical characteristics (peaking/base load/etc.), and location of resources.

b. Consideration of a balanced relationship among transmission system elements to avoid excessive dependence on any one transmission circuit, structure, right-of-way, or substation.

c. Transmission systems should provide flexibility in switching arrangements, voltage control, and other control measures

1.4 Effective Date - December 01, 2009

1.5 Background

This Directory was developed from the NPCC A-2 criteria document - Basic Criteria for the Design and Operation of Interconnected Power Systems (May 6, 2004 version). Guidelines and Procedures for consideration in the implementation of this Directory are provided in the Appendices.

1.6 Applicability

1.6.1 Functional Entities

Reliability CoordinatorsTransmission Operators Balancing AuthoritiesPlanning Coordinators Transmission Planners Resource Planners

2.0 Terms Defined in this Directory

Terms appearing in bold typeface in this Directory (including the Appendices) are defined in Appendix A.

3.0 NERC ERO Reliability Standard Requirements

The NERC ERO Reliability Standards containing requirements that are associated with this Directory include, but may not be limited to:

3.1 EOP-001-0 - Emergency Operations Planning

3.2 FAC-011-2 - System Operating Limits Methodology for the Operations Horizon3.3 IRO-002-1 - Reliability Coordination - Facilities3.4 IRO-014-1 — Procedures, Processes, or Plans to Support Coordination Between

Reliability Coordinators3.5 MOD-010-0 - Steady-State Data for Transmission System Modeling and

Simulation3.6 MOD-011-0 — Regional Steady-State Data Requirements and Reporting

Procedures3.7 MOD-012-0 — Dynamics Data for Transmission System Modeling and

Simulation3.8 MOD-013-1 — RRO Dynamics Data Requirements and Reporting Procedures3.9 MOD-014-0 — Development of Interconnection-Specific Steady State System

Models3.10 MOD-015-0 — Development of Interconnection-Specific Dynamics System

Models3.11 MOD-016-1 — Actual and Forecast Demands, Net Energy for Load,

Controllable DSM3.12 TOP-001-1 — Reliability Responsibilities and Authorities3.13 TOP-002-2 — Normal Operations Planning3.14 TOP-003-0 — Planned Outage Coordination3.15 TOP-004-2 — Transmission Operations3.16 3.17

TPL-001-0 — System Performance Under Normal ConditionsTPL-002-0 — System Performance Following Loss of a Single BES Element NPCC Regional Reliability Standard Requirements

3.18 TPL-003-0 — System Performance Following Loss of Two or More BES Elements

3.19 TPL-004-0 — System Performance Following Extreme BES Events3.20 TPL-005-0 — Regional and Interregional Self-Assessment Reliability Reports3.21 TPL-006-0 — Assessment Data from Regional Reliability Organizations3.22 VAR-001-1 — Voltage and Reactive Control

4.0 NPCC regional Reliability Standards Requirements

None

5.0 NPCC Full Member, More Stringent Criteria

NPCC provides a forum for coordinating the design and operations of its five Reliability Coordinator Areas. NPCC shall conduct regional and interregional studies, and assess and monitor Planning Coordinator Area studies and Reliability Coordinator operations to assure conformance to these criteria through committees, task forces, and working groups.

It is the responsibility of each Reliability Coordinator to ascertain that theirportion of the bulk power system is operated in conformance with these criteria. It is the responsibility of each Transmission Planner and Planning Coordinator to ascertain that their portion of the bulk power system is designed in conformance with these criteria

5.1 General Requirements

Specific system conditions may require Planning Coordinators or Reliability Coordinators to develop criteria which are more stringent than those set out herein. Any constraints imposed by these more stringent criteria will be observed. It is also recognized that these Criteria are not necessarily applicable to those elements that are not a part of the bulk power system or in the portions of a system where instability or overloads will not jeopardize the reliability of the remaining bulk power system.

5.1.1 Design Criteria

These design criteria will be used in the assessment of the bulk power

system by each of the NPCC Transmission Planners and Planning Coordinators, and in the reliability testing at the Transmission Operator, Reliability Coordinator and Regional Council levels.

Design studies shall assume power flow conditions utilizing transfers, load and generation conditions which stress the system. Transfer capability studies shall be based on the load and generation conditions expected to exist for the period under study. All reclosing facilities shall be assumed in service unless it is known that such facilities will be rendered inoperative.

Special protection systems (SPS) shall be used judiciously and when employed shall be installed, consistent with good system design and operating criteria found in Directory #7 – Special Protection Systems. A SPS may be used to provide protection for infrequent contingencies,or for temporary conditions that may exist such as project delays, unusual combinations of system demand and equipment outages or availability, or specific equipment maintenance outages. A SPS may also be applied to preserve system integrity in the event of severe facility outages and extreme contingencies. The decision to employ a SPS shall take into account the complexity of the scheme and the consequences of correct or incorrect operation as well as its benefits.

The requirements of special protection systems are defined in the NPCC Bulk Power System Protection Criteria, (Directory#4), and the Special Protection Systems, (Directory #7).

5.1.2 Operating Criteria

Coordination among and within the Reliability Coordinator Areas of NPCC is essential to the reliability of interconnected operations. Timely information concerning system conditions shall be transmitted by the NPCC Reliability Coordinators to other NPCC Reliability Coordinators, adjacent Reliability Coordinators or other entities as needed to assure reliable operation of the bulk power system.

The operating criteria represent the application of the design criteria to inter-Reliability Coordinator Area, intra- Reliability Coordinator Areaoperation.

The operating criteria define the minimum level of reliability that shall apply to inter-Reliability Coordinator Area operation. Where inter-Reliability Coordinator Area reliability is affected, each Reliability

Coordinator shall establish limits and operate so that the contingencies

stated in Section 5.5.1 and 5.5.2 can be withstood without causing a significant adverse impact on other Reliability Coordinator Areas.

When adequate bulk power system facilities are not available, special

protection systems (SPS) may be employed to maintain system security.

Two categories of transmission transfer capabilities, normal and emergency, are applicable. Normal transfer capabilities are to be observed unless an emergency is declared.

5.1.3 Data Exchange Requirements for Modeling and System Analysis

It is the responsibility of NPCC and NPCC Members to protect the proprietary nature of the following information and to ensure it is used only for purposes of efficient and reliable system design and operation.Also, any sharing of such information must not violate anti-trust laws.

For reliability purposes, Reliability Coordinators shall share and coordinate forecast system information and real time information to enable and enhance the analysis and modeling of the interconnected bulk power system by security application software on energy management systems. Each Registered Entity within an NPCC Reliability Coordinator Area shall provide needed information to its Reliability Coordinator as required. Analysis and modeling of the interconnected power system is required for reliable design and operation. Data needed to analyze and model the electric system and its component facilities must be developed, maintained, and made available for use in interconnected operating and planning studies, including data for fault level analysis.

Reliability Coordinators and Registered Entities shall maintain and submit, as needed, data in accordance with applicable NPCC Procedures.

Data submitted for analysis representing physical or control characteristics of equipment shall be verified through appropriate methods. System analysis and modeling data must be reviewed annually, and verified on a periodic basis. Generation equipment, and its component controllers, shall be tested to verify data.

5.2 Resource Adequacy – Design Criteria

The probability (or risk) of disconnecting firm load due to resource deficiencies shall be, on average, not more than one day in ten years as

determined by studies conducted for each Resource Planning and Planning Coordinator Area. Compliance with this criterion shall be evaluated probabilistically, such that the loss of load expectation (LOLE) of disconnecting firm load due to resource deficiencies shall be, on average, no more than 0.1 day per year. This evaluation shall make due allowance for demand uncertainty, scheduled outages and deratings, forced outages and deratings, assistance over interconnections with neighboring Planning Coordinator Areas, transmission transfer capabilities, and capacity and/or load

relief from available operating procedures.

5.3 Resource Adequacy – Operating Criteria

Each Balancing Authority shall have procedures in place to schedule outages and deratings of resources in such a manner that the available resources will be adequate to meet the Resource Planner’s and Planning Coordinator’s forecasted demand and reserve requirements, in accordance with the NPCC Operating Reserve Criteria (Directory#5).

For consistent evaluation and reporting of resource adequacy, it is necessary to measure the net capability of generating units and loads

utilized as a resource of each Planning Coordinator Area.

5.4 Transmission Design Criteria

The portion of the bulk power system in each Planning Coordinator Area and in each Transmission Planning Area shall be designed with sufficient transmission capability to serve forecasted demand under the conditions noted in Sections 5.4.1 and 5.4.2. These criteria will also apply after any critical generator, transmission circuit, transformer, series or shunt compensating device or HVdc pole has already been lost, assuming that the Planning Coordinator Area generation and power flows are adjusted between outages by the use of ten-minute reserve and where available, phase angle regulator control and HVdc control.

Anticipated transfers of power from one Planning Coordinator Area to another, as well as within Planning Coordinator Areas, shall be considered in the design of transmission facilities. Transmission transfer capabilities shall be determined in accordance with the conditions noted in Sections 5.4.1 and 5.4.2.

5.4.1 Stability Assessment

Stability of the bulk power system shall be maintained during and following the most severe of the contingencies stated below, with due regard to reclosing. For each of the contingencies below that involve a fault, stability shall be maintained when the simulation is based on

fault clearing initiated by the “system A” protection group, and also shall be maintained when the simulation is based on fault clearing

initiated by the “system B” protection group.a. A permanent three-phase fault on any generator,

transmission circuit, transformer or bus section with normal fault clearing.

b. Simultaneous permanent phase to ground faults on different phases of each of two adjacent transmission circuits on a multiple circuit tower, with normal fault

clearing. If multiple circuit towers are used only for station entrance and exit purposes, and if they do not exceed five towers at each station, then this condition is an acceptable risk and therefore can be excluded. Other similar situations can be excluded on the basis of acceptable risk, provided that the Reliability Coordinating Committee specifically accepts each request for exclusion.

c. A permanent phase to ground fault on any transmission circuit, transformer, or bus section with delayed fault clearing.

d. Loss of any element without a fault.

e. A permanent phase to ground fault on a circuit breaker with normal fault clearing. (Normal fault clearing

time for this condition may not always be high speed.)

f. Simultaneous permanent loss of both poles of a direct current bipolar facility without an ac fault

g. The failure of a circuit breaker to operate when initiated by a SPS following: loss of any element

without a fault; or a permanent phase to ground fault, with normal fault clearing, on any transmission circuit, transformer or bus section.

5.4.2 Steady State Assessment

a. Each Transmission Planner shall design its system in accordance with these criteria and its own voltage control procedures and criteria, and coordinate these with adjacentTransmission Planner Areas. Adequate reactive power

resources and appropriate controls shall be installed in each Transmission Planner Area to maintain voltages within

normal limits for pre-disturbance conditions, and within applicable emergency limits for the system conditions that exist following the contingencies specified in 5.4.1.

b. Line and equipment loadings shall be within normal limits for pre-disturbance conditions and within applicable

emergency limits for the system conditions that exist following the contingencies specified in 5.4.1.

5.4.3 Fault Current Assessment

Each Transmission Planner and Planning Coordinator shall establish procedures and implement a system design that ensures equipment capabilities are adequate for fault current levels with all transmission and generation facilities in service for all potential operating conditions, and coordinate these procedures with adjacent Planning Coordinator Areas.

5.5 Transmission Operating Criteria

Scheduled outages of facilities that affect inter-Reliability Coordinator Area reliability shall be coordinated sufficiently in advance of the outage to permit the affected Reliability Coordinators to maintain reliability. Each Reliability Coordinator shall notify adjacent Reliability Coordinators of scheduled or forced outages of any facility on the NPCC Transmission Facilities Notification List and of any other condition which may impact on inter-Reliability Coordinator Area reliability. Work on facilities which impact inter-Reliability Coordinator Area reliability shall be expedited to minimize the time that the facilities are out of service.

Individual Reliability Coordinator Areas shall be operated in a manner such that the contingencies noted in Section 5.5.1 and 5.5.2 can be withstood and do not adversely affect other Reliability Coordinator Areas.

Appropriate adjustments shall be made to Reliability Coordinator Areaoperations to accommodate the impact of protection group outages, including the outage of a protection group which is part of a Type I special protection

system. For typical periods of forced outage or maintenance of a protection

group, it can be assumed, unless there are indications to the contrary, that the remaining protection will function as designed. If the protection group will be out of service for an extended period of time, additional adjustments to operations may be appropriate considering other system conditions and the consequences of possible failure of the remaining protection group.

5.5.1 Normal Transfers

Pre-contingency voltages, line and equipment loadings shall be within normal limits. Unless specific instructions describing alternate action are in effect, normal transfers shall be such that manual reclosing of a faulted element can be carried out before any manual system adjustment, without affecting the stability of the bulk power system.

Stability of the bulk power system shall be maintained during and following the most severe of the contingencies stated below, with due regard to reclosing. For each of the contingencies stated below that involves a fault, stability shall be maintained when the simulation is based on fault clearing initiated by the “system A” protection group,and also shall be maintained when the simulation is based on fault

clearing initiated by the “system B” protection group.

a. A permanent three-phase fault on any generator, transmission circuit, transformer or bus section, with normal fault clearing.

b. Simultaneous permanent phase to ground faults on different phases of each of two adjacent transmission circuits on a multiple circuit tower, with normal fault

clearing. If multiple circuit towers are used only for station entrance and exit purposes, and if they do not exceed five towers at each station, then this condition is an acceptable risk and therefore can be excluded. Other similar situations can be excluded on the basis of acceptable risk, provided that the Reliability Coordinating Committee specifically accepts each request for exclusion.

c. A permanent phase to ground fault on any transmission circuit, transformer, or bus section with delayed fault clearing.


e. A permanent phase to ground fault on a circuit breaker, with normal fault clearing. (Normal fault

clearing time for this condition may not always be high speed.)

f. Simultaneous permanent loss of both poles of a direct current bipolar facility without an ac fault.

g. The failure of a circuit breaker to operate when initiated by a SPS following: loss of any element

without a fault; or a permanent phase to ground fault, with normal fault clearing, on any transmission circuit, transformer or bus section.

Reactive power resources shall be maintained in each Reliability Coordinator Area in order to maintain voltages within normal limits for pre-disturbance conditions, and within applicable emergency limits

for the system conditions that exist following the contingencies

specified in the foregoing. Adjoining Reliability Coordinators shall mutually agree upon procedures for inter-Reliability Coordinator Areavoltage control.

Line and equipment loadings shall be within normal limits for pre-disturbance conditions and within applicable emergency limits for the system conditions that exist following the contingencies specified in the foregoing.

Since contingencies b, c, e, f, and g, are not confined to the loss of a single element, individual Transmission Operators and Reliability Coordinators may choose to permit a higher post contingency flow on remaining facilities than for contingencies a and d. This is permissible providing operating procedures are documented to accomplish corrective actions; the loadings are sustainable for at least the anticipated time required to effect such action, and other Transmission Operator Areas or Reliability Coordinator Areas will not be subjected to the higher flows without prior agreement.

5.5.2 Emergency Transfers

When firm load cannot be supplied within normal limits in aTransmission Operator Area, or a portion of a Transmission Operator Area, transfers may be increased to the point where pre-contingency

voltages, line and equipment loadings are within applicable emergency

limits. Emergency transfer levels may require generation adjustment before manually reclosing faulted elements.

Stability of the bulk power system shall be maintained during and following the most severe of the following contingencies, and with due regard to reclosing:

a. A permanent three-phase fault on any generator, transmission circuit, transformer or bus section, with normal fault clearing.

b. The loss of any element without a fault.

Immediately following the most severe of these contingencies,voltages, line and equipment loadings will be within applicable

emergency limits.

5.5.3 Post Contingency Operation

Immediately after the occurrence of a contingency, the status of the bulk power system must be assessed and transfer levels must be adjusted, if necessary, to prepare for the next contingency. If the readjustment of generation, load resources, phase angle regulators, and direct current facilities is not adequate to restore the system to a secure state, then other measures such as voltage reduction and shedding of firm load may be required. System adjustments shall be completed as quickly as possible, but in all cases within 30 minutes after the occurrence of the contingency.

Voltage reduction need not be initiated and firm load need not be shed to observe a post contingency loading requirement until the contingency occurs, provided that adequate response time for this action is available after the contingency occurs and other measures will maintain post contingency loadings within applicable emergency

limits.

Emergency measures, including the pre-contingency disconnection of firm load if necessary, must be implemented to limit transfers to within the requirements of 5.5.2 above.

5.5.4 Operation under High Risk Conditions

Operating to the contingencies listed in Sections 5.5.1 and 5.5.2 is considered to provide an acceptable level of bulk power system

security. Under certain unusual conditions, such as severe weather, the expectation of occurrence of some contingencies, and the associated consequences, may be judged to be temporarily, but significantly, greater than the long-term average expectation. When these conditions, referred to as high risk conditions, are judged to exist in a Transmission Operator Area, consideration should be given to operating in a more conservative manner than that required by the provisions of Sections 5.5.1 and 5.5.2.

5.6 Extreme Contingency Assessment

Extreme contingency assessment recognizes that the bulk power system can be subjected to events which exceed, in severity, the contingencies listed in Section 5.4.1. One of the objectives of extreme contingency assessment is to

determine, through planning studies, the effects of extreme contingencies on system performance. This is done in order to obtain an indication of system strength, or to determine the extent of a widespread system disturbance, even though extreme contingencies do have low probabilities of occurrence.

The specified extreme contingencies listed below are intended to serve as a means of identifying some of those particular situations that could result in awidespread bulk power system disturbance. It is the responsibility of each Planning Coordinator Area to identify any additional extreme contingencies to be assessed.

Assessment of the extreme contingencies listed below shall examine post contingency steady state conditions, as well as stability, overload, cascading outages and voltage collapse. Pre-contingency load flows chosen for analysis shall reflect reasonable power transfer conditions within or between Planning Coordinator Areas.

Analytical studies shall be conducted to determine the effect of the following extreme contingencies:

a. Loss of the entire capability of a generating station.

b. Loss of all transmission circuits emanating from a generating station, switching station, dc terminal or substation

c. Loss of all transmission circuits on a common right-of-way.

d. Permanent three-phase fault on any generator, transmission circuit, transformer, or bus section, with delayed fault clearing

and with due regard to reclosing.

e. The sudden dropping of a large load or major load center.

f. The effect of severe power swings arising from disturbances

outside the Council's interconnected systems.

g. Failure of a special protection system, to operate when required following the normal contingencies listed in Section 5.4.1.

h. The operation or partial operation of a special protection system

for an event or condition for which it was not intended to operate.

i. Sudden loss of fuel delivery system to multiple plants, (i.e. gas pipeline contingencies, including both gas transmission lines and gas mains.)

Note: The requirement of this section is to perform extreme contingency

assessments. In the case where extreme contingency assessment concludes there are serious consequences, an evaluation of implementing a change to design or operating practices to address such contingencies shall be conducted.

5.7 Extreme System Conditions Assessment

The bulk power system can be subjected to wide range of other than normal system conditions that have low probability of occurrence. One of the objectives of extreme system conditions assessment is to determine, through planning studies, the impact of these conditions on expected steady-state and dynamic system performance. This is done in order to obtain an indication of system robustness or to determine the extent of a widespread system disturbance. Each Transmission Planner and Planning Coordinator has theresponsibility to incorporate special simulation testing to assess the impact of extreme system conditions.

Analytical studies shall be conducted to determine the effect of design contingencies under the following extreme conditions:

a. Peak load conditions resulting from extreme weather conditions with applicable rating of electrical elements.

b. Generating unit(s) fuel shortage, (i.e. gas supply adequacy)

After due assessment of extreme system conditions, measures may be utilized, where appropriate, to mitigate the consequences that are indicated as a result of testing for such system conditions. .

___________________________________________________________________________

Prepared by: Task Force on Coordination of Planning

Review and Approval: Revision to any portion of this Directory will be posted by the lead Task Force in the NPCC Open Process for a 45 day review and comment period. Upon satisfactorily addressing all the comments in this forum, the Directory document will be sent to the remaining Task Forces for their recommendation to seek RCC approval.

Upon approval of the RCC, this Directory will be sent to the Full Member Representatives for their final approval if sections pertaining to the Requirements and Criteria portion have been revised. All voting and approvals will be conducted according to the most current "NPCC. Bylaws" in effect at the time the ballots are cast.

Revisions pertaining to the Appendices or any other portion of the document such as Links glossary terms, etc., only RCC Members will need to conduct the final approval ballot of the document.

This Directory will be updated at least once every three years and as often as necessary to keep it current and consistent with NERC, Regional Reliability Standards and other NPCC documents.

References: NPCC Glossary of Terms Bulk Power System Protection Criteria (Directory#4) Emergency Operations (NPCC Directory #2) Special Protection Systems (Directory #7))

Appendix A - Definition of Terms

Applicable emergency limits - These limits depend on the duration of the occurrence, and on the policy of the various member systems of NPCC regarding loss of life to equipment, voltage limitations, etc.

Emergency limits are those which can be utilized for the time required to take corrective action, but in no case less than five minutes.

The limiting condition for voltages should recognize that voltages should not drop below that required for suitable system stability performance, and should not adversely affect the operation of the bulk power system.

The limiting condition for equipment loadings should be such that cascading outages will not occur due to operation of protective devices upon the failure of facilities. (Various definitions of equipment ratings are found elsewhere in this glossary.)

Bulk power system - The interconnected electrical systems within north-eastern NorthAmerica comprising generation and transmission facilities on which faults or disturbances

can have a significant adverse impact outside of the local area. In this context, local areas are determined by the Council members.

Contingency - An event, usually involving the loss of one or more elements, which affects the power system at least momentarily.

NPCC Specific Definitions:

NPCC Emergency Criteria Contingencies - The set of contingencies to be observed when operating the bulk power system under emergency conditions. (Document C-1; also reference Document A-2, Section 6.2 - Emergency Transfers.)

NPCC Normal Criteria Contingencies - The set of contingencies to be observed when operating the bulk power system under normal conditions. (Document C-1; also reference Document A-2, Section 6.1 - Normal Transfers.)

Double Element Contingency - A contingency which involves the loss of two elements.(Document C-1)

Single Contingency - A single event which may result in the loss of one or more elements.

Single Element Contingency - A contingency involving the loss of one element. (Document C-1)

Limiting Contingency - The contingency which establishes the transfer capability.(Document C-1)

First Contingency Loss - The largest capacity outage including any assigned Ten-Minute Reserve which would result from the loss of a single element (Documents A-6 and C-1)

Second Contingency Loss - The largest capacity outage which would result from the loss of a single element after allowing for the First Contingency Loss. (Documents A-6 and C-1)

Disturbance - Severe oscillations or severe step changes of current, voltage and/or frequency usually caused by faults.

System Disturbance - An event characterized by one or more of the following phenomena: the loss of power system stability; cascading outages of circuits; oscillations; abnormal ranges of frequency or voltage or both.

Element - Any electric device with terminals that may be connected to other electricdevices, such as a generator, transformer, circuit, circuit breaker, or bus section.

Limiting Element - The element that is either operating at its appropriate rating or would be, following a limiting contingency and, as a result, establishes a system limit.

Emergency - Any abnormal system condition that requires automatic or manual action to prevent or limit loss of transmission facilities or generation supply that could adversely affect the reliability of the electric system.

Specific to NPCC: An Emergency is considered to exist in an Area if firm load may have to be shed.

Fault ClearingDelayed fault clearing - Fault clearing consistent with correct operation of a breaker failure protection group and its associated breakers, or of a backup protection group with an intentional time delay.

High speed fault clearing - Fault clearing consistent with correct operation of high speed relays and the associated circuit breakers without intentional time delay.Notes: The specified time for high-speed relays in present practice is 50 milliseconds (three cycles on a 60Hz basis) or less. [IEEE C37.100-1981]. For planning purposes, a total clearing time of six cycles or less is considered high speed.

Normal fault clearing - Fault clearing consistent with correct operation of the protection

system and with the correct operation of all circuit breakers or other automatic switching devices intended to operate in conjunction with that protection system.

Load - The electric power used by devices connected to an electrical generating system. (IEEE Power Engineering). Also see Demand.


Firm Load - Loads that are not Interruptible Loads.

Interruptible Load - Loads that are interruptible under the terms specified in a contract.

PowerApparent Power - The product of the volts and amperes. It comprises both real and

reactive power, usually expressed in kilovoltamperes (kVA) or megavoltamperes (MVA).

Reactive Power - The portion of electricity that establishes and sustains the electric and magnetic fields of alternating-current equipment. Reactive power must be supplied to most types of magnetic equipment, such as motors and transformers. It also must supply the reactive losses on transmission facilities. Reactive power is provided by generators, synchronous condensers, or electrostatic equipment such as capacitors. Reactive power directly influences electric system voltage. It is usually expressed in kilovars (kVAr) or megavars (MVAr).

Real Power - The rate of producing, transferring, or using electrical energy, usually expressed in kilowatts (kW) or megawatts (MW).

Protection - The provisions for detecting power system faults or abnormal conditions and taking appropriate automatic corrective action.

Protection group - A fully integrated assembly of protective relays and associated equipment that is designed to perform the specified protective functions for a power system element,independent of other groups.

Notes:(a) Variously identified as Main Protection, Primary Protection, Breaker Failure Protection, Back-Up Protection, Alternate Protection, Secondary Protection, A Protection, B Protection, Group A, Group B, System 1 or System 2.

(b) Pilot protection is considered to be one protection group. Protection system Element Basis One or more protection groups; including all equipment such as instrument transformers, station wiring, circuit breakers and associated trip/close modules, and communication facilities; installed at all terminals of a power system element to provide the complete protection of that element.

Terminal BasisOne or more protection groups, as above, installed at one terminal of a power system element, typically a transmission line.

Pilot Protection - A form of line protection that uses a communication channel as a means to compare electrical conditions at the terminals of a line.

Rating - The operational limits of an electric system, facility, or element under a set of specified conditions.

ReclosingAutoreclosing - The automatic closing of a circuit breaker in order to restore an element to

service following automatic tripping of the circuit breaker. Autoreclosing does not include automatic closing of capacitor or reactor circuit breakers.

High-speed autoreclosing - The autoreclosing of a circuit breaker after a necessary time delay (less than one second) to permit fault arc deionization with due regard to coordination with all relay protective systems. This type of autoreclosing is generally not supervised by voltage magnitude or phase angle.

Manual Reclosing - The closing of a circuit breaker by operator action after it has been tripped by protective relays. Operator initiated closing commands may originate from local control or from remote (supervisory) control. Either local or remote close commands may be supervised or unsupervised.

Supervision- A closing command is said to be supervised if closing is permitted to occur only if certain prerequisite conditions are met (e.g., synchronism-check).

Synchronism-check - refers to the determination that acceptable voltages exist on the two sides of the breaker and the phase angle between them is within a specified limit for a specified time.

Relay - An electrical device designed to respond to input conditions in a prescribed manner and after specified conditions are met to cause contact operation or similar abrupt change in associated electric control circuits. (Also: see protective relay).

Reliability - The degree of performance of the bulk electric system that results in electricity

being delivered to customers within accepted standards and in the amount desired. Reliability may be measured by the frequency, duration, and magnitude of adverse effects on the electric supply. Electric system reliability can be addressed by considering two basic and functional aspects of the electric system — Adequacy and Security.

Adequacy — The ability of the electric system to supply the aggregate electricaldemand and energy requirements of the customers at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements.

Security — The ability of the electric system to withstand disturbances such aselectric short circuits or unanticipated loss of system elements.

Reserve - In normal usage, reserve is the amount of capacity available in excess of the

demand

Reserve Requirement - That capability above firm system demand required to provide for regulation, load forecasting error, equipment forced and scheduled outages, and local area supply adequacy


Non-Synchronized Reserve — That portion of operating capacity which is available by synchronizing a generator to the network, and that capacity which can be made available by reducing load that is dependent on starting a generator to replace energy that is supplied from the grid. Non-Synchronized Reserve also includes the capacity achieved through the implementation of voltage reduction. (Documents A-6 and C-1)

Operating Reserve - The sum of ten-minute and thirty-minute reserve. (Documents A-3, A-6, and A-1)

Reserve on Automatic Generation Control (AGC) - That portion of synchronized reserve

which is under the command of an automatic controller to respond to load demands without need for manual action. (Documents A-6 and C-1)

Synchronized Reserve - The unused capacity from resources that are synchronized to the system and ready to achieve claimed capacity (Documents A-6 and C-1)

Ten-minute reserve - The sum of synchronized and non-synchronized reserve that is fully available in ten minutes. (Documents A-6 and C-1)

Thirty-Minute Reserve - The sum of synchronized and non-synchronized reserve that can be utilized within thirty minutes of receiving an activation request, excluding capacity assigned to ten minute reserve. (A-6, C-1)

Resource - Resource refers to the total contributions provided by supply-side and demand-side facilities and/or actions. Supply-side facilities include utility and non-utility generation and purchases from neighboring systems. Demand-side facilities include measures for reducing load, such as conservation, demand management, and interruptible load.

Significant adverse impact - With due regard for the maximum operating capability of the affected systems, one or more of the following conditions arising from faults or disturbances, shall be deemed as having significant adverse impact:

a. instability:• any instability that cannot be demonstrably contained to a well defined local area,• any loss of synchronism of generators that cannot be demonstrably contained to a well-defined local area.

b. unacceptable system dynamic response:

• an oscillatory response to a contingency that is not demonstrated to be clearly positively damped within 30 seconds of the initiating event.

c. unacceptable equipment tripping: • tripping of an un-faulted bulk power system element (element that has already been classified as bulk power system) under planned system configuration due to operation of a protection system in response to a stable power swing, • the operation of a Type I or Type II Special Protection System in responseto a condition for which its operation is not required

d. voltage levels in violation of applicable emergency limits; e. loadings on transmission facilities in violation of applicable emergency limits.

Special Protection System (SPS) – A protection system designed to detect abnormal system conditions, and take corrective action other than the isolation of faulted elements.Such action may include changes in load, generation, or system configuration to maintain system stability, acceptable voltages or power flows. Automatic underfrequency load shedding as defined in the NPCC Directory #2 - Emergency Operations - is not considered a SPS. Conventionally switched, locally controlled shunt devices are not special protection

systems.

Stability - The ability of an electric system to maintain a state of equilibrium during normal and abnormal system conditions or disturbances.

Small-Signal Stability - The ability of the electric system to withstand small changes or disturbances without the loss of synchronism among the synchronous machines in the system.

Transient Stability - The ability of an electric system to maintain synchronism between its parts when subjected to a disturbance, and to regain a state of equilibrium following that disturbance.

Appendix B - Guidelines and Procedures for NPCC Area Transmission Reviews

1.0 Introduction

NPCC has established a Reliability Assessment Program to bring together work done by NPCC, Transmission Planners and Planning Coordinators relevant to the assessment of bulk power system reliability. As part of the Reliability Assessment Program, the Task Force on System Studies (TFSS) is charged on an ongoing basis with conducting periodic reviews of the reliability of the planned bulk power transmission system of each Planning Coordinator Area of NPCC and the transmission interconnections to other Planning Coordinator Areas. The purpose of these reviews is to determine whether each Planning Coordinator Area’s planned bulk power transmission system is in conformance with the NPCC Design and Operation of the

Bulk Power System (Directory #1). Since it is the intention of the NPCC that the Basic Criteria in Directory #1 be consistent with the NERC Standards, conformance with the NPCC Basic Criteria in Directory #1 assures consistency with the NERC Standards.

To assist the TFSS in carrying out this charge, each NPCC Planning Coordinator shall conduct an annual assessment of the reliability of the planned bulk power transmission system within the Planning Coordinator Area and the transmission interconnections to other Planning Coordinator Areas (an Area Transmission Review), in accordance with these Guidelines, and present a report of this assessment to the TFSS for review. Each Planning Coordinator is also responsible for providing an annual report to the Compliance Committee in regard to its Area Transmission Review in accordance with the NPCC Reliability Compliance and Enforcement Program

(Document A-8).

The NPCC role in monitoring conformance with the NPCC Basic Criteria in Directory #1 is limited to those instances where non-conformance could result in adverse consequences to more than one Planning Coordinator Area. If in the process of conducting the reliability review; problems of an intra-Reliability Coordinator Area nature are identified, NPCC shall inform the affected systems and the Planning Coordinator within which the systems are located, but follow-up concerning resolution of the problem shall be the Planning Coordinators responsibility and not that of NPCC. The affected Planning Coordinator will notify NPCC on a timely basis as to the resolution of the identified problem. If the problem is of an inter-Reliability Coordinator Area nature, NPCC shall inform the affected Planning Coordinators and, further, shall take an active role in following-up resolution of the identified problem.

2.0 Purpose of Area Review Presentation

The purpose of the presentation associated with an Area Transmission Review is to demonstrate that the Planning Coordinators planned transmission system, based on its projection of available resources, is in conformance with the NPCC Basic Criteria in Directory #1. By such a presentation, the Task Force will satisfy itself that the criteria have been met and, in general, that the reliability of the NPCC Interconnected Systems will be maintained. Analysis of this material should include a review of Special Protection Systems, as well as an assessment of the potential for widespread cascading due to overloads, instability or voltage collapse. In addition, the potential consequences of failure or misoperation of Dynamic Control Systems (DCS), which include Transmission Control Devices as defined in the NERC Standards, should be addressed.

This review by the TFSS does not alter Planning Coordinators and/or Company responsibilities with respect to their system's conformity with the NPCC Basic

Criteria in Directory #1.

3.0 The Study Year to be considered

It is suggested that a study year of 4 to 6 years from the reporting date is a realistic one, both from the viewpoint of minimum lead times required for construction, and the ability to alter plans or facilities. The reviews may be conducted for a longer term beyond 6 years to address identified marginal conditions that may have longer lead-time solutions

4.0 Types and Frequency of Reviews

Each Planning Coordinator is required to present an annual transmission review to TFSS. However, the review presented by the Planning Coordinator may be one of three types: a Comprehensive (or Full) Review, an Intermediate (or Partial) Review, or an Interim Review.

A Comprehensive Review is a thorough assessment of the Planning Coordinator’sentire bulk power transmission system, and includes sufficient analyses to fully address all aspects of an Area Transmission Review as described in Section 5.0. A Comprehensive Review is required of each Planning Coordinator at least every five years. TFSS may require a Planning Coordinator to present a Comprehensive Review in less than five years if changes in the Planning Coordinator’s planned facilities or forecasted system conditions (system changes) warrant it.

In the years between Comprehensive Reviews, Planning Coordinators may conduct

either an Interim Review, or an Intermediate Review, depending on the extent of the Planning Coordinator’s system changes since its last Comprehensive Review. If the system changes are relatively minor, the Planning Coordinator may conduct an Interim Review. In an Interim Review, the Planning Coordinator provides a summary of the changes in planned facilities and forecasted system conditions since its last Comprehensive Review and a brief discussion and assessment of the impact of those changes on the bulk power transmission system. No new analyses are required for an Interim Review.

