Environmental Assessment for the

Cove Point Liquefaction Project

May 2014

Dominion Cove Point LNG, LP Docket No. CP13-113-000

Federal Energy Regulatory Commission

Office of Energy Projects

Washington, DC 20426

Cooperating Agencies:

U.S. Army 

Corps of Engineers U.S. Coast Guard U.S. Department 

of Transportation

Federal Energy

Regulatory Commission

Office of Energy Projects

Washington, DC 20426 Office of Fossil Energy

DOE Docket No. FE 11-128-LNG
This environmental assessment was prepared by the staff of the 

Federal Energy Regulatory Commission to assess the potential 

environmental impacts of the Cove Point Liquefaction Project (Docket 

No. CP13-113-000), proposed for construction in Maryland and 

Virginia. The cooperation and assistance of the U.S. Department of 

Energy, U.S. Army Corps of Engineers, U.S. Department of 

Transportation, U.S. Coast Guard, and Maryland Department of 

Natural Resources was greatly appreciated.
FEDERAL ENERGY REGULATORY COMMISSION

WASHINGTON, D.C. 20426

OFFICE OF ENERGY PROJECTS In Reply Refer To:

OEP/DG2E/Gas 2

Dominion Cove Point LNG, LP

Cove Point Liquefaction Project

Docket No. CP13-113-000

TO THE PARTY ADDRESSED:

The staff of the Federal Energy Regulatory Commission (FERC or Commission) 

has prepared an environmental assessment (EA) for the Cove Point Liquefaction Project 

(Project) proposed by Dominion Cove Point LNG, LP (DCP) in the above-referenced 

docket. DCP requests authorization to construct and operate facilities to process and 

export domestically sourced liquefied natural gas (LNG) at the existing Cove Point LNG 

Terminal (LNG Terminal) in Calvert County, Maryland. The Project would enable DCP 

to export approximately 5.75 million metric tons per annum of LNG via LNG marine 

carriers that would dock at the existing offshore pier. A draft General Conformity 

Determination has also been prepared by the FERC to assess the potential air quality 

impacts associated with construction and operation of the proposed Project and is 

included as appendix B of this EA.

The EA assesses the potential environmental effects of the construction and 

operation of the Project in accordance with the requirements of the National 

Environmental Policy Act (NEPA). The draft General Conformity Determination was 

prepared to implement the conformity provision of the Clean Air Act. The FERC staff 

concludes that approval of the proposed Project, with appropriate mitigating measures, 

would not constitute a major federal action significantly affecting the quality of the 

human environment.

The U.S. Department of Energy, U.S. Department of Transportation, U.S. Army 

Corps of Engineers, U.S. Coast Guard, and Maryland Department of Natural Resources

participated as cooperating agencies in the preparation of the EA and draft General 

Conformity Determination. Cooperating agencies have jurisdiction by law or special 

expertise with respect to resources potentially affected by the proposal and participate in 

the NEPA analysis.

The proposed facilities associated with the LNG Terminal include the following: 
2

 one LNG liquefaction train consisting of gas treatment equipment, natural 

gas-fired turbine-driven refrigerant compressors, waste heat recovery 

systems, fire and gas detection and safety systems, and control systems;

 additional power generation including waste heat-driven steam turbine 

generators and other electrical accessories to supplement the existing onsite power generation;

 minor modifications to the existing pier; and

 the use of two off-site areas to support construction.

The Project would also include the addition of up to 62,500 horsepower of 

electric-driven compression at DCP’s existing Pleasant Valley Compressor Station in 

Fairfax County, Virginia, and modifications to an existing metering and regulating 

facility at DCP’s Loudoun Compressor Station in Loudoun County, Virginia.

The FERC staff mailed copies of the EA and draft General Conformity 

Determination to federal, state, and local government representatives and agencies; 

elected officials; environmental and public interest groups; Native American tribes; 

potentially affected landowners and other interested individuals and groups; libraries in 

the Project area; and parties to this proceeding. In addition, the EA, including the draft 

General Conformity Determination, has been placed in the public files of the FERC and 

is available for public viewing on the FERC’s website at www.ferc.gov using the 

eLibrary link. A limited number of copies of the EA and draft General Conformity 

Determination are also available for distribution and public inspection at: 

Federal Energy Regulatory Commission

Public Reference Room

888 First Street NE, Room 2A

Washington, DC 20426

(202) 502-8371

Any person wishing to comment on the EA and draft General Conformity 

Determination may do so. Your comments should focus on the potential environmental 

effects, reasonable alternatives, and measures to avoid or lessen environmental impacts. 

The more specific your comments, the more useful they will be. To ensure that your 

comments are properly recorded and considered prior to a Commission decision on the 

proposal, it is important that the FERC receives your comments in Washington, DC on or 

before June 16, 2014.