If the Planning Coordinator’s system changes since its last Comprehensive Review are moderate or concentrated in a portion of the Planning Coordinator’s system, the Planning Coordinator may conduct an Intermediate Review. An Intermediate Review covers all the elements of a Comprehensive Review, but the analyses may be limited to addressing only those issues considered to be of significance, considering the extent of the system changes. If the system changes are major or pervasive, the Planning Coordinator should conduct a Comprehensive Review.

In March of each year, each Planning Coordinator shall present to the TFSS a proposal for the type of review to be conducted that year. TFSS will consider each Planning Coordinator’s proposal and either indicate their concurrence, or require the Planning Coordinator to conduct a more extensive review if the Task Force feels that such is warranted based on the Planning Coordinator’s system changes since its last Comprehensive Review. Area Interim Review reports shall be presented to TFSS by the end of that calendar year, and Area Intermediate and Comprehensive Review reports shall be presented to TFSS by April of the following year.

5.0 Format of Presentation – Comprehensive and Intermediate Review

Introduction

Reference the most recent Area Comprehensive Review and any subsequent Intermediate or Interim reviews as appropriate.

Describe the type and scope of this review.

For a Comprehensive Review, describe the existing and planned bulk

power system facilities included in this review.

Describe changes in system facilities, schedules and loads since the most recent Comprehensive Review.

Include maps and one-line diagrams of the system showing proposed changes as necessary.

Describe the selected demand levels over the range of forecast system demands.

Discuss projected firm transfers and interchange schedules.

Study results demonstrating conformance with Section 5.4 of NPCC Directory #1,Design and Operation of the Bulk Power System entitled, “Transmission Design Criteria”, which includes evaluation of contingencies after any critical generator, transmission circuit, transformer, series or shunt compensating device or HVDC pole has already been lost.

a) Discuss the scope of the analyses. The analyses conducted for a Comprehensive Review should be thorough, but an Intermediate Review may focus on specific areas of the system, specific system conditions, or a more limited set of “critical” contingencies.

b) Steady State Assessment

Discuss the load model, power factor, demand side management, and other modeling assumptions used in the analysis. Discuss the methodology used in voltage assessments. (An Intermediate Review may refer to the discussion from the last Comprehensive Review.)

Provide supporting information on the contingencies selected for evaluation and an explanation of why the remaining simulations would produce less severe results.

Include plots of "base case" load flows with all lines in service for the various conditions studied, e.g., peak, off-peak, and heavy transfers.

Discuss the load flows showing the effects of major planned changes on the system.

Discuss applicable transfer limits between contiguous areas.

Discuss the adequacy of voltage performance and voltage control capability for the planned bulk power transmission system.

Include in the study the planned (including maintenance) outage of any bulk electric equipment (including protection systems or their components) at those demand levels for which planned (including maintenance) outages are performed.

c) Stability Assessment

Discuss and/or refer to significant studies showing the effect on the system of contingencies as specified in Section 5.4.1 of NPCC Directory #1, Design and Operation of the Bulk Power

System, entitled "Stability Assessment" and report on the most severe contingencies in the following manner:

Provide supporting information on the contingencies

selected for evaluation and an explanation of why the remaining simulations would produce less severe results.

Nature of fault, elements switched, switching times.

Plots of angles versus time for significant machines, HVdc and SVC response, voltages at significant buses and significant interface flows.

Include the effects of existing and planned protection

systems, including any backup or redundant systems.

Include the effects of existing and planned control devices.

Include in the study the planned (including maintenance) outage of any bulk electric equipment (including protection

systems or their components) at those demand levels for which planned (including maintenance) outages are performed.

For a Comprehensive or Intermediate Review, discuss the load

model and other modeling assumptions used in the analysis. (An Intermediate Review may refer to the discussion from the last Comprehensive Review.)

d) Fault Current Assessment

Discuss the methodology and assumptions used in the fault current assessment. (An Intermediate Review may refer to the discussion from the last Comprehensive Review.)

Discuss instances where fault levels exceed equipment capabilities and measures to mitigate such occurrences.

Discuss changes to fault levels at stations adjacent to other Planning Coordinator Areas.

Extreme Contingency Assessment

a) Discuss the scope of the analyses. The analyses conducted for a Comprehensive Review should be thorough, but an Intermediate Review may focus on specific areas of the system, specific system conditions, or a more limited set of “critical” contingencies.

b) Provide supporting information on the extreme contingencies selected for evaluation and an explanation of why the remaining simulations would produce less severe results.

c) Discuss and/or refer to significant load flow studies showing the base case and the post fault conditions for the contingencies as specified in Section 5.6 of Directory #1 entitled "Extreme Contingency Assessment". Report on the most severe contingencies tested.

d) Discuss and/or refer to significant stability studies showing the effect on the system of contingencies as specified in Section 5.6 of Directory #1. Report on the most severe contingencies tested.

e) In the case where contingency assessment concludes serious consequences, conduct an evaluation of implementing a change to address such contingencies.

Extreme System Condition Assessment

a) Discuss the scope of the analyses.

b) Discuss and/or refer to significant load flow studies showing the effect on the steady state performance of extreme system conditions as specified in Section 5.7 of Directory #1, entitled "Extreme System Condition Assessment". Report on the most severe system conditions and contingencies tested.

c) Provide supporting information on the contingencies selected for evaluation and an explanation of why the remaining simulations would produce less severe results.

d) Discuss and/or refer to significant stability studies showing the effect on the dynamic performance of extreme system conditions as specified in Section 5.7 of Directory #1. Report on the most severe system conditions and contingencies tested.

e) In the case where extreme condition assessment concludes serious consequences, conduct an evaluation of implementing measures to mitigate such consequences.

Review of Special Protection Systems (SPSs)

a) Discuss the scope of review. A Comprehensive Review should review all the existing, new, and modified SPSs included in its transmission plan. An Intermediate Review may focus on the new and modified SPSs, and just those existing SPSs that may have been impacted by system changes since they were last reviewed.

b) For those SPSs whose failure or misoperation has an inter-Planning Coordinator Area or interregional effect, discuss and/or refer to appropriate load flow and stability studies analyzing the consequences.

c) For those SPSs whose failure or misoperation has only local or inter-company consequences, discuss and/or refer to load flow and stability

studies demonstrating that this is still the case for the time period being reviewed.

d) For instances where a SPS which was formerly considered to have only local consequences is identified as having the potential for inter- Planning Coordinator Area effects, for the time period being reviewed, the TFSS should notify the Task Forces on Coordination of Planning, System Protection and Coordination of Operation. In such instances a complete review of the SPS should be made, as per the Procedure for

NPCC Review of New or Modified Bulk Power System Special

Protection Systems (SPS) in Directory #7.

Review of Dynamic Control Systems (DCSs)

For those DCSs whose failure or misoperation may have an inter-Planning Coordinator Area or interregional effect, discuss and/or refer to appropriate stability studies analyzing the consequences of such failure or misoperation in accordance with the Joint Working Group (JWG)-1 report, "Technical Considerations and Suggested Methodology for the Performance Evaluation of Dynamic Control Systems". A Comprehensive Review should address all potentially impactive existing and new DCSs, but an Intermediate Review may focus on new DCSs and just those existing DCSs that may have been impacted by system changes since they were last reviewed.

Review of Exclusions to the Basic Criteria.

Review any exclusions granted under the NPCC Guidelines for Requesting

Exclusions to Sections 5.4.1(b) and 5.5.1(b) Directory #1 Design and

Operation of the Bulk Power System (Appendix E). A Comprehensive Review should address all exclusions, but an Intermediate Review may focus

on just those exclusions that may have been impacted by system changes since they were last reviewed.

Overview Summary of System Performance for Year Studied

6.0 Format of Presentation - Interim Review

Introduction of Interim Review

Reference the most recent Comprehensive Review and any subsequent Intermediate or Interim Reviews as appropriate.

Changes in Facilities (Existing and Planned) and Forecasted System Conditions Since the Last Comprehensive Review.

a) Load Forecast

b) Generation Resources

c) Transmission Facilities

d) Special Protection Systems

e) Dynamic Control Systems

f) Exclusions

Brief Impact Assessment and Overview Summary

The Planning Coordinator will provide a brief assessment of the impact of these changes on the reliability of the interconnected bulk power system,based on engineering judgment and internal and joint system studies as appropriate.

7.0 Documentation

The documentation required for a Comprehensive or Intermediate Review should be in the form of a report addressing each of the elements of the above presentation format. The report should be accompanied by the Planning Coordinator’s bulk power system map and one-line diagram, summary tables, figures, and appendices, as appropriate. The report may include references to other studies performed by the Planning Coordinator or by utilities within the Planning Coordinator Area that are relevant to the Area review, with appropriate excerpts from those studies.

The documentation required for an Interim Review should be in the form of a

summary report (normally not exceeding 5 pages), containing a description of system changes and a brief assessment on their impact on the reliability of the interconnected bulk power system.

8.0 Task Force Follow-Up Procedures

8.1 Once a Planning Coordinator has presented its Review report to the TFSS, TFSS will review the Planning Coordinator’s report and any supporting documentation and:

a. Consider whether to accept the report as complete and in full conformance with these Guidelines. If the report is found to be unacceptable, TFSS will indicate to the Planning Coordinator the specific areas of deficiency, and request the Planning Coordinator to address those deficiencies.

b. Consider their concurrence with the results and conclusion(s) of the Planning Coordinator’s Review. If there is not concurrence, TFSS will indicate to the Planning Coordinator the specific areas of disagreement, and work with the Planning Coordinator to try to achieve concurrence. If agreement has not been reached within a reasonable period of time, TFSS shall prepare a summary of the results of its review, including a discussion of the Planning Coordinators of disagreement.

8.2 If the results of the Area Review indicates that the Planning Coordinator’s planned bulk power transmission system is not in conformance with NPCC Directory #1, TFSS will request the Planning Coordinator to develop a plan to achieve conformance with the Criteria.

8.3 If the Area Review indicates an overall bulk power system reliability concern (not specific to the Planning Coordinator’s planned bulk power transmission system), TFSS will consider what additional studies may be necessary to address the concern, and prepare a summary discussion and recommendation to the Task Force on Coordination of Planning.

8.4 Upon completion of an Area Review, TFSS will report the results of the review to the Task Force on Coordination of Planning and to the Reliability Coordinating Committee.

Appendix C - Procedure for Testing and Analysis of Extreme Contingencies

1.0 Introduction

Extreme Contingencies (ECs) are tested "as a measure of system strength", in order to identify potential patterns of weakness in the bulk power transmission system. This procedure for the testing and analysis of ECs should be used when testing ECs for NPCC studies or studies submitted for NPCC review.

This procedure applies to reliability studies that consider the overall performance of the interconnected systems of the NPCC Planning Coordinator Areas. It principally applies to NPCC - wide studies of the bulk power system, and generally does not apply to studies normally conducted by NPCC Planning Coordinators that concentrate on individual or a limited number of facilities. This procedure applies to NPCC Overall and Area Transmission Reviews, and may be applicable to other reliability

studies conducted by the Planning Coordinators, and even to individual facility investigations, where such studies and investigations consider the overall performance of the interconnected systems of the NPCC Planning Coordinator Areas. Certain Transmission Planners or Planning Coordinators may elect to completely mitigate the effects of specific ECs.

Finally, this procedure should be followed in multi-regional reliability studies in which NPCC is an active participant, to the extent that this is possible within the framework of such multi-regional efforts.

2.0 Choosing Contingencies for Testing

The ECs are defined in the NPCC Directory #1- Design and Operation of the Bulk

Power System, and in the NERC Standards. Testing should focus on those ECs expected to have the greatest potential effect on the interconnected system. Particular attention should be paid to contingencies which would result in major angular power shifts, e.g., interruption of shorter transmission paths carrying heavy power flows, leaving longer transmission paths as the only remaining paths. Additionally, contingencies which would result in reversal of major power transfers, e.g., loss of major ties in a neighboring region or Area when said region or Area was transferring power away from the area of interest, should be considered for their impact in subjecting the system to severe power swings (reference EC type “f”). In considering specific contingencies to be investigated in an NPCC reliability study, all relevant testing done at the Planning Coordinator level should first be reviewed.

In general, a contingency in a particular Planning Coordinator Area should be studied, if requested by any other Planning Coordinator, based on a reasonable surmise that the requesting Planning Coordinator may be adversely affected.

3.0 Modeling Assumptions

The assumed generation dispatch is a major consideration in all EC testing. In general, EC testing should use a dispatch pattern considered to be highly probable for the year and load level being studied. Intra-Reliability Coordinator Area inter-Reliability Coordinator Area and, where appropriate, inter-regional transfers should be simulated at a level which is experienced or expected at least 75% of the time on a flow duration basis, up to the maximum operating limit for the interfaces being tested.It is not the NPCC intent to test the worst imaginable extreme, but EC tests should be severe.

Each Planning Coordinator shall specify the appropriate Planning Coordinator load

representation (e.g. active and reactive power as a function of voltage) for use in NPCC reliability studies. This applies to long term stability tests or post-transient loadflows as well as transient stability tests.

4.0 Evaluating Individual Test Results

A question in evaluating the results of a particular test run is - “Does the system "pass" or "fail" for this contingency?” While in the final analysis this is a matter of informed engineering judgment, factors which should be considered include:

1. Lines or transformers loaded above short time emergency ratings,

2. Buses with voltage levels in violation of applicable emergency limits, (which vary depending on the location within the system),

3. Magnitude and geographic distribution of such overloads and voltage violations across the system,

4. Transient generator angles, frequencies, voltages and power,

5. Operation of Dynamic Control Systems and Special Protection Systems

(SPS),

6. Oscillations that could cause generators to lose synchronism or lead to dynamic instability,

7. net loss of source resulting from any combination of loss of synchronism of one or more units, generation rejection or runback initiated by SPS, or any other defined system separation,

8. Identification of the extent of the Planning Coordinator Area (s) involved for any indicated instability or islanding (the involvement of more than one

Planning Coordinator Area, should be a major consideration),

9. Relay operations or the proximity of apparent impedance trajectories to relay

trip characteristics,

10. The angle across opened breakers,

11. Adequacy of computer simulation models and data.

Finally, a judgment should be attempted as to whether a "failure" is symptomatic of a basic system weakness, or just sensitivity to a particular EC. For example, should failures turn up for several EC tests in a particular part of the system, it is likely that a basic system weakness has been identified.

The loss of portions of the system should not necessarily be considered a failed result, provided that these losses do not jeopardize the integrity of the overall bulk power

system.

NPCC study groups should avoid characterizations like "successful" and "unsuccessful" when commenting on individual runs. Rather, the specific initial conditions directly causing or related to the failure, the complete description of the nature of the failure (e.g., voltage collapse, instability, system separation, as well as the facilities involved), and the extent of potential impact on other Planning Coordinator Areas should be reported.

5.0 Evaluating the Results of a Program of EC Testing

The NPCC Directory #1 document - “Design and Operation of Bulk Power System”, calls for testing of Extreme Contingencies (EC) "as a measure of system strength."The results of all NPCC reliability studies are made available to the Planning Coordinators as a guide for planners and designers in the conduct of their future work. The focus of NPCC reports, then, should be on indicating those portions of the system in which basic system weaknesses may be developing, rather than on the results of one specific contingency.

Any patterns of weaknesses should be identified, which may include reference to earlier NPCC reliability studies and/or Planning Coordinator or member system investigations. There is also a need to distinguish between a "failed" test which indicates sensitivity only to a particular contingency run and a "failed" test which indicates a more general system weakness (always keeping in mind the severity of possible consequences of the contingency). Actions taken by member systems or Planning Coordinators to reduce the probability of occurrence or mitigate the consequences of the contingency should also be cited.

NPCC follow-up, after publication of a final report, is appropriate only for instances

of possible general system weakness. In these instances, the results should be specifically referred to the affected Planning Coordinator or Planning Coordinators for further and more detailed investigation with subsequent reporting to NPCC.

Appendix D - Guidelines for Area Review of Resource Adequacy

1.0 Introduction

NPCC has established a Reliability Assessment Program to bring together work done by the NPCC and Planning Coordinators relevant to the assessment of bulk power

system reliability. As part of the Reliability Assessment Program, each Planning Coordinator submits to the Task Force on Coordination of Planning its resource adequacy assessment consistent with these guidelines. The Task Force is charged, on an ongoing basis, with reviewing and recommending NPCC Reliability Coordinating Committee approval of these reviews of resource adequacy of each Planning Coordinator Area of NPCC.

Resources refer to the total contributions provided by supply-side and demand-side facilities and actions. Supply-side facilities include all generation sources within aPlanning Coordinator Area and firm capacity backed purchases from neighboring systems. Demand-side facilities include measures for reducing or shifting load, such as conservation, load management, interruptible loads, dispatchable loads and small identified generation which is not metered at the control centers.

The NPCC role in monitoring conformance with the NPCC Directory #1 - Design and

Operation of Bulk Power System is essential because under this criterion, each Planning Coordinator determines its resource requirements by considering interconnection assistance from other Planning Coordinators, on the basis that adequate resources will be available in those Planning Coordinator Areas. Because of this reliance on interconnection assistance, inadequate resources in one Planning Coordinator Area could result in adverse consequences in another Planning Coordinator Area.

It is recognized that all Planning Coordinators may not necessarily express their own resource adequacy criterion as stated in the NPCC Basic Criteria in Directory #1.However, the NPCC Basic Criteria provides a reference point against which a Planning Coordinator’s resource adequacy criterion can be compared.

The NPCC will not duplicate reviews and studies completed by member systems and Planning Coordinators. The NPCC may reference these reviews in appropriate NPCC reports.

2.0 Purpose of Presentation

The purpose of the presentation associated with a resource adequacy review is to show that each Planning Coordinator's proposed resources are in accordance with the NPCC Directory #1 - Design and Operation of the Bulk Power System. By such a presentation, the Task Force will satisfy itself that the proposed resources

of each NPCC Planning Coordinator will meet the NPCC Resource Adequacy -

Design Criteria, as defined NPCC Directory #1, over the time period under consideration. The review by the Task Force on Coordination of Planning does not replace Planning Coordinator and/or company responsibility to assess their systems in conformity with the NPCC Basic Criteria in Directory #1.

3.0 Time Period to be Considered

The time period to be considered for a Planning Coordinator’s Comprehensive Resource Review will be five years and be undertaken every three years. In subsequent years, the Planning Coordinator shall conduct Annual Interim Reviews that will cover, at a minimum, the remaining years studied in the Comprehensive Review. Based on the results of the Annual Interim Review, the Task Force may recommend that the Planning Coordinator conduct the next Comprehensive Review at a date earlier than specified above. Comprehensive and Interim reviews are normally expected to be presented to the Task Force before the beginning of the first time period covered by the assessment.

4.0 Format of Presentation and Report – Comprehensive Review

Each Planning Coordinator should include in its presentations and in the accompanying report documentation, as a minimum, the information listed below. At its own discretion, the Planning Coordinator may discuss other related issues not covered specifically by these guidelines.

4.1 Executive Summary

4.1.1 Briefly illustrate the major findings of the review.

4.1.2 Provide a table format summary of major assumptions and results.

4.2 Table of Contents

4.2.1 Include listing of all tables and figures.

4.3 Introduction

4.3.1 Reference the previous NPCC Area Review.

4.3.2 Compare the proposed resources and load forecast covered in this NPCC review with that covered in the previous review

4.4 Resource Adequacy Criterion

4.4.1 State the Planning Coordinator's resource adequacy criterion.

4.4.2 State how the Planning Coordinator criterion is applied; e.g., load relief steps.

4.4.3 Summarize resource requirements to meet the criteria for the time period under consideration. If interconnections to other Planning Coordinators and regions are considered in determining this requirement, indicate the value of the interconnections in terms of megawatts.

4.4.4 If the Planning Coordinator criterion is different from the NPCC criterion, provide either an estimate of the resources required to meet the NPCC criteria or a statement as to the comparison of the two criteria.

4.4.5 Discuss resource adequacy studies conducted since the previous AreaReview, as appropriate.

4.5 Resource Adequacy Assessment

4.5.1 Evaluate proposed resources versus the requirement to reliably meet projected electricity demand assuming the Planning Coordinator's most likely load forecast.

4.5.2 Evaluate proposed resources versus the requirement to reliably meet projected electricity demand assuming the Planning Coordinator’s high load growth scenario.

4.5.3 Discuss the impact of load and resource uncertainties on projectedPlanning Coordinator Area reliability and discuss any available mechanisms to mitigate potential reliability impacts.

4.5.4 Review the impacts that major proposed changes to market rules may have on Planning Coordinator Area reliability.

4.6 Proposed Resource Capacity Mix

4.6.1 Discuss any reliability impacts resulting from the proposed resources

fuel supply and transportation or environmental considerations.

4.6.2 Describe available mechanisms to mitigate any potential reliability

impacts of resource fuel supply, demand resource response, transportation issues and/or environmental considerations.

4.6.3 Discuss any reliability impacts related to an Area’s compliance with state, Federal or Provincial requirements (such as environmental, renewable energy, or greenhouse gas reductions).

5.0 Format of Presentation and Report – Annual Interim Review

The Annual Interim Review should include a reference to the most recent Comprehensive Review; a listing of major changes in: facilities and system conditions, load forecast, generation resources availability; related fuel supply and transportation information, environmental considerations, demand response programs, transfer capability and emergency operating procedures. In addition, the assessment should also include a comparison of major changes in market rules, implementation of new rules, locational requirements, and installed capacity requirements. Finally, the report should include a brief impact assessment and an overall summary.

The Planning Coordinator will provide a brief assessment of the impact of these changes on the reliability of the interconnected bulk power system.This assessment should be based on engineering judgment, internal system studies and appropriate joint interconnected studies. To the extent that engineering judgment or existing studies can be used to clearly demonstrate that a Planning Coordinator Area is expected to meet the NPCC resource adequacy criterion, detailed system LOLE studies are not required.

The documentation for the Annual Interim Review should be in the form of a summary report (normally not exceeding three to five pages.)

Sections A and B should describe the reliability model and program used for the resource adequacy studies discussed in Section 4.5. Section C should describe the Task Force follow-up procedures.

A. Description of Resource Reliability Model

1.1 Load Model

1.1.1 Description of the load model and basis of period load

shapes.

1.1.2 How load forecast uncertainty is handled in model.

1.1.3 How the electricity demand and energy projections of interconnected entities within the Planning Coordinator Area that are not members of the Planning Coordinator Area are addressed.

1.1.4 How the effects (demand and energy) of demand-side management programs (e.g., conversion, interruptible demand, direct control load management, demand (load) response programs) are addressed.

1.2 Supply Side Resource Representation

1.2.1 Resource Ratings1.2.1.1 Definitions.

1.2.1.2 Procedure for verifying ratings.Reference NPCC Document B-9, Guide

for Rating Generating Capability.

1.2.2 Unavailability Factors Represented

1.2.2.1 Type of unavailability factors represented; e.g., forced outages, planned outages, partial derating, etc.

1.2.2.2 Source of each type of factor represented and whether generic or individual unit history provides basis for existing and new units.

1.2.2.3 Maturity considerations, including any possible allowance for in-service date uncertainty.

1.2.2.4 Tabulation of typical unavailability factors.

1.2.3 Purchase and Sale Representation.

1.2.3.1. Describe characteristics and level of dependability of transactions.

1.2.4 Retirements.

1.2.4.1 Summarize proposed retirements.

1.3 Representation of Interconnected System in Multi-AreaReliability Analysis, including which Planning Coordinator Areas and regions are considered, interconnection capacities assumed, and how expansion plans of other Planning Coordinators and regions are considered.

1.4 Modeling of Variable and Limited Energy Sources.

1.5 Modeling of Demand Side Resources and Demand (Load)Response Programs.

1.5.1 Description should include how such factors as in-service date uncertainty, rating, availability, performance and duration are addressed.

1.6 Modeling of all Resources.1.6.1 Description should include how such factors as in-

service date uncertainty; capacity value, availability, emergency assistance, scheduling and deliverability are addressed.

1.7 Other assumptions i.e., internal transmission limitations,

maintenance over-runs, fuel supply and transportation and environmental constraints.

1.8 Incorporate the reliability impacts of market rules.

B. Other Factors, If Any, Considered in Establishing Reserve

Requirement Documentation

The documentation required to meet the requirements of the above format should be in the form of summaries of studies performed within a Planning Coordinator Area, including references to applicable reports, summaries of reports or submissions made to regulatory agencies.

C. Task Force Follow-Up Procedures

Once a specific Planning Coordinator has made a presentation or a series of presentations to the Task Force on Coordination of Planning, the latter shall:

1. Prepare a brief summary of key issues discussed during the presentation.

2. Note where further information was requested and the results of such further interrogations.

3. Note the specific items that require additional study and indicate the responsibilities for undertaking these studies.

4. Recommend approval to the Reliability Coordinating Committee.

Appendix E - Guidelines for Requesting Exclusions to Sections 5.4.1 (B) and 5.5.1 (B) of

NPCC Directory #1 – Design and Operation of the Bulk Power System

1.0 Introduction

The Northeast Power Coordinating Council (NPCC) was formed to promote the reliability and efficiency of electric service of the interconnected bulk power system

of the members of the NPCC by extending the coordination of their system design and operations as cited in the NPCC Memorandum of Agreement. Towards that end, the Member Systems of NPCC adopted the Basic Criteria for Design and Operation of

Interconnected Power Systems (Directory #1 – Design and Operation of the Bulk

Power System), which establishes the minimum standards for design and operation of the interconnected bulk power system of NPCC. In accordance with those standards, the bulk power system should be designed and operated so as to withstand certain specific contingencies.

One such contingency, listed under Section 5.4.1(b), Transmission Design Criteria - Stability Assessment, and under Section 5.5.1(b), Transmission Operating Criteria - Normal Transfers, involves "simultaneous permanent phase to ground faults on different phases of each of two adjacent transmission circuits on a multiple circuit tower, with normal fault clearing." Although this contingency is normally included in the NPCC Criteria, the Basic Criteria in Directory #1 define specific conditions for which a multiple circuit tower situation is an acceptable risk and, therefore, can be excluded.

Directory #1 also allows for requests for exclusion from this contingency, on the basis of acceptable risk, for other instances of multi-circuit tower construction. All exclusions must be approved by the Reliability Coordinating Committee (RCC). An acceptance of a request for exclusion is dependent on the successful demonstration that such exclusion is an acceptable risk. These guidelines describe the procedure to be followed and the supporting documentation required when requesting exclusion, and establishes a procedure for periodic review of exclusions of record.

2.0 Documentation

The documentation supporting a request for exclusion to Sections 5.4.1(b) and 5.5.1(b) of the Basic Criteria must include the following:

2.1 A description of the facilities involved, including geographic location, length and type of construction, and electrical connections to the rest of the interconnected power system;

2.2 Relevant design information pertinent to the assessment of acceptable risk, which might include: details of the construction of the facilities, geographic or

atmospheric conditions, or any other factors that influence the risk of sustaining a multi-circuit contingency;

2.3 An assessment of the consequences of the occurrence of a multi-circuit contingency, including, but not limited to, a discussion of levels of exposure and probability of occurrence of significant adverse impact outside the local area;

2.4 For existing facilities, the historical outage performance, including cause, for multi-circuit contingencies on the specific facility (facilities) involved as compared to that of other multi-circuit tower facilities;

2.5 For planned facilities, the estimated frequency of multi-circuit contingencies

based on the historical performance of facilities of similar construction located in an area with similar geographic climate and topography.

3.0 Procedure for obtaining an Exclusion

The following procedure shall be used in obtaining exclusion to Sections 5.4.1(b) or 5.5.1(b) of Directory #1:

3.1 The entity requesting the exclusion (the Requestor) shall submit the request and supporting documentation to the Task Force on System Studies (TFSS) after acceptance has been granted by the Requestor’s own Planning Coordinator, if such process is applicable.

3.2 TFSS shall review the request, verify that the documentation requirements have been met, and determine the acceptability of the request.

3.3 If TFSS deems the request acceptable, TFSS shall request the Task Force on Coordination of Planning (TFCP), the Task Force on Coordination of Operation (TFCO), and the Task Force on System Protection (TFSP) to review the request. The Requestor shall provide copies of the request and supporting documentation to the other Task Forces as directed by TFSS. If additional information is requested by the other Task Forces as part of their assessment, the Requestor will provide this information directly to the interested Task Force, with a copy to the TFSS. The other Task Forces shall review the request and indicate their acceptance or non-acceptance to TFSS.

3.4 If any of the four Task Forces determines the request is not acceptable, TFSS will respond to the Requestor with the determination and inform the RCC and the other Task Forces of the decision.

3.5 TFSS shall notify TFCP, TFCO, and TFSP of an exclusion that has been accepted by the Task Forces and the basis for the exclusion. The TFSS will then make a recommendation to the RCC regarding the exclusion.

3.6 The NPCC Policy for Alternative Dispute Resolution is available for use if the decision is unacceptable to the Requestor.

Upon acceptance of the requested exclusion by the RCC, TFSS shall so notify the Requestor and update a summary list of the exclusions. The summary list and supporting documents shall be maintained by NPCC.

4.0 Periodic Review of Exclusions of Record

Exclusions shall be reviewed within the Planning Coordinator’s transmission reviews as provided in Guidelines for NPCC Area Transmission Reviews (NPCC Directory #1 – Appendix C). This review shall verify that the basis for each exclusion is still valid. TFSS shall notify TFCP, TFCO, TFSP, and the RCC when a Planning Coordinator’stransmission review has determined exclusion is no longer applicable, and revise the exclusion summary list accordingly.

Appendix F – Procedure for Operational Planning Coordination

1.0 Introduction

The Reliability Coordinators (RC) of the Northeast Power Coordinating Council, Inc. (NPCC) require access to the security data specified in this procedure in order to adequately assess the reliability of the NPCC bulk power system. All users of the electric systems, including market participants, must supply such data to the NPCC Reliability Coordinators. Coordination among and within the Reliability Coordinator Areas (RC Area) of NPCC is essential to the reliability of interconnected operations. Timely information concerning system conditions should be transmitted by the NPCC RC Areas to other RC Areas as needed to assure reliable operation of the bulk power

system. One aspect of this coordination is to ensure that adjacent RC Areas andneighboring systems are advised on a regular basis of expected operating conditions, including generator, transmission and system protection, including Type I special

protection system, outages that may materially reduce the ability of an RC Area to contribute to the reliable operation of the interconnected system, or to receive and/or render assistance to another RC Area. To the extent practical, the coordination of outage schedules is desirable in order to limit the severity of such impacts.

To ensure that there is effective coordination for system reliability concerns, this document establishes procedures for the exchange of information regarding load/capacity forecasts, including firm sales and firm purchases, generator outage schedules, and transmission outage schedules for those facilities that may have an adverse impact on other RC Area(s). It also details general action that may be taken to improve the communication of problems as well as specific topics that may be discussed in regularly scheduled, pre-arranged conference call meetings or inconference calls arranged in anticipation of problems such as capacity deficiency or inadequate light load margin in one or more RC Areas.

Participants and other recipients of the information provided by this process must adhere to the NERC Confidentiality Agreement for Electric System Operating

Reliability Data.

2.0 Load/Capacity Forecasts

2.1 Twice yearly, by May 15th and November 15th respectively, the Operations Planning Working Group (CO 12) will perform a summer and winter assessment for the next season. The methodology and format of the seasonal report will be presented in NPCC Document C-45, “CO-12 Seasonal Assessment Methodology,” currently under development.

The results will be reviewed by the NPCC Task Force on Coordination of Operation (TFCO) and the NPCC Reliability Coordinating Committee (RCC) in advance of the spring and autumn meetings of both groups.

2.2 Each week, each RC Area will review its weekly net resource capacity margin, as defined in Attachment A, for the twelve weeks to follow and forward the information to the NPCC Staff for distribution to all NPCC RC Areas. If an NPCC RC Area identifies a deficiency or light load condition, the RC Area should identify the cause(s) and mitigation measures that have been implemented, or will be implemented, to manage the issue.

3.0 Generator Outage Coordination

3.1 Each RC Area should exchange current and expected critical generation outages.

4.0 Transmission Outage Coordination

4.1 Advance Planning of Transmission Facility Outages

NPCC Document Directory#1, Basic Criteria for Design and Operation of

Interconnected Power Systems, requires that scheduled outages of transmission facilities that affect reliability between RC Areas be coordinated sufficiently in advance of the outage to permit the affected RC Area to maintain reliability. For the purposes of this procedure, each RC should exchange critical transmission outages as identified in coordination agreements with their interconnected neighbors and jointly develop and maintain a Facilities Notification List.

4.2 Facilities Notification List

The NPCC Facilities Notification List, Attachment D, has two components:

1) the NPCC Transmission Facilities Notification List; and2) the list of NPCC Type I special protection systems.

The Facilities Notification List is developed by each RC Area and specifies all facilities that, if removed from service, may have a significant, direct or indirect impact on another RC Area’s transfer capability. The cause of such impact might include stability, voltage, and/or thermal considerations.

Prior to October 1st of each year, each RC Area will review and update its Facilities Notification List and coordinate necessary changes with other appropriate NPCC RC Areas. Prior to January 1st, and after review by the TFCO, the approved, updated Facilities Notification List will be posted on the NPCC secure website.

The Task Force on System Protection develops yearly the list of NPCC Type 1 special protection systems with input from the Task Force on System Studies.

It should be noted that revisions to the Facilities Notification List only will not follow the NPCC Process for Open Review due to the secure nature of the information contained, and Attachment D is not openly published with this Procedure.

A temporary reconfiguration of the network may result in an outage to one or more facilities not listed in Attachment D having an impact on other NPCC RC Areas. It is the responsibility of the RC experiencing the condition to notify impacted RCs in a timely manner and provide updated status reports during the condition.

4.3 Notifications of Work

4.3.1 Notification requirements should be defined in interconnected coordination agreements. The time frames identified below are the minimum notification requirements.

4.3.2 The initiating RC will advise affected RCs of all applications for outages of facilities on the Facilities Notification List, including those which have been planned.

All outages to equipment listed in the Facilities Notification List should be planned with as much lead time as practical.

Normally, notification for work on facilities covered by this instruction will be submitted to the appropriate RC Areas at least two (2) working days prior to the time the facility is to be taken out of service.

When an RC Area receives an outage notification from another RC Area, prompt attention will be given to the notification and appropriate comments rendered. Analysis will be conducted by each RC Area in accordance with internal procedures.

4.3.3 An RC Area will not normally remove from service any transmission facility, which might have a reliability impact on an RC Area without prior notification to and appropriate review by that RC Area. In the event of an emergency condition, each RC Area may take action asdeemed appropriate. Other RC Areas should be notified immediately.

An RC Area will make every effort to reschedule routine (non-emergency) transmission outages that severely degrade the reliability of an adjacent RC Area or neighboring system.

4.3.4 Each RC Area will advise the other affected RC Areas of any protection outage associated with RC Area tie line facilities. Coordination agreements may identify additional reporting

requirements associated with protection outages.

5.0 Data Providers

NPCC entities are to provide the data in order to adequately assess the reliability of the NPCC bulk power system.

6.0 Specific Communications

Conditions in an RC Area that may have an impact on another RC Area should be communicated in a clear and timely manner. Specific communications are conducted as follows:

6.1 Weekly

Each Thursday a conference call will be initiated by the NPCC Staff to discuss operations expected during the seven-day period starting with the following Sunday. Operations personnel from the NPCC RC Areas will participate. In advance of the conference call, each RC Area will prepare the data specified in Attachments A and B, and forward it to the NPCC Staff a minimum of one hour in advance of the scheduled call. The completed “NPCC Weekly Conference Call Generating Capacity Worksheet,” Attachment B, together with the list of “Twelve Weeks Projections of Net Margins,” Attachment C, will be forwarded to the conference call participants by the NPCC Staff.

Each RC will review its weekly capacity margins for the next twelve week period. If a deficiency or light load condition is identified, the RC will identify the cause of the deficiency or light load condition and discuss proposed mitigation measures.

The NPCC Staff will prepare Conference Call Notes that will be forwarded to the conference call participants and members of the TFCO by the following Friday afternoon.

If a deficiency or light load condition, or if adverse system operating conditions are expected within the next week, any RC Area may recommend that an Emergency Preparedness Conference Call (NPCC Document C-01) take place at an appropriate time.

Items of particular concern that should be discussed during the weekly conference call are described in Attachment C.

6.2 Emergency Preparedness Conference Call

Whenever adverse system operating or weather conditions are expected, any RC Area may request the NPCC Staff to arrange an Emergency Preparedness Conference Call (NPCC Document C-01) to discuss operating details with appropriate operations management personnel from the NPCC RC Areas and neighboring systems.

6.3 Daily Conference Calls

Each of the NPCC Reliability Coordinator Area control rooms participate in a regularly scheduled daily conference call. The goal of this call is to alert NPCC Reliability Coordinators of any potential emerging problems. Subjects for discussion are limited to credible events which could impact the ability of a Reliability Coordinator to serve its load and meet its operating reserve obligations, or which would impose a burden to the Interconnection.

Procedure for Operational Planning Coordination – Attachment A

Load and Capacity Table Instructions

and

Generating Capacity Worksheet Instructions

Week Beginning The seven day period for which data is to be reported is defined as starting with the Sunday following the conference call through the following Saturday.

Installed Generating Capacity (Line

Item 1)

Include all available generation at its maximum demonstrated capability for the appropriate seasonal capability period.

Firm Purchases (Line Item 2) Include only those transactions where capacity is delivered. Exclude “energy only” transactions.

Firm Sales (Line Item 3) Include only those transactions where capacity is delivered. Exclude “energy only” transactions.

Net Capacity (Line Item 4) Add Installed Generating Capacity and Firm Purchases. Subtract Firm Sales. (Line 1+Line 2-Line3)

Peak Load Forecast (Line Item 5) The peak load forecast should be the best estimate of the RC Area’s maximum peak load exposure anticipated for the week reported.

Available Reserve (Line Item 6) Subtract Peak Load Forecast from Net Capacity. (Line 4-Line5.)

Demand Side Management (Line Item

7)

Include only maximum capability which can be obtained by operator initialization within four (4) hours.

Attachment A (continued)

Known Unavailable Capability (Line

Item 8)

Include all known outages, as well as those deratings or unit outages presently forced out, unavailable, on extended cold standby or which are anticipated to remain out of service. This would also include capacity unavailable due to transmission constraints.

Net Reserve (Line Item 9) Available Reserve plus Demand Side Management minus Known Unavailable Capacity. (Line 6+Line 7-Line 8)

Required Operating Reserve (Line Item

10)

The methodology used by each RC Area in calculating operating reserve must, as a minimum, meet the requirements of NPCC Document A-06, “Operating Reserve Criteria.” Methodologies differing from the A-06 requirements should be clarified in Attachment B, “NPCC Weekly Conference Call Generating Capacity Worksheet,” under the tab for “Operating Reserve.”

Gross Margin (Line Item 11) Subtract Required Operating Reserve from Net Reserve. (Line 9-Line 10)

Unplanned Outages (Line Item 12) Estimate the amount of generating capacity which will be unavailable. This quantity should be based on historical averages for forced outages and deratings.

Net Resource Capacity Margin (Line

Item 13)

Subtract Unplanned Outages from Gross Margin. A positive value reflects surplus reserve. A negative value reflects a deficiency. (Line 11-Line 12)

Forecast High / Low Temperatures and

Days (Line Item 14)

Include the expected high and low temperatures for the RC Area for the week, and indicate the day on which they are expected to occur.

Attachment A (continued)

Seasonal High / Low Temperatures

(Line Item 15)

Include the expected high and low forecast seasonal temperatures for the RC Area.

Minimum Load Forecast (Line Item 16) The minimum load forecast should be the best estimate of the RC Area’s minimum load exposure anticipated for the week reported.

Minimum Resources (Line Item 17) The Minimum Resources are the Reliability Coordinator Area’s total expected on-line generator minimum output capability and must-take purchases.

Light Load Margin (Line Item 18) Subtract Minimum Resources from Minimum Load Forecast. A negative number indicates a light load condition. (Line 16-Line 17)

Procedure for Operational Planning Coordination – Attachment B

NPCC Weekly Conference Call Generating Capacity Worksheet

The “NPCC Weekly Conference Call Generating Capacity Worksheet” is an active Excel spreadsheet used each week to assist in the calculation of the data discussed during the weekly conference call. A blank template, in Microsoft Office Excel 2003, is available from the NPCC office.

Procedure for Operational Planning Coordination - Attachment C

CONDITIONS FOR DISCUSSION

Items of particular concern that should be discussed during a conference call include, but are not limited to, the following:

• anticipated weather;

• largest first and second contingencies;

• operating reserve requirements and expected available operating reserve;

• capacity deficiencies;

• potential fuel shortages or potential supply disruptions which could lead to energy shortfalls;

• light load margins;

• general and specific voltage conditions throughout each system or RC Area;

• status of short term contracts and other scheduled arrangements, including those that impact on operating reserves;

• additional capability available within twelve hours and four hours;

• generator outages that may have a significant impact on an adjacent RC Area or neighboring system;

• transmission outages that might have an adverse impact on internal and external energy transfers;

• potential need for emergency transfers;

• expected transfer limits and limiting elements;

• a change or anticipated change in the normal operating configuration of the system, such as the temporary modification of relay protection schemes so that the usual and customary levels of protection will not be provided, or the arming of special protection systems not normally armed, or the application of abnormal operating procedures; and

• update of the abnormal status of NPCC Type I special protection systems forced out of service.

Attachment D

NPCC Facilities Notification List

Attachment D is not publicly available due to the confidential nature of the information presented.

Appendix G - Procedures for Inter Reliability Coordinator Area Voltage Control

1.0 Introduction

This Procedure provides general principles and guidance for effective inter- Transmission Operator Area voltage control, consistent with the NPCC, Directory #1,“Design and Operation of the Bulk Power System,” and applicable NERC Standards. Specific methods to implement this Procedure may vary among Transmission Operators, depending on local requirements. Coordinated inter- Transmission Operator Area voltage control is necessary to regulate voltages to protect equipment from damage and prevent voltage collapse. Coordinated voltage regulation reduces electrical losses on the network and lessens equipment degradation. Local control actions are generally most effective for voltage regulation. Occasions arise when adjacent Transmission Operators can assist each other to compensate for deficiencies or excesses of reactive power and improve voltage profiles and system security.

2.0 Principles

Each Transmission Operator develops, and operates in accordance with, its own voltage control procedures and criteria which are consistent with NPCC, Inc. Criteria and NERC Standards. Adjacent Transmission Operators should be familiar with the respective criteria and procedures of their neighboring Transmission Operators should mutually agree upon procedures for inter- Transmission Operator Area voltage control. Whether inter- Transmission Operator Area voltage control is carried out through specific or general procedures, the following should be considered and applied:

2.1 To effectively coordinate voltage control, location and placement of metering for reactive power resources and voltage controller status should be consistent between adjacent Transmission Operators.

2.2 the availability of voltage regulating transformers in the proximity of tie lines;

2.3 voltage levels, limits, and regulation requirements for stations on either side of an inter- Transmission Operator Area interface;

2.4 the circulation of reactive power (export at one tie point in exchange for import at another);

2.5 tie line reactive losses as a function of real power transfer;

2.6 reactive reserve of on-line generators;

2.7 shunt reactive device availability and switching strategy; and

2.8 static VAR compensator availability, reactive reserve, and control strategy.

3.0 Procedure

Transmission Operators maintain normal voltage conditions, in accordance with their own individual or joint operating policies, procedures and applicable interconnection agreements. In the event the system state changes to an abnormal voltage condition, the Transmission Operator in which the abnormal condition is originating should immediately take corrective action. If the corrective control actions are ineffective, or the Transmission Operator has insufficient reactive resources to control the problem, assistance may be requested from other Transmission Operators.

3.1 Normal Voltage Conditions

The bulk power system is operating with Normal Voltage Conditions when:

• actual voltages are within applicable normal (pre-contingency) voltage ranges; and

• expected post-contingency voltages are within applicable post-contingency minimum and maximum levels following the most severe contingency specified in Directory #1 “Design and Operation of theBulk Power System.”

Each Transmission Operator should maintain a mix of static and dynamic resources, including reactive reserves.

3.1.1 Providing that it is feasible to regulate reactive flows on its tie lines, each Transmission Operator should establish a mutually agreed upon voltage profile with adjacent Transmission Operators and with other neighboring systems. This voltage profile should conform to the provisions of the relevant interconnection agreements and may provide for:

• The minimum and maximum voltage at stations at or near terminals of inter-Transmission Operator Area tie lines;

• The receipt of reactive flow at one tie point in exchange for delivery at another;

• The sharing of the reactive requirements of tie lines and series regulating equipment (either equally or in proportion to line lengths, etc.); and

• The transfer of reactive power from one Transmission Operator toanother.

This voltage profile, adjusted for changes in operating conditions, should be considered as the basis for determining which Transmission Operator should implement necessary measures to alleviate abnormal voltage conditions affecting more than one Transmission Operator as discussed in 3.2.10 below.

3.1.2 Each Transmission Operator should anticipate voltage trends and initiate corrective action in advance of critical periods of heavy and light loads.

4.0 Procedure for Triennial Monitoring and Reporting of Inter-Area Voltage Control

4.1 On, or shortly before, the first of July, the TFCO Secretary will write to each TFCO member, requesting a written response by the end of July in the form of:

a) A copy of any new procedures and principles between the reporting Reliability Coordinator and adjacent Reliability Coordinators providing detailed application, or,

b) a copy of any new understanding, such as the minutes of an operating committee meeting between Reliability Coordinators, indicating that such detailed application is not required, and why;

c) a copy of any revisions to the procedures and principles, or understandings currently on file at NPCC, that exists between the reporting Reliability Coordinator and adjacent Reliability Coordinators;

d) a response indicating no change to existing procedures and principles, or understandings currently on file at NPCC.

4.2 The TFCO Secretary will draft a report summarizing the extent to which responses indicated conformance with the NPCC Procedures, and will forward it to TFCO members at least two weeks prior to the October TFCO meeting.

4.3 Following TFCO review and adoption, the TFCO Chairman will forward the report to the Chairman of the Reliability Coordinating Committee (RCC) recommending acceptance or other action as deemed appropriate. This will normally be forwarded three weeks prior to the next regularly scheduled RCC meeting.

Appendix 2-4

ISO New England

Planning Procedure No. 3

Reliability Standards for

the New England Area

Bulk Power Supply System

ISO New England Planning Procedure PP3 – Reliability Standards for the New England Area Bulk Power Supply System

ISO NEW ENGLAND PLANNING PROCEDURE NO. 3

RELIABILITY STANDARDS FOR THE

NEW ENGLAND AREA BULK POWER SUPPLY SYSTEM

EFFECTIVE DATE: March 1, 2013

REFERENCES:

NPCC Reliability Reference Directory # 1 Design and Operation of the Bulk Power System, December 1, 2009 (Includes references to NERC ERO Reliability Standards)

NPCC Regional Reliability Reference Directory # 2 Emergency Operations, June 26, 2009

NPCC Reliability Reference Directory # 4 Bulk Power System Protection Criteria, December 1, 2009

NPCC Glossary of Terms, October 26, 2011

NPCC Regional Reliability Reference Directory # 7 Special Protection Systems, December 27, 2007

ISO New England Planning Procedure 5-5, Special Protection Systems Application Guidelines

Damping Criterion Basis Document, Stability Task Force, Approved April 1,2009.

NERC NUC-001-2, Nuclear Plant Interface Coordination Reliability Standard,Adopted by NERC Board of Trustees: August 5, 2009

NERC Glossary of Terms Used in Reliability Standards, Updated December 21, 2012

Master/Local Control Center Procedure No. 1 - Nuclear Plant Transmission Operations


CONTENTS

1. INTRODUCTION .................................................................................................................... 1

2. RESOURCE ADEQUACY ...................................................................................................... 3

3. AREA TRANSMISSION REQUIREMENTS .......................................................................... 4

3.1 STABILITY ASSESSMENT ..................................................................................... 5

3.2 STEADY STATE ASSESSMENT............................................................................. 6

3.3 FAULT CURRENT ASSESSMENT ......................................................................... 6

4. TRANSMISSION TRANSFER CAPABILITY........................................................................ 6

4.1 NORMAL TRANSFERS ............................................................................................ 6

4.2 EMERGENCY TRANSFERS ..................................................................................... 7

5. EXTREME CONTINGENCY ASSESSMENT ........................................................................ 7

6. EXTREME SYSTEM CONDITIONS ASSESSMENT ............................................................ 8

APPENDIX "A" .......................................................................................................................... 10

LIST OF DEFINITIONS

APPENDIX "B" ............................................................................................................................ 13

GENERAL GUIDELINES FOR DEMONSTRATING COMPLIANCE WITH

PLANNING PROCEDURE NO. 3, RELIABILITY STANDARDS FOR THE NEW ENGLAND AREA BULK POWER SUPPLY SYSTEM

APPENDIX "C" ............................................................................................................................ 15

DAMPING CRITERION


1

RELIABILITY STANDARDS

FOR THE

NEW ENGLAND AREA BULK POWER SUPPLY SYSTEM

1. INTRODUCTION

The ISO New England Transmission, Markets and Services Tariff (the “Tariff”) provides for the

establishment of reliability standards for the bulk power supply system of the New England Area. The reliability standards set forth herein have been adopted as appropriate for the New England bulk

power supply system1. Further, they are consistent with those established by the Northeast Power

Coordinating Council in the NPCC "Basic Criteria for Design and Operation of Interconnected Power Systems" and the NPCC "Bulk Power System Protection Criteria."

The purpose of these New England Reliability Standards is to assure the reliability and efficiency of the New England bulk power supply system through coordination of system planning, design and operation. These standards apply to all entities comprising or using the New England bulk power

supply system. The host Governance Participant (the Governance Participant through which a non-Governance Participant connects to the bulk power supply system) shall use its best efforts to assure that, whenever it enters into arrangements with non-Governance Participants, such arrangements are consistent with these standards.

These Reliability Standards establish minimum design criteria for the New England bulk power

supply system. It is recognized that more rigid design and operating criteria may be applied in some segments of the pool because of local considerations. Any constraints imposed by the more rigid criteria will be taken into account in all testing. It is also recognized that the Reliability Standards are not necessarily applicable to those elements that are not a part of the New England bulk power

supply system.

Because of the long lead times required for the planning and construction of generation and transmission facilities versus the short lead times available for responding to changed operating conditions, it is necessary that criteria for planning and design vary in some respects from the System Rules used in actual operations. The intent is to have the system operate at the level of reliability that was contemplated at the time it was designed. For this reason, it is necessary that the design criteria simulate the effects of the equipment outages which may be expected to occur in actual operation. Nevertheless, it should be recognized that in actual operations, it may not always be possible to achieve the design level of reliability due to delays in construction of critical facilities, excessive forced outages, or loads exceeding the predicted levels.

1 Terms in bold typeface are defined in Appendix A.


2

These Reliability Standards are intended to be used for planning and design of the New England bulk

power system. Reliability criteria and procedures for operations are detailed elsewhere, with theprimary reliability-related documents used in system dispatch and operations being:

1. ISO New England Operating Procedure No. 1 – Central Dispatch Operating Responsibility and Authority of ISO New England, the Local Control Centers and Market Participants

2. ISO New England Operating Procedure No. 3 – Transmission Outage Scheduling

3. ISO New England Operating Procedure No. 4 – Action During a Capacity Deficiency

4. ISO New England Operating Procedure No. 5 – Generation Maintenance and Outage Scheduling

5. ISO New England Operating Procedure No. 6 – System Restoration

6. ISO New England Operating Procedure No. 7 – Action in an Emergency

7. ISO New England Operating Procedure No. 8 – Operating Reserve and Regulation

8. ISO New England Operating Procedure No. 11 – Black Start Capability Testing Requirements

9. ISO New England Operating Procedure No. 12 – Voltage and Reactive Control

10. ISO New England Operating Procedure No. 13 – Standards for Voltage Reduction and Load Shedding Capability

11. ISO New England Operating Procedure No. 14 – Technical Requirements for Generators,Demand Resources and Asset Related Demands

12. ISO New England Operating Procedure No. 17 – Load Power Factor Correction

13. ISO New England Operating Procedure No. 18 – Metering and Telemetering Criteria

14. ISO New England Operating Procedure No. 19 – Transmission Operations

The New England bulk power supply system shall be designed for a level of reliability such that the loss of a major portion of the system, or unintentional separation of any portion of the system, will not result from reasonably foreseeable contingencies. Therefore, the system is required to be designed to meet representative contingencies as defined in these Reliability Standards. Analyses of simulations of these contingencies should include assessment of the potential for widespread cascading outages due to overloads, instability, voltage collapse, or the inability to meet the Nuclear Plant Interface

Requirements (NPIRs). The NPIRs for each nuclear plant generator subject to dispatch by ISO New England Inc. (ISO) are documented in the Attachment to Master/Local Control Center Procedure No. 1 - Nuclear Plant Transmission Operations (M/LCC 1) applicable to that nuclear plant generator. The


3

loss of small portions of the system may be tolerated provided the reliability of the overall interconnected system is not jeopardized and the NPIRs are met.

The standards outlined hereinafter are not tailored to fit any one system or combination of systems but rather outline a set of guidelines for system design which will result in the achievement of the desired level of reliability and efficiency for the New England bulk power supply system.

2. RESOURCE ADEQUACY

Resources will be planned and installed in such a manner that, after due allowance for the factors enumerated below, the probability of disconnecting noninterruptible customers due to resource

deficiency, on the average, will be no more than once in ten years. Compliance with this criteria shall be evaluated probabilistically, such that the loss of load expectation [LOLE] of disconnecting noninterruptible customers due to resource deficiencies shall be, on average, no more than 0.1 day per year.

a. The possibility that load forecasts may be exceeded as a result of weather variations.

b. Immature and mature equivalent forced outage rates appropriate for generating units of various sizes and types, recognizing partial and full outages.

c. Due allowance for scheduled outages and deratings.

d. Seasonal adjustment of resource capability.

e. Proper maintenance requirements.

f. Available operating procedures.

g. The reliability benefits of interconnections with systems that are not Governance Participants.

h. Such other factors as may from time-to-time be appropriate.

For planning purposes, the assumed equivalent forced outage rate of a generating unit connected to the transmission network by a radial transmission line will be increased to reflect the estimated transmission line forced outage rate if significant.

The potential power transfers from outside New England that are considered in determining the New


4

England capacity requirements must not exceed the emergency inter-Area transmission transfer capabilities, as determined in accordance with Section 4.2, using long term emergency (LTE) ratings.

3. AREA TRANSMISSION REQUIREMENTS

The New England bulk power supply system shall be designed with sufficient transmission capacity to integrate all resources and serve area loads and meet the applicable NPIRs under the conditions noted in Sections 3.1 and 3.2. These requirements will also apply after any critical generator, transmission circuit, transformer, phase angle regulating transformer, HVDC pole, series or shunt compensating device has already been lost, assuming that the area resources and power flows are adjusted between outages, using all appropriate reserve resources available in ten minutes and where applicable, any phase angle regulator control, and HVDC control.

With due allowance for generator maintenance and forced outages, design studies will assume power flow conditions with applicable transfers, load, and resource conditions that reasonably stress the system. Transfers of power to and from another Area, as well as within New England, shall be considered in the design of inter-Area and intra-Area transmission facilities.

Transmission transfer capabilities will be based on the load and resource conditions expected to exist for the period under study and shall be determined in accordance with Section 4.1 for normal transfers, and Section 4.2 for emergency transfers. All reclosing facilities will be assumed in service unless it is known that such facilities have been or will be rendered inoperative.

In applying these criteria, it is recognized that it may be necessary to restrict the output of a generating station(s) and/or HVDC terminal(s) following the loss of a system element. This may be necessary to maintain system stability or to maintain line loadings within appropriate thermal ratings in the event of a subsequent outage. But, the system design must be such that, with all transmission facilities in service, all resources required for reliable and efficient system operation can be dispatched without unacceptable restriction.

Special Protection Systems (SPSs) may be employed in the design of the interconnected power system. All SPSs proposed for use on the New England system must be reviewed by the Reliability Committee and NPCC and approved by the ISO. Some SPSs may also require acceptance by NPCC. The requirements for the design of SPSs are defined in the NPCC "Bulk Power System Protection Criteria" and the NPCC "Special Protection System Criteria". A set of guidelines for application of SPSs on the New England system are contained in the ISO New England Planning Procedure 5-6 “Special Protection Systems Application Guidelines”.


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3.1 STABILITY ASSESSMENT

The New England bulk power supply system shall remain stable and damped in accordance with the criterion specified in Appendix C during and following the most severe of the contingencies

stated below with due regard to reclosing, and before making any manual system adjustments. For each of the contingencies below that involves a fault, stability and damping in accordance with the criterion specified in Appendix C shall be maintained when the simulation is based on fault clearing initiated by the “system A” protection group, and also shall be maintained when the simulation is based on fault clearing initiated by the “system B” protection group where such protection group is required or where there would otherwise be a significant adverse impact outside the local area.

a. A permanent three-phase fault on any generator, transmission circuit, transformer, or bus section with normal fault clearing.

b. Simultaneous permanent phase-to-ground faults on different phases of each of two adjacent transmission circuits on a multiple circuit transmission tower, with normal fault

clearing. If multiple circuit towers are used only for station entrance and exit purposes, and if they do not exceed five towers at each station, then this condition and other similar situations can be excluded on the basis of acceptable risk, provided that the ISO specifically approves each request for exclusion. Similar approval must be granted by the NPCC Reliability Coordinating Committee.

c. A permanent phase-to-ground fault on any transmission circuit, transformer or bus section with delayed fault clearing. This delayed fault clearing could be due to circuit breaker, relay system or signal channel malfunction.


e. A permanent phase-to-ground fault in a circuit breaker, with normal fault clearing. (Normal fault clearing time for this condition may not be high speed.)

f. Simultaneous permanent loss of both poles of a direct current bipolar facility without an ac fault.

g. The failure of any SPS which is not functionally redundant to operate properly when required following the contingencies listed in "a" through "f" above.

h. The failure of a circuit breaker to operate when initiated by an SPS following: loss of any element without a fault; or a permanent phase to ground fault, with normal fault

clearing, on any transmission circuit, transformer, or bus section.


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3.2 STEADY STATE ASSESSMENT

a. Adequate reactive power resources with reserves and appropriate controls shall be installed to maintain voltages within normal limits for pre-disturbance conditions, and within applicable emergency limits for the system conditions that exist following the contingencies specified in Section 3.1.

b. Line and equipment loadings shall be within normal limits for pre-disturbance conditions and within applicable emergency limits for the system load and generation conditions that exist following the contingencies specified in Section 3.1.

3.3 FAULT CURRENT ASSESSMENT

The New England bulk power supply system shall be designed to ensure equipment capabilities are adequate for fault current levels with all transmission and generation facilities in service for all potential operating conditions.

4. TRANSMISSION TRANSFER CAPABILITY

The New England bulk power supply system shall be designed with adequate inter-Area and intra-Area transmission transfer capability to minimize system reserve requirements, facilitate transfers, provide emergency backup of supply resources, permit economic interchange of power, and to assure that the conditions specified in Sections 3.1 and 3.2 can be sustained without adversely affecting the New England system or other Areas and without violating the NPIRs. Anticipated transfers of power from one area to another, as well as within areas, should be considered in the design of inter-Area and intra-Area transmission facilities. Therefore, design studies will assume applicable transfers and the most severe load and resource conditions that can be reasonably expected.

Firm transmission transfer capabilities shall be determined for Normal and Emergency transfer conditions as defined in Sections 4.1 and 4.2. Normal transfer conditions are to be assumed except during an Emergency as defined by Item 7 in Appendix A. In determining the emergency transfer capabilities, a less conservative margin is justified.

4.1 NORMAL TRANSFERS

For normal transfer conditions the New England bulk power supply system shall remain stable and damped in accordance with the criterion specified in Appendix C in during and following the most severe of the conditions specified in Section 3.1 "a" through "h", with due regard to

reclosing, and before making any manual system adjustments.


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Voltages, line loadings and equipment loadings shall be within normal limits for pre-disturbance conditions and within applicable emergency limits for the system load and resource conditions that exist following any disturbance specified in Section 3.1.

4.2 EMERGENCY TRANSFERS

For emergency transfer conditions the New England bulk power supply system shall remain stable and damped in accordance with the criterion specified in Appendix C during and following the most severe of the contingencies stated in "a" and "b" below. Emergency transfer levels may require adjustment of resources and, where available, phase angle regulator controls and HVDC controls, before manually reclosing faulted elements.

a. A permanent three-phase fault on any generator, transmission circuit, transformer, or bus section, with normal fault clearing and with due regard to reclosing.

b. Loss of any element without a fault.

For emergency transfer conditions the pre-disturbance voltages, line, and equipment loadings shall be within applicable emergency limits. The post-disturbance voltages, line, and equipment loadings shall be within applicable emergency limits immediately following the contingencies

above.

5. EXTREME CONTINGENCY ASSESSMENT

Extreme contingency assessment recognizes that the New England bulk power system can be subjected to events which exceed in severity the contingencies listed in Section 3.1. Planning studies will be conducted to determine the effect of the following extreme contingencies on New England bulk power supply system performance as a measure of system strength. Plans or operating procedures will be developed, where appropriate, to reduce the probability of occurrence of such contingencies, or to mitigate the consequences that are indicated as a result of the simulation of such contingencies.

a. Loss of the entire capability of a generating station.

b. Loss of all transmission circuits emanating from a generating station, switching station, dc terminal or substation.

c. Loss of all transmission circuits on a common right-of-way.

d. Permanent three-phase fault on any generator, transmission circuit, transformer or bus section,


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with delayed fault clearing and with due regard to reclosing. This delayed fault clearing

could be due to circuit breaker, relay system or signal channel malfunction.

e. The sudden dropping of a large load or major load center.

f. The effect of severe power swings arising from disturbances outside of New England.

g. Failure of a Special Protection System to operate when required following the normal contingencies listed in Section 3.1 "a" through "f".

h. The operation or partial operation of a Special Protection System for an event or condition for which it was not intended to operate.

i. Common mode failure of the fuel delivery system that would result in the sudden loss of multiple plants (i.e. gas pipeline contingencies, including both gas transmission lines and gas mains).

6. EXTREME SYSTEM CONDITIONS ASSESSMENT

The New England bulk power supply system can be subjected to a wide range of other than normal system conditions that have low probability of occurrence. One of the objectives of extreme system conditions assessment is to determine through planning studies, the impact of these conditions on expected steady-state and dynamic system performance. This is done in order to obtain an indication of system robustness or to determine the extent of a widespread adverse system response.

Analytical studies will be conducted to determine the effect of design contingencies under the following extreme system conditions:

a. Peak load conditions resulting from extreme weather conditions with applicable rating of electrical elements.

b. Generating unit(s) fuel shortage, (e.g. gas supply unavailability).

After due assessment of extreme system conditions, measures may be utilized, where appropriate, to mitigate the consequences that are indicated as a result of testing for such extreme system conditions.


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Document History2

Rev. 0 Rec.: RTPC - 6/8/99; App.: NEC - 7/9/99

Rev. 1 Rec.: RC - 12/7/04; App.: PC - 1/7/05 Rev. 2 Eff.: 2/1/05

Rev. 3 Rec.: RC – 8/29/06; Rec.:PC – 10/13/06; Eff. 10/13/06

Rev. 4 Rec.: RC – 5/19/09; Rec.:PC – 6/05/09; Eff. 6/11/09 Rev. 5 Modifications Only Address NERC Standard NUC-001-2

Rec.: RC – 2/26/10; Rec. PC – 3/05/10; Eff. 3/05/10

Rev. 6 Rec.: RC – 2/14/13; Rec. PC – 3/01/13; Eff. 3/01/13

2 This Document History documents action taken on the equivalent NEPOOL Procedure prior to the RTO Operations Date as well as revisions to the ISO New England Procedure subsequent to the RTO Operations Date.


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APPENDIX “A”

LIST OF DEFINITIONS

1. APPLICABLE EMERGENCY LIMIT

These emergency limits depend on the duration of the occurrence, and are subject to New England standards.

Emergency limits are those which can be utilized for the time required to take corrective action, but in no case less than five minutes.

The limiting condition for voltages should recognize that voltages should not drop below that required for suitable system stability performance, meet the Nuclear Plant Interface

Requirements and should not adversely affect the operation of the New England bulk power

supply system.

The limiting condition for equipment loadings should be such that cascading outages will not occur due to operation of protective devices upon the failure of facilities.

2. AREA

An Area (when capitalized) refers to one of the following: New England, New York, Ontario, Quebec or the Maritimes (New Brunswick, Nova Scotia and Prince Edward Island); or, as the situation requires, area (lower case) may mean a part of a system or more than a single system.

3. BULK POWER SUPPLY SYSTEM

The New England interconnected bulk power supply system is comprised of generation and transmission facilities on which faults or disturbances can have a significant effect outside of the local area.

4. CONTINGENCY (as defined in NPCC Glossary of Terms) An event, usually involving the loss of one or more elements, which affects the power system at least momentarily.

5. DELAYED FAULT CLEARING (as defined in NPCC Glossary of Terms) Fault clearing consistent with correct operation of a breaker failure protection group and its associated breakers, or of a backup protection group with an intentional time delay.


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6. ELEMENT (as defined in NPCC Glossary of Terms) Any electric device with terminals which may be connected to other electric devices, usually limited to a generator, transformer, circuit, circuit breaker, or bus section.

7. EMERGENCY

An emergency is considered to exist if firm load may have to be reduced because sufficient capacity or energy is unavailable after due allowance for purchases. Emergency transfers are applicable under such conditions. The emergency is considered to exist as long as any firm system load is potentially or actually curtailed.

8. EQUIVALENT FORCED OUTAGE RATE

The equivalent forced outage rate (EFOR) is the ratio of total time a generator is completely forced out of service plus the equivalent full outage time of any forced partial restrictions, to the total time that the unit is not on scheduled maintenance.

9. HVDC SYSTEM, DIRECT CURRENT BIPOLAR

An HVDC system with two poles of opposite polarity.

10. NORMAL FAULT CLEARING (as defined in NPCC Glossary of Terms) Fault clearing consistent with correct operation of the protection system and with the correct operation of all circuit breakers or other automatic switching devices intended to operate in conjunction with that protection system

11. NUCLEAR PLANT INTERFACE REQUIREMENTS (as defined in the NERC Glossary of Terms Used in Reliability Standards and as documented in M/LCC 1, Attachments A through D)

12. PROTECTION GROUP (as defined in NPCC Glossary of Terms)A fully integrated assembly of protective relays and associated equipment that is designed to perform the specified protective functions for a power system element, independent of other groups.

Notes:

a) Variously identified as Main Protection, Primary Protection, Breaker Failure Protection, Back-Up Protection, Alternate Protection, Secondary Protection, A Protection, B Protection, Group A, Group B, System 1 or System 2.

b) Pilot protection is considered to be one protection group.

13. PROTECTION SYSTEM (as defined in NPCC Glossary of Terms)


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Element Basis: One or more protection groups; including all equipment such as instrument transformers, station wiring, circuit breakers and associated trip/close modules, and communication facilities; installed at all terminals of a power system element to provide the complete protection of that element.

Terminal Basis: One or more protection groups, as above, installed at one terminal of a power system element, typically a transmission line.

14. RESOURCE

Resource refers to a supply side or demand-side facility and/or action. For the purposes of this procedure, resource means a generating unit, a Demand Resource, a Dispatchable Load, an External Resource or an External Transaction. Demand Resource, Dispatchable Load, External Resource and External Transaction are as defined in Market Rule 1.

15. SPECIAL PROTECTION SYSTEM (SPS) (as defined in NPCC Glossary of Terms) A protection system designed to detect abnormal system conditions, and take corrective action other than the isolation of faulted elements. Such action may include changes in load, generation, or system configuration to maintain system stability, acceptable voltages or power flows. Automatic under frequency load shedding, as defined in NPCC Emergency Operation Criteria A-3, is not considered an SPS. Conventionally switched, locally controlled shunt devices are not SPSs.

16. TEN-MINUTE RESERVE (as defined in NPCC Glossary of Terms) The sum of synchronized and non-synchronized reserve that is fully available in ten minutes.

17. WITH DUE REGARD TO RECLOSING (as defined in NPCC Glossary of Terms) This phrase means that before any manual system adjustments, recognition will be given to the type of reclosing (i.e., manual or automatic) and the kind of protection.


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APPENDIX "B"

GENERAL GUIDELINES FOR DEMONSTRATING COMPLIANCE WITH PLANNING

PROCEDURE NO. 3,

RELIABILITY STANDARDS FOR THE NEW ENGLAND AREA BULK POWER SUPPLY

SYSTEM

General guidelines for demonstrating compliance with criteria are outlined as follows:

• Testing should be performed to examine the performance of the system. This could be done using "standard" deterministic approaches, and must consider a sufficient range of reasonably stressed system conditions. A consensus of appropriate review groups would be required regarding the adequacy of the system test conditions.

• To demonstrate compliance with criteria:

Ø Identify there are no operational restrictions, with all lines in service

and

all load can be served by available resources (allowing full use of ten-minute reserve,phase shifters, HVDC control, etc.) with any facility assumed already forced out of service.

or

Ø If there are operational restrictions or conditions for which all load can not be served:

1) Determine the predicted frequency, duration, period, and magnitude of the restrictions.

2) Convert these findings into a statement describing their effects upon the Governance Participants.

3) Establish the impact of these effects on the reliable and efficient operation of the bulk

power supply system.

Appropriate review groups will determine the acceptability of restrictions, based on the facts established.

This approach is based on the premise that compliance can be demonstrated if there are no conceivable problems or if it can be proven that potential problems are not significant. As stated, there must be agreement that a sufficient range of system conditions has been analyzed. The significance of any identified problems must be clearly and adequately described; the degree of analysis required will depend on the problem. It may be possible to evaluate the significance of some apparently minor problems by simple means. Problems which appear to be of greater concern may require more


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substantial and rigorous analysis.