For your convenience, there are four methods you can use to submit your 

comments to the Commission. In all instances please reference the Project docket 
____________________ 

1

 See the previous discussion on the methods for filing comments.

3 

number (CP13-113-000) with your submission. The Commission encourages electronic 

filing of comments and has expert staff available to assist you at (202) 502-8258 or 

efiling@ferc.gov. 

(1) You can file your comments electronically by using the eComment feature, 

which is located on the Commission’s website at www.ferc.gov under the 

link to Documents and Filings. This is an easy method for interested 

persons to submit brief, text-only comments on a project; 

(2) You can file your comments electronically by using the eFiling feature 

on the Commission’s website at www.ferc.gov under the link to Documents 

and Filings. With eFiling, you can provide comments in a variety of 

formats by attaching them as a file with your submission. New eFiling 

users must first create an account by clicking on “eRegister.” You must 

select the type of filing you are making. A comment on a particular project 

is considered a “Comment on a Filing;” or 

 

(3) You may file a paper copy of your comments at the following address: 

Kimberly D. Bose, Secretary 

Federal Energy Regulatory Commission 

888 First Street NE, Room 1A 

Washington, DC 20426 

(4) In lieu of sending written or electronic comments, the Commission invites 

you to attend a public comment meeting that its staff will conduct in the 

Project area to receive comments on the EA and draft General Conformity 

Determination. We encourage interested groups and individuals to attend 

and present oral comments on the EA and draft General Conformity 

Determination. A transcript of the meeting will be available for review in 

eLibrary under the Project docket number. The meeting is scheduled as 

follows: 

Date and Time Location 

Saturday, May 31, 2014 

1:00 – 6:00 p.m. 

Patuxent High School 

12485 Southern Connector Boulevard 

Lusby, MD 20657 

Any person seeking to become a party to the proceeding must file a motion to 

intervene pursuant to Rule 214 of the Commission’s Rules of Practice and Procedures (18 

CFR 385.214).1

 Only intervenors have the right to seek rehearing of the Commission’s 
4

decision. The Commission grants intervenor status to affected landowners and others

with environmental concerns who show good cause by stating that they have a clear and 

direct interest in this proceeding which no other party can adequately represent. Simply 

filing comments will not grant you intervenor status, but you do not need intervenor 

status to have your comments considered.

Additional information about the Project is available from the Commission’s 

Office of External Affairs, at (866) 208-FERC, or on the FERC website (www.ferc.gov) 

using the eLibrary link. Click on the eLibrary link, click on “General Search,” and enter 

the docket number excluding the last three digits in the Docket Number field (i.e., CP13-

113). Be sure you have selected an appropriate date range. For assistance, please contact 

FERC Online Support at FercOnlineSupport@ferc.gov or toll free at (866) 208-3676, or 

for TTY, contact (202) 502-8659. The eLibrary link also provides access to the texts of 

formal documents issued by the Commission, such as orders, notices, and rulemakings.

In addition, the Commission offers a free service called eSubscription which 

allows you to keep track of all formal issuances and submittals in specific dockets. This 

can reduce the amount of time you spend researching proceedings by automatically 

providing you with notification of these filings, document summaries, and direct links to 

the documents. Go to http://www.ferc.gov/docs-filing/esubscription.asp.

 Kimberly D. Bose,

 Secretary
i

TABLE OF CONTENTS

Cove Point Liquefaction Project

Environmental Assessment

Page

1.0 PROPOSED ACTION................................................................................................................... 1

1.1 INTRODUCTION .............................................................................................................. 1

1.2 PROPOSED FACILITIES.................................................................................................. 2

1.2.1 Liquefaction Facilities ........................................................................................... 3

1.2.2 Virginia Facilities ................................................................................................ 10

1.2.3 Offsite Areas........................................................................................................ 13

1.2.4 Access Roads....................................................................................................... 16

1.3 NONJURISDICTIONAL FACILITIES AND ACTIVITIES........................................... 16

1.3.1 Nonjurisdictional Facilities.................................................................................. 16

1.3.2 Other Related Activities....................................................................................... 18

1.4 PROJECT PURPOSE AND NEED.................................................................................. 18

1.5 SCOPE OF THIS ENVIRONMENTAL ASSESSMENT................................................ 19

1.5.1 Federal Energy Regulatory Commission............................................................. 19

1.5.2 U.S. Department of Energy Role ......................................................................... 20

1.5.3 U.S. Coast Guard Role......................................................................................... 20

1.5.4 U.S. Department of Transportation Role ............................................................. 20

1.5.5 U.S. Army Corps of Engineers Role.................................................................... 21

1.5.6 Maryland Department of Natural Resources Role............................................... 21

1.6 PUBLIC REVIEW AND COMMENT............................................................................. 21

1.7 CONSTRUCTION, OPERATION, AND MAINTENANCE .......................................... 25

1.7.1 General Procedures.............................................................................................. 25

1.7.2 Liquefaction Facilities ......................................................................................... 26