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APPENDIX "C"

DAMPING CRITERION

The purpose of the damping criterion is to assure small signal stability of the New England bulk

power supply system. System damping is characterized by the damping ratio, zeta ( ). The damping ratio provides an indication of the length of time an oscillation will take to dampen. The damping criterion specifies a minimum damping ratio of 0.03, which corresponds to a 1% settling time of one minute or less for all oscillations with a frequency of 0.4 Hz or higher. Conformance with the criterion may be demonstrated with the use of small signal eigenvalue analysis to explicitly identify the damping ratio of all questionable oscillations.

Time domain analysis may also be utilized to determine acceptable system damping. Acceptable damping with time domain analysis requires running a transient stability simulation for sufficient time (up to 30 seconds) such that only a single mode of oscillation remains. A 53% reduction in the magnitude of the oscillation must then be observed over four periods of the oscillation, measuring from the point where only a single mode of oscillation remains in the simulation.

As an alternate method, the time domain response of system state quantities such as generator rotor angle, voltage, and interface transfers can be transformed into the frequency domain where the damping ratio can be calculated.

A sufficient number of system state quantities including rotor angle, voltage, and interface transfers should be analyzed to ensure that adequate system damping is observed.

Appendix 2-5

ISO New England

Planning Procedure No. 5-3

Guidelines for Conducting

and Evaluating Proposed

Plan Application Analyses

ISO New England Planning Procedure PP5-3: Guidelines For Conducting And Evaluating Proposed Plan Application Analyses

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ISO NEW ENGLAND PLANNING PROCEDURE 5-3

GUIDELINES FOR

CONDUCTING AND EVALUATING PROPOSED PLAN

APPLICATION ANALYSES

EFFECTIVE DATE: March 1, 2013


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GUIDELINES FOR CONDUCTING AND EVALUATING PROPOSED PLAN APPLICATION

ANALYSES

TABLE OF CONTENTS

Section Title Page

1.0 Introduction 11.1 Section I.3.9 Requirement 11.2 Using the Guidelines 1

2.0 Generating Units - Power Supply Concerns 2

3.0 Generating Units and Transmission Facilities- Bulk Power System Performance 2 3.1 Classification and Reporting of Analyses 2 3.2 Evaluation 63.3 Steady State Analysis 73.4 Other Testing 103.5 Stability Analysis 12

4.0 Protection Systems and Dynamic Control Systems 15

5.0 Definitions 16

Attachments

1 Items to Determine Level of Analysis (Table 1) 19

2 Level of Analysis Flow Chart (Figure 1) 20


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GUIDELINES FOR CONDUCTING AND EVALUATING PROPOSED PLAN APPLICATION

ANALYSES

1. Introduction

1.1 Section I.3.9 Requirement

Under Section I.3.9 of the Tariff, each Governance Participant must submit plans for additions to or changes in facilities that might "have a significant effect on the stability, reliability or operating characteristics of the Transmission Owner’s transmission system, the transmission

facilities of another Transmission Owner or the system of a Market Participant". Section 1 of ISO New England Planning Procedure PP5-1, “Procedure for Review of Governance Participant’s Proposed Plans”, describes the process and contains the procedures to be followed

in complying with the stated requirement. Section 1 also summarizes the information recommended or required for a formal submittal of a Proposed Plan Application. PP5-1 also contains the Proposed Plan Application forms and description of the information required.

This PP5-3 guideline is intended to be an aid to both the Governance Participant filing a Proposed Plan Application and the committees who evaluate the effects of proposed additions or changes. To allow opportunity for an orderly and timely review, applicants are strongly recommended to supply supporting information in accordance with these guidelines with lead times appropriate for anticipated “Level of Analysis Required” (see PP5-3, Section 3.1.2). It is further recommended that the Governance Participant confirm with the ISO and, if applicable, the Task Forces that information is complete prior to formal submittal of its Proposed Plan Application.

1.2 Using the Guidelines

These guidelines are structured according to the facility for which an application is required and by concerns specific to that type of facility. Each section outlines the information to be provided and the measures used to evaluate the information in determining if the proposed facilities will or will not have a "significant adverse effect" on the stability, reliability or operating characteristics of the electric power system.

Generating unit operating characteristics and other power supply related concerns are addressed in Section 2.0 Generating Units – Power Supply Concerns. Since a generating unit can affect the performance of the integrated generation/transmission bulk power system, the guidelines of Section 3.0 also apply for generation Proposed Plan Applications.

Transmission facility additions and changes refer to transmission lines and substation equipment for which Proposed Plan Applications are required, including HVDC terminals and static VAR compensators and are addressed in Section 3.0 Generating Units and Transmission Facilities

– Bulk Power System Performance.

Guidelines for protection and control system changes requiring approval of Proposed Plan Applications, including Special Protection Systems (SPSs) and Dynamic Control Systems, are


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discussed in Section 4.0 Protection Systems and Dynamic Control Systems. A list of defined terms utilized in this guide is included in Section 5.0 Definitions.

2.0 Generating Units - Power Supply Concerns

Governance Participants filing a Proposed Plan Application shall provide all information requested on the generation Proposed Plan Application, which is Attachment 1 to PP5-1. Only complete applications will be accepted for review. New units are required to meet specific criteria, listed below. Non-compliance with the criteria below will be grounds for rejecting the Proposed Plan Application. A Proposed Plan Application should be rejected if a significant adverse impact on the existing electric system is identified. The Proposed Plan Application will not be accepted until it is modified to eliminate the identified negative impact.

a. Both physical and contractual operating characteristics of all units must be reported. During emergency conditions, including the entire spectrum of load levels from peak to light load, the most restrictive operating limitations, either physical or contractual will be used to determine the unit’s operation. Identify the normal and emergency operating

characteristics of the unit from a physical unit characteristic perspective. Also, identify the contractual operating characteristics, if different. Particular attention should be given to operating limits (high and low), minimum shut down times, minimum run times, and start up times.

If unable to complete the NX-12 form, provide a detailed description of the amount of dispatch control the ISO will have in determining the operation and/or output of the unit. Indicate when, and how frequently the unit can be reduced to its low limit and/or shut down during emergency conditions.

Provide information on any constraints due to waste to energy conversion, primary/secondary steam requirements, or any other physical constraints that determine operating flexibility.

b. If a new unit is 10 MW or larger, it must be equipped with a functioning turbine governor.

c. The settings for underfrequency relays must comply with NPCC guidelines and be approved by the host utility.

3.0 Generating Units and Transmission Facilities - Bulk Power System Performance

3.1 Classification and Reporting of Analyses

This section provides guidance on the bulk power system performance analyses required to support a generation or transmission Proposed Plan Application. The type of change/addition and its potential effects on the interconnected system determines the depth of analysis expected in support of a particular Proposed Plan Application. It defines the levels of analysis expected over the range of Proposed Plan Applications and guides the applicant to that level best suited to


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the particular application at hand. General guidance on performance measures and expectations is provided in Subsection 2.0. Subsections 3.0, 4.0, and 5.0 provide specific details on expected studies.

3.1.1 Areas of investigation

A Proposed Plan Application analysis is expected to demonstrate the impact of the change/addition on system performance in two transmission-related areas: area transmission requirements and transmission transfer capabilities. As applicable, the analysis should demonstrate the impact on the power supply concerns detailed in Section 2.0 above.

Impact on area transmission requirements is investigated by showing that the resultant system (after the change/addition) has sufficient transmission capacity to serve the area loads under the conditions noted below and in Planning Procedure 3 “Reliability

Standards for the New England Area Bulk Power System” (the “Reliability

Standards”)(Section 3). Impact on inter-Area and intra-Area transmission transfer capability should be demonstrated for the conditions noted below and in the Reliability Standards (Section 4).

3.1.2 Level of analysis required

Based on factors such as the size of a generator and/or operating voltage level and connection of a transmission line (radial or networked), four levels of analysis are identified for supporting a particular Proposed Plan Application. Additional analyses may be requested by the Principal Committees, Task Forces, or individual Governance Participants. The levels are defined as follows:

Level 0: A Proposed Plan Application is not required

Level I: A Proposed Plan Application is required for information only; reporting of study results or analysis is not required

Level II: As appropriate, analyses based on testing such as load flow, short circuit, transient network analysis (TNA), etc. should address one or both of the following: - Area Transmission Steady State Assessment (Reference:

Reliability Standards, Sections 3.0 and 3.2) - Transfer Capability Assessment (Reference: Reliability

Standards, Sections 4.0, 4.1 and 4.2) Detailed descriptions will be found in Section 3.3 Steady State Analysis and Section 3.4 Other Testing.

Level III: As appropriate, the analyses should include Level II testing and should address one or more of the following:


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- Area Transmission Stability Assessment (Reference: Reliability Standards, Sections 3.0 and 3.1)

- Dynamic Transfer Capability Assessment (Reference: Reliability Standards, Sections 4.0, 4.1 and 4.2)

Detailed descriptions will be found in Section 3.3 Steady State Analysis Section 3.4 Other Testing, and Section 3.5 Stability Analysis.

PP5-1 defines items that may require Proposed Plan Applications. This list has been expanded and augmented with a flow chart to guide the Proposed Plan applicant to the appropriate minimum level of analysis consistent with the proposed addition or change. The expanded list of items, Table 1, and the Level of Analysis Flow Chart, Figure 1 are in Attachment 1 of this guideline.

The following steps will help guide the Proposed Plan applicant in determining the appropriate minimum level of analysis:

a. From Table 1, identify each proposed item that is to be added or changed. After the item is identified, and if appropriate, choose the class of voltage.

b. From column 3 of Table 1, read the appropriate minimum level of analysis or "See Figure 1"; i.e. Level of Analysis Flow Chart.

c. Follow the steps in the Level of Analysis Flow Chart to identify the appropriate minimum level of analysis.

If the proposed addition or change involves more than one pass through the list of items or flow chart, then the appropriate minimum level of analysis is the highest level identified.

In general, if the proposed addition or modification is not listed in Table 1, then no Proposed Plan Application is required; i.e. Level 0. If the proposed addition or modification is listed in Table 1 as requiring a Proposed Plan Application, but it does not affect other Governance Participants or neighboring Control Areas, then the application is required for information only; i.e. Level I.

For the more complex Level II analyses and those of Level III, the applicant is strongly urged to submit a single scope of work for review by both the Transmission and Stability Task Forces. This scope should include the items listed in Sections 3.1.3.1 and 3.1.3.2 below: a brief description of the facility changes and a description of the system representation to be used in the study, including all major assumptions regarding test conditions for load flow, dynamics and/or other studies. Periodic status reports to the respective Task Forces, summarizing testing and results to date, will assist in completing these complex analyses in a timely manner.

Based on past analyses, the expected amount of time generally needed from initial submission of study work to completion of review (and formal submittal of application) is as follows:


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Level I: No study work submitted Level II: 1 to 4 months, depending on complexity Level III: 3 to 12 months, depending on complexity

3.1.3 Reporting

This section contains guidelines for the content of reports submitted in support of Proposed Plan Applications. Materials submitted with a Proposed Plan Application must be adequate to support the proposal. It is recognized that it may be necessary to conduct a Proposed Plan study using preliminary data describing transmission line and machine parameters. Using such data implies an obligation to provide more specific information at a later time.

3.1.3.1 Description of Proposed Facility(ies) Describe the proposed facilities including how the modified system will be operated and a brief reason for the proposal.

Provide a map showing geographical location, a one-line diagram of the affected portion of the power system, and a switching diagram including the proposed facility and nearby facilities.

3.1.3.2 Description of System Representation Used in Studies For Level II and III analyses, as appropriate, provide:

3.1.3.2.1 Load flow Studies - Year, season, load level, base interchanges, list of future facilities represented, source of representation and pertinent test assumptions as described in Section 3.1.1, Conditions to be Tested (below).

3.1.3.2.2 Dynamics Studies - Source of machine data and other dynamics modeling and data, load model, special protection systems and other pertinent assumptions as described in Section 3.5.1, Conditions to be Tested (below).

3.1.3.2.3 Other Testing (transient network analysis, short circuit analysis, etc.) - Source of representation, including machine data and network equivalents. Other pertinent test assumptions should be noted where they differ from those described above for load flow studies.

3.1.3.2.4 Analysis and Reporting of Results For Level II and III analyses, as appropriate, provide a description of the baseline performance without the modification, a summary of the tests conducted with the modification and the resulting system performance in terms of its conformance to the Reliability Standards. Information of interest is discussed below in Section 3.3.1.2, 3.3.1.3 and 3.3.1.4 and Section 3.3.2 for Steady State Analyses, Section 3.5.1.2, 3.5.1.3 and 3.5.1.4 and Section 3.5.2 for Stability Analyses and Section 3.4.0 for Other Testing. This information should be sufficient to clearly demonstrate system performance without including exhaustive details of all results.


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3.1.3.2.5 Conclusions Present arguments for approval of application consistent with Section 3.3.3 for steady state analyses, Section 3.5.3 for stability analyses and Section 3.4 for other testing.

3.2 Evaluation

The Reliability Committee and its Task Forces will evaluate a number of aspects of the studies submitted in support of a Proposed Plan Application. The evaluation of the acceptability of the proposed changes or additions begins with review of the adequacy and acceptability of testing and test results. The results of tests performed and submitted in support of proposed additions or changes in facilities should clearly demonstrate compliance with the desired level of reliability as outlined in the Reliability Standards. The level of performance expected is intended to: 1) assure the reliability of the overall interconnected system and minimize the risk of widespread cascading outages due to overloads, instability or voltage collapse; and 2) demonstrate that the Nuclear Plant Interface Requirements (NPIRs) as documented in Master/Local Control Center Procedure No. 1 - Nuclear Plant Transmission Operations, Attachments A through D, are met. Sections 3, 4 and 5 of the Reliability Standards establish a minimum design criteria by outlining representative contingency tests and assessment.

Demonstration of acceptable system performance under the enumerated conditions and assumptions should be considered the minimum level of compliance. Additional testing, evaluations or adjustments to assumptions may be deemed necessary to either assure the adequacy of system performance or to distinguish a sensitivity to one particular condition from a more general system weakness. The final conclusions and recommendations should be based on the informed engineering judgment of the Reliability Committee and its Task Forces with the objective of assuring that proposed changes or additions in facilities will not have a significant adverse impact on the stability, reliability or operating characteristics of the interconnected bulk power system.

Generally, if results of testing indicate that the system is not sufficient to accommodate the proposed changes or additions in facilities, system reinforcements or other mitigating measures will be required. These reinforcements or mitigating measures should fully alleviate all adverse impacts which were introduced by the proposed change or addition.

Occasionally, testing may identify weaknesses in the system prior to introduction of the proposed change or addition in facilities. The degree to which the proposed change or addition further degrades the stability, reliability or operating characteristics of the system will be of primary concern. Where no significant impact is identified, it may be possible to conclude that the proposed change or addition does not degrade system reliability. This judgment should take into account the frequency, duration, magnitude and consequences of any conditions where reliability violations occur both prior to and subsequent to the proposed changes or additions.


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3.3 Steady State Analysis

It is the responsibility of the Governance Participant submitting the Proposed Plan Application to identify the most severe conditions that can reasonably be expected to exist. It must be demonstrated that under such conditions, the proposed additions or changes will not have any significant adverse impact upon the reliability or operating characteristics of the bulk power system; otherwise, the Governance Participant must propose system modifications, protection systems and/or operating restrictions on the proposed addition which will eliminate such adverse impact. Studies demonstrating steady state performance must then simulate normal conditions as well as conditions that stress the system beyond "typical" combinations of load level, generation dispatch and power transfers. Since it is necessary for supporting studies to reflect conditions expected to exist at the time of a future system modification, such conditions might include other future facilities with or without Proposed Plan approval that may be installed by about the same point in the future. Upon request, the Transmission Task Force will assist the Governance Participant in identifying reasonably stressed conditions for testing.

3.3.1 Conditions to be Tested

3.3.1.1 Assumptions a. Selection of Year or Year(s) to Model - The initial year chosen for study is

normally that of the anticipated system modification. However, the following matters may need to be considered:

- other facilities coming on-line in the same time period; and - other influences in the area, such as changes in contracts.

The Reliability Committee and its Task Forces will provide guidance in selecting the year(s) and related conditions to be studied.

b. Source of Base Case - The base case should have its origin from the ISO’s

library of cases, with changes or modifications as provided by the Stability and/or Transmission Task Forces.

c. Other Proposed Facilities - Inclusion of planned or proposed facilities in a study is subject to the status of other Proposed Plan Applications, the System Impact Study queue, and the Subordinate Proposed Plan Application Policy. Consequently each proposed or planned facility must be individually identified in the scope of the study with the aid of the Task Forces and the ISO prior to the start of the study. Having identified the planned or proposed facilities to include in the study, the study can be done with either or both of the following approaches: 1) the facility assumed installed in the base condition with tests determining the sensitivity of system response without the facility, or 2) as not installed in the base condition, but with sensitivity tests conducted with the facility included. The Governance Participant conducting the analysis should judge which approach is appropriate for the evaluation.


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March 1, 2013 8

d. Modeling Devices - Models for devices of particular concern, such as HVdc terminals, are available from the ISO. It is the responsibility of the Proposed Plan applicant to properly represent these devices where appropriate.

e. Load Level - Disturbances should be studied at peak load levels since they usually promote more pronounced thermal and voltage response within the New England Control Area than at other load levels. However, other load levels may be of interest in a particular analysis. This should be determined and, as appropriate, additional studies should be conducted.

f. Generation Dispatch - Testing should not be restricted to only typical dispatch; rather the dispatch(es) should be developed to reasonably test the proposed additions or changes. For example, for an export condition within the study area, the dispatch should model the maximum number of fully loaded generators expected to be in-service unless constrained by the transfer limits of an interface. For an import condition, unit outages simulated within the study area should reflect must-run, spinning reserve and minimum reactive support requirements of system operation. All dispatches are subject to review by the Task Forces.

g. Modeling of Transfer Conditions - Generally, intra-Area transfers will be simulated at or near their established limits (in the direction to produce "worst cases" results) and sensitivities to inter-Area transfers will be determined as appropriate. The rationale for maintaining these transfer levels before and after the addition of the proposed facility should be discussed. The ISO has developed and maintains a list of intra-Area interfaces used in operations.

3.3.1.2 Baseline Performance Using the supplied and/or modified library case, testing should be conducted to determine pre-addition system performance. This testing will: - validate the representation of the case used; and - establish a baseline of performance from which the direct impact of the proposed

modification can be demonstrated.

3.3.1.3 Contingency Selection The applicant should develop a specific list of contingencies that comply with each section of the Reliability Standards which applies, including extreme contingencies. Additional contingency tests, consistent with those standards may be requested by the Task Forces.

3.3.1.4 Tests With A Line Out Of Service Applications for major changes in transmission or generation facilities should include tests of system performance with selected lines out of service assuming that the area resources and power flows are adjusted between outages. These tests should identify and evaluate potential constraints to future system operation.


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3.3.2 Results Reporting

The applicant should provide sufficient details and information to clearly demonstrate system performance under both normal and stressed conditions. This would include:

3.3.2.1 Summary of load flow tests conducted and their results, with and without the proposed modifications, showing at a minimum the following information: - Load level, generation dispatch and pertinent major interface loadings (both

inter-Area and intra-Area); - Contingencies tested; - A single summary of lines loaded to 95% or more of their applicable rating; - Bus voltages outside a range of .95 to 1.05 p.u.; - Interactions with existing special protection systems; and - Observed results and related comments, including impact on NPIRs, as

appropriate.

3.3.2.2 Summary of results from any other pertinent testing performed such as the analyses described in Section 3.4, Other Testing.

3.3.2.3 One line diagrams showing flows and voltages with and without the proposed changes or additions for the following conditions: - Normal generation dispatch conditions with all lines in service; - Stressed generation dispatch conditions with all lines in service; and - All significant contingency conditions for both normal and stressed generation

dispatch cases.

3.3.2.4 Clear, concise narrative interpreting the above results and leading to the conclusion that installation of the subject facility(ies) will have no significant adverse effect on the reliability of the bulk power system as specified in Section I.3.9 of the Tariff. Also, any actions required to mitigate adverse system behavior associated with the proposed facility should be fully documented and explained.

3.3.3 Steady State Evaluations

Evaluations of steady state analyses submitted in support of Proposed Plan Applications will be based on the considerations and expectations described in Section 3.2, Evaluation. Additionally, the two aspects noted below will be of primary concern to the Reliability Committee and its Task Forces during their review.

3.3.3.1 Was the analysis conducted according to generally accepted practice? - Were assumptions and test conditions as outlined in Section 3.3.1? - Were tools and procedures applied properly and were they sufficient to provide a

complete analysis?

3.3.3.2 Do results of the analysis support the conclusion that the change(s) will: 1) result in no significant adverse effect on the reliability of the bulk power system; and 2)


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meet the NPIRs? If the analyses indicated any problem areas, how were they resolved?

In particular, the Transmission Task Force will review each analysis to ensure that all of the applicable conditions specified in the Reliability Standards are satisfied. The recommendation of the Transmission Task Force to the Reliability Committee will be based on the applicant having satisfied the applicable conditions required in the Reliability Standards.

3.4 Other Testing

Studies demonstrating system performance may occasionally require other testing, in addition to the load flow testing described in Section 3.3 above, to adequately assess the effects of proposed facility changes or additions on the reliability and operating characteristics of the bulk power system. The need for this other testing, such as transient network analysis, short-circuit analysis, and/or reactive power and voltage (Q/V) analysis, depends on the specific project involved. These three analyses, while dealing with dynamic phenomena, do not involve the detailed time simulation of a stability analysis; rather, each is a single snapshot of the ability of the power system to withstand events such as loss of components, short-circuits or unanticipated demand. It is the responsibility of the Governance Participant submitting the Proposed Plan Application to consider the need for these tests when preparing the Proposed Plan supporting analysis and include them as appropriate. The Reliability Committee, its Task Forces, or individual Governance Participants may request any one or more of these other tests or in the course of their review of the supporting analysis may request other testing not described in this guideline. Each Governance Participant that is a Nuclear Plant Generator Operator is expected to have its Reliability Committee representative review the reporting of analysis of a proposed plan and request any additional analysis to address meeting any applicable NPIRs.

3.4.1 Transient Network Analysis (TNA)

Transient Network Analysis studies are typically performed as part of the detailed design engineering of a project where there may be concern for transient or temporary overvoltages, voltage flicker, arrester capabilities or insulation coordination. Sudden changes in circuit conditions, such as switching operations, lightning strikes, sudden loss of load or inrush currents (e.g., from a cable, capacitor bank or transformer energization or de-energization) can lead to this type of overvoltage, whose effects are usually confined to an area localized to the switching station. As such, those projects where this would be a concern typically include a TNA study as part of the design process but do not usually include the TNA results as part of the Proposed Plan study.

In those situations where a neighboring Governance Participant is close enough to be affected (typically no more than two busses away from the switching location), the applicant and the other Governance Participant should engage in a joint review of the base case models to be used in the TNA study. Then, in the Proposed Plan study, the applicant should provide sufficient details and information to clearly demonstrate system performance under both normal and stressed conditions. This would normally include a


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summary of all TNA tests conducted and their results, generally in the form of peak overvoltages or percent voltage change at selected busses and a clear, concise narrative interpreting these results and leading to the conclusion that installation of the subject facility(ies) will have no significant effect on the reliability of the bulk power system as specified in Section I.3.9 of the Tariff. Any actions required to mitigate adverse system behavior associated with the proposed change or addition should be fully documented and explained.

3.4.2 Short-Circuit Analysis

Projects such as the addition of a generator or a transmission element can have a significant impact on the short-circuit duty at substations in the vicinity of the proposed facilities. For those projects where this would be a concern, the applicant should include an analysis of the incremental effects of the project on short-circuit interrupting duty in the vicinity of the proposed change or addition. In those situations where a neighboring Governance Participant is close enough to be significantly affected, the applicant and the other Governance Participant(s) should engage in a joint review of the capabilities of the equipment in the area prior to submission of the Proposed Plan analysis.

In the Proposed Plan study, the applicant should provide sufficient details and information to clearly demonstrate system performance with respect to short-circuits. This would normally include a summary of the short-circuit tests conducted and their results, generally in the form of duty at selected busses, and a clear, concise narrative interpreting these results and leading to the conclusion that installation of the subject facility(ies) will have no significant effect on the reliability of the bulk power system as specified in Section I.3.9 of the Tariff. Any actions required to mitigate adverse system behavior associated with the proposed change or addition should be fully documented and explained.

3.4.3 Q/V Analysis

Voltage and reactive power performance of the bulk power system varies according to the load, transmission and generation in each area. It cannot be predicted system-wide by a single type of facility change or addition. Rather, the impact on the bulk system of a particular change or addition is evidenced by a high sensitivity of voltage at key busses in the system to changes in load, circuit conditions, or reactive compensation. For those projects where this would be a concern, the applicant should include an analysis of the effects of the proposed change or addition on the reactive power and voltage performance of the bulk power system.

In the Proposed Plan study, the applicant should provide sufficient details and information to clearly demonstrate reactive power support and voltage performance under both normal and stressed conditions. This would normally include a summary of all tests conducted and their results, generally in the form of Q/V (or P/V) curves or another measure of reactive power and voltage margin in the affected area and a clear, concise narrative interpreting these results and leading to the conclusion that installation of the


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subject facility(ies) will have no significant effect on the reliability of the bulk power system as specified in Section I.3.9 of the Tariff. Any actions required to mitigate adverse system behavior associated with the proposed change or addition should be fully documented and explained.

3.5 Stability Analysis

It is the responsibility of the Governance Participant submitting a Proposed Plan Application to identify the most severe conditions that can reasonably be expected to exist. It must be demonstrated that under such conditions, the proposed additions or changes will not have any significant adverse impact upon the stability, reliability or operating characteristics of the bulk power system; otherwise, the Governance Participant must propose system modifications, protection systems and/or operating restrictions which will eliminate such adverse impact. Studies demonstrating dynamic performance must then simulate conditions that stress the system beyond "typical" combinations of load level, generation dispatch and power transfers. Further, while the dynamic response of an individual proposed generating unit is of interest, the response of the bulk power system is of primary importance. Since it is necessary for supporting studies to reflect conditions expected to exist at the time of a future system modification, such conditions might include other future facilities with or without Proposed Plan approval that may be installed by about the same point in the future. Upon request, the Stability Task Force will assist the Governance Participant in identifying reasonably stressed conditions for testing.

3.5.1 Conditions to be Tested

3.5.1.1 Assumptions a. Selection of Year(s) to Model - The initial year chosen for study is normally that

of the anticipated system modification. However, the following matters may need to be considered:

- other facilities coming on-line in the same time period; and - other influences in the area, such as changes in contracts.

The Reliability Committee and its Task Forces will provide guidance in selecting the year and related conditions to be studied.

b. Source of Base Case(s) - The base case(s) should have its origin from the ISO’s

library of cases, with changes or modifications as provided by the Stability and/or Transmission Task Forces.

c. Other Proposed Facilities - Inclusion of planned or proposed facilities in a study is subject to the status of other Proposed Plan Applications, the System Impact Study queue, and the Subordinate Proposed Plan Application Policy. Consequently each proposed or planned facility must be individually identified in the scope of the study with the aid of the Task Forces and the ISO prior to the start of the study. Having identified the planned or proposed facilities to include in the study, the study can be done with either or both of the following approaches: 1) the facility assumed installed in the base condition with tests


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March 1, 2013 13

determining the sensitivity of system response without the facility, or 2) the facility not installed in the base condition, but with sensitivity tests conducted with the facility included. The Governance Participant conducting the analysis should judge which approach is appropriate for the evaluation.

d. Modeling Devices - Models for devices of particular concern, such as HVdc terminals, are available from the ISO. It is the responsibility of the Proposed Plan applicant to properly represent these devices where appropriate.

e. Load Level - Disturbances should be studied at light load levels since they usually promote more pronounced dynamic response within the New England Control Area than at other load levels. However, other load levels may be of interest in a particular analysis. This should be determined and, as appropriate, additional studies should be conducted.

f. Generation Dispatch - Testing should not be restricted to only typical dispatch; rather the dispatch(es) should be developed to test the proposed modification under stressed conditions. For example, an export condition would be tested by modeling the maximum number of fully loaded generators expected to be in-service in the exporting area unless constrained by the transfer limits of an interface. This will demonstrate if groups of machines in such areas could accelerate and lose synchronism with the bulk power system. At the same time, a "reasonable" number of units should be dispatched within the importing areas. These units need not be fully dispatched but they should reflect must-run, spinning reserve and minimum reactive support requirements of system operation. All dispatches are subject to review by the Task Forces.

g. Modeling of Transfer Conditions - Transfer levels should be selected to produce accentuated dynamic response. Generally, intra-Area transfers will be simulated at or near their established limits (in the direction to produce "worst cases" results) and sensitivities to inter-Area transfers will be determined as appropriate. The rationale for choosing particular interface loadings before and after a modification due to a proposed facility should be discussed. The ISO has developed and maintains a list of interfaces used in operations.

3.5.1.2 Baseline Performance Using the supplied and/or modified library case, testing should be conducted to validate the representation of the case and dynamics modeling used. If contingency testing indicates a problem, pre-addition testing will be needed to establish a baseline of performance from which the direct impact of the proposed modification can be demonstrated.

3.5.1.3 Contingency Selection The applicant should develop a specific list of contingencies that comply with each section of the Reliability Standards which applies, including extreme contingencies. Additional contingency tests, consistent with those standards may be requested by


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March 1, 2013 14

the Task Forces. To assist in understanding the selection of contingencies, the applicant should provide a general description of the relay systems at 115 kV stations and above in the vicinity of the proposed change.

3.5.1.4 Tests With A Line Out Of Service Applications for major changes in transmission or generation facilities should include tests of system performance with selected lines out of service assuming that the area resources and power flows are adjusted between outages. These tests should identify and evaluate potential constraints to future system operation.

3.5.2 Results Reporting

The applicant should provide sufficient details and information to clearly demonstrate system performance under both normal and stressed conditions. This would include:

3.5.2.1 Summary of dynamic tests conducted and their results, with and without the proposed modification, showing at a minimum the following information:

- Load level, generation dispatch and major interface loadings; - Contingencies tested, with assumed sequence of events and associated times; - Interactions with existing special protection systems; and - Observed results and related comments as appropriate.

3.5.2.2 One line diagrams showing at a minimum flows and voltages with and without the proposed modifications for the conditions tested, including:

- Normal generation dispatch conditions with all lines in service; - Stressed generation dispatch conditions with all lines in service; and

- Conditions tested with lines out of service.

3.5.2.3 Plots demonstrating that stability is maintained in the area of the modification, in other areas of New England and in neighboring systems. Enough information must be provided to demonstrate no other dynamics problems are encountered, such as unacceptable voltage or frequency excursions, undamped oscillations, control system problems, etc.

3.5.2.4 Clear, concise narrative interpreting the above results and leading to the conclusion that installation of the subject facility(ies) will have no significant adverse effect on the reliability of the bulk power system as specified in Section I.3.9 of the Tariff. Also, any actions required to mitigate adverse system behavior associated with the proposed facility should be fully documented and explained.

3.5.3 Stability Evaluations

Evaluations of stability analyses submitted in support of Proposed Plan Applications will be based on the considerations and expectations described in Section 3.2. Additionally, the two aspects noted below will be of primary concern to the Reliability Committee and its Task Forces during their review.


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3.5.3.1 Was analysis conducted according to generally accepted practice? - Were assumptions and test conditions as outlined in Section 3.5.1? - Were tools and procedures applied properly and were they sufficient to provide a

complete analysis?

3.5.3.2 Do results of analysis support conclusion that the change(s) will: 1) result in no significant adverse effect on the reliability of the bulk power system; and 2) meet the NPIRs? If the analyses indicated any problem areas, how were they resolved?

The Stability Task Force will review each analysis to ensure that all of the applicable conditions in the Reliability Standards are satisfied. The recommendation of the Stability Task Force to the Reliability Committee will be based on the applicant having satisfied the applicable conditions required in the Reliability Standards.

4.0 Protection Systems and Dynamic Control Systems

Sections 2.6 and 3.3 of PP5-1 indicate the protection system additions/changes for which Proposed Plan Applications are required. These fall into two categories: fault clearing and special protection systems (SPSs).

Proposed Plan Applications for additions/changes in protection systems designed for fault clearing should include assurance that: - the protection system is designed in accordance with the NPCC Bulk Power System Protection

Criteria; - the associated fault clearing time will not degrade system reliability performance; and - the NPIRs will be met. A Level III analysis, as described in Section 3.0, may be needed to demonstrate the effects of increased fault clearing times.

Applications for SPSs require analyses similar to that of a generation or transmission application and the guidelines of Section 3.0 apply. In addition to compliance with the Reliability Standards and NPCC Bulk Power System Protection Criteria, the following factors will be considered in evaluating an application for an SPS:- Is the SPS initiated by a normal contingency or an extreme contingency? - How many events trigger the SPS? Are the triggers local or remote? - What are the monitoring requirements? - How selective are the triggers (i.e., monitor system parameters vs. breaker contact)? - Is the response local or remote? - How many inputs, decisions and actions are involved? - What is potential for interaction with other SPSs? - Is the SPS required to control dynamic, voltage or thermal response? - What actions are taken (load rejection, generation rejection, opening of a transmission line)? - What is the probability that the SPS will be required to operate? - What are the implications of inadvertent operation or misoperation (local vs. widespread

effects)?


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- Operational considerations (operator's view of requirements and constraints). - Anticipated life of the SPS - is it meant to be temporary or permanent? - What operating options are available if planning assumptions do not materialize? - What are modeling requirements; when will they be provided? - Economic tradeoffs with other alternatives. - Will the NPIRs be met?

Dynamic control systems such as voltage regulator/exciter systems, power system stabilizers and governors on generators can have a significant effect on the stability, reliability or operating characteristics of the bulk power system. Such dynamic control systems and their attendant effects are to be included in the analyses conducted in support of new generator additions. Effects of changes in dynamic control systems should normally be determined in the course of design studies and a Proposed Plan Application should be submitted if such a change could have a significant effect on the performance of the bulk power system. In such cases, a stability analysis may be requested as outlined in Section 3.5.

5.0 Definitions

If appropriate definitions were available from the Reliability Standards they are used in this section. The source of the definition is shown in parenthesis. Following these existing definitions, additional comments are included to assist the reader in interpreting them.

For those cases where no formal definition exists, the one used here is based on a review of existing ISO New England and NPCC documents.

5.1 Applicable Emergency Limit

Transmission circuit loading limits have been established for use under both normal and emergency conditions. In general, normal ratings are used for "All lines in" conditions. Under emergency conditions, long term emergency ratings (LTE) may be used for up to one daily load cycle assuming no contingency would cause the loading to go above LTE. Short term emergency ratings (STE) may be used following a system disturbance for up to fifteen minutes. The STE ratings may only be used in situations where the component loading can be reduced below the LTE ratings within fifteen minutes by operator corrective action.

In actual system operations, under emergency conditions, drastic action limits (DAL) may be used where preplanned immediate post contingency actions can reduce loadings below LTE within five minutes. These DAL limits are only used as a last resort during actual system operations. They should not be used in testing the system adequacy in the Proposed Plan Application studies.

Emergency voltage limits have also been established for system operation under emergency conditions. These limits recognize that voltages should not drop below those voltages required for acceptable system stability performance, acceptable operation of generating auxiliaries, acceptable operation of other electrical equipment, operation well above the knee of the voltage


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curve, and for meeting the NPIRs. Also, the voltage should not rise above the maximum rating of electrical equipment.

5.2 Reasonably Stressed Conditions

Reasonably stressed conditions are those severe load and generation system conditions which have a reasonable probability of actually occurring. Generally both import and export conditions should be addressed. The purpose of testing these conditions is to identify potential weaknesses in the system and not to test the worst imaginable extreme.

5.3 Operating Characteristics

The actual operation of the interconnected system requires that each component of the system must be capable of operating in such a manner as not to adversely affect the system operation. Any additions to the system must be able to operate in such a manner so as not to degrade the present operating flexibility of the system. Operating Characteristics include, but are not limited to: dispatchability, including constraints on economic dispatch, voltage control, flicker, harmonics, black start capability, environmental limitations, maintenance scheduling, TV and radio interference, audible noise, and under frequency load shedding.

5.4 Significant Adverse Effect (Section I.3.9 of the Tariff)

The existing system is designed and operated to meet specific criteria as contained in the various documents referenced through this guideline. After the addition it must be demonstrated that there has been no significant degradation in the level of system performance.

5.5 Normal Dispatch Conditions

Normal Dispatch Conditions refers to the economic dispatch of all New England Control Area generation with appropriate allowance for scheduled maintenance and forced outages. Applicable firm contractual transfers, both purchases and sales, should be included.

5.6 Special Protection Systems (Reliability Standards, Appendix A)

"A Special Protection System (SPS) is defined as a protection system designed to detect abnormal system conditions, and take corrective action other than the isolation of faulted elements. Such action may include changes in load, resource, or system configuration to maintain system stability, acceptable voltages or power flows. Automatic under frequency load shedding, as defined in NPCC Emergency Operation Criteria A-3, is not considered an SPS."


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Document History1

Rev. 0 Rec.: RTPC – 1/18/00; App.: PC – 2/4/00 Rev. 1 Rec.: RC – 11/14/00; App.: PC 12/1/00 Rev. 2 Eff.: 2/1/05 Rev. 3 Rec. RC – 2/26/10; Rec.: PC 3/05/10; Eff.: 3/05/10 Rev. 4 Rec. RC – 2/14/13; Rec.: PC 3/01/13; Eff.: 3/01/13



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Attachment 1 ISO New England Planning Procedure 5-3

TABLE 1

ITEMS TO DETERMINE LEVEL OF ANALYSIS

Item No. Description Level of Analysis

1. PTF constructed or rebuilt Class A - 230kV and above See Figure 1

2. Non-PTF Transformers or PTF Transformers

Class A - 345kV/230kV to 69kV and above See Figure 1 Class B - 345kV/230kV to below 69kV See Figure 1

3. PTF constructed or rebuilt Transmission Lines Class B - Below 230kV to 69kV See Figure 1

4. PTF to PTF Transformers or Non-PTF Transformers Class B - 115kV to below 69kV See Figure 1

5. Non-PTF 69kV and above Class A - 230kV and above See Figure 1 Class B - Below 230kV to 69kV See Figure 1

6. Generation addition or rating change of 5MW or greater or Generator reactive rating change of (+/-) 5 MVAR or greater See Figure 1

7. Generation addition or rating change of less than 5MW and Reactive rating change of less than (+/-) 5 MVAR Addition of a new unit (Notify ISO-NE) Level 0 Proposed Plan Application (See Figure 1) Modification or change in output rating of an existing unit No action required

8. Outside Pool Purchase/Sales Outside the Scope of Proposed Plan Applications Procedures

9. Interconnections operating at 69 kV or above with Non-Governance Participants LEVEL III

10. Protection Systems - See Planning Procedure No. 5 Section 3.3 & Reliability Standard Appendix A #14

Is the System a Special Protection System (SPS)? YES - LEVEL III NO - To Be Determined By Appropriate Task Force

11. Other Elements - See Reliability Standard Appendix A #6 Shunt Device LEVEL II HVDC LEVEL III Series Compensation LEVEL III Control Devices To Be Determined by Appropriate Task Force Circuit Breakers To Be Determined by Appropriate Task Force All Others To Be Determined by Appropriate Task Force


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Attachment 2 ISO New England Planning Procedure 5-3

FIGURE 1

LEVEL OF ANALYSIS FLOW CHART

(Diagram applies to Items 1-8)

Appendix 2-6

ISO New England

Planning Procedure No. 5-6

Scope of Study for System

Impact Studies under the

Generation Interconnection

Procedures

ISO New England Planning Procedure PP5-6: Scope of Study for System Impact Studies under the Generation


August 10, 2010 1

ISO NEW ENGLAND PLANNING PROCEDURE NO. 5-6

SCOPE OF STUDY FOR SYSTEM IMPACT STUDIES

UNDER THE GENERATION INTERCONNECTION

PROCEDURES

EFFECTIVE DATE: August 10, 2010

REFERENCES: ISO New England Transmission, Markets and Services Tariff (the “Tariff”)

ISO New England Planning Procedure 3 (PP3): Reliability Standards for the New England Area Bulk Power Supply System

ISO New England Planning Procedure 5-1 (PP5-1): Procedure for Review of Governance Participant’s Proposed Plans

ISO New England Planning Procedure 5-3 (PP5-3): Guidelines For Conducting And Evaluating Proposed Plan Application Analyses

ISO New England Planning Procedure 10 (PP10): Planning Procedure to Support the Forward Capacity Market



August 10, 2010 2

Scope of Study for System Impact Studies

Under the

Generator Interconnection Procedures

Background

The objective of this document is to provide guidance which ensures that the Network CapabilityInterconnection Standard (“NCIS”) is consistently applied in defining the scope and study assumptions for System Impact Studies.

NCIS describes the minimum characteristics required to 1) interconnect a proposed new Resource1 in the New England Control Area or 2) materially change and increase the capacity of an existing Resource. Additional information on procedures is found in Planning Procedures PP5-1 and PP5-3.

NCIS is defined in Schedules 22 (“LGIP”) and 23 (“SGIP”) of Section II of the ISO New England Transmission, Markets and Services Tariff (the “Tariff”) and “shall mean the minimum criteria required to permit the Interconnection Customer to interconnect in a manner that avoids any significant adverse effect on the reliability, stability, and operability of the New England Transmission System, including protecting against the degradation of transfer capability for interfaces affected by the Generating Facility.”

The objective of this document is also to provide guidance which ensures that the scope and study assumptions for preliminary analyses under the Capacity Capability Interconnection Standard (“CCIS”) are consistently applied.

System Impact Studies that follow the guidance provided by this document will typically satisfy the expectations of the Reliability Committee and the ISO; however, that does not preclude the possibility that some results may suggest the need for additional studies.

Network Capability Interconnection Standard Scope of Study

1. Identify the minimum required upgrades to meet all of the following requirements:

(a) Satisfy Sections 3.1, 3.2, 4, and 5 of ISO New England Planning Procedure 3:“Reliability Standards for the New England Area Bulk Power Supply System” (the “Reliability Standards”) on a regional (i.e. New England Control Area) and sub-regional basis, subject to the conditions analyzed.

(b) As a result of the addition of the proposed new Resource, the maximum collective change in the amount by which other Resources must be redispatched2 to meet the

1 For the purposes of this document, a Resource may be a generator or an import from another Control Area; redispatch of imports refers to rescheduling.2 Unless otherwise noted, the terms “dispatch” or “redispatch” in this document refers to generation modeling and



August 10, 2010 3

Reliability Standards, does not exceed the capacity of the new Resource, as measured by its intended high limit. If the request for interconnection involves multiple generating units at a plant and the applicant for interconnection controls all the existing generating units at that plant, the applicant for interconnection shall specify the desired maximum output for the plant and the design of the interconnection shall be based on this specified maximum output.

(c) The proposed new Resource does not diminish the transfer capability across any transmission line or relevant interface below the level of achievable transfers during reasonably stressed conditions3 and does not diminish the reliability or operating characteristics of the New England Area bulk power supply system and its component systems. For a proposed new Resource in an exporting area, an increase in the transfer capability out of the exporting area is not required to meet this interconnection standard.

(d) The proposed new Resource does not diminish the transfer capability across any transmission line or relevant interface below the level of possible imports during reasonably stressed conditions and does not diminish the reliability or operating characteristics of the New England Area bulk power supply system and its component systems.

(e) The addition of the proposed new Resource does not create a significant adverse effect on the ISO’s ability to reliably operate and maintain the system.

2. Conduct the following analyses:

- Steady state- Short circuit- Stability

3. Conditions for Analyses

A. Steady State1. Steady State analyses will demonstrate compliance with applicable voltage and

thermal loading criteria. 2. These studies should consider a Resource dispatch such that it stresses power flows

across applicable transmission lines or interfaces. A stressed line or interface should, to the extent reasonable, be at or near their ratings or transfer limits. A reasonable condition when power flows may not be at or near their transfer limits would exist when the maximum number of fully loaded Resources that may reasonably be expected to be in service for the expected system conditions does not result in stressed power flows.

3. When studying a new Resource, any other Resource may be redispatched subject to the following:

associated changes relative to planning assumptions, not actual operations.3 “reasonably stressed conditions” refers to conditions described in Section 3 “Conditions for Analyses”



August 10, 2010 4

a) Resources that continue to be required for system reliability4 cannot be redispatched,

b) Redispatched Resources and the new Resource can be practicably monitored and observed for purposes of system operation and unit commitment, and

c) If the most limiting transmission constraints occur on sub-transmission or lower voltage (less than 100 kV) facilities, then generation redispatch is not acceptable.

4. No Resource(s) can be assumed as Must Run as a condition for acceptable operation of the new Resource. If an existing Resource is considered Must Run prior to placing the new Resource in service, the existing Resource may continue to be modeled as Must Run, but the Must Run requirement of this Resource should not be increased. Studies must examine relevant stressed existing Resource outage conditions in addition to outages or reductions that have been considered as part of Resource redispatch.

5. No Resource(s) can be manually tripped to relieve any first contingency facility loading in excess of the more limiting of either the Short Term Emergency Ratings or any other applicable Transmission Owner-specific emergency ratings. Manually ramping down Resources to relieve first contingency overloads, can only be applied to the Resource(s) under study, provided that the Resource reduction is acceptable to the ISO.

6. Load levels and Resource capability to be evaluateda) Peak load: Load should be at 100% of the projected (90/10 forecast) peak

New England Control Area load for the year the Resource is projected to be in service and the Resource is at full capability.

b) Intermediate Load: Load should be at 75% of the projected (50/50 forecast) peak New England Control Area load for the year the Resource is projected to be in service and the Resource is at full capability.

c) Light Load: Unless the proposed unit can reach minimum load within 2 hours,a light load analysis should be performed at 45% of the projected (50/50forecast) peak New England Control Area load for the year the Resource is projected to be in service and the Resource is at minimum load. Other Resources that may be dispatched at 75% of the projected peak New England Control Area load should also be assumed to be running, but may also be at minimum load except for units which can reach minimum load within 2 hours. Units that can start up and reach minimum load within 2 hours may be off in the 45% case. Careful consideration of realistic operating conditions needs to be provided when simulating nuclear and hydro (run of river or ponding) facilities.

B. Short Circuit1. Short Circuit analyses will demonstrate that short circuit duties will not exceed

equipment capability.

4 “required for reliability” generally refers to resources which still are “must run”, typically for local area reliability.



August 10, 2010 5

2. All Resources that can physically and concurrently be in service, including deactivated reserve, should be modeled in service.

C. Stability1. Power Flows across applicable transmission lines or interfaces should be at the

most limiting of the existing stability or thermal transfer limits. In cases where the transfers are not stability limited, the transfers should be modeled at levels recommended by the Stability Task Force. (Note: All units modeled as in servicefor a particular stability case should be modeled at its full output which may result in total transfers greater than the existing transfer limit. More detail on modeling is available in Planning Procedure 5-3 (PP5-3): Guidelines For Conducting And Evaluating Proposed Plan Application Analyses).

2. Consider reasonable combinations of all Resources and devices that would be expected to have significant interactions.

3. Load levels to be evaluated at full capability of the new Resourcea) Light Load: Load should be at 45% of the projected (50/50 forecast) peak

New England Control Area load for the year the Resource is projected to be in service. (Note: The focus of the stability analyses should be performed at this load level. A number of combinations of Resources should be studied to ensure that stability is maintained for all reasonable conditions.)

b) Intermediate Load: Load should be at 75% of the projected (50/50forecast) peak New England Control Area load for the year the Resource is projected to be in service. (Note: Testing at 75% load level should be performed for line out conditions as required by the Stability Task Force. The line out conditions may be referred to as N-2 testing because it represents a condition where all but two facilities are in service. The Stability Task Force may require line out testing at higher load levels if higher transfers can be achieved across critical interfaces.)

c) Peak load: Load should be at 100% of the projected (90/10 forecast) peak New England Control Area load for the year the Resource is projected to be in service. (Note: The emphasis of the stability analyses performed at this load level is to confirm that the response has not significantly changed with the load level. It may also be used to assess changes in damping if the possibility of an oscillatory response is recognized in the light load analyses. If all Resources can not be dispatched behind the limiting lines or interface, a reasonable number of combinations may need to be studied.)

4. System Configuration - Analyses and sensitivities should be performed with the existing system facilities and topology and with all Resources and their associated upgrades in the study queue ahead of the Resource under study. Analyses and sensitivities should alsoinclude planned and proposed transmission facilities that are under study or under construction and may influence the results of System Impact Study for the Resource under study.



August 10, 2010 6

5. Operational Considerations - Assess the operating constraints of the proposed transmission and generation system. Determine the estimated magnitude of required redispatch of generation under typical and reasonably stressed conditions. Do not identify the upgrades necessary to reduce the operating constraints. If requested by the ISO, limited operating studies may be required to demonstrate viable operability of the proposed Resources and provide some indication of the system conditions for which the Resource’s operation may be restricted. The conditions to be considered in these studies will be coordinated through the ISO. Examples of studies that may be expected include:

a) Describe a methodology of determining and implementing the dispatch of Resources in any constrained area in a day-to-day operating environment.

b) Demonstrate that the proposed new Resource is able to operate through a load cycle without causing an increased likelihood of causing another Resource to be committed or increased in output if already committed, or require equipment switching which may compromise the reliability of the system.

c) Demonstrate that generation can be redispatched or other system adjustments can be made within 30 minutes following a first contingency to accommodate a second contingency.

(Note: Extensive operating studies, separate from the interconnection studies, may be necessary prior to actual operation.)

6. Identification of Related Upgrades - Any aggregate study should identify the upgrades associated with each proposed Resource.

Preliminary Analyses of Overlapping Interconnection Impacts under the Capacity

Capability Interconnection Standard: Scope of Study

The preliminary analysis will use the same criteria and assumptions that are prescribed in the analysis of overlapping interconnection impacts in Planning Procedure 10: Planning Procedure to Support the Forward Capacity Market (PP10). The starting point for the base case to be used in the preliminary analysis will be the latest developed base case that has been prepared, pursuant to PP10, for the analysis of New Generating Capacity Resources seeking to participate in a Forward Capacity Auction (“FCA”).

An Interconnection Customer with a Capacity Network Resource Interconnection Service Request may request that the Feasibility Study or System Impact Study include a preliminary, non-binding, analysis to identify potential upgrades that may be necessary for theInterconnection Customer’s Generating Facility to qualify for participation in an FCA under Section III.13 of the Tariff, based on a limited set of assumptions to be specified by the Interconnection Customer.

The set of additional assumptions that may be specified by the Interconnection Customer are limited to additional transmission projects and/or generation projects with active Interconnection



August 10, 2010 7

Requests under the L/SGIP that the Interconnection Customer requests to be added to the base case.

To the extent the Interconnection Customer requests a preliminary analysis of Overlapping Interconnection Impacts under the Capacity Capability Interconnection Standard, a report will contain the results of the requested preliminary analysis, along with an identification of potential upgrades that may be necessary for the Interconnection Customer’s Generating Facility to qualify for participation in a FCA pursuant to Section III.13 of the Tariff.

Document History5

Rev. 0 App.: RTPC – 4/13/99

Rev. 1 Rec.: RC – 2/13/01; App.: PC 3/2/01

Rev. 2 Eff.: 2/1/05

Rev. 3 App.: RC 5/19/09; NPC 6/5/09; ISO-NE 7/7/09

Rev. 4 App.: RC 7/19/10; NPC 8/6/10; ISO-NE 8/10/10


Appendix 2-7

ISO New England

Operating Procedure No. 12

Voltage and Reactive Control

ISO New England Operating Procedure OP 12 – Voltage and Reactive Control

This document is controlled when viewed on the ISO New England Internet web site. When downloaded and printed, this document becomes UNCONTROLLED, and users should check the Internet web site to ensure that they have the latest version. In addition, a Controlled Copy is available in the Master Control Room procedure binders at the ISO.

Hard Copy Is Uncontrolled Revision 5, Effective Date: April 13, 2012 Page 1 of 10

ISO New England Operating Procedure No. 12

VOLTAGE AND REACTIVE CONTROL

Effective Date: April 13, 2012

References:

1. ISO New England Transmission Operating Guides - All Voltage/Reactive Guides

2. ISO New England Operating Procedure No. 4 - Action During a Capacity Deficiency (OP-4)

3. ISO New England Operating Procedure No. 7 - Action in an Emergency (OP-7)

4. ISO New England Operating Procedure No. 14 - Technical Requirements for Generation, Demand Resources and Asset Related Demands (OP-14)

5. ISO New England Operating Procedure No. 16 - Transmission System Data (OP-16)

6. ISO New England Operating Procedure No.19 - Transmission Operations (OP-19)

7. Master/Local Control Center Procedure No. 8 - Coordination of Generator Voltage Regulator and Power System Stabilizer Outages (M/LCC 8)

8. Master/Local Control Center Procedure No. 9 - Operation of the Chester Static VAR Compensator (SVC) (M/LCC 9)

9. NERC Reliability Standard VAR-001 - Voltage and Reactive Control

10. NERC Reliability Standard IRO-005 - Reliability Coordinator Current Day Operations

11. NERC Reliability Standard VAR-002 - Generator Operations for Maintaining Network Voltage Schedules

12. NERC Reliability Standard MOD-025 - Verification of Generator Gross and Net Reactive Power Capability

13. NPCC Directory #10 - Verification of Generator Gross and Net Reactive Power Capability (NPCC D#10)

14. ISO New England Ancillary Service Schedule No. 2 Business Procedure



TABLE OF CONTENTS

I. INTRODUCTION ................................................................................................. 3

II. CRITERIA ............................................................................................................ 4

A. Voltage Schedules and Limits for Generators and Key Transmission Stations .................................................................................. 4

B. Generator Reactive Capabilities, Commitments and Required Reactive Reserves ............................................................................... 4

C. Verification of Generator Reactive Power Capability ........................................... 4

III. VOLTAGE/REACTIVE OPERATING PRACTICES ............................................. 6

A. Traditional Voltage/Reactive Control ................................................................... 6

B. Transmission Interface Transfer Limits To Avoid Low Voltage ............................ 6

C. Circuit Switching to Control High Voltage ............................................................ 6

D. Load Management for Voltage/Reactive Reliability ............................................. 6

IV. RESPONSIBILITIES ............................................................................................ 7

A. Generating and Transmission Stations ................................................................ 7

B. LCCs .................................................................................................................... 8

C. ISO ...................................................................................................................... 9

OP 12 Revision History.................................................................................................. 10

APPENDICES

Appendix A - Voltage/Reactive Documents in the ISO New England Transmission Operating Guides

Appendix B - Voltage and Reactive Schedules and Surveys



I. INTRODUCTION

This Operating Procedure (OP) provides broad criteria, operating practices and responsibilities to help ensure that desired/reliable voltage and reactive conditions are maintained on the power system. It also includes general actions to control voltage/reactive conditions when deviations from normal occur or are needed to minimize adverse effects during abnormal conditions.

More specific criteria and actions may be required when the measures described in this OP do not correct the abnormal voltage/reactive conditions. This information is contained in detailed voltage/reactive documents issued as part of the ISO New England (ISO) Transmission Operating Guides. Whereas these guides are referenced several times throughout this OP, Appendix A - Voltage/Reactive Documents in the ISO New England Transmission Operating Guides lists the documents and indicates the types of information they contain. To facilitate references to Appendix A, its column numbering and headings are consistent with the format and order of this OP.



II. CRITERIA

A. VOLTAGE SCHEDULES AND LIMITS FOR GENERATORS AND KEY TRANSMISSION STATIONS

Major generating stations throughout the New England Reliability Coordinator Area (RCA) have a specified voltage schedule which is the prescribed voltage that a generator must maintain as measured at the high side of the generator step-up transformer or as otherwise specified. These voltage schedules, which are specified in Appendix B - Voltage and Reactive Schedules and Surveys (Appendix B) of this OP for heavy and light load periods, shall be maintained as closely as possible in system operations while a unit at the generating station is online. These voltage schedules shall also be used by operators and planners in off-line studies of the power system. During certain conditions at a generating station or on the power system, sustained deviations from voltage schedules may be required/unavoidable and minimum and maximum voltages have been established that can be sustained at generating stations during these infrequent conditions.

During certain conditions, sustained deviations from voltage schedules may be required by the ISO or LCC; therefore in addition to voltage schedules, minimum and maximum voltage schedule limits at several key generating or transmission stations have been established to promote system reliability during adverse voltage/reactive conditions. These voltage schedule limits are specified in Appendix B for heavy and light load periods and may be based upon, among other things, the security of the transmission system or station service supplies to nuclear Generators. The key generating and transmission stations and the associated voltage schedule limits are detailed in the area voltage guides issued as part of the ISO Transmission Operating Guides (refer to Appendix A, column 1).

B. GENERATOR REACTIVE CAPABILITIES, COMMITMENTS AND REQUIRED REACTIVE RESERVES

Generator reactive capabilities available to regulate voltages shall be employed in system operations and analyses. Data collection methods [see ISO New England Operating Procedure No. 14 - Technical Requirements for Generation, Demand Resources and Asset Related Demands (OP-14)] have been designed such that these reactive capabilities shall be fully available except for occasional times when unique temporary problems occur at a particular generating station.

To promote security of the transmission system during adverse voltage/reactive conditions, required Generator commitments and levels of required reactive reserve from Generators within certain areas of the New England RCA have been established. System conditions that warrant the prescribed Generator commitments or reactive reserves have also been identified. Details are provided in the ISO Transmission Operating Guides (see Appendix A columns 2 and 3).

C. VERIFICATION OF GENERATOR REACTIVE POWER CAPABILITY

NPCC Directory #10 - Verification of Generator Gross and Net Reactive Power Capability (NPCC D#10) requires that each Transmission Operator establish and administer a Generator Reactive Power Capability Verification Program. It also requires each associated Generator Owner to comply with the Generator Reactive Power Capability Verification Program. The following language establishes the requirements of the ISO-NE Generator Reactive Power Capability Verification Program that each associated Generator Owner must meet to satisfy the NPCC D#10 Generator



Owner compliance obligations.

ISO-NE Generator Reactive Power Capability Verification Program applies to Generators that satisfy all of the following conditions:

1. Located in the New England RCA

2. Connected at or above 100 kV and having a MVA capability greater than either one of the following:

20 MVA for a single generator

75 MVA for a generating station connected at a common transmission bus.

3. Have been identified as having compliance obligations with the NERC Reliability Standards in accordance with the NERC Statement of Compliance Registry Criteria

Each Generator Owner shall verify the Reactive Power Capability of their Generators that meet the above criterion in accordance with the requirements and processes contained within Sections 2.2.5 & 2.2.6 of ISO New England Ancillary Service Schedule No. 2 Business Procedure. The ISO New England Ancillary Service Schedule No. 2 Business Procedure can be located on the ISO-NE website.

The one exception to a Generator Owners adherence to the Sections 2.2.5 & 2.2.6 requirements is that the requirement for a Generator to first be recognized as a “Qualified Reactive Resource” does not apply. While Generators that are not recognized as a “Qualified Reactive Resource” do not receive Capacity Cost (CC) compensation under Ancillary Service Schedule 2 - Reactive Supply and Voltage Control from Qualified Reactive Resources Service (“Schedule 2”) under Section II of the ISO New England Tariff, they must still adhere to the Section 2.2.5 & 2.2.6 requirements.

If the results of a reactive capability test demonstrate that a Generator reactive capability is different than the reactive capability reported in the latest NX-12D, the Generator Owner must resolve the discrepancy in accordance with Section 3.9 of Part I and Schedules 22 or 23 of Part II of the ISO Tariff.

To maintain compliance with NPCC D#10 and this OP, a Generator that is unable to conduct the required reactive capability test within the defined period, because of an extended outage, must test within thirty (30) days after returning to service. If the return to service is outside of the defined testing period, or there are not thirty (30) days left in the testing period, the Generator must test within the first thirty (30) days of the next applicable testing period. This does not apply to testing requirements for compensation purposes outlined in the ISO New England Ancillary Service Schedule No. 2 Business Procedure.



III. VOLTAGE/REACTIVE OPERATING PRACTICES

A. TRADITIONAL VOLTAGE/REACTIVE CONTROL

Besides the use of Generator reactive capabilities, the proper dispatch of shunt capacitors/reactors combined with effective transformer voltage schedules or fixed tap settings are the most traditional means of achieving desired voltages and reactive conditions. Listings of switchable shunt devices installed to support the New England Transmission System (115 kV and above) and guides for switching them can be found in the ISO Transmission Operating Guides (see Appendix A, column 4).

B. TRANSMISSION INTERFACE TRANSFER LIMITS TO AVOID LOW VOLTAGE

In some cases, custom software tools have been developed to calculate voltage based transfer limits for transmission interfaces. These limits ensure acceptable voltage response to contingencies. Appendix A column 5 notes the ISO Transmission Operating Guides that contain voltage based transfer limits for transmission interfaces.

C. CIRCUIT SWITCHING TO CONTROL HIGH VOLTAGE

In some areas, transmission circuit switching is a viable option for controlling high voltage/excessive charging conditions. Appendix A column 6 identifies the ISO Transmission Operating Guides that provide information for switching circuits to control high voltage.

D. LOAD MANAGEMENT FOR VOLTAGE/REACTIVE RELIABILITY

In severe cases of low voltage and/or inadequate reactive reserves, load management actions can be taken. Details on conditions when these actions can/shall be used and how they shall be implemented are provided in the ISO Transmission Operating Guides (as identified in Appendix A, column 7) and ISO New England Operating Procedure No. 4 - Action During a Capacity Deficiency (OP-4) and ISO New England Operating Procedure No. 7 - Action in an Emergency (OP-7).



IV. RESPONSIBILITIES

This OP is based on the principle that voltage control is best achieved when action is taken as close as possible to the affected area. Voltage schedules and other reactive conditions shall be supervised by the generating station operators, transmission station operators, Local Control Center (LCC) System Operators and ISO New England System Operators, each having a specific area of responsibility. Regardless of who requests or directs corrective measures, action must ultimately be taken by generating/transmission station operators or LCC System Operators depending on who has "hands on" control of the reactive resources.

A. GENERATING AND TRANSMISSION STATIONS

Generating and transmission station operators are responsible for maintaining station service and other local voltage requirements and scheduled voltages at levels designated by individual Market Participants.

NERC Reliability Standard VAR-002 - Generator Operations for Maintaining Network Voltage Schedules requires each Generator equipped with an Automatic Voltage Regulator (AVR) to operate in the automatic voltage control mode. Whenever the AVR operation is available, the Generator AVR will:

1. Be in service and controlling voltage, and

2. Remain in this configuration unless otherwise directed by the ISO or LCC System Operator.

The Generator Operator shall promptly notify the ISO when AVR operation is temporarily unavailable.

Generating station operators are also responsible for maintaining voltage schedules set for the high side of the generator step-up transformers by the Voltage Task Force. Normally, automatic voltage regulation works off the low side of the step-up transformer (generator terminals). Thus, in order to maintain a high side voltage schedule, manual intervention can be required to offset varying power flows through and voltage drops across the step-up transformer.

When unable to maintain scheduled station and local voltages with the means under their control, the generating or transmission station operators must notify their respective LCC System Operator (and local dispatch authority if appropriate).

Generator station operators are responsible to comply with the reactive capability verification process defined in Section II.C.



B. LCCS

LCCs are responsible for monitoring and supervising the following conditions within their territories:

1. Voltage schedules and limits,

2. Generator MVAR loadings, capabilities and reserves,

3. Shunt capacitor and reactor dispatches,

4. Transformer voltage schedules or fixed tap settings,

5. Synchronous condenser operation (requested via ISO by the LCC unless in emergency conditions),

6. MVAR flows between the AC system and HVDC facilities,

7. Static VAR Compensator operation (must be coordinated with ISO),

8. Line switching for voltage/reactive control (must be coordinated with ISO and, if warranted, with other LCCs),

9. Other predefined indicators of voltage/reactive security (e.g. a particular circuit flow, the status of specific Generators, area load level, etc.).

The LCCs are responsible for:

1. Detecting and correcting deviations from normal scheduled voltage/reactive operations

2. Responding to notifications by generating or transmission station operators of difficulty in maintaining station or other local voltage or reactive schedules

3. Responding to ISO requests to assist with inter-LCC or inter-Area problems.

The LCCs will notify/coordinate with ISO when there is a need to adjust the real power (MW) output of a Generator in order to adjust its MVAR output, and ISO will provide the direction to the Designated Entity/Generator Operator to adjust their Generator real power (MW) output. Unless an emergency condition warrants such action, the LCCs will not directly provide direction to the Generator Operator to adjust the real power output (MW) of their Generator in order to adjust its MVAR output.

The LCCs are authorized to exercise the following actions to correct voltage/reactive difficulties within their territories:

1. Direct voltage schedules and levels of reactive output and reserve on Generators, synchronous condensers and Static VAR Compensators,

2. Direct the use of shunt capacitors and reactors,

3. Direct the operation of LTC transformers.

When an LCC is unable to correct a voltage/reactive problem using the above actions or the LCC believes that the problem should be handled on a multi-LCC or inter-RCA basis, the LCC shall notify ISO and request assistance.

Before exercising any of the following voltage/reactive control actions, LCCs must notify ISO and coordinate their implementations:

1. Line switching,

2. Load management.



C. ISO

ISO is responsible for general monitoring and supervision of voltage/reactive conditions in the New England RCA (115 KV and above). When system monitoring detects a problem within an LCC, ISO shall contact the LCC and request action.

When an LCC reports to ISO that it is not possible to correct an abnormal voltage/reactive-related operating condition at a station or LCC level, ISO shall assume direct responsibility for alleviating the problem. ISO is authorized to direct, through the appropriate LCC(s), all actions listed in the above LCC Section B and in addition any MW re-dispatching.

ISO is also responsible for monitoring and supervising voltage/reactive operations of inter-RCA ties. Abnormal voltage/reactive-related operating conditions may be noticed by ISO or appear in the form of requests from a neighboring Reliability Coordinator or companies for assistance. ISO shall inform the appropriate LCC (s) of the nature of the problem specifying; the pool or company involved, the location of the undesirable voltage/reactive condition and, general conditions aggravating the difficulty. ISO is authorized to work with/through the LCCs and use all Section B actions and MW re-dispatching to eliminate the problem.

When abnormal voltage/reactive operating conditions materialize, ISO may initiate a survey of key system parameters to better assess the nature and expanse of the conditions. Appendix B contains the survey forms that ISO will use. The forms are broken down based on LCC territories.

ISO shall report annually to NPCC about the status of the ISO-NE Generator Reactive Power Capability Verification Program including any changes in the verification process and provide copies of any changes to the Generator Owners and NPCC within 30 days of issue. ISO shall also report annually to NPCC any discrepancies between published (NX-12D) and demonstrated reactive capability.



OP 12 REVISION HISTORY

Document History (This Document History documents action taken on the equivalent NEPOOL Procedure prior to the RTO

Operations Date as well revisions made to the ISO New England Procedure subsequent to the RTO Operations Date.)

Rev. No. Date Reason

Rev 1 08/18/98

Rev 2 02/01/05 Updated to conform to RTO terminology

Rev 3 05/06/05 Update References for NERC Version 0 Standards

Rev 4 06/04/10 Biennial Review by Procedure Owner. To the footer, added disclaimer on page 1 and added “uncontrolled to remaining pages; Corrected and added Reference titles. Minor clerical revisions (font format changed to Arial, grammar, etc..) Defined terms and approved acronyms for use in this document: ISO New England (ISO); Local Control Center (LCC); Reliability Coordinator Area (RCA) Inserted new language applicable to meeting requirements of NPCC Directory #10 & NERC Reliability Standard VAR-002 New Section II.C - Verification of Generator Reactive Power Capability. Section IV added related responsibilities to Generators and ISO.

5 04/13/12 Replaced page numbers in footers with Page X of Y format; References Section Item 7 replaced “…stabilizer…” with “…Stabilizer…”; Section II.A: defined voltage schedules and added reference to Appendix B Section II.C: in 1

st paragraph, replaced “…satisfy both…” with “…satisfy all…”

Section II.C: as new item II.C.3, added language to exempt units that are not NERC registered from testing requirements; Section II.C: as a new paragraph at the end of the section, added language to clarify testing requirements for units on extended outage; Section III. C. deleted “…in the Boston area…”; Section IV A: Inserted “Whenever AVR operation is available,..” Section IV.B.9: deleted the comma (,) at the beginning of the item. Section IV.C. 3

rd paragraph replaced “…MWh…” with “…MW…”

ISO New England Operating Procedure No. 12 Voltage and Reactive Control – Appendix A –Voltage/Reactive Documents in the ISO New England Transmission Operating Guides

Effective Date: February 17, 2011 Revision No. 9

Operating Procedures

ISO New England Operating Procedure OP 12 – Voltage and Reactive Control Appendix A

This document is controlled when viewed on the ISO New England Internet web site. When downloaded and printed, this document becomes UNCONTROLLED, and users should check the Internet web site to ensure that they have the latest version. In addition, a Controlled Copy is available in the Master Control Room procedure binders at the ISO. The information contained in this document is for use by ISO New England staff and the Local Control Centers and is subject to modification. ISO New England Inc. is not responsible for any reliance on this document by others, or for any errors or omissions or misleading information contained herein.