1.7.3 Offsite Areas........................................................................................................ 27

1.7.4 Virginia Facilities ................................................................................................ 29

1.8 ENVIRONMENTAL COMPLIANCE INSPECTION AND MONITORING ................ 30

1.9 LAND REQUIREMENTS................................................................................................ 32

1.10 PERMITS, APPROVALS, AND REGULATORY CONSULTATIONS........................ 33

1.11 FUTURE PLANS AND ABANDONMENT ................................................................... 35

2.0 ENVIRONMENTAL ANALYSIS.............................................................................................. 36

2.1 GEOLOGY AND SOILS ................................................................................................. 36

2.1.1 Geologic Setting, Mineral Resources, and Geologic Hazards............................. 36

2.1.2 Design and Construction of the Cove Point Liquefaction Facilities and 

Pleasant Valley Compressor Station.................................................................... 40

2.1.3 Soils ..................................................................................................................... 43

2.2 WATER RESOURCES, FISHERIES, AND WETLANDS............................................. 44

2.2.1 Groundwater ........................................................................................................ 44

2.2.2 Surface Water ...................................................................................................... 48

2.2.3 Fisheries Resources.............................................................................................. 55

2.2.4 Wetlands.............................................................................................................. 58

2.3 VEGETATION AND WILDLIFE ................................................................................... 60

2.3.1 Vegetation............................................................................................................ 60

2.3.2 Wildlife ................................................................................................................ 64

2.3.3 Protected Species................................................................................................. 66

2.4 LAND USE, RECREATION, AND VISUAL RESOURCES ......................................... 75
ii

2.4.1 Existing Land Use................................................................................................ 75

2.4.2 Recreation and Special Interest Areas ................................................................. 77

2.4.3 Existing Residences and Planned Future Developments..................................... 81

2.4.4 Coastal Zone Management .................................................................................. 83

2.4.5 Visual Resources.................................................................................................. 83

2.5 SOCIOECONOMICS....................................................................................................... 86

2.5.1 Population, Economy, and Employment ............................................................. 86

2.5.2 Housing................................................................................................................ 88

2.5.3 Public Services..................................................................................................... 89

2.5.4 Transportation and Traffic ................................................................................... 89

2.5.5 Property Values.................................................................................................... 91

2.5.6 Tax Revenues....................................................................................................... 91

2.5.7 Environmental Justice.......................................................................................... 92

2.6 CULTURAL RESOURCES............................................................................................. 92

2.6.1 Cultural Resources Investigations........................................................................ 93

2.6.2 Native American Consultation............................................................................. 94

2.6.3 Unanticipated Discovery Plan ............................................................................. 95

2.6.4 Compliance with the National Historic Preservation Act.................................... 95

2.7 AIR QUALITY AND NOISE .......................................................................................... 95

2.7.1 Air Quality ........................................................................................................... 95

2.7.2 Noise .................................................................................................................. 116

2.8 RELIABILITY AND SAFETY...................................................................................... 123

2.8.1 Virginia Facilities .............................................................................................. 123

2.8.2 Regulatory Agencies.......................................................................................... 124

2.8.3 Hazards.............................................................................................................. 125

2.8.4 Technical Review of the Preliminary Engineering Design................................ 131

2.8.5 Siting Requirements........................................................................................... 142

2.8.6 Siting Analysis................................................................................................... 145

2.8.7 Emergency Response......................................................................................... 158

2.8.8 Facility Security and LNG Vessel Safety .......................................................... 158

2.8.9 Conclusions on Facility Reliability and Safety.................................................. 159

2.9 CUMULATIVE IMPACTS............................................................................................ 159

2.9.1 Projects and Activities Considered .................................................................... 160

2.9.2 Geology and Soils.............................................................................................. 164

2.9.3 Waterbodies and Wetlands ................................................................................ 164

2.9.4 Vegetation and Wildlife..................................................................................... 165

2.9.5 Land Use, Recreation, and Visual Resources.................................................... 165

2.9.6 Socioeconomics................................................................................................. 166

2.9.7 Cultural Resources............................................................................................. 167

2.9.8 Air Quality and Noise ........................................................................................ 168

2.9.9 Climate Change.................................................................................................. 169

2.9.10 Safety ................................................................................................................. 172

2.9.11 Conclusion ......................................................................................................... 172

3.0 ALTERNATIVES...................................................................................................................... 173