Hard Copy Is Uncontrolled Revision 9, Effective Date: February 17, 2011 Page 1 of 3

1

Voltage/Reactive Documents in the ISO New England Transmission Operating Guides

Voltage/Reactive Document

1 2 3 4 5 6 7

Voltage Limits

Units Critical to Voltage Control

RequiredReactive Reserves

Shunt Information

InterfaceVoltage TransferLimits

Line Switching for High Voltage

Load Management

Actions

Eastern Massachusetts and Rhode Island Low Voltage Guide x x x x

Northern New England Transmission Corridor-Low Voltage Guide x x x x

Northern New England Transmission Corridor-High Voltage Guide x x x x

Orrington Capacitor Bank Control Operating Guide x x

Boston Import Area Operations Planning Guide and Operations Guide x x x x

Northern Vermont Interface (NVI) Limit Guide x x x x

M/LCC 9 - Operation of the Chester SVC x x x

M/LCC 1 - Nuclear Plant Transmission Operations, Atts A, B, C, & D x

Procedure to Protect for Loss of Single Source Contingency Guide x

Southwest Connecticut Import Voltage/Reactive Limit Guide x x x

Tremont-East Area Operations Guide x x x x x x

Connecticut Import Voltage/Reactive Limit Guide x x x

New England to New Brunswick Voltage/Reactive (V/R) Limit Calculator Guide

x x x x x

VELCO Highgate Converter Export Guidelines x x x x



Voltage/Reactive Document

1 2 3 4 5 6 7

Voltage Limits

Units Critical to Voltage Control

RequiredReactive Reserves

Shunt Information

InterfaceVoltage TransferLimits

Line Switching for High Voltage

Load Management

Actions

Voltage Reactive Coordination of New England-New Brunswick Interface Guide

x x x x x

Western Maine Area Voltage Support Requirements Guide x x x x

Southwest Connecticut Unit Commitment Requirements x x x

Pittsfield Area Operating Guide x x x

Connecticut Operating Guide x x x x

Halvarsson-Tomson 481 Line Guide x

Norwalk Harbor-Northport 601, 602 & 603 Cables Operating Guide x

388 Line Out Guide x x

ISO-NE – NBSO CDI-001 Operating Guide x x x

NewPage Plant Load Shedding Scheme Description Guide x x

C-040 Common Dispatch Instructions for HQ & ISONE for ± 450 kV DC Line

x

Gen-C-042 Common Operating Instruction for the Phase II Facilities x x x

M/LCC 5 Att B - Procedure for Millstone Point Station Generation Reduction

x x

Northwest New England 345 kV High Voltage Guide x x x x x



OP 12 APPENDIX A REVISION HISTORY

Document History (This Document History documents action taken on the equivalent NEPOOL Procedure prior to the RTO Operations Date as well revisions made to the ISO New England Procedure subsequent to the RTO Operations Date.)


Rev 1 05/23/03

Rev 2 08/05/03

Rev 3 07/25/04

Rev 4 11/09/04

Rev 5 02/01/05 Updated to conform to RTO

Rev 6 09/07/06 Revised document references

Rev 7 12/20/07 Revised document references

Rev 8 02/26/10 Reformatted, changed font to Arial; Added uncontrolled disclaimer to footer; Updated list to reflect current document usage

Rev 9 02/17/11 Biennial review by procedure owner; NVI data row added x in column 3 (Required Reactive Reserves); Corrected the title “Procedure to Protect for Loss of Single Source Contingency Guide” Provided the correct title “Norwalk Harbor-Northport 601, 601 & 603 Cables Operating Guide” Provided the correct title “Newpage Plant Load Shedding Scheme Description Guide” Added data row for Northwest New England 345 kV High Voltage Guide

ISO New England Operating Procedure OP-12 - Voltage and Reactive Control, Appendix B

Revision 27 - Effective Date: March 25, 2013 i

Appendix B -

Voltage & Reactive Schedules and Surveys

Contents

CONVEX ......................................................................................................................................................................3

CONVEX Voltage & Reactive Schedules & Surveys - Appendix B, Generators .......................................................3

CONVEX Voltage & Reactive Schedules & Surveys for Transmission, Capacitors ..................................................8

CONVEX Voltage & Reactive Schedules & Surveys for Transmission, Reactors .................................................. 10

CONVEX Voltage & Reactive Schedules & Surveys for Transmission, STATCOMs .............................................. 11

CONVEX Voltage & Reactive Schedules & Surveys for Autotransformers with LTCs .......................................... 12

Maine ....................................................................................................................................................................... 13

Maine Voltage & Reactive Schedules & Surveys - Appendix B, Generators ....................................................... 13

Maine Voltage & Reactive Schedules & Surveys for Transmission, Capacitors .................................................. 15

Maine Voltage & Reactive Schedules & Surveys for Transmission, Reactors ..................................................... 15

Maine Voltage & Reactive Schedules & Surveys for Transmission, Static VAR Compensator ............................ 16

Maine Voltage & Reactive Schedules & Surveys for Autotransformers with LTCs ............................................. 16

New Hampshire ....................................................................................................................................................... 17

New Hampshire Voltage & Reactive Schedules & Surveys – Appendix B, Generators ....................................... 17

New Hampshire Voltage & Reactive Schedules & Surveys for Transmission, Capacitors ................................... 18

New Hampshire Voltage & Reactive Schedules & Surveys for Transmission, Reactors ...................................... 19

New Hampshire Voltage & Reactive Schedules & Surveys for Autotransformers with LTCs .............................. 20

NSTAR ...................................................................................................................................................................... 21

NSTAR Voltage & Reactive Schedules & Surveys - Appendix B, Generators ....................................................... 21

NSTAR Voltage & Reactive Schedules & Surveys for Transmission, Capacitors .................................................. 23

NSTAR Voltage & Reactive Schedules & Surveys for Transmission, Reactors ..................................................... 24

NSTAR Voltage & Reactive Schedules & Surveys for Autotransformers with LTCs ............................................. 25

REMVEC ................................................................................................................................................................... 26

REMVEC Voltage & Reactive Schedules & Surveys - Appendix B, Generators .................................................... 26

REMVEC Voltage & Reactive Schedules & Surveys for Transmission, Capacitors ............................................... 28

REMVEC Voltage & Reactive Schedules & Surveys for Transmission, Reactors .................................................. 29

REMVEC Voltage & Reactive Schedules & Surveys for Autotransformers with LTCs .......................................... 30


Revision 27 - Effective Date: March 25, 2013 ii

VELCO ...................................................................................................................................................................... 31

VELCO Voltage & Reactive Schedules & Surveys - Appendix B, Generators ....................................................... 31

VELCO Voltage & Reactive Schedules & Surveys for Transmission, Capacitors .................................................. 32

VELCO Voltage & Reactive Schedules & Surveys for Transmission, Reactors ..................................................... 33

VELCO Voltage & Reactive Schedules & Surveys for Transmission, STATCOMs ................................................. 34

VELCO Voltage & Reactive Schedules & Surveys for Autotransformers with LTCs ............................................. 34

OP-12 Appendix B Revision History ......................................................................................................................... 35

Endnotes .................................................................................................................................................................. 38


Revision 27 - Effective Date: March 25, 2013 Page 3 of 38

CONVEX

CONVEX Voltage & Reactive Schedules & Surveys - Appendix B, Generators

Survey Date: Survey Time: Survey Load Period: Heavy/Light (circle one)

Legend

Sched = Schedule

Max = Maximum

Min = Minimum

MVARs Out = Gross Lagging

MVARs In = Gross Leading

Units

Voltage Schedules

Heavy Load Period1

Voltage Schedules Light

Load Period2

MVARs

Out @

S-SCC3

MVARs

In @ Min

Manual

Load3

Survey Results

kV

Sched

kV

Max

kV

Min

kV

Sched

kV

Max

kV

Min

Actual kV

(Voltage) MVARs

AVR

Status

(On/Off)

A. L. PIERCE 118 121 116 117 121 116 28 -15

ALTRESCO 119 121 109 119 121 109 108 -24

BERKSHIRE POWER 117 121 108 117 121 105 163 -65

BRIDGEPORT ENERGY 118 121 116 117 121 116 296 -95

BRIDGEPORT HBR 2 118 121 116 117 121 116 106 0

BRIDGEPORT HBR 3 118 121 116 117 121 116 218 -128.6

BRIDGEPORT HBR 4 118 121 116 117 121 116 4 -3

BRIDGEPORT RESCO 118 121 116 117 121 116 25 -15

CABOT 115 120 111 115 120 108 43.8 -25

COS COB 10 119 121 109 119 121 109 4 0

COS COB 11 119 121 109 119 121 109 3 0

COS COB 12 119 121 109 119 121 109 4 0

COS COB 13 119 121 109 119 121 109 0 0

COS COB 14 119 121 109 119 121 109 1.5 -1.5

CROSS SOUND CABLE 357 362 340 357 362 340 34.5*

-148.5*

DEVON 10 118 121 116 117 121 116 1 0

DEVON 11 118 121 116 117 121 116 20 -16

DEVON 12 118 121 116 117 121 116 20 -17

DEVON 13 118 121 116 117 121 116 15 -14





Legend

Sched = Schedule

Max = Maximum

Min = Minimum



Units

Voltage Schedules

Heavy Load Period1


Load Period2

MVARs

Out @

S-SCC3

MVARs

In @ Min

Manual

Load3

Survey Results

kV

Sched

kV

Max

kV

Min

kV

Sched

kV

Max

kV

Min

Actual kV

(Voltage) MVARs

AVR

Status

(On/Off)

DEVON 14 118 121 116 117 121 116 19 -14

DEVON 15 118 121 116 117 121 116 7 -8

DEVON 16 118 121 116 117 121 116 10 -8

DEVON 17 118 121 116 117 121 116 9 -8

DEVON 18 118 121 116 117 121 116 9 -8

KLEEN ENERGY CT1 357 362 340 357 362 340 99 -91

KLEEN ENERGY CT2 357 362 340 357 362 340 99 -91

KLEEN ENERGY ST 357 362 340 357 362 340 125 -112

LAKE ROAD 1 357 362 340 357 362 340 187 -81

LAKE ROAD 2 357 362 340 357 362 340 184 -80

LAKE ROAD 3 357 362 340 357 362 340 181 -78

MASS POWER 119 121 111 119 121 111 104 -38

MIDDLETOWN 2 118 121 112 116 121 112 53 -30

MIDDLETOWN 3 118 121 112 116 121 112 75 -41

MIDDLETOWN 4 357 362 340 357 362 340 204 -100

MIDDLETOWN 10 118 121 112 116 121 112 0 -1.7

MIDDLETOWN 12 357 362 340 357 362 340 10 -15

MIDDLETOWN 13 357 362 340 357 362 340 10 -15

MIDDLETOWN 14 357 362 340 357 362 340 10 -15

MIDDLETOWN 15 357 362 340 357 362 340 10 -15

MILFORD 1 118 121 116 117 121 116 158 -98





Legend

Sched = Schedule

Max = Maximum

Min = Minimum



Units

Voltage Schedules

Heavy Load Period1


Load Period2

MVARs

Out @

S-SCC3

MVARs

In @ Min

Manual

Load3

Survey Results

kV

Sched

kV

Max

kV

Min

kV

Sched

kV

Max

kV

Min

Actual kV

(Voltage) MVARs

AVR

Status

(On/Off)

MILFORD 2 118 121 116 117 121 116 131 -86

MILLSTONE 2 357 362 345 357 362 345 350 0

MILLSTONE 3 357 362 345 357 362 345 395 0

MONTVILLE 5 117 121 110 117 121 110 28 -7

MONTVILLE 6 117 121 110 117 121 110 190 -111

MOUNT TOM 117 121 111 117 121 109 17 -38

NEW HAVEN HBR 119 121 116 117 121 116 181 -50

NEW HAVEN HBR 2 119 121 116 117 121 116 30 -25

NEW HAVEN HBR 3 119 121 116 117 121 116 30 -25

NEW HAVEN HBR 4 119 121 116 117 121 116 30 -25

NORTHFIELD G1 359 362 344 351 362 344 95 -53

NORTHFIELD G2 359 362 344 351 362 344 136 -103

NORTHFIELD G3 359 362 344 351 362 344 90 -56

NORTHFIELD G4 359 362 344 351 362 344 92 -64

NORTHFIELD P1 359 362 344 351 362 344 80 -58

NORTHFIELD P2 359 362 344 351 362 344 80 -58

NORTHFIELD P3 359 362 344 351 362 344 80 -70

NORTHFIELD P4 359 362 344 351 362 344 80 -58

NORWALK HBR 1 119 121 114 119 121 113 41 -28

NORWALK HBR 2 119 121 114 119 121 113 34 -27

NORWALK HBR 3 119 121 114 119 121 113 1 0





Legend

Sched = Schedule

Max = Maximum

Min = Minimum



Units

Voltage Schedules

Heavy Load Period1


Load Period2

MVARs

Out @

S-SCC3

MVARs

In @ Min

Manual

Load3

Survey Results

kV

Sched

kV

Max

kV

Min

kV

Sched

kV

Max

kV

Min

Actual kV

(Voltage) MVARs

AVR

Status

(On/Off)

ROCKY RIVER 117 121 105 116 121 105 5 -8

SHEPAUG 117 121 109 116 121 109 16 -10

SOUTH MEADOW 5 116 121 104 116 121 104 30 -23

SOUTH MEADOW 6 116 121 104 116 121 104 22 -20

SOUTH MEADOW 11 116 121 104 116 121 104 15 0

SOUTH MEADOW 12 116 121 104 116 121 104 15 0

SOUTH MEADOW 13 116 121 104 116 121 104 0 -5.6

SOUTH MEADOW 14 116 121 104 116 121 104 15 -1.6

STEVENSON 1 116 121 112 116 121 112 10 -7

STONY BROOK 1A 358 362 335 351 362 335 71 -34

STONY BROOK 2A 358 362 335 351 362 335 37 -21

STONY BROOK 1B 358 362 335 351 362 335 64 -31

STONY BROOK 2B 358 362 335 351 362 335 36 -20

STONY BROOK 1C 358 362 335 351 362 335 71 -33

WALLINGFORD ENERGY 1 118 121 116 117 121 116 26 -12





WALLINGFORD REFUSE 118 121 116 117 121 116 0 0

WATERBURY 118 121 109 118 121 109 95 -14





Legend

Sched = Schedule

Max = Maximum

Min = Minimum



Units

Voltage Schedules

Heavy Load Period1


Load Period2

MVARs

Out @

S-SCC3

MVARs

In @ Min

Manual

Load3

Survey Results

kV

Sched

kV

Max

kV

Min

kV

Sched

kV

Max

kV

Min

Actual kV

(Voltage) MVARs

AVR

Status

(On/Off)

WATERSIDE 119 121 109 119 121 109 25 -10

WEST SPRINGFIELD 1 117 121 109 117 121 109 26 -17



Note: Units not listed will follow local voltage schedules in accordance with Local Control Center requirements or Interconnection Agreements.

*Zero Power -150 MVAR, Half Load 113/-113 MVAR, Three-quarter Load 95/-95, and Full Load 35 MVAR



CONVEX Voltage & Reactive Schedules & Surveys for Transmission, Capacitors


Substation Location Available

MVAR Nominal Voltage (kV) Actual Voltage (kV)

Closed/

Open

AGAWAM 11K; 12K 2 @ 50.4 115

BERLIN 11K; 12K 2 @ 37.8 115

BERLIN 13K 1 @ 50.4 115

BRANFORD 10K 1 @ 37.8 115

CANTON 11K; 12K 2 @ 25.2 115

DARIEN10K 1 @ 37.8 115

EAST SHORE 1K; 2K 2 @ 42.0 115

FRANKLIN DRIVE10K 1 @ 37.8 115

FROST BRIDGE 11K; 12K; 13K 3 @ 50.4 115

FROST BRIDGE 21K; 22K 2 @ 50.4 115

GLENBROOK 11K; 12K 2 @ 36.0 115

GLENBROOK 13K; 14K 2 @ 50.4 115

GLENBROOK 21K; 22K 2 @ 36.0 115

GLENBROOK 23k 1 @ 37.8 115

GLENBROOK 24k 1 @ 50.4 115

HADDAM 10K 1 @ 37.8 115

MANCHESTER 11K; 12K; 13K 3 @ 50.4 115

MANCHESTER 21K; 22K; 23K 3 @ 50.4 115

MONTVILLE 11K; 12K 2 @ 50.4 115

MYSTIC 21K; 22K 2 @ 25.2 115

NORTH BLOOMFIELD 11K; 12K 2 @ 50.4 115

NORTH BLOOMFIELD 20K 1 @ 50.4 115

NORTH HAVEN 1K 1 @ 42.0 115

PLEASANT 11K; 12K 2 @ 14.4 115

PLUMTREE 11K 1 @ 37.8 115

PLUMTREE 12K 1 @ 50.4 115

ROCKY RIVER 10K 1 @ 25.2 115

SACKETT 1K* 1 @ 42.0 115

SOUTHINGTON 11K; 12K; 13K 3 @ 50.4 115

SOUTHINGTON 21K; 22K;23K 3 @ 50.4 115

STONY HILL 10K 1 @ 25.2 115

STONY HILL 21K; 22K 2 @ 37.8 115

WATERSIDE 10K 1 @ 37.8 115



CONVEX Voltage & Reactive Schedules & Surveys for Transmission, Capacitors




Closed/

Open

WOODLAND 21K; 22K 2 @ 14.4 115

* Sackett 1K capacitor will be out of service in 2012



CONVEX Voltage & Reactive Schedules & Surveys for Transmission, Reactors


Substation Location

Available


Closed/

Open

NORWALK R1; R2 2 @ -50 Fixed;

-50 Variable 345

NORWALK JUNCTION F1; F2 2 @ -75 Fixed;

-75 Variable 345

PLUMTREE 345-F1 1 @ -75 Fixed;

-75 Variable 345

Singer R1; R2; R3; R4 4 @ -50 Fixed;

-50 Variable 345



CONVEX Voltage & Reactive Schedules & Surveys for Transmission, STATCOMs

Survey Date:

Survey Time: Survey Load Period: Heavy/Light (circle one)

Legend

Sched = Schedule

Max = Maximum

Min = Minimum

Location

Voltage Schedules

Heavy Load Period1

Voltage Schedules

Light Load Period2

Available MVAR

Nominal

Voltage

Actual

Voltage

(kV) Closed/Open

kV

Sched

kV

Max

kV

Min

kV

Sched

kV

Max

kV

Min

GLENBROOK STATCOM 119 121 114 119 121 114 2 @ -75 / +75 115



CONVEX Voltage & Reactive Schedules & Surveys for Autotransformers with LTCs


Legend

Sched = Schedule

Max = Maximum

Min = Minimum

Auto = Automatic

Substation Name

High Side

kV/ Low

Side kV

LTC Setting

(Auto/Manual)

Scheduled

Voltage

(kV)

Max

LTC

Tap

Min

LTC

Tap

Voltage

Control

Bandwidt

h (kV)

Survey Results

Surveyed

Actual

Voltage (kV)

Surveyed LTC

Setting

(Auto/Manual)

BARBOUR HILL 1X 345/115 A 118 109-121

BERKSHIRE 1X; 2X 345/115 A 119 109-121

CARD 5X 345/115 A 115 109-121

EAST DEVON 2X 345/115 M 118 109-121

EAST SHORE 8X; 9X 345/115 M 119 116-121

FROST BRIDGE 1X 345/115 A 118 110-121

HADDAM 6X 345/115 A 118 109-121

KILLINGLY 2X 345/115 A 117 112-119

LUDLOW1X; 3X 345/115 A 119 108-121

MANCHESTER4X; 5X; 6X 345/115 A 118 107-121

MONTVILLE18X; 19X 345/115 A 117 110-121

NORTH BLOOMFIELD 5X 345/115 A 118 108-121

NORWALK 8X; 9X 345/115 A 119 109-121

NORWALK HARBOR 8X 138/115 M 119 114-121

PLUMTREE 1X; 2X 345/115 A 119 111-121

SINGER 1X*, 2X 345/115 M 118 116-121

SOUTHINGTON BUS 1X; 4X 345/115 A 118 110-120

SOUTHINGTON BUS 2X; 3X 345/115 A 118 110-120

* Singer 1X is a GSU with tap changing options. It is LTC capable but is normally operated in manual.



Maine

Maine Voltage & Reactive Schedules & Surveys - Appendix B, Generators


Legend

Sched = Schedule

Max = Maximum

Min = Minimum



Units

Voltage Schedules

Heavy Load Period1


Load Period2

MVARs

Out @

S-SCC3

MVARs

In @ Min

Manual

Load3

Survey Results

kV

Sched

kV

Max

kV

Min

kV

Sched

kV

Max

kV

Min

Actual kV

(Voltage) MVARs

AVR

Status

(On/Off)

AEI LIVERMORE 117 121 113 117 121 113 19.5 -17

BUCKSPORT G4 120 121 118 120 121 118 115 -97

CAPE GT 4 120 121 113 120 121 113 9 -2.7

CAPE GT 5 120 121 113 120 121 113 9 -2.9

HARRIS HYDRO G1 120 121 113 120 121 113 5.8 -3

HARRIS HYDRO G2 120 121 113 120 121 113 11 -7.8

HARRIS HYDRO G3 120 121 113 120 121 113 12 -7.6

KIBBY WIND 120 121 113 120 121 113 27 -38

MAINE INDEPENDENCE GT1 121 123 114 121 123 114 110 -50

MAINE INDEPENDENCE GT2 121 123 114 121 123 114 110 -50

MAINE INDEPENDENCE ST 121 123 114 121 123 114 114 -55

ROLLINS WIND 117.5 118 117 117.5 118 117 29 -29

RUMFORD POWER GT & ST 117 121 113 117 121 113 140 -90

STRATTON ENERGY 120 121 113 120 121 113 15 -15

STETSON WIND 117.5 118 117 117.5 118 117 28 -28

VERSO (ANDROSCOGGIN) AEC #1 117 121 113 117 121 113 33 -9

VERSO (ANDROSCOGGIN) AEC #2 117 121 113 117 121 113 33 -10

VERSO (ANDROSCOGGIN) AEC #3 117 121 113 117 121 113 33 -7.5

WESTBROOK 1A 120 121 113 120 121 113 154 -90

WESTBROOK 2B 120 121 113 120 121 113 154 -89



Maine Voltage & Reactive Schedules & Surveys - Appendix B, Generators


Legend

Sched = Schedule

Max = Maximum

Min = Minimum



Units

Voltage Schedules

Heavy Load Period1


Load Period2

MVARs

Out @

S-SCC3

MVARs

In @ Min

Manual

Load3

Survey Results

kV

Sched

kV

Max

kV

Min

kV

Sched

kV

Max

kV

Min

Actual kV

(Voltage) MVARs

AVR

Status

(On/Off)

WYMAN HYDRO 1 118 121 113 118 121 113 11 -7

WYMAN HYDRO 2 118 121 113 118 121 113 12 -1.20

WYMAN HYDRO 3 118 121 113 118 121 113 12 -5

YARMOUTH 1 120 121 113 120 121 113 18 -17

YARMOUTH 2 120 121 113 120 121 113 18 -20

YARMOUTH 3 120 121 113 120 121 113 43 -25

YARMOUTH 4 355 362 349 355 362 349 213 -100

Units not listed will follow local voltage schedules in accordance with Local Control Center requirements or Interconnection Agreements.



Maine Voltage & Reactive Schedules & Surveys for Transmission, Capacitors




Closed/

Open

CROWLEYS KC2 1 @ 50 115

EPPING TAP [email protected] 115

GULF ISLAND KC1 1 @ 30 115

HEYWOOD KC1 1 @ 20 115

KEENE RD 1 @ 15 115

KIMBALL ROAD KC1; KC2 2 @ 30 115

MAGUIRE ROAD KC1 1 @ 50 115

MASON KC2; KC3 2 @ 50 115

MAXCYS KC1; KC2 2 @ 50 115

ORRINGTON KC1; KC2; KC3 3 @ 67 115

RILEY KC1 1 @ 30 115

RUMFORD IP KC1 1 @ 25 115

SANFORD KC1 1 @ 30.6 115

SOUTH GORHAM KC1; KC2 2 @ 50 115

SUROWIEC KC1; KC2; KC3 3 @ 50 115

WYMAN HYDRO KC1; KC2 2 @ 17.5 115

Maine Voltage & Reactive Schedules & Surveys for Transmission, Reactors




Closed/

Open

ORRINGTON KR1; KR2 2 @ -40 13.8

SUROWIEC KR1; KR2 2 @ -40 13.8

LARRABEE [email protected] 13.8



Maine Voltage & Reactive Schedules & Surveys for Transmission, Static VAR Compensator


Legend

Sched = Schedule

Max = Maximum

Min = Minimum

Location

Voltage Schedules

Heavy Load Period1

Voltage Schedules

Light Load Period2

Available

MVAR

Nominal

Voltage

(kV)

Actual

Voltage

(kV)

Closed/

Open kV

Sched

kV

Max

kV

Min

kV

Sched

kV

Max

kV

Min

CHESTER SVC * NA 358 348 NA 358 348 -123.29 / +448.32 345

* See M/LCC 9 and M/LCC 9 Attachment B for a detailed description of the voltage / reactive scheduling for the Chester SVC.

Maine Voltage & Reactive Schedules & Surveys for Autotransformers with LTCs


Legend

Sched = Schedule

Max = Maximum

Min = Minimum

Auto = Automatic

Substation Name

High Side

kV/ Low

Side kV

LTC Setting

(Auto/Manual)

Scheduled

Voltage

(kV)

Max

LTC

Tap

Min

LTC

Tap

Voltage

Control

Bandwidth

(kV)

Survey Results

Surveyed

Actual

Voltage (kV)

Surveyed LTC

Setting

(Auto/Manual)

KEENE ROAD 345/115 M 118 16 -16 117-120

LARRABEE 345/115 A 119 16 -16 118-120

MASON T9 345/115 A 119 16 -16 118-120

MAXCYS T3 345/115 A 119 16 -16 118-120

ORRINGTON T1 345/115 M 121* 16 -16 120-122

ORRINGTON T2 345/115 M 121* 16 -16 120-122

SOUTH GORHAM T1 345/115 A** 119 16 -16 118-120

SOUTH GORHAM T2 345/115 A** 119 16 -16 118-120

SUROWIEC T1 345/115 A 119 16 -16 118-120

* - When being operated in manual the Orrington scheduled voltage is ~1kV less than Graham bus voltage.

** - This transformer LTC is run in manual when WEC is online.


Revision 27 -Effective Date: March 25, 2013 Page 17 of 38

New Hampshire

New Hampshire Voltage & Reactive Schedules & Surveys – Appendix B, Generators


Legend

Sched = Schedule

Max = Maximum

Min = Minimum



Units

Voltage Schedules

Heavy Load Period1


Load Period2

MVARs

Out @

S-SCC3

MVARs

In @ Min

Manual

Load3

Survey Results

kV

Sched

kV

Max

kV

Min

kV

Sched

kV

Max

kV

Min

Actual kV

(Voltage) MVARs

AVR

Status

(On/Off)

AES GRANITE RIDGE ST 1* 119 121 109 119 121 109 190 -101

GRANITE RELIABLE WIND POWER 118.5 121 117 118.5 121 117 20 -28

MERRIMACK 1 119 121 109 119 121 109 49 -17

MERRIMACK 2 119 121 109 119 121 109 124 -43

MERRIMACK CT1 119 121 109 119 121 109 13 -11

MERRIMACK CT2 119 121 109 119 121 109 13 -11

NEWINGTON 357 362 339 357 362 339 188 -57

CONED NEWINGTON ENERGY 1 357 362 339 357 362 339 115 -58



SCHILLER 4 119 121 109 119 121 109 25 -22

SCHILLER 5 119 121 109 119 121 109 25 -12

SCHILLER 6 119 121 109 119 121 109 25 -22

SEABROOK 357 362 345 357 362 345 447 -36

TAMWORTH 117.5 121 109 117.5 121 109 14 0

Note: Units not listed will follow local voltage schedules in accordance with Local Control Center requirements or Interconnection Agreements.

*Granite units CT1 & CT2 are located in the REMVEC Section



New Hampshire Voltage & Reactive Schedules & Surveys for Transmission,

Capacitors


Substation Location Available MVAR Nominal Voltage (kV) Actual Voltage (kV) Closed/Open

BEEBE J1153; J1164; J1165 3 @ 13.3 115

CHESTNUT HILL J1156; J1157 2 @ 12.2 115

CHESTNUT HILL J1158 1 @ 24.4 115

JACKMAN J1168; J1169 2 @ 13.3 115

MADBURY J1162; J1163 2 @ 26.7 115

MERRIMACK J1151; 1152 2 @ 36.7 115

OAK HILL J1179; J1180 2 @ 13.3 115

OCEAN RD. J1154; J1155 2 @ 24.4 115

THREE RIVERS J1159 1 @ 12.2 115

THREE RIVERS J1160; J1161 2 @ 24.4 115

WHITE LAKE J1166 1 @ 13.3 115

WHITE LAKE J1167 1 @ 6.6 115



New Hampshire Voltage & Reactive Schedules & Surveys for Transmission, Reactors



SCOBIE POND R31; R32 2 @ -40.0 115



New Hampshire Voltage & Reactive Schedules & Surveys for Autotransformers with LTCs


Legend

Sched = Schedule

Max = Maximum

Min = Minimum

Auto = Automatic

Substation Name

High Side

kV/ Low

Side kV

LTC Setting

(Auto/Manual)

Scheduled

Voltage

(kV)

Max

LTC

Tap

Min

LTC

Tap

Voltage Control

Bandwidth (kV)

Survey Results

Surveyed

Actual

Voltage (kV)

Surveyed LTC

Setting

(Auto/Manual)

DEERFIELD TB14 345/115 A 119.3 33 1 117.9-120.8

DEERFIELD TB28 345/115 A 119.3 16 -16 117.9-120.8

FITZWILLIAM TB34 345/115 A 119.51 16 -16 118-121.1

LITTLETON TB41 230/115 A 116.5 33 1 115-118.8

MERRIMACK A253* 230/115 M 119.0 16 -16 117.5-120.5

SACO-VALLEY PS1 115/115 M 117 10 -10 115-119

SCOBIE TB30 345/115 A 119.5 33 1 118.0-121.1

SCOBIE TB90 345/115 A 119.5 16 -16 118.0-121.1

SCOBIE TB120 345/115 A 119.5 16 -16 118.0-121.1

* This transformer LTC is run in manual when Merrimack units are on line



NSTAR

NSTAR Voltage & Reactive Schedules & Surveys - Appendix B, Generators


Legend

Sched = Schedule

Max = Maximum

Min = Minimum



Units

Voltage Schedules

Heavy Load Period1


Load Period2

MVARs

Out @

S-SCC3

MVARs

In @ Min

Manual

Load3

Survey Results

kV

Sched

kV

Max

kV

Min

kV

Sched

kV

Max

kV

Min

Actual kV

(Voltage) MVARs

AVR

Status

(On/Off)

ANP BLACKSTONE 1 356 362 335 356 362 335 160 -95

ANP BLACKSTONE 2 356 362 335 356 362 335 104 -94

CANAL 1 356 362 327 356 362 327 248 -100

CANAL 2 356 362 327 356 362 327 121 -100

DARTMOUTH POWER 116 121 109 116 121 109 33 -24

DARTMOUTH 3 115 121 109 115 121 109 14 -10

FORE RIVER GT 1 118 121 110 116 121 110 160 -110

FORE RIVER GT 2 118 121 110 116 121 110 160 -110

FORE RIVER ST 1 118 121 110 116 121 110 160 -125

KENDALL G4 119 121 110 117 121 110 125 -66

MEDWAY J1 238 241 219 235 241 219 20 -10

MEDWAY J2 238 241 219 235 241 219 20 -10

MEDWAY J3 115 121 109 115 121 109 20 -20

MYSTIC 7 358 362 335 356 362 335 324 -183

MYSTIC 8 GT1 358 362 335 356 362 335 160 -101

MYSTIC 8 GT2 358 362 335 356 362 335 160 -101

MYSTIC 8 ST 358 362 335 356 362 335 160 -125

MYSTIC 9 GT1 119 121 109 117 121 109 160 -105

MYSTIC 9 GT2 119 121 109 117 121 109 160 -105

MYSTIC 9 ST 119 121 109 117 121 109 160 -91



NSTAR Voltage & Reactive Schedules & Surveys - Appendix B, Generators


Legend

Sched = Schedule

Max = Maximum

Min = Minimum



Units

Voltage Schedules

Heavy Load Period1


Load Period2

MVARs

Out @

S-SCC3

MVARs

In @ Min

Manual

Load3

Survey Results

kV

Sched

kV

Max

kV

Min

kV

Sched

kV

Max

kV

Min

Actual kV

(Voltage) MVARs

AVR

Status

(On/Off)

NEA BELLINGHAM (1-3) 356 362 328 356 362 328 87 -120

PILGRIM 356 362 342 356 362 342 299 -100

POTTER 2 118 121 110 116 121 110 21 -24

SEMASS G1 118 121 109 118 121 109 15 -5

SEMASS G2 118 121 109 118 121 109 10 -2

THOMAS A. WATSON 1 118 121 110 116 121 110 35 -17

THOMAS A. WATSON 2 118 121 110 116 121 110 35 -17




NSTAR Voltage & Reactive Schedules & Surveys for Transmission, Capacitors



BAKER STREET C1; C2 2 @ 53.6 115

BARNSTABLE C1 1 @ 35.3 115

CHELSEA C1 1 @ 36.7 115

DOVER C1 1 @ 53.6 115

FALMOUTH TAP C1 1 @ 35.3 115

FRAMINGHAM C1 1 @ 53.6 115

HARWICH C1 1 @ 21.2 115

HARTWELL [email protected] 115

HYANNIS JCT. C1 1 @ 39.6 115

K-STREET C1; C2 2 @ 53.6 115

LEXINGTON C1 1 @ 53.6 115

MASHPEE C1 1 @35.3 115

MYSTIC C1 1 @ 53.6 115

ORLEANS C1 1 @ 13.6 115

SUDBURY C1 1 @ 49.5 115

WING LANE STATION C1 1 @35.3 115

W.FRAMINGHAM 1 @ 54.4 115



NSTAR Voltage & Reactive Schedules & Surveys for Transmission, Reactors



MVAR Nominal Voltage (kV) Actual Voltage (kV) Closed/Open

EDGAR 2 @ -40 115

K-STREET 1 @ -80 115

K-STREET 2 @ -70 Fixed;

-90 Variable

345

LEXINGTON 1 @ -70 Fixed;

-90 Variable

345

MYSTIC 1 @ -80 115

MYSTIC 1 @ -70 Fixed;

-90 Variable

345

NORTH CAMBRIDGE 2 @ -80 115

NORTH CAMBRIDGE 1 @ -70 Fixed;

-90 Variable

345

STOUGHTON 4 @ -70 Fixed;

-90 Variable

345

WEST WALPOLE 1 @ -70 Fixed;

-90 Variable

345

WOBURN 3 @ -80 115



NSTAR Voltage & Reactive Schedules & Surveys for Autotransformers with LTCs


Legend

Sched = Schedule

Max = Maximum

Min = Minimum

Auto = Automatic

Substation Name

High Side

kV/ Low

Side kV

LTC Setting

(Auto/Manual)

Scheduled

Voltage

(kV)

Max

LTC

Tap

Min

LTC

Tap

Voltage

Control

Bandwidth

(kV)

Survey Results

Surveyed

Actual

Voltage

(kV)

Surveyed LTC

Setting

(Auto/Manual)

KINGSTON 345A 345/115 M 119 10 -10 103.4-126.6

KINGSTON 345B 345/115 M 119 10 -10 103.4-126.6

WOBURN 345 345/115 M 118 33 1 103.96-126.45

NSTAR Voltage & Reactive Schedules & Surveys for Transmission, Static VAR Compensator

Survey Date:


Legend

Sched = Schedule

Max = Maximum

Min = Minimum

Location

Voltage Schedules

Heavy Load Period1

Voltage Schedules

Light Load Period2

Available

MVAR

Nominal

Voltage (kV)

Actual

Voltage (kV)

Closed/

Open

kV

Sched

kV

Max

kV

Min

kV

Sched

kV

Max

kV

Min

BARNSTABLE SVC* NA 120 109 NA 120 109 1 @ 0/ 125* 115

* Under normal operational conditions, the SVC will be operating with a zero (0) MVAR output, ready to respond to faults in the network. During the first 2 seconds, the

maximum MVAR output is 225 MVAR. After that, the MVAR output is rapidly reduced to a maximum of 125 MVAR, which can be sustained for up to 30 minutes.



REMVEC

REMVEC Voltage & Reactive Schedules & Surveys - Appendix B, Generators


Legend

Sched = Schedule

Max = Maximum

Min = Minimum



Units

Voltage Schedules

Heavy Load Period1


Load Period2

MVARs

Out @

S-SCC3

MVARs

In @ Min

Manual

Load3

Survey Results

kV

Sched

kV

Max

kV

Min

kV

Sched

kV

Max

kV

Min

Actual kV

(Voltage) MVARs

AVR

Status

(On/Off)

AES GRANITE RIDGE CT1* 238 241.5 219 238 241.5 219 161 -110

AES GRANITE RIDGE CT2* 238 241.5 219 238 241.5 219 161 -143

ANP BELLINGHAM 1 356 362 335 356 362 335 142 -82

ANP BELLINGHAM 2 356 362 335 356 362 335 142 -83

BEAR SWAMP 1 GEN 240 241 219 225 241 219 84 -55

BEAR SWAMP 1 PUMP 240 241 219 225 241 219 120 0

BEAR SWAMP 2 GEN 240 241 219 225 241 219 100 -70

BEAR SWAMP 2 PUMP 240 241 219 225 241 219 120 0

BRAYTON 1 118 121 110 116 121 110 115 -93

BRAYTON 2 118 121 110 116 121 110 118 -96

BRAYTON 3 356 362 335 356 362 335 260 -284

BRAYTON 4 356 362 328 356 362 328 230 -153

CLEARY CC 118 121 110 116 121 110 71 -45

CLEARY 8 118 121 110 116 121 110 14 -5

COMERFORD 240 241 219 238 241 219 68 -58

DIGHTON POWER 1 118 121 110 116 121 110 94 -21

FPL RISE GT 1 119 121 110 117 121 110 50 -40

FPL RISE GT 2 119 121 110 117 121 110 50 -40

FPL RISE ST 1 119 121 110 117 121 110 76 -57

L’ENERGIA 118 121 110 116 121 110 55 -26



REMVEC Voltage & Reactive Schedules & Surveys - Appendix B, Generators


Legend

Sched = Schedule

Max = Maximum

Min = Minimum



Units

Voltage Schedules

Heavy Load Period1


Load Period2

MVARs

Out @

S-SCC3

MVARs

In @ Min

Manual

Load3

Survey Results

kV

Sched

kV

Max

kV

Min

kV

Sched

kV

Max

kV

Min

Actual kV

(Voltage) MVARs

AVR

Status

(On/Off)

MANCHESTER ST 9/9A 119 121 110 117 121 110 101 -50

MANCHESTER ST 10/10A 119 121 110 117 121 110 65 -55

MANCHESTER ST 11/11A 119 121 110 117 121 110 98 -45

MILFORD POWER (1-2) 118 121 110 117 121 110 119 -57

MILLENIUM GT & ST 117 121 112 115 121 110 155 -96

MOORE (1-4) 240 241 219 238 241 219 74 -62

OCEAN STATE 1 (GT1/GT2/ST1) 356 362 335 356 362 335 122 -98

OCEAN STATE 2 (GT3/GT4/ST2) 356 362 335 356 362 335 109 -103

RESCO SAUGUS 117 121 112 116 121 112 33 -18

SALEM HARBOR 3 119 121 109 117 121 109 61 -60

SALEM HARBOR 4 119 121 109 117 121 109 275 -210

SOMERSET JET2 118 121 110 116 121 110 13 0

TIVERTON (GT, ST) 118 121 109 116 121 109 180 -50

WATERS RIVER JET2 119 121 109 117 121 109 3 0

WMI MILLBURY 118 121 109 116 121 109 15 -6


* The Granite Ridge ST unit is located in New Hampshire Section


Revision 27 - Effective Date: Page 28 of 38

REMVEC Voltage & Reactive Schedules & Surveys for Transmission, Capacitors


Substation Location

Available


Closed/

Open

FRANKLIN SQUARE C2 1 @ 63 115

KENT COUNTY C2 1 @ 63 115

KENT COUNTY C5; C6 2@72 115

MONROEC11; C12 2 @ 31.5 230

MONROE C21; C22 2 @ 31.5 230

MONROE C31 1 @ 63 230

MILBURY C1; C3 2 @ 63 115

NORTHBORO RD. C6 1 @ 54 115

NORTHBORO RD. C3; C4 2 @ 36 69

PRATTS JCT 4A 1 @ 63 115

REVERE C1 1 @ 30 115

SALEM HARBOR C1; C2 2 @ 63 115

SANDY POND C11; C21 2 @ 99 345

SANDY POND C12; C22 2 @ 186 345

SANDY POND F11; F21 2 @ 175 345

SANDY POND F12; F22 2 @ 85 345

SANDY POND F13; F23 2 @ 178 345

TEWKSBURY C1; C2 2 @ 63 115



REMVEC Voltage & Reactive Schedules & Surveys for Transmission, Reactors


Substation Location

Available


Closed/

Open

MONROE R13 – 14; R21; R23 4 @ -20.2 14.3

SANDY POND 3 @ -160 345



REMVEC Voltage & Reactive Schedules & Surveys for Autotransformers with LTCs


Legend

Sched = Schedule

Max = Maximum

Min = Minimum

Auto = Automatic

Substation Name

High Side

kV/ Low

Side kV

LTC Setting

(Auto/

Manual)

Scheduled

Voltage

(kV)

Max

LTC

Tap

Min

LTC

Tap

Voltage

Control

Bandwidth

(kV)

Survey Results

Surveyed

Actual

Voltage (kV)

Surveyed LTC

Setting (Auto/

Manual)



VELCO

VELCO Voltage & Reactive Schedules & Surveys - Appendix B, Generators


Legend

Sched = Schedule

Max = Maximum

Min = Minimum



Units

Voltage Schedules

Heavy Load Period1


Load Period2

MVARs

Out @

S-SCC3

MVARs

In @ Min

Manual

Load3

Survey Results

kV

Sched

kV

Max

kV

Min

kV

Sched

kV

Max

kV

Min

Actual kV

(Voltage) MVARs

AVR

Status

(On/Off)

GRANITE SYNC COND 117.0 118.5 115.0 117.0 118.5 115.0 4 @ 25 4 @ -12.5

VERMONT YANKEE 358 362 342 354 362 342 210 -50




VELCO Voltage & Reactive Schedules & Surveys for Transmission, Capacitors


Substation Location

Available

MVAR Nominal Voltage (kV) Actual kV (Voltage)

Closed/

Open

BERLIN C87 1 @ 24.8 115

COOLIDGE C91; C92 2 @ 25 115

ESSEX #1 C34 1 @ 24.3 115

ESSEX C35; C36; C37; C38; C39 5 @ 24.8 115

GEORGIA C41 1 @ 24.8 115

HARTFORD C40 1 @ 25.0 115

HIGHGATE CONVERTER TERMINAL 6 @ 20

2 @ 10 115

GRANITE C61; C62; C66 3 @ 25 115

LYNDONVILLE C21; C23 2 @ 12.50 115

MIDDLEBURY VB72 1 @ 22.9 115

NORTH RUTLAND C71 1 @ 24.8 115

SANDBAR C82 1 @ 24.8 115

VERMONT YANKEE C50; C51 2 @ 15 115

VERMONT YANKEE C52 1 @ 30 115

WEST RUTLAND C45; C46 2 @25.0 115

WILLISTON C83 1 @ 25.2 115



VELCO Voltage & Reactive Schedules & Surveys for Transmission, Reactors


Substation Location

Available


Closed/

Open

COOLIDGE R41; R42 2 @-34 Fixed

-26 Variable 345



VELCO Voltage & Reactive Schedules & Surveys for Transmission, STATCOMs

Survey Date:


Legend

Sched = Schedule

Max = Maximum

Min = Minimum

Location

Voltage Schedules

Heavy Load Period1

Voltage Schedules

Light Load Period2

Available

MVAR Nominal

Voltage (kV)

Actual Voltage

(kV)

Closed/

Open

kV

Sched

kV

Max kV

Min

kV

Sched

kV

Max kV

Min

ESSEX STATCOM 117 119 112 117 119 112 -65 / +85 115

VELCO Voltage & Reactive Schedules & Surveys for Autotransformers with LTCs


Legend

Sched = Schedule

Max = Maximum

Min = Minimum

Auto = Automatic

Substation Name

High Side

kV/ Low

Side kV

LTC Setting

(Auto/Manual)

Scheduled

Voltage

(kV)

Max

LTC

Tap

Min

LTC

Tap

Voltage

Control

Bandwidth

(kV)

Survey Results

Surveyed

Actual

Voltage

(kV)

Surveyed LTC

Setting

(Auto/Manual)

COOLIDGE XF 345/115 M 117 33 1 N/A

GRANITE T1 230/115 A 234 16 -16 237-230

GRANITE T2 230/115 A 234 16 -16 237-230

WEST RUTLAND (1) * 345/115 A 116.4 16 -16 118.7-114.1

WEST RUTLAND (2) * 345/115 A 116.4 16 -16 118.7-114.1

NEW HAVEN (1) * 345/115 A 116.4 16 -16 118.7-114.1

NEW HAVEN (2) * 345/115 A 116.4 16 -16 118.7-114.1

*New Haven and West Rutland transformers operated in tandem



OP-12 Appendix B Revision History

Document History (This Document History documents action taken on the equivalent NEPOOL Procedure prior to the RTO Operations

Date as well revisions made to the ISO New England Procedure subsequent to the RTO Operations Date.)


Rev 1 05/23/03

Rev 2 08/05/03

Rev 3 07/25/04

Rev 4 11/09/04

Rev 5 02/01/05 Updated to conform to RTO terminology

Rev 6 05/06/05 Update for initiation of VELCO Local Control Center

Rev 7 06/02/05 Update information resulting from VTF review

Rev 8 09/07/06 Updated information resulting from VTF review

Rev 9 10/26/06 Corrected MVAR value for Rumford

Rev 10 09/17/07 Updated information resulting from ISO Operations Support Services review

Rev 11 03/04/08 Revised for NSTAR LCC status

Rev 12 05/22/08 Completely reformatted to allow better use and ease making future revisions.

Updated information resulting from VTF review.

Rev 13 06/26/08 Updated information resulting from VTF review.

Rev 14 09/16/08 Updated information resulting from VTF review and new test results.







Rev 21 5/24/10 Minor reformatting of tables to make sure date is displayed consistently;

Updated information resulting from VTF review and new test results.


Rev 23 5/25/11 Replaced page numbers with Page X of Y format;

Updated information resulting from VTF review.

Rev 24 07/21/11 CONVEX Generators added Kleen Energy station units CT1, CT2 &ST data rows;

New Hampshire Capacitors added Oak Hill capacitors (J1179; J1180) data row;

NSTAR Capacitors added Chelsea capacitor C1 data row;

REMVEC Comerford Capacitors corrected capacitor data(was C15, now C31)

REMVEC Comerford Reactors added unit designations for reactors (R21-24 & R31-34);

REMVEC Comerford Reactors corrected reactor data MVAR (now20.2) and Nominal Voltage (now 14.3)



Rev 25 02/14/12 Biennial review by procedure owner;

CONVEX – Generators: Added data row for the following:

A. L. Pierce

Bridgeport HBR 4

Bridgeport RESCO

Cos Cob 10, 11, 12, 13, 14

Devon 10, 11, 12, 13, 14, 15, 16, 17, 18

Middletown 10, 12, 13, 14, 15

New Haven HBR 2, 3, 4

Norwalk HBR 3

South Meadow 11, 12, 13, 14

Tunnel

Wallingford REFUSE

Waterbury

Waterside

Modified the MVARs OUT for New Haven HBR

Modified the MVARs IN min value for Northfield P1, P2, P3, P4

CONVEX – Capacitors, Added an asterisk (*) to Sackett 1K & added a foot note

CONVEX – Autotransformers with LTCs, Modified:

Barbour Hill 1X Schedule voltage and voltage control bandwidth

Manchester 4X, 5X, 6X Scheduled voltage

North Bloomfield 5X Scheduled voltage

Maine – Generators, added new data rows for Cape GT 4 & Cape GT 5

Maine Static Var Compensator- reattributed note with asterisk

Maine – Autotransformers with LTCs, Modified the LTC setting (Auto/Manual) and modified asterisks for

this column for:

Keene Road

Orrington T1, T2

New Hampshire – Generators, Added new data row for :

Merrimack CT1, CT2

Tamworth

New Hampshire – Autotransformers with LTCs,

Added data row for Deerfield TB28

Fitzwilliam added “TB34” to station name;

Littleton TB41 modified scheduled voltage and Voltage Control Bandwidth;

Saco-Valley added “PS1” to station name

NSTAR – Generators, Added new data row for:

Dartmouth 3

REMVEC – Generators, Added new data row for:

Cleary 8

RESCO Saugus

Somerset Jet2

Waters River Jet2

WMI Millbury

Modified the MVARS Out and In for L’ENERGIA

REMVEC – Capacitors, Added data row for Kent County C5, C6

VELCO – Generators, Modified MVARs out for Vermont Yankee

VELCO – Capacitors, Added new data row for:

Lyndonville C21, C23

West Rutland C45, C46



26 05/30/12 CONVEX – Generators, Modified data row for the following:

Middletown 12, 13, 14 & 15 Voltage Heavy Load/Light Load Sched, Max & Min values all changed

Waterside Voltage Schedules both Heavy/Light kV Min values

West Springfield Heavy/Light kV Min values

Maine – Generators, Modified data rows for

AEI Livermore Voltage Schedules Heavy/Light Load, kV Sched values;

Bucksport Voltage Schedules Heavy/Light Load, kV min values;

Harris Hydro G1, MVARs Out @ S-SCC values;

Rumford Power GT, Voltage Schedules Heavy/Light Load, kV Sched values;

Stratton Energy, MVARs out @ S-SCC and MVARs In @ Min Manual, Load values;

VERSO AEC #1, #2 & #3, Voltage Schedules Heavy/Light Load, kV Sched values;

Maine – Static VAR Compensator, Modified the data row for:

Chester SVC, Available MVAR values

REMVEC – Generators, Modified data row for:

Modified data row for:

ANP Bellingham 1, MVARS IN @ MIN MANUAL Load value

Manchester 10/10A MVARS In @ MIN MANUAL Load value

27 03/25/13 CONVEX:

AES Thames was deleted;

Cabot generator was added;

Berkshire Power leading capability was changed to -65 MVAR;

Bridgeport Energy lagging capability was changed to 296 MVAR;

Kleen Energy the lagging and leading capability (99 MVAR, 99 MVAR and 125 MVAR) and (-91

MVAR,-91 MVAR and -112 MVAR);

Mass Power the lagging and leading capabilities were changed to 104 MVAR and -38 MVAR;

Mount Tom lagging capability was changed to 17 MVAR;

Northfield 2G lagging and leading capabilities changed to 136 MVAR and -103 MVAR

Norwalk Harbor 1 and 2 leading capability were changed to -28 and -27 MVAR;

East Devon 2X LTC setting changed to Manual.

Stonybrook 2B leading capability changed to -20 MVAR

Wallingford Energy 1 & 4 lagging capabilities changed to 26 & 27 MVAR

Maine:

Cape 4 and Cape 5 changed leading capability to -2,7 and 2.9 MVAR;

Rollins Wind and Stetson Wind were added;

Epping Tap capacitors bank was added (10.2 MVAR);

Larrabee two reactors were added (2@-40 MVAR)

The nominal voltage was changed for Orrington and Surowiec reactors to 13.8 kV;

Chester SVC reactive capability was changed to -123.29/448.32 MVAR;

Larrabee 345/115 transformer was added.

New Hampshire:

Granite Reliable Wind was added.

Schiller 6 leading capability changed to -22 MVAR

NSTAR:

Mystic 7 leading capability was changed to -183 MVAR;

Voltage schedule was changed for ANP Blackstone 1 & 2; Canal 1, 2; Dartmouth Power;

NEA Bellingham; Pilgrim; SEMass;

Hartwell capacitor bank added ([email protected] MVAR).

REMVEC:

Voltage schedule was changed for ANP Bellingham 1 & 2, Brayton 3 & 4 and Ocean State 1 & 2;

ANP Bellingham 2 leading capability changed to -83 MVAR,

Bearswamp 1 Gen leading capability changed to -55 MVAR,

Brayton 1 leading capability changed to -93 MVAR

Salem Harbor 1 & 2 deleted;

Comerford capacitors banks and reactors were renamed to Monroe;

Sandy Pond C11 & C21 available MVAR changed to 99 MVAR

VELCO:

Capacitors- Georgia replaced C80 with C41; Granite deleted C64, available MVAr changed to 3;

Reactor s@ New Haven deleted data row;

Two reactors were added to Coolidge (- 34 MVAR fixed and-26 MVAR is variable).



Endnotes

1

Heavy 07:00-22:00 hours Monday through Saturday except Holidays.

2 Light all other hours.

3 Data from NX-12D, pt. 19 (MVAR lagging), pt. 15 (MVAR leading) of the Normal Reactive Capability portion of the

table/curve.

Appendix 2-8

National Grid Transmission

Group Procedure (TGP 28)

Transmission Planning Guide

2.0 Introduction

2.1 Objective of the Transmission Planning Guide

The objective of the Transmission Planning Guide is to define the criteria and standards used to assess the reliability of the existing and future National Grid transmission system for reasonably anticipated operating conditions and to provide guidance, with consideration of public safety and safety of operations and personnel, in the design of future modifications or upgrades to the transmission system. The guide is a design tool and is not intended to address unusual or unanticipated operating conditions.

2.2 Planning and Design Criteria

All National Grid facilities that are part of the bulk power system and part of the interconnected National Grid system shall be designed in accordance with the latest versions of the NERC Reliability Standards, Northeast Power Coordinating Council (NPCC) Criteria, ISO-New England Reliability Standards, New York State Reliability Council (NYSRC) Reliability Rules, and the National Grid Design Criteria. The fundamental guiding documents are:

• NERC Reliability Standards TPL-001, System Performance Under Normal Conditions, TPL-002, System Performance Following Loss of a Single BES Element, TPL-003, System Performance Following Loss of Two or More BES Elements, and TPL-004, System Performance Following Extreme BES Events,

• NPCC Directory #1, Design and Operation of the Bulk Power System and Directory #4, BulkPower System Protection Criteria,

• Reliability Standards for the New England Area Bulk Power Supply System (ISO-NE Planning Procedure No. 3),

• New York State Reliability Council Reliability Rules for Planning and Operation of the New York State Power System, and

• National Grid Transmission Planning Guide (this document).

Interconnections of new generators to the National Grid transmission system in New England shall be configured and designed in compliance with the ISO-New England document, “General Transmission System Design Requirements for the Interconnection of New Generators (Resources) to the Administered Transmission System.” If corresponding New York ISO requirements are established, interconnections to the National Grid transmission system in New York will be configured and designed in compliance with those requirements.

All National Grid facilities operated at 115 kV and above in New York and 69 kV and above in New England shall be designed in accordance with the latest version of this document.

All National Grid or National Grid transmission customers' facilities which are served by transmission providers other than National Grid shall be designed in accordance with the planning and design criteria of the transmission supplier and the applicable NERC, NPCC, ISO-NE, and NYSRC documents.

Detailed design of facilities may require additional guidance from industry or other technical standards which are not addressed by any of the documents referenced in this guide.

2.3 Operational Considerations in Planning and Design

The system should be planned and designed with consideration for ease of operation and with input from Operations. Such considerations include, but are not limited to:

- utilization of standard components to facilitate availability of spare parts - optimization of post contingency switching operations - use and location of switching devices (ex. Adding sectionalizing switches on either side

of a substation tap to reduce Load at Risk (LAR) for scheduled outages) - switch capabilities (need to consult with Operations to confirm that any proposed

switches meet operating criteria) - reduction of operational risks - judicious use of Special Protection Systems (SPSs) - impact on the underlying distribution system (e.g. thermal, short circuit, automated

switching schemes) - use of SCADA, telemetry, etc to communicate the Control Center Energy Management

System (EMS) - impact to system restoration plan - need, use, and location of reactive supplies - development of operating procedures for new or revised facilities - longevity of the solution to minimize rework - operational and outage issues associated with construction - integration of multiple needs to provide an efficient approach to performing upgrades or

replacements

3.0 System Studies

3.1 Basic Types of Studies

The basic types of studies conducted to assess conformance with the criteria and standards stated in this guide include but are not limited to Powerflow, Stability, Short Circuit, and Protection Coordination.

3.2 Study Horizon

The lead time required to plan, permit, license, and construct transmission system upgrades is typically between one and ten years depending on the complexity of the project. Some very large and complex projects, which are less common, may even require lead times of up to 15 years. As a result, investments in the transmission system should be evaluated for different planning horizons in the one to fifteen-year range. The typical horizons are referred to as near term (one to three years), mid-term (three to six years), and long term (six or more years). Projects taking less than a year to implement tend to consist of non-construction alternatives that are addressed by operating studies.

3.3 Future Facilities

Planned facilities should not automatically be assumed to be in-service during study periods after the planned in-service date. Sensitivity analysis should be performed to identify interdependencies of the planned facilities. These interdependencies should be clearly identified in the results and recommendations.

3.4 Equipment Thermal Ratings

Thermal ratings of each load carrying element in the system are determined such that maximum use can be made of the equipment without damage or undue loss of equipment life. The thermal ratings of each transmission circuit reflect the most limiting series elements within the circuit. The existing rating procedures are based on guidance provided by the NEPOOL System Design Task Force (SDTF) in Planning Policy 7 (PP 7 Procedures for Determining and Implementing Transmission Facility Ratings in New England), the NYPP Task Force Report on Tie Line Ratings (1995), and industry standards. Similar rating procedures have been developed for rating National Grid facilities in New England and New York. The applicable National Grid procedure will be applied to all new and modified facilities. The principal variables used to derive the ratings include specific equipment design, season, ambient conditions, maximum allowable equipment operating temperatures as a function of time, and physical parameters of the equipment. Procedures for calculating the thermal ratings are subject to change. Equipment ratings are summarized in the following table by durations of allowable loadings for three types of facilities. Where applicable, actions that must be taken to relieve equipment loadings within the specified time period also are included.

Equipment

RATINGS

Normal

Long Time Emergency (LTE)

Short Time

Emergency (STE)

Drastic Action Limit

(DAL)4 Overhead Transmission

Continuous

Loading must be reduced below the Normal rating within 4 hours2

Loading must be reduced below the LTE rating within 15 minutes

requires immediate action to reduce loading below the LTE rating

Underground Cables1

Continuous

Loading must be reduced below the 100 hr or 300 hr rating within 4 hours2

Loading must be reduced below the 100 hr or 300 hr rating within 15 minutes


Transmission Transformers

Continuous

Loading must be reduced below the Normal rating within 4 hours2

Loading must be reduced below the LTE rating within 15 minutes3


1 Ratings for other durations may be calculated and utilized for specific conditions on a case-by-case basis. Following expiration of the 100 hr or 300 hr period, loading of the cable must be reduced below the Normal rating. Either the 100 hr or the 300 hr rating may be utilized after the transient period, but not both. If the 100 hr rating is utilized, the loading must be reduced below the Normal rating within 100 hr, and the 300 hr rating may not be used.

2 The summer LTE rating duration is 12 hours in New England. The winter LTE rating duration in New England, and the summer and winter LTE rating duration in New York is 4 hours. The time duration does not affect the calculated value of the LTE rating. The duration difference reflects how the LTE ratings are applied by the ISO in each Area.

3 The transformer STE rating is based on 30 minute duration to provide additional conservatism, but is applied in operations as a 15 minute rating.

4 The DAL rating is only calculated only in New England based on historical ISO requirements.

3.4.1 Other Equipment

Industry standards and input from task forces in New England and New York should continue to be used as sources of guidance for developing procedures for rating new types of equipment or for improving the procedures for rating the existing equipment.

3.4.2 High Voltage DC

High Voltage dc (HVdc) equipment is rated using the manufacturer's claimed capability.

3.5 System Models

Base case system models for powerflow and transient stability analysis are available from libraries maintained through a process involving the ISOs, NPCC, and the Eastern Interconnection Reliability Assessment Group (ERAG). Through this process entities supply their respective ISOs with modeling updates for their system; the ISOs combine information and develop Area updates and provide them to NPCC; NPCC combines information from all of the Areas into a regional update and provides it to ERAG; and ERAG, through the Multiregional Modeling Working Group (MMWG) combines all the regional updates into a master model which is then redistributed back down the chain for use by the industry. The modeling updates include load forecast over the ten year planning horizon (which through the course of the process are modified to recognize the diversity of the aggregate seasonal peak demand relative to the sum of the area seasonal peak demands) and equipment characteristics (e.g. impedance, line charging, normal and emergency ratings, nominal voltages, tap ratios and regulated buses for transformers, and equipment status). The modeling updates are provided in the form of solved powerflow and stability models created annually for selected years and seasons within the planning horizon. The years and seasons modeled typically are:

Near-term (one to three years out): Summer peak, winter peak. Fall peak, spring peak, and spring light load may also be looked at.

Mid-term (three to six years out): Summer peak and winter peak

Long-term (six or more years out): Summer peak.

Details on this process can be found in NPCC Document C-29, Procedures for System Modeling: Data Requirements & Facility Ratings, and the MMWG Procedure Manual.

This process is completed once per year coincident with the need to provide base cases in response to the FERC 715 filing requirement. However, updates typically are provided by or to the ISOs as information becomes available (e.g. as projects are approved or go into service). The load forecasts are seasonal peak load assumptions that include adjustments for energy efficiency. Demand response is not included in the load models. Any given base case may need to be revised to reflect local concerns (e.g. proposed system changes not included in the model, local peak loads).

When scaling load on an area basis, care must be taken to avoid scaling non-conforming load, i.e. load that does not conform to a typical load-duration curve such as industrial or generating plant station service load. When a light load case is desired in a year for which a light load base case is not available, a light load case should be developed from an available light load case for another year; this is always preferable to scaling a peak load case down to a light load level. In general, peak load cases should not be scaled below 70 percent of peak load and light load cases should not be scaled above 70 percent of peak load. When scaling load it also is necessary to be sure that generator voltage schedules and dispatch of reactive resources is appropriate for the load level modeled. In particular, generator units in the REMVEC portion of New England have different voltage schedules for heavy and light load levels.

3.6 Modeling for Powerflow Studies

The representation for powerflow studies should include models of transmission lines, transformers, generators, reactive sources, and any other equipment which can affect power flow or voltage. The representation for fixed-tap, load-tap-changing, and phase shifting transformers should include voltage or angle taps, tap ranges, and voltage or power flow control points. The representation for generators should include reactive capability ranges and voltage control points. Equipment ratings should be modeled for each of these facilities including

related station equipment such as buses, circuit breakers and switches. Study specific issues that need to be addressed are discussed below.

3.6.1 Forecasted Load

The forecasted summer and winter peak active and reactive loads should be obtained annually from the Transmission Customers for a period of ten or more years starting with the highest actual seasonal peak loads within the last three years. The forecast should have sufficient detail to distribute the active and reactive coincident loads (coincident with the Customers' total peak load) across the Customers' Points of Delivery. Customer owned generation should be modeled explicitly when the size is significant compared to the load at the same delivery point, or when the size is large enough to impact system dynamic performance.

The Point of Delivery for powerflow modeling purposes may be different than the point of delivery for billing purposes. Consequently, these points need to be coordinated between National Grid and the Transmission Customer.

To address forecast uncertainty, the peak load forecast should include forecasts based on normal and extreme weather. The normal weather forecast has a 50 percent probability of being exceeded and the extreme weather forecast has a 10 percent probability of being exceeded. Due to the lead time required to construct new facilities, planning should be based conservatively on the extreme weather forecast.

3.6.2 Load Levels

To evaluate the sensitivity to daily and seasonal load cycles, many studies require modeling several load levels. The most common load levels studied are peak (100% of the extreme weather peak load forecast), intermediate (70 to 80% of the peak), and light (45 to 55% of the peak). The basis can be either the summer or winter peak forecast. In some areas, both seasons may have to be studied.

Sensitivity to the magnitude of the load assumptions must be evaluated with the assumed generation dispatch to assess the impact of different interactions on transmission circuit loadings and system voltage responses.

3.6.3 Load Balance and Harmonics

Balanced three-phase 60 Hz ac loads are assumed at each Point of Delivery unless a customer specifies otherwise, or if there is information available to confirm the load is not balanced. Balanced loads are assumed to have the following characteristics:

- The active and reactive load of any phase is within 90% to 110% of the load on both of the other phases

- The voltage unbalance between the phases measured phase-to-phase is 3% or less

- The negative phase sequence current (RMS) in any generator is less than the limits defined by the current version of ANSI C50.13

Harmonic voltage and current distortion is required to be within limits recommended by the current version of IEEE Std. 519.

If a customer load is unbalanced or exceeds harmonic limits, then special conditions not addressed in this guide may apply.

3.6.4 Load Power Factor

Load Power Factor for each delivery point is established by the active and reactive load forecast supplied by the customer in accordance with Section 3.5.1. The reactive load may be adjusted as necessary to reflect load power factor observed via the Energy Management System (EMS) or metered data. The Load Power Factor in each area in New England should be consistent with the limits set forth in Operating Procedure 17 (OP17).

3.6.5 Reactive Compensation

Reactive compensation should be modeled as it is designed to operate on the transmission system and, when provided, on the low voltage side of the supply transformers. Reactive compensation on the feeder circuits is assumed to be netted with the load. National Grid should have the data on file, as provided by the generator owners, to model the generator reactive capability as a function of generator active power output for each generator connected to the transmission system.

3.6.6 Generation Dispatch

Analysis of generation sensitivity is necessary to model the variations in dispatch that routinely occur at each load level. The intent is to bias the generation dispatch such that the transfers over select portions of the transmission system are stressed pre-contingency as much as reasonably possible. An exception is hydro generation that should account for seasonal variation in the availability of water.

A merit based generation dispatch should be used as a starting point from which to stress transfers. A merit based dispatch can be approximated based on available information such as fuel type and historical information regarding unit commitment. Interface limits can be used as a reference for stressing the transmission system. Dispatching to the interface limits may stress the transmission system in excess of transfer levels that are considered normal.

3.6.7 Facility Status

The initial conditions assume all existing facilities normally connected to the transmission system are in service and operating as designed or expected. Future facilities should be treated as discussed in Section 3.3.

3.7 Modeling For Stability Studies

3.7.1 Dynamic Models

Dynamic models are required for generators and associated equipment, HVdc terminals, SVCs, other Flexible AC Transmission Systems (FACTS), and protective relays to calculate the fast acting electrical and mechanical dynamics of the power system. Dynamic model data is maintained as required by NERC, NPCC, ISO-NE, and NYSRC.

3.7.2 Load Level and Load Models

The load levels studied in stability studies vary between New England and New York consistent with accepted practices in each Area. Stability studies within New England typically exhibit the most severe system response under light load conditions. Consequently, transient stability studies are typically performed for several unit dispatches at a system load level of 45% of peak system load. At least one unit dispatch at 100% of system peak load is also analyzed. Other system load levels may be studied when required to stress a system interface, or to capture the response to a particular generation dispatch.

Stability studies within New York typically exhibit the most severe system response under summer peak load conditions. Consequently, transient stability studies are typically performed with a system load level of 100% of summer peak system load. Other system load levels may be studied when required to stress a system interface, or to capture the response to a particular generation dispatch.

System loads within New England and New York are usually modeled as constant admittances for both active and reactive power. These models have been found to be appropriate for studies of rotor angle stability and are considered to provide conservative results. Other load models are utilized where appropriate such as when analyzing the underfrequency performance of an islanded portion of the system, or when analyzing voltage performance of a local portion of a system.

Loads outside NEPOOL are modeled consistent with the practices of the individual Areas and regions. Appropriate load models for other Areas and regions are available through NPCC.

3.7.3 Generation Dispatch

Generation dispatch for stability studies typically differs from the dispatch used in thermal and voltage analysis. Generation within the area of interest (generation behind a transmission interface or generation at an individual plant) is dispatched at full output within known system constraints. Remaining generation is dispatched to approximate a merit based dispatch. To minimize system inertia, generators are dispatched fully loaded to the extent possible while respecting system reserve requirements.

3.8 Modeling for Short Circuit Studies

Short Circuit studies are performed to determine the maximum fault duty at a point on the system. Transmission Planning uses this to evaluate circuit breakers fault duty withstand and to determine appropriate fault impedances for modeling unbalanced faults in transient stability studies. Other groups may use the Short Circuit information to evaluate fault duty capability for other equipment on the system. Transmission Planning also uses the fault duty to inform substation engineering of the short circuit currents (recommended and minimum) to be considered for substation design (e.g., equipment ratings, bus work & grounding system design). This requirement is noted on the Project Data Sheet (PDS).

Short Circuit studies for calculating maximum fault duty assume all generators are on line, and all transmission system facilities are in service and operating as designed. When results are used to assess whether the interrupting capability of a circuit breaker will be exceeded, the assessment must consider the switchyard configuration to determine the contribution of the total fault current the circuit breaker must interrupt. The assessment also must consider whether the circuit breaker is total-current rated or symmetrical current rated and oil circuit breakers1 must be derated to account for autoreclosing.