3.1 NO ACTION ALTERNATIVE...................................................................................... 173

3.2 ALTERNATIVE ENERGY............................................................................................ 173

3.3 SYSTEM ALTERNATIVES.......................................................................................... 175

3.3.1 Other LNG Terminal Alternatives..................................................................... 175

3.3.2 Other Pipeline Alternatives................................................................................ 176

3.3.3 Compression Alternatives.................................................................................. 177
iii

3.4 LIQUEFACTION FACILITIES DESIGN ALTERNATIVES ...................................... 178

3.5 ALTERNATIVE WATER SOURCES FOR THE LIQUEFACTION FACILITIES..... 178

3.6 OFFSITE AREA ALTERNATIVES.............................................................................. 179

3.6.1 Offsite Area A Alternatives............................................................................... 179

3.6.2 Offsite Area B Alternatives ............................................................................... 184

4.0 CONCLUSIONS AND RECOMMENDATIONS................................................................... 186

5.0 REFERENCES........................................................................................................................... 199

6.0 LIST OF PREPARERS............................................................................................................. 205

LIST OF TABLES

Table 1.6-1 Issues Identified in Comments Received During the Public and Agency Scoping 

Process............................................................................................................................22

Table 1.9-1 Summary of Land Requirements....................................................................................32

Table 1.10-1 Major Environmental Permits, Licenses, Approvals, and Certificates for 

Construction, Operation, and Maintenance of the Project .............................................33

Table 2.2.1-1 Potable Water Supply Wells and Springs within 150 feet of Proposed Project 

Construction Workspaces...............................................................................................46

Table 2.2.2-1 Impacts on Waterbodies within the Project Sites...........................................................49

Table 2.2.3-1 NMFS Managed Fish Species Near the LNG Terminal and Offsite Area B .................56

Table 2.2.4-1 Summary of Wetlands Affected by the Project..............................................................59

Table 2.3.1-1 Upland Vegetation Cover Types Found within the Project Area...................................61

Table 2.3.1-2 Project Impacts on Upland Vegetation (acres)...............................................................62

Table 2.3.3-1 Birds of Conservation Concern Within the Proposed Project Area ...............................67

Table 2.3.3-2 State-Listed Threatened and Endangered Species Identified in the Vicinity of the 

Project ............................................................................................................................73

Table 2.3.3-3 Rare and Uncommon Plant Species Identified by the MDNR at St. Paul’s Branch ......75

Table 2.4.1-1 Land Use Affected by Construction and Operation of the Cove Point Liquefaction 

Project ............................................................................................................................76

Table 2.5.1-1 Existing Economic Conditions in the Project Area........................................................87

Table 2.5.2-1 Housing Statistics by County in the Project Area ..........................................................88

Table 2.7.1-1 Climate Data for Project Area ........................................................................................96

Table 2.7.1-2 National Ambient Air Quality Standards.......................................................................97

Table 2.7.1-3 Ambient Air Quality Concentrations in the Project Area ..............................................98

Table 2.7.1-4 Total Construction and Non-Permitted Project Emissions Summary ..........................106

Table 2.7.1-5 Total Construction Emissions Summary......................................................................109

Table 2.7.1-6 Liquefaction Facilities Potential Emissions Summary.................................................112

Table 2.7.1-7 Pleasant Valley Compressor Station Potential Emissions Summary (tons/year).........112

Table 2.7.1-8 LNG Terminal SIL Analysis Summary........................................................................114

Table 2.7.1-9 LNG Terminal NAAQS Analysis Summary................................................................115

Table 2.7.2-1 Sound Level Predictions – Liquefaction Facilities.......................................................121

Table 2.7.2-2 Sound Level Predictions – Pleasant Valley Compressor Station .................................122

Table 2.8.6-1 Impoundment Area Sizing ...........................................................................................147

Table 2.8.6-2 Vapor Dispersion Scenarios from Process Releases....................................................153

Table 2.8.6-3 Acute Exposure Guideline Levels (in ppm) at 10 minutes...........................................153

Table 2.8.6-4 Overpressure Distances from Refrigerant and Heavy Hydrocarbon Releases.............155

Table 2.8.6-5 Thermal Radiation Exclusion Zones for Impoundment Basins ...................................156

Table 2.9-1 Existing or Proposed Projects Evaluated for Potential Cumulative Impacts................161
iv

Table 3.6.1-1 Comparison of Offsite Area A Alternatives.................................................................182

LIST OF FIGURES

Figure 1.2-1 Project Overview Map .....................................................................................................4

Figure 1.2.1-1 LNG Terminal and Offsite Support Areas.......................................................................5

Figure 1.2.1-2 LNG Terminal Detail .......................................................................................................6

Figure 1.2.1-3 Liquefaction Facilities......................................................................................................7

Figure 1.2.2-1 Pleasant Valley Compressor Station, Suction/Discharge Pipelines, and M&R 

Facility............................................................................................................................11

Figure 1.2.2-2 Loudoun M&R Facility and Leesburg Compressor Station Contractor Staging Area...12

Figure 1.2.3-1 Offsite Area A................................................................................................................14

Figure 1.2.3-2 Offsite Area B ................................................................................................................15

Figure 2.8.6-1 Vapor and Sound Barrier Locations...........................................................................151

Figure 2.8.6-2 Impoundment 10,000, 3,000, and 1,600-Btu/ft2-hr Thermal Radiation Exclusion 

Zones............................................................................................................................157

Figure 3.6.1-1 Offsite Area Alternatives .............................................................................................180

LIST OF APPENDICES

APPENDIX A SOIL CHARACTERISTICS AFFECTED BY THE PROJECT

APPENDIX B GENERAL CONFORMITY ANALYSIS

TECHNICAL ACRONYMS AND ABBREVIATIONS

°F degrees Fahrenheit 

μg/m3 micrograms per cubic meter

μg/Nm3 micrograms per normal cubic meter

ACHP Advisory Council on Historic Preservation

AEGL Acute Exposure Guideline Level

AGRU acid gas removal unit 

AQCR Air quality control regions

ASCE American Society of Civil Engineers

ASME American Society of Mechanical Engineers

BACT Best Available Control Technology

BCC Birds of Conservation Concern 

bcf billion cubic feet 

BCR Bird Conservation Regions 

BGEPA Bald and Golden Eagle Protection Act 

BLEVE boiling-liquid-expanding-vapor explosion

BMPs best management practices 

bmsl below mean sea level 

BOG boil off gas 

Btu/ft2-hr British thermal units per square foot-hour

CAA Clean Air Act

Cabot Cabot Oil & Gas Corporation
v

CCS carbon capture and sequestration

CEMS continuous emissions monitoring system

Certificate Certificate of Public Convenience and Necessity

CFR Code of Federal Regulations 

CO carbon monoxide

CO2 carbon dioxide 

CO2e carbon dioxide equivalents

COE U.S. Army Corps of Engineers 

COMAR Code of Maryland Regulations 

Commission Federal Energy Regulatory Commission 

COOP U.S. Cooperative Observer Program

CPCN Maryland Public Service Commission Certificate of Public Convenience and Necessity 

CWA Clean Water Act 

dB decibels

dBA decibels on the A-weighted scale

DCP Dominion Cove Point LNG, LP 

DOD U.S. Department of Defense

DOE-FE U.S. Department of Energy, Office of Fossil Energy 

DOT U.S. Department of Transportation 

DTI Dominion Transmission, Inc. 

E&SCPs Erosion and Sediment Control Plans 

EA environmental assessment 

EFH Essential Fish Habitat 

EI Environmental Inspector 

EIS environmental impact statement 

EPA U.S. Environmental Protection Agency

ERP emergency response plan

ESA Endangered Species Act 

ESD emergency shutdown

FEED Front-End Engineering Design

FEMA Federal Emergency Management Agency

Fenced Area A 131-acre area that includes the land-based components of the LNG Terminal

FERC Federal Energy Regulatory Commission 

FIDS Forested Interior Dwelling Species 

FIRM Flood Insurance Rate Maps

FLAG Federal Land Managers’ Air Quality Related Values Work Group

FLSUs floating liquefaction and storage units 

ft3cubic feet

FTA Free Trade Agreement 

FWS U.S. Fish and Wildlife Service

GCRA Global Change Research Act of 1990

GHG greenhouse gas

GHGRP Greenhouse Gas Reporting Program

gpd gallons per day 

gpm gallons per minute

GWP global warming potential

GZA GZA GeoEnvironmental Inc.
vi

H2S hydrogen sulfide 

H2SO4 sulfuric acid mist

HAPs hazardous air pollutants

HAZOP Hazards and Operability Study

hp horsepower 

HRSG heat recovery steam generators 

HRU hydrocarbon removal unit 

HUC Hydrologic Unit Code 

HVAC heating, ventilation, and air conditioning

IEA International Energy Agency

IPCC Intergovernmental Panel on Climate Change

LAER Lowest Achievable Emission Rate

lb/MMBtu pounds per million British thermal units

LDAR leak detection and repair

Ldn day-night sound level

Leq equivalent sound level

LFL lower flammability limit

LNG liquefied natural gas 

LNG Terminal Cove Point LNG Terminal 

LOR Letter of Recommendation 

M&R Metering and Regulating 

m/s meters per second

MACT Maximum Achievable Control Technology

MAOP maximum allowable operating pressure 

MBTA Migratory Bird Treaty Act 

MCHE main cryogenic heat exchanger 

MDE Maryland Department of the Environment 

MDNR Maryland Department of Natural Resources 

mgd million gallons per day 

MMBtu/hr million British thermal units per hour

MOU Memorandum of Understanding 

mph miles per hour

MR mixed refrigerant 

MRL mixed refrigerant liquid

MSHA Maryland State Highway Administration 

MST Major Source Threshold

MTPA metric tons per annum 

MW megawatt 

N2O nitrous oxide

NAAQS National Ambient Air Quality Standards

NEPA National Environmental Policy Act 

NESHAP National Emission Standard for Hazardous Air Pollutants for Source Categories

NFPA National Fire Protection Association 

ng/J nanograms per Joule

NGA Natural Gas Act 

NGL natural gas liquid 

NGOs non-governmental organizations 
vii

NHPA National Historic Preservation Act

NMFS National Marine Fisheries Service 

NNSR Nonattainment New Source Review

NO2 nitrogen dioxide

NOI Notice of Intent 

NOx nitrogen oxides

NPDES National Pollutant Discharge Elimination System

NSA noise sensitive area

NSPS New Source Performance Standards

OEP Office of Energy Projects 

OPS Office of Pipeline Safety

OSHA Occupational Safety and Health Administration

OTR Ozone Transport Region

P&IDs piping and instrumentation diagrams

Pb lead

PCBs polychlorinated biphenyls 

PHA Process Hazards Analysis

PHMSA Pipeline and Hazardous Materials Safety Administration

Plan Upland Erosion Control, Revegetation, and Maintenance Plan

PM10 particulate matter less than 10 microns

PM2.5 particulate matter less than 2.5 microns

ppb parts per billion

ppm parts per million 

ppm-v parts per million by volume

PPRP Power Plant Research Division 

ppt parts per thousand 

Procedures Wetland and Waterbody Construction and Mitigation Procedures

Project Cove Point Liquefaction Project 

PSC Public Service Commission 

PSD Prevention of Significant Deterioration

psig pounds per square inch gauge 

PSM Process Safety Management of Highly Hazardous Chemicals; Explosive and Blasting 

Agents

PVMRM plume volume molar ration method

Q/d ratio of visibility-affecting emissions to distance

QRA quantitative risk assessment

Reviewing State 

Agencies

Maryland Departments of the Environment; Natural Resources; Transportation; 

Planning; Business and Economic Development; and Agriculture; and the Maryland 

Energy Administration

RICE reciprocating internal combustion engines

RMP risk management plan

Secretary Secretary of the Commission 

SEP surface emissive power

SER Significant Emission Rate

SHPO State Historic Preservation Office

SIP State Implementation Plan

SMECO Southern Maryland Electric Cooperative 
viii

SMPs Stormwater Management Plans 

SO2 sulfur dioxide

T-BACT Best Available Control Technology for Toxics

TAPs toxic air pollutants

TCEQ Texas Commission of Environmental Quality

tpy tons per year

UFL upper flammability limit

USC United States Code 

USCG U.S. Coast Guard 

USGCRP U.S. Global Change Research Program

USGS U.S. Geological Survey 

VDACS Virginia Department of Agriculture and Consumer Services 

VDCR Virginia Department of Conservation and Recreation 

VDEQ Virginia Department of Environmental Quality 

VDGIF Virginia Department of Game and Inland Fisheries 

VOCs volatile organic compounds 

WSA Waterway Suitability Assessment
1

1.0 PROPOSED ACTION

1.1 INTRODUCTION

The staff of the Federal Energy Regulatory Commission (Commission or FERC) has prepared 

this environmental assessment (EA) to assess the potential environmental impact of facilities proposed by 

Dominion Cove Point LNG, LP (DCP) to process and export domestically sourced liquefied natural gas 

(LNG). We1 prepared this EA in compliance with the requirements of the National Environmental Policy 

Act (NEPA) (Title 40 of the Code of Federal Regulations [CFR], Parts 1500-1508), and the 

Commission’s implementing regulations under 18 CFR 380. The U.S. Department of Energy, Office of 

Fossil Energy (DOE-FE); U.S. Department of Transportation (DOT); U.S. Army Corps of Engineers 

(COE); U.S. Coast Guard (USCG); and Maryland Department of Natural Resources (MDNR) participated 

as cooperating agencies in preparing this EA (see section 1.5).

On April 1, 2013, DCP filed an application in Docket No. CP13-113-000 under section 3(a) of 

the Natural Gas Act (NGA) and the procedures of Part 153 of the Commission’s regulations seeking 

authority to site, construct, modify, and operate facilities to be used for the liquefaction of natural gas for 

export at DCP’s existing Cove Point LNG Terminal (LNG Terminal) in Calvert County, Maryland. The 

section 3(a) facilities are referred to as the Liquefaction Facilities. In addition, DCP’s application 

requested authorization under section 7(c) of the NGA and Part 157 of the Commission’s regulations to 

construct, install, own, operate, and maintain facilities at DCP’s existing Pleasant Valley Compressor 

Station in Fairfax County, Virginia and existing Loudoun Compressor Station in Loudoun County, 

Virginia, for the transportation of natural gas associated with DCP’s proposal. The facilities proposed 

under sections 3(a) and 7(c) of the NGA are collectively referred to as the Cove Point Liquefaction 

Project (Project) and are described in section 1.2. Prior to filing its application, DCP participated in the 

Commission’s pre-filing process under Docket No. PF12-16-000.

On September 1, 2011, DCP filed an Application for Long-Term Authorization to Export LNG to 

Free Trade Agreement Countries with the DOE-FE (FE Docket No. 11-115-LNG). In its application, 

DCP requested approval to export up to approximately 1.0 billion cubic feet (bcf) of natural gas per day, 

or about 7.8 million metric tons per annum (MTPA) of LNG, to any country that has or in the future 

develops the ability to import LNG via ocean-going carrier and with which the United States has, or in the 

future enters into, a Free Trade Agreement (FTA). On October 7, 2011, DOE-FE issued Order No. 3019 

authorizing DCP to export LNG to FTA nations in accordance with section 3(c) of the NGA as amended 

by section 201 of the Energy Policy Act of 1992.

On October 3, 2011, DCP filed an Application for Long-Term Authorization to Export LNG to 

Non-Free Trade Agreement Countries with the DOE-FE (FE Docket No. 11-128-LNG). In its 

application, DCP requested approval to export up to approximately 7.82 million MTPA of LNG to any 

country with which the United States does not have a FTA and with which trade is not prohibited by U.S. 

law or policy. Subsequent to the two above-referenced applications with the DOE-FE and as indicated in 

FERC Docket No. CP13-113-000, DCP modified the Project and is seeking authorization to export 5.75 

million MTPA of LNG to FTA and non-FTA nations. On September 11, 2013, DOE-FE issued Order 

No. 3331 conditionally authorizing DCP to export LNG to non-FTA nations in accordance with section 

3(a) of the NGA as amended by section 201 of the Energy Policy Act of 1992.

 

1

“We,” “us,” and “our” refer to the environmental staff of the Commission’s Office of Energy Projects.
2

Previous Cove Point LNG Terminal Authorizations

The Federal Power Commission (now the FERC) originally authorized Cove Point LNG, LP to 

construct and operate the LNG Terminal and Cove Point Pipeline on June 6, 1972, in Docket No. CP71-

68-000. The LNG Terminal was designed to receive imported LNG from ocean-going carriers, 

temporarily store LNG in insulated tanks, and vaporize the LNG for delivery to U.S. markets. The LNG 

Terminal includes a pier located 1.1 miles offshore in the Chesapeake Bay, as well as a concrete-lined 

tunnel beneath the floor of the Chesapeake Bay that provides personnel access, LNG piping, and other 

support systems to the offshore pier. In 1980, LNG imports ceased, and between 1980 and 1994 the 

original facilities were unused except for a small amount of interruptible transportation service on the 

Cove Point Pipeline.

In 1994, the FERC authorized Cove Point LNG, LP to reactivate the on-shore storage and 

vaporization facilities and to construct a liquefaction unit to liquefy domestic natural gas in order to 

provide LNG peaking and storage services (Docket No. CP94-59-000). The environmental review for the 

project was included in an EA issued in August 1994. The offshore pier at the LNG Terminal was not 

reactivated in 1994.

In 2001, the FERC authorized Cove Point LNG, LP to construct new facilities and reactivate and 

operate existing facilities, including the offshore pier, in order to recommence LNG import and terminal 

services (Docket No. CP01-76-000). The new facilities included a fifth LNG storage tank, increasing the 

LNG Terminal’s storage capacity to 7.8 bcf. The environmental review for the facilities was included in 

an EA for the project issued in July 2001. DCP acquired the LNG Terminal and Cove Point Pipeline in 

2002 and has operated the facilities to date.

In 2006, the FERC approved DCP’s Cove Point Expansion Project, which included the 

construction of two new LNG storage tanks and additional vaporization facilities that increased the 

storage capacity to 14.6 bcf and peak send-out capacity to approximately 1.8 bcf per day. The Cove Point 

Expansion Project also included expansion of the Cove Point Pipeline by DCP, and construction of new 

downstream pipeline and storage facilities by Dominion Transmission, Inc. (DTI). Environmental review 

of the Cove Point Expansion Project was included in an environmental impact statement (EIS) issued 

under Docket Nos. CP05-130-000, CP05-131-000, and CP05-132-000 in April 2006.

In 2009, the FERC authorized the Pier Reinforcement Project to modify the existing offshore pier 

at the LNG Terminal to accommodate larger vessels (Docket No. CP09-60-000). The environmental 

review for this project was included in an EA issued in May 2009. 

1.2 PROPOSED FACILITIES

The Project would generally include the construction and operation of:

 new Liquefaction Facilities at the LNG Terminal in Calvert County, Maryland; 

 installation of additional compression at the existing Pleasant Valley Compressor Station, 

miscellaneous piping and measurement upgrades at the Pleasant Valley Metering and 

Regulating (M&R) Facility, and installation/replacement of the Pleasant Valley Suction/

Discharge Pipelines in Fairfax County, Virginia;

 miscellaneous piping and measurement upgrades at the Loudoun M&R Facility at the 

existing Loudoun Compressor Station in Loudoun County, Virginia; and 
3

 the temporary use of sites in Maryland and Virginia to support construction of the

facilities. 

If approved by the Commission, DCP proposes to begin construction of the Liquefaction 

Facilities in the summer of 2014, and would place the facilities in service in June 2017. Construction of 

the Virginia facilities would begin in the first quarter of 2016 and the facilities would be placed in service 

in March 2017. The locations of the proposed facilities are depicted on figure 1.2-1.

Under section 3 of the NGA, the FERC considers as part of its decision to authorize natural gas 

facilities, all factors bearing on the public interest. Specifically, regarding whether to authorize natural 

gas facilities used for importation or exportation, the FERC shall authorize the proposal unless it finds 

that the proposed facilities will not be consistent with the public interest. 

Under section 7 of the NGA, the Commission determines whether interstate natural gas 

transportation facilities are in the public convenience and necessity and, if so, grants a Certificate of 

Public Convenience and Necessity (Certificate) to construct and operate them. The Commission bases its 

decisions on technical competence, financing, rates, market demand, gas supply, environmental impact, 

long-term feasibility, and other issues concerning a proposed project.

1.2.1 Liquefaction Facilities

Figure 1.2.1-1 depicts the location of the LNG Terminal and offsite support areas. The landbased components of the LNG Terminal are situated within a 131-acre area, referred to as the Fenced 

Area, which is located within an approximately 1,017-acre parcel owned by DCP. As indicated on figure 

1.2.1-2, portions of the land owned by DCP are covered under conservation easements with the Cove 

Point Beach Association (20 acres), Calvert County (91 acres), the Maryland Environmental Trust and 

The Nature Conservancy (588 acres), and the Sierra Club and the Maryland Conservation Council (318

acres, which includes the 131-acre Fenced Area). DCP’s property is generally bounded by the 

Chesapeake Bay to the east, residential development to the south and west, and Calvert Cliffs State Park 

to the north.

The Liquefaction Facilities would occupy 59.5 acres within the Fenced Area and would tie into 

the existing facilities and share common equipment and infrastructure such as the LNG storage tanks, 

pumps, piping, and offshore pier to support both the import and export of LNG (figure 1.2.1-3). The 

primary Liquefaction Facilities would consist of the components described below. 

Pre-treatment Facilities

Natural gas for liquefaction would be received via the Cove Point Pipeline, which terminates on 

the west side of the LNG Terminal. The feed gas would be pretreated prior to liquefaction in order to 

remove impurities that have no heating value, have corrosive potential, or would solidify during the 

liquefaction process. Mercury would be removed from the feed gas in order to protect the aluminum heat 

exchangers in the liquefaction equipment. After mercury removal, the feed gas would flow to an acid gas 

removal unit (AGRU) to remove all of the carbon dioxide (CO2) and the majority of sulfur compounds 

from the gas. Upon acid gas removal, water would be removed from the feed gas through a series of 

molecular sieve dryers. After dehydration, the feed gas would flow through a heavy hydrocarbon 

removal unit (HRU) where heavier hydrocarbons would be condensed and removed. The resulting 

stabilized condensate would be routed to two storage tanks. A truck loading station with loading pumps 

would be installed to facilitate periodic truck load-out of the condensate.
%,

#*

#*

Loudoun 

Compressor Station

Pleasant Valley 

Compressor Station

Cove Point 

LNG Terminal

Chesapeake Bay

Prince

George’s

County

Talbot County

Anne

Arundel

County

Dorchester

County

Loudoun

County

Fauquier

County

Fairfax

County

Prince

William

County

Spotsylvania

County

Culpeper

County

Orange

County

Montgomery

County

Kent

County

Queen

Anne’s

County

District

of Columbia

Arlington County

County

Falls

Church

County

Fairfax

City County

Alexandria

County

Calvert

County

Charles

County

St.

Mary’s

County

Manassas

County

Manassas

Park County

Stafford

County

King

George

County

District of

Columbia

Maryland

Virginia

Virginia

Maryland

0 5 10

Miles

Date: (7/25/2013) Source: Z:\Clients\A_D\Dominion\Cove_Point\ArcGIS\2013\07\Application\Dominion_Cove_Point_Figure_1.2-1.mxd

4 #* Existing Compressor Station

%, Existing LNG Terminal

Figure 1.2-1

Cove Point Liquefaction Project

Project Overview Map

4
Offsite 

Area B

Offsite 

Area A

Fenced Area

LNG Terminal 

Boundary

Calvert County

Chesapeake Bay

Patuxent River

UV765

UV760

UV2

UV4

UV235

UV265

Virginia

Maryland

0 0.5 1

Miles

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4 Figure 1.2.1-1

Cove Point Liquefaction Project

LNG Terminal and Offsite Support Areas

5
LNG Terminal

Boundary

Fenced Area

Association Area (Cove Point 

Beach Association Easement)

County Area (Calvert 

Park Easement)

Offshore Pier

Maryland