The interrupting capability for symmetrical current rated circuit breakers is assessed using IEEE/ANSI in standard C37.010-1999. This method uses the system X/R ratio at the fault point as defined by the standard, the relay operating time, and the breaker contact parting time to determine a factor that is multiplied by the symmetrical current to arrive at the actual interrupting current. This current is then compared with the circuit breaker interrupting capability. If the breaker is an oil circuit breaker, the interrupting capability would be derated for reclosing duties. Special consideration may be necessary when assessing generating unit breakers.

1IEEE C37.010 Application Guide for AC High-Voltage Circuit Breakers Rated on a Symmetrical Current Basis

Short Circuit studies for determining impedances for modeling unbalanced faults in stability studies typically assume all generators are on line. Switching sequences associated with the contingency may be accounted for in the calculation.

3.9 Modeling for Protection Studies

Conceptual protection system design should be performed to ensure adequate fault detection and clearing can be coordinated for the proposed transmission system configuration in accordance with the National Grid protection philosophy and where applicable, with the NPCC "Bulk Power System Protection Criteria". Preliminary relay settings should be calculated based on information obtained from powerflow, stability, and short circuit studies to ensure feasibility of the conceptual design.

Facilities subject to NPCC Bulk Power System Protection Criteria (BPS) are identified through performance analysis. As a result, analysis may be required to consider whether any recommended changes to the system configuration or protection design would impact the BPS designation of any facility. TGP29 describes this requirement in detail.

When an increase in the thermal rating of main circuit equipment is required, a review of associated protection equipment is necessary to ensure that the desired rating is achieved. The thermal rating of CT secondary equipment must be verified to be greater than the required rating. Also, it is necessary to verify that existing or proposed protective relay trip settings do not restrict loading of the protected element and other series connected elements to a level below the required circuit rating.

3.10 Other Studies

For some applications it may be necessary to include other types of studies. Examples include:

• Switching surge studies to assess voltage transients associated with switching underground cables and capacitors, or to determine minimum approach distances for live-line maintenance on overhead transmission lines.

• Harmonics studies to assess impacts of large converter loads; e.g. HVdc terminals, arc furnaces, or electric rail traction systems.

• Sub-Synchronous Resonance (SSR) studies associated with application of series capacitors or control systems associated with HVdc or Flexible AC Transmission System (FACTS) devices near large turbine-generators.

3.11 Development and Evaluation of Alternatives

If the projected performance or reliability of the system does not conform to the applicable planning criteria, then alternative solutions based on safety, performance, reliability, environmental impacts, and economics need to be developed and evaluated. The evaluation of alternatives leads to a recommendation that is summarized concisely in a report.

3.11.1 Safety

All alternatives shall be designed with consideration to public safety and the safety of operations and maintenance personnel. Characteristics of safe designs include:

• adequate equipment ratings for the conditions studied and margin for unanticipated conditions

• use of standard designs for ease of operation and maintenance

• ability to properly isolate facilities for maintenance

• adequate facilities to allow for staged construction of new facilities or foreseeable future expansion

Consideration shall be given to address any other safety issues that are identified that are unique to a specific project or site.

3.11.2 Performance

The system performance with the proposed alternatives should meet or exceed all applicable design criteria.

3.11.3 Reliability

This guide assesses deterministic reliability by defining the topology, load, and generation conditions that the transmission system must be capable of withstanding safely. This deterministic approach is consistent with NERC, NPCC, ISO-NE, and NYSRC practice. Defined outage conditions that the system must be designed to withstand are listed in Table 4.1. The transmission system is designed to meet these deterministic criteria to promote the reliability and efficiency of electric service on the bulk power system, and also with the intent of providing an acceptable level of reliability to the customers.

Application of this guide ensures that all customers receive an acceptable level of reliability, although the level of reliability provided through this approach will vary. All customers or groups of customers will not necessarily receive uniform reliability due to inherent factors such as differences in customer load level, load shape, proximity to generation, interconnection voltage, accessibility of transmission resources, customer service requirements, and class and vintage of equipment.

3.11.4 Environmental

An assessment should be made for each alternative of the human and natural environmental impacts. Assessment of the impacts is of particular importance whenever expansion of substation fence lines or transmission rights-of-way are proposed. However, environmental impacts also should be evaluated for work within existing substations and on existing transmission structures. Impacts during construction should be evaluated in addition to the impact of the constructed facilities. Evaluation of environmental impacts will be performed consistent with all applicable National Grid policies.

3.11.5 Economics

Initial and future investment cost estimates should be prepared for each alternative. The initial capital investment can often be used as a simple form of economic evaluation. This level of analysis is frequently adequate when comparing the costs of alternatives for which all expenditures are made at or near the same time. Additional economic analysis is required to compare the total cost of each alternative when evaluating more complex capital requirements, or for projects that are justified based on economics such as congestion relief. These analyses should include the annual charges on investments, losses, and all other expenses related to each alternative.

A cash flow model is used to assess the impact of each alternative on the National Grid business plan. A cumulative present worth of revenue requirements model is used to assess the impact of each alternative on the customer. Evaluation based on one or both models may be required depending on the project.

If the justification of a proposed investment is to reduce or eliminate annual expenses, the economic analysis should include evaluation of the length of time required to recover the investment. Recovery of the investment within 5 years is typically used as a benchmark, although recovery within a shorter or longer period may be appropriate.

3.11.6 Technical Preference

Technical preference should be considered when evaluating alternatives. Technical preference refers to concerns such as standard versus non-standard design or to an effort to develop a future standard. It may also refer to concerns such as age and condition of facilities, availability of spare parts, ease of operations and maintenance, ability to accommodate future expansion, ability to implement, or reduction of risk.

3.11.7 Sizing of Equipment

All equipment should be sized based on economics, operating requirements, standard sizes used by the company, and engineering judgment. Economic analysis should account for indirect costs in addition to the cost to purchase and install the equipment. Engineering judgment should include recognition of realistic future constraints that may be avoided with minor incremental expense. As a guide, unless the equipment is part of a staged expansion, the capability of any new equipment or facilities should be sufficient to operate without constraining the system and without major modifications for at least 10 years. As a rough guide, if load growth is assumed to be 1% to 2%, then the minimum reserve margin should be at least 20% above the maximum expected demand on the equipment at the time of installation. However, margins can be less for a staged expansion.

3.12 Recommendation

A recommended action should result from every study. The recommendation includes resolution of any potential violation of the design criteria. The recommended action should be based on composite consideration of factors such as safety, the forecasted performance and reliability, environmental impacts, economics, technical preference, schedule, availability of land and materials, acceptable facility designs, and complexity and lead time to license and permit.

3.13 Reporting Study Results

A transmission system planning study should culminate in a concise report describing the assumptions, procedures, problems, alternatives, economic comparison, conclusions, and recommendations resulting from the study.

4.0 Design Criteria

4.1 Objective of the Design Criteria

The objective of the Design Criteria is to define the design contingencies and measures used to assess the adequacy of the transmission system performance.

4.2 Design Contingencies

The Design Contingencies used to assess the performance of the transmission system are defined in Table 4.1. In association with the design contingencies, this table also includes information on allowable facility loading. Control actions may be available to mitigate some contingencies listed in Table 4.1.

The reliability of local areas of the transmission system may not be critical to the operation of the interconnected NEPOOL system and the New York State Power System. Where this is the case, the system performance requirements for the local area under National Grid design contingencies may be less stringent than what is required by NERC Reliability Standards, NPCC Criteria, ISO-NE Reliability Standards, or NYSRC Reliability Rules.

4.2.1 Fault Type

As specified in Table 4.1, some contingencies are modeled without a fault; others are modeled with a three phase or a single phase to ground fault. All faults are considered permanent with due regard for reclosing facilities and before making any manual system adjustments.

4.2.2 Fault Clearing

Design criteria contingencies involving ac system faults on bulk power system facilities are simulated to ensure that stability is maintained when either of the two independent protection groups that performs the specified protective function operates to initiate fault clearing. In practice, design criteria contingencies are simulated based on the assumption that a single protection system failure has rendered the faster of the two independent protection groups inoperable.

Design criteria contingencies involving ac system faults on facilities that are not part of the bulk power system are simulated based on correct operation of the protection system on the faulted element. Facilities that are not part of the bulk power system must be reviewed periodically to determine whether changes to the power system have caused facilities to become part of the bulk power system. National Grid utilizes for this purpose a methodology based on applying a three-phase fault, uncleared locally, and modeling delayed clearing of remote terminals of any elements that must open to interrupt the fault.

4.2.3 Allowable Facility Loading

The normal rating of a facility defines the maximum allowable loading at which the equipment can operate continuously. The LTE and STE ratings of equipment may allow an elevation in operating temperatures over a specific period provided the emergency loading is reduced back to, or below, a specific loading in a specific period of time (for specific times, see Section 3.4).

The system should be designed to avoid loading equipment above the normal rating prior to a contingency and to avoid loading equipment above the LTE rating following a design contingency (see Table 4.1 contingencies a through i). Under limited

circumstances, however, it is acceptable to design the system such that equipment may be loaded above the LTE rating, but lower than the STE rating. Loading above the LTE rating up to the STE rating is permissible for contingencies b, c, e, f, g, h, and i, for momentary conditions, provided automatic actions are in place to reduce the loading of the equipment below the LTE rating within 15 minutes, and it does not cause any other facility to be loaded above its LTE rating. Such exceptions to the criteria will be well documented and require acceptance by National Grid Network Operations.

The STE rating is dependent on the level of loading prior to applying a contingency. The published STE rating is valid when the pre-contingency loading is within the normal rating. When the pre-contingency loading exceeds the normal rating, the STE rating must be reduced to prevent equipment from exceeding its allowable emergency temperature.

In New England an additional rating, the Drastic Action Limit (DAL), is calculated for use in real-time operations. The DAL is an absolute operating limit, based on the maximum loading to which a piece of equipment can be subjected over a five-minute period without sustaining damage. Although the DAL is computed based on a five minute load duration, if equipment loadings reach a level between the STE and DAL limits, then immediate action is required to reduce loading to below LTE. The DAL is not used in planning studies or for normal operating situations. In some cases when the STE rating may be exceeded, it may be necessary to provide redundant controls to minimize the risk associated with failure of the automated actions to operate as intended.

4.2.4 Reliability of Service to Load

The transmission system is designed to allow the loss of any single element without a resulting loss of load, except in cases where a customer is served by a single supply. Where an alternate supply exists, interruption of load is acceptable for the time required to transfer the load to the alternate supply.

Loss of load is acceptable for contingencies that involve loss of multiple elements such as simultaneous outage of multiple circuits on a common structure, or a circuit breaker failure resulting in loss of multiple elements. For these contingencies, measures should be evaluated to mitigate the frequency and/or the impact of such contingencies when the amount of load interrupted exceeds 100 MW. Such measures may include differential insulation of transmission circuits on a common structure, or automatic switching to restore unfaulted elements. Where such measures are already implemented, they should be assumed to operate as intended, unless a failure to operate as intended would result in a significant adverse impact outside the local area.

A higher probability of loss of customer load is acceptable during an extended generator or transformer outage, maintenance, or construction of new facilities. Widespread outages resulting from contingencies more severe than those defined by the Design Contingencies may result in loss of customer load in excess of 100 MW and/or service interruptions of more than 3 days.

4.2.5 Load Shedding

NPCC requires that each member have underfrequency load shedding capability to prevent widespread system collapse. As a result, load shedding for regional needs is acceptable in whatever quantities are required by the region. In some cases higher quantities of load shedding may be required by the Area or the local System Operator.

Manual or automatic shedding of any load connected to the National Grid transmission system in response to a design contingency listed in Table 4.1 may be employed to maintain system security when adequate facilities are not available to supply load. However, shedding of load is not acceptable as a long term solution to design criteria violations, and recommendations will be made to construct adequate facilities to maintain system security without shedding load.

4.2.6 Expected Restoration Time

The transmission restoration time for the design contingencies encountered most frequently is typically expected to be within 24 hours. Restoration times are typically not more than 24 hours for equipment including overhead transmission lines, air insulated bus sections, capacitor banks, circuit breakers not installed in a gas insulated substation, and transformers that are spared by a mobile substation. For some contingencies however, restoration time may be significantly longer. Restoration times are typically longer than 24 hours for generators, gas insulated substations, underground cables, and large power transformers. When the expected restoration for a particular contingency is expected to be greater than 24 hours, analysis should be performed to determine the potential impacts if a second design contingency were to occur prior to restoration of the failed equipment.

4.2.7 Generation Rejection or Ramp Down

Generation rejection or ramp down refers to tripping or running back the output of a generating unit in response to a disturbance on the transmission system. As a general practice, generation rejection or ramp down should not be included in the design of the transmission system. However, generation rejection or ramp down may be considered if the following conditions apply:

- acceptable system performance (voltage, current, and frequency) is maintained following such action

- the interconnection agreement with the generator permits such action

- the expected occurrence is infrequent (the failure of a single element is not typically considered infrequent)

- the exposure to the conditions is unlikely or temporary (temporary implies that system modifications are planned in the near future to eliminate the exposure or the system is operating in an abnormal configuration).

Generation rejection or ramp down may be initiated manually or through automatic actions depending on the anticipated level and duration of the affected facility loading. Plans involving generation rejection or ramp down require review and approval by National Grid Network Operations, and may require approval of the System Operator.

4.2.8 Exceptions

These Design Criteria do not apply if a customer receives service from National Grid and also has a connection to any other transmission provider regardless of whether the connection is open or closed. In this case, National Grid has the flexibility to evaluate the situation and provide interconnection facilities as deemed appropriate and economic for the service requested.

National Grid is not required to provide service with greater deterministic reliability than the customers provide for themselves. As an example, if a customer has a single transformer, National Grid does not have to provide redundant transmission supplies.

4.3 Voltage Response

Acceptable voltage response is defined in terms of maximum and minimum voltage in per unit (p.u.) for each transmission voltage class (Table 4.2), and in terms of percent voltage change from pre-contingency to post-contingency (Table 4.3). The values in these tables allow for automatic actions that take less than one minute to operate and which are designed to provide post-contingency voltage support. The voltage response also must be evaluated on the basis of voltage transients.

4.4 Stability

4.4.1 System Stability

Stability of the transmission system shall be maintained during and following the most severe of the Design Contingencies in Table 4.1, with due regard to reclosing. Stability shall also be maintained if the outaged element as described in Table 4.1, is re-energized by autoreclosing before any manual system adjustment.

In evaluating the system response it is insufficient to merely determine whether a stable or unstable response is exhibited. There are some system responses which may be considered unacceptable even though the bulk power system remains stable. Each of the following responses is considered an unacceptable response to a design contingency:

• Transiently unstable response resulting in wide spread system collapse.

• Transiently stable response with undamped power system oscillations.

4.4.2 Generator Unit Stability

With all transmission facilities in service, generator unit stability shall be maintained on those facilities that remain connected to the system following fault clearing, for

a. A permanent single-line-to-ground fault on any generator, transmission circuit, transformer, or bus section, cleared in normal time with due regard to reclosing.

b. A permanent three-phase fault on any generator, transmission circuit, transformer, or bus section, cleared in normal time with due regard to reclosing.

Isolated generator instability may be acceptable. However, generator instability will not be acceptable if it results in adverse system impact or if it unacceptably impacts any other entity in the system.

4.5 Generator Low Voltage Ride Through

All generators should be capable of riding through low voltage transient conditions in which Generator Unit Stability is maintained. If there are concerns, it may be necessary to obtain information from generator owners on generator protection settings to confirm that a generator is actually capable of riding through low voltage transient conditions. (Draft NERC Standard PRC-024-1 is to be used as a reference.)

Table 4.1: Design Contingencies

Ref. CONTINGENCY

(Loss or failure of:)

Allowable Facility Loading

a

A permanent three-phase fault on any generator, transmission circuit, transformer, or bus section

LTE

b

Simultaneous permanent single-line-to-ground faults on different phases of two adjacent transmission circuits on a multiple circuit tower (> 5 towers)

2

LTE

1

c

A permanent single-line-to-ground fault on any transmission circuit, transformer, or bus section, with a breaker failure

LTE

1

d

Loss of any element without a fault (including inadvertent opening of a switching device

LTE

e

A permanent single-phase-to-ground fault on a circuit breaker with normal clearing

LTE

1

f

Simultaneous permanent loss of both poles of a bipolar HVdc facility without an ac system fault

LTE

1

g

Failure of a circuit beaker to operate when initiated by an SPS following: loss of any element without a fault, or a permanent single-line-to-ground fault on a transmission circuit, transformer, or bus section

LTE

1

h

Loss of a system common to multiple transmission elements (e.g., cable cooling)

LTE

1

i

Permanent single-line-to-ground faults on two cables in a common duct or trench

LTE

1

Notes: 1 Loading above LTE, but below STE, is acceptable for momentary conditions provided automatic actions are in place to reduce the loading of equipment below the LTE rating within 15 minutes.

2 If multiple circuit towers are used only for station entrance and exit purposes, and if they do not exceed five towers at each station, then this condition is an acceptable risk and therefore can be excluded. Other similar situations can be excluded on the basis of acceptable risk, subject to approval in accordance with Regional (NPCC) and Area (NYSRC or ISO-NE) exemption criteria, where applicable.

Table 4.2: Voltage Range

CONDITION

345 & 230 kV

115 kV

1 & Below

Low Limit

(p.u.)High Limit

(p.u.)Low Limit

(p.u.)High Limit

(p.u.)

Normal Operating

0.98

1.05

0.95

1.05 Post Contingency & Automatic Actions

0.95

1.05

0.90

1.05

1 Buses that are part of the bulk power system, and other buses deemed critical by Network Operations shall meet

requirements for 345 kV and 230 kV buses.

Table 4.3: Maximum Percent Voltage Variation at Delivery Points

CONDITION

345 & 230 kV

(%)

115 kV

1 & Below

(%)

Post Contingency & Automatic Actions

5.0

10.0

Switching of Reactive Sources or Motor Starts (All elements in service)

2.0 *

2.5 *

Switching of Reactive Sources or Motor Starts (One element out of service)

4.0 *

5.0 *

1 Buses that are part of the bulk power system, and other buses deemed critical by Network Operations shall meet

requirements for 345 kV and 230 kV buses. * These limits are maximums which do not include frequency of operation. Actual limits will be considered on a case-

by-case basis and will include consideration of frequency of operation and impact on customer service in the area.

Notes to Tables 4.2 and 4.3: a. Voltages apply to facilities which are still in service post contingency. b. Site specific operating restrictions may override these ranges. c. These limits do not apply to automatic voltage regulation settings which may be more stringent. d. These limits only apply to National Grid facilities.

5.0 Interconnection Design Requirements

5.1 Objective of the Interconnection Design Requirements

The objective of the interconnection design requirements is to provide guidance on the minimum acceptable configurations to be applied when a new generator or transmission line is to be interconnected with the National Grid transmission system. The goal is to assure that reliability and operability are not degraded as a consequence of the new interconnection. National Grid will determine the configuration that appropriately addresses safety, reliability, operability, maintainability, and expandability objectives, consistent with this Transmission Planning Guide for each new or revised interconnection.

5.2 Design Criteria

5.2.1 Safety

Substation arrangements shall be designed with safety as a primary consideration. Standard designs shall be utilized for ease of operation and maintenance and to promote standardization of switching procedures. Substation arrangements shall also provide means to properly isolate equipment for maintenance and allow appropriate working clearances for installed equipment as well as for staged construction of future facilities. Consideration shall be given to address any other safety issues that are identified that are unique to a specific project or site.

5.2.2 Planning and Operating Criteria

Substation arrangements shall be designed such that all applicable Planning and Operating Criteria are met. These requirements may require ensuring that certain system elements do not share common circuit breakers or bus sections so as to avoid loss of both elements following a breaker fault or failure; either by relocating one or both elements to different switch positions or bus sections or by providing two circuit breakers in series. These requirements may also require that existing substation arrangements be reconfigured, e.g. from a straight bus or ring bus to a breaker-and-a-half configuration.

5.2.3 System Protection

Substation arrangements shall provide for design of dependable and secure protection systems. Designs that create multi-terminal lines shall not be allowed except in cases where Protection Engineering verifies that adequate coordination and relay sensitivity can be maintained when infeed or outfeed fault current is present.

To ensure reliable fault clearing, it generally is desirable that no more than two circuit breakers be required to be tripped at each terminal to clear a fault on a line or cable circuit. For transformers located within the substation perimeter, the incidence of faults is sufficiently rare that this requirement may be relaxed to permit transformers to be connected directly to the buses in breaker-and-a-half or breaker-and-a-third arrangements.

5.2.4 Reliability

Factors affecting transmission reliability shall be considered in interconnection designs. These factors include, but are not limited to:

• additional exposure to transmission outages resulting from additional transmission line taps, with consideration to length of the proposed tap,

• the number of other taps already existing on the subject line. In general, new taps will be avoided if three or more taps already exist,

• the number and type of customers already existing on the subject line and potential impacts to these customers resulting from a proposed interconnection,

• the existing performance of the subject line and how the proposed interconnection will affect that performance, and

• the impact on the complexity of switching requirements, and the time and personnel required to perform switching operations.

Periodic transmission assessments shall consider whether system modifications are necessary to improve reliability in locations where greater than three taps exist on a single transmission line.

5.2.5 Operability

Substation switching shall be configured to prevent the loss of generation for normal line operations following fault clearing. Generators shall not be connected directly to a transmission line through a single circuit breaker position except as noted in Section 5.4.2.

5.2.6 Maintainability

Substations shall be configured to permit circuit breaker maintenance to be performed without taking lines or generators out of service, recognizing that a subsequent fault on an element connected to the substation might result in the isolation of more than the faulted element. At existing substations with straight bus configurations, consideration will be given to modifying terminations in cases where an outage impacts the ability to operate the system reliably.

5.2.7 Future Expansion

Substation designs shall be based on the expected ultimate layout based on future existing system needs and physical constraints associated with the substation plot.

5.3 Standard Bus Configurations

Given the development of the transmission system over time and through mergers and acquisitions of numerous companies, several different substation arrangements exist within the National Grid system. Future substation designs are standardized on breaker-and-a-half, breaker-and-a-third, and ring bus configurations, depending on the number of elements to be terminated at the station. Other substation configurations may be retained at existing substations, but are evaluated in periodic transmission assessments to consider whether continued use of such configurations is consistent with the reliable operation of the transmission system.

Determination of the appropriate substation design is based on the total number of elements to be terminated in the ultimate layout, and how many major transmission elements will be terminated. Guidance is also available in ISO-NE Planning Policy 9 (PP9 Major Substation Bus

Arrangement Application Guidelines). Major transmission elements include networked transmission lines 115 kV and above and power transformers with at least one terminal connected at 230 kV or 345 kV.

5.3.1 Breaker-and-a-Half

A breaker-and-a-half configuration is the preferred substation arrangement for new substations with an ultimate layout expected to terminate greater than four major transmission elements or greater than six total elements. If the entire ultimate layout is not constructed initially, the substation may be configured initially in a ring bus configuration. Cases will exist where a breaker-and-a-half configuration is required with fewer elements terminated in order to meet the criteria stated above.

Major transmission elements are terminated in a bay position between two circuit breakers in a breaker-and-a-half configuration. Other elements such as capacitor banks, shunt reactors, and radial 115 kV transmission lines may be terminated on the bus through a single circuit breaker. Transformers with no terminal voltage greater than 115 kV may be terminated directly on a bus. It may be permissible to terminate 345-115 kV or 230-115 kV transformers directly on a 115 kV bus if there is no reasonable expectation that more than two such transformers will be installed. Such a decision requires careful consideration however, given the difficulty of re-terminating transformers to avoid tripping two transformers for a breaker fault or failure in the event that a third transformer is installed at a later time.

5.3.2 Breaker-and-a-Third

A breaker-and-a-third configuration is an acceptable alternate to a breaker-and-a-half configuration in cases where a breaker-and-a-half arrangement is not feasible due to physical or environmental constraints. Considerations for terminating elements on a bus are the same as for breaker-and-a-half, except that 345-115 kV or 230-115 kV transformers may be terminated directly on a 115 kV bus since additional transformers may be terminated in a bay without a common breaker between two transformers.

5.3.3 Ring Bus

A ring bus may be utilized for new substations where four or fewer major elements will be terminated or six or fewer total elements will be terminated. A ring bus also may be utilized as an interim configuration during staged construction of a substation.

5.3.4 Straight Bus

Many older substations on the system have a straight bus configuration, with each element terminating on the bus through a single breaker. Variations exist in which the bus is segmented by one or more bus-tie breakers, provisions are provided for a transfer bus, or the ability exists to transfer some or all elements from the main bus to an emergency bus. Periodic transmission assessments shall consider whether continued use of existing straight bus configurations is consistent with maintaining reliable operation of the transmission system.

New bulk power system substations shall not utilize a straight bus design. Straight bus designs may be utilized at non-bulk power system substations subject to the following conditions:

• A transfer bus is provided to facilitate circuit breaker maintenance.

• The transfer breaker protection system is capable of being coordinated to provide adequate protection for any element connected to the bus.

• Justification is provided to support deviating from the standard breaker-and-a-half, breaker-and-a-third, or ring bus configuration.

• All requirements of Section 5.2 are met.

5.4 Substation Design Considerations

5.4.1 NPCC Bulk Power System Design Requirements

When an element has been identified as part of the NPCC bulk power system, the protection system for that element must be designed to meet the NPCC Directory #4 Bulk Power System Protection Criteria. These criteria require redundancy and separation of protection system components and have a significant impact on physical space requirements as well as project scope, schedule, and cost. These impacts typically are greatest when modifications are required at existing substations. Given that these impacts can be significant, it is appropriate to consider designing and in some cases pre-building facilities to meet these requirements to avoid more costly retrofitting at a later time. The following guidance is provided for cases where facilities have been identified as part of the NPCC bulk power system2, have the potential to become bulk power system facilities, or are unlikely to become bulk power system facilities.

5.4.1.1 NPCC bulk power system facilities: These facilities have been identified as part of the bulk power system through application of the NPCC A-10 Criteria for Classification of Bulk Power System Elements.

These facilities always are designed and constructed to meet NPCC Criteria.

5.4.1.2 Potential NPCC bulk power system facilities: These facilities have not been identified as part of the bulk power system through application of the NPCC A-10 Criteria for Classification of Bulk Power System Elements, but have been identified as potential bulk power system facilities through the results of testing (e.g. marginally acceptable results), proximity to existing bulk power system facilities, or are reasonably expected to become part of the bulk power system due to proposed transmission reinforcements within the 10-year planning horizon. The extent to which facilities will be designed and constructed to meet NPCC Criteria must consider scope, schedule, and cost of future modifications of the facilities compared to the incremental scope, schedule, and cost of designing or constructing to meet NPCC Criteria as part of the project.

New substations are expected to be designed to meet NPCC Criteria, but are not expected to be constructed to meet NPCC Criteria except where the incremental cost is minimal, e.g. circuit breakers purchased with two current transformers per bushing and two trip coils. Locations are identified for future batteries, cable conduits, etc. and incorporated into drawings.

Modifications at existing substations must consider the extent of work related to the project compared to future work that may be required to meet NPCC Criteria.

If major modifications are being made at a substation and deferring design to meet NPCC Criteria would significantly increase future scope, schedule, and cost; then incorporating the design changes in the project to meet NPCC Criteria must be considered.

2The List of Bulk Power System Elements is maintained through testing included as part of NERC Compliance Studies, System Impact

Studies, and local area transmission studies. Results of these studies are provided to the appropriate ISO to initiate the process for updating the list as provided in Section 5.0 of TGP29 “Maintenance of the National Grid List of Bulk Power System Elements”. TGP29 provides detailed information on how National Grid applies the NPCC A-10 Criteria in these studies.

If minor modifications are being made at a substation, then the facilities are designed to meet NPCC Criteria only when there will not be a significant impact on the scope, schedule, or cost of the project.

5.4.1.3 System facilities Unlikely to be Classified as NPCC Bulk Power: These facilities have not been identified as bulk through application of the NPCC A-10 Criteriafor Classification of Bulk Power System Elements, and are unlikely to become part of the bulk power system within the 10-year planning horizon.

These facilities are not designed or constructed to meet NPCC Criteria.

5.4.2 Independent Pole Tripping Circuit Breakers

Circuit breakers with independent pole tripping (IPT) capability may be installed to mitigate the impact of an extreme contingency three-phase fault accompanied by a breaker failure. The independent operating mechanisms and control circuitry for each pole of the circuit breaker result in a high probability that a breaker failure will result in a failure to interrupt the fault current in only one breaker pole. In simulations of these extreme contingencies the fault is downgraded from three-phase to single-line-to-ground after failure of a circuit breaker with IPT capability and clearing of other sources contributing to the fault.

The National Grid standard design specification for 345 kV circuit breakers requires IPT capability for all applications. At transmission voltages 230 kV and below, circuit breakers with IPT capability are installed based on a case-by-case review considering the potential impact to be mitigated and the incremental cost of the circuit breaker application. The incremental cost consists of two components. The first component is the incremental equipment cost for purchasing the circuit breaker. The second component is associated with additional auxiliary relays and increased control wiring requirements.

Circuit breakers with IPT capability are applied at transmission voltages 230 kV and below when transient stability simulations of three-phase faults accompanied by a breaker failure indicate a basic system weakness that jeopardizes the integrity of the overall bulk power system. In these cases adding or replacing circuit breakers with IPT capability is justified to comply with NPCC Directory #1, Design and Operation of the Bulk Power System.

When 230 kV or 115 kV circuit breakers are added or replaced at bulk power system substations, IPT capability should be considered when there will not be a significant impact on the scope, schedule, or cost of the project. In these cases the incremental cost is justified to avoid the potential for significant cost to replace the circuit breakers later if system changes result in a basic system weakness that jeopardizes the integrity of the overall bulk power system.

5.4.3 Placement of Surge Arrestors

Surge arrestors are sometimes applied on substation buses at air-insulated substations. Surge arrestors also are applied on equipment terminals when the element connected to the bus is an underground cable or transformer.

Surge arrestors also may be applied on line terminals at air-insulated substations to limit transient overvoltage at 230 kV and 345 kV. The need for line arrestors is determined on case-by-case basis either instead of or in addition to pre-insertion closing resistors in the circuit breakers at the remote line terminal. In these cases a line arrestor may be necessary to control switching surges when the line is energized from the remote

terminal when the local terminal is open (in which case the bus arrestor cannot control the switching surge).

Surge arresters are applied on equipment terminals for all elements connected to a gas-insulated substation via SF6 to air bushings.

5.5 Issues Specific to Generator Interconnections

5.5.1 Interconnection Voltage

It is desirable to connect generators at the lowest voltage class available in the area for which an interconnection is feasible. In general, small generators no larger than 20 MW will be interconnected to the transmission system only when there is no acceptable lower voltage alternative in the area and it is not feasible to develop a lower voltage alternative.

5.5.2 Interconnection Facilities

The minimum interconnection required for all generators is a three-breaker ring bus. Additional circuit breakers and alternate substation configurations may be required when interconnecting multiple generating units. Generators shall not be connected directly to a transmission line through a single circuit breaker position unless an exception is granted as noted below.

Exceptions to the Generators Interconnection Requirements

Exceptions may be granted for either of the following two conditions: (1) generators connected to radial transmission lines, and (2) small generators no larger than 20 MW. Exceptions shall be evaluated on a case-by-case basis and shall be granted only when the following conditions are met:

• Protection Engineering verifies that the transmission line and interconnection facilities can be protected adequately, while ensuring that transmission system protective relay coordination and relay sensitivity can be maintained.

• Transmission Planning verifies that transmission reliability is not adversely impacted by assessing the Design Criteria listed above in Section 5.2 above pertaining to safety, planning and operating criteria, reliability, and maintainability.

• Provisions acceptable to National Grid are made to accommodate future expansion of the interconnection to at least a three-breaker ring bus.

5.5.3 Status of Interconnection Design

The design for any generator interconnection is valid only for the generating capacity and unit characteristics specified by the developer at the time of the request. Any modifications to generating capacity and unit characteristics require a separate system impact study and may result in additional interconnection requirements.

Modifications to the interconnection design may be required as a result of future modifications to the transmission system. National Grid will notify the generation owner when such modifications are required.

5.5.4 Islanding of Load and Generation

System operation with generation and customer load islanded from the transmission system is undesirable due to frequency and voltage fluctuations that likely will occur as a result of an imbalance between load and generation. When the potential exists for islanding load and generation for N-1 or N-1-1 contingencies, the interconnection

protection must be designed to detect when the generation is islanded with load to ensure tripping of the generator. The protection requirements are relatively straight-forward when the maximum output of the generation is less than the minimum connected load. When it is possible for the load and generation to be balanced detection is more difficult and direct transfer tripping of the generator may be required.

6.0 Glossary of Terms

Bulk Power System The interconnected electrical system comprising generation and transmission facilities on which faults or disturbances can have a significant impact outside the local area.

Contingency An event, usually involving the loss of one or more elements, which affects the power system at least momentarily.

ElementAny electric device with terminals which may be connected to other electric devices, such as a generator, transformer, transmission circuit, circuit breaker, an HVdc pole, braking resistor, a series or shunt compensating device or bus section. A live-tank circuit breaker is understood to include its associated current transformers and the bus section between the breaker bushing and its free standing current transformer(s).

Fault Clearing - Delayed Fault Clearance consistent with correct operation of a breaker failure protection group and its associated breakers or of a backup protection group with an intentional time delay.

Fault Clearing - Normal Fault Clearance consistent with correct operation of the protection system and with correct operation of all circuit breakers or other automatic switching devices intended to operate in conjunction with that protection system. Note: Zone 2 clearing of line-end faults on lines without pilot protection is normal clearing, not delayed clearing, even though a time delay is required for coordination purposes.

High Voltage dc (HVdc) System, Bipolar An HVdc system with two poles of opposite polarity and negligible ground current.

InterfaceA group of transmission lines connecting two areas of the transmission system.

Load Cycle The normal pattern of demand over a specified time period (typically 24 hours) associated with a device or circuit.

Load Level A scale factor signifying the total load relative to peak load or the absolute magnitude of load for the year referenced.

Loss of Customer Load (or Loss of Load) Loss of service to one or more customers for longer than the time required for automatic switching.

Point(s) of Delivery The point(s) at which the Company delivers energy to the Transmission Customer.

National Grid TGP28 Issue 3 – 22 November 2010

UNCONTROLLED WHEN PRINTED 29 USA Operations

Special Protection Systems A protection system designed to detect abnormal system conditions and take corrective action other than the isolation of faulted elements. Such action may include changes in load, generation, or system configuration to maintain system stability, acceptable voltages, or power flows. Automatic underfrequency load shedding and conventionally switched locally controlled shunt devices are not considered to be SPSs.

Supply Transformer Transformers that only supply distribution load to a single customer.

TransferThe amount of electrical power that flows across a transmission circuit or interface.

Transmission Customer Any entity that has an agreement to receive wholesale service from the National Grid transmission system.

Transmission Transformer Any transformer with two or more transmission voltage level windings or a transformer serving two or more different customers.

Appendix 2-9

Worst Case

Load Flow Results

The appendix material has been redacted for Critical

Energy Infrastructure Information (CEII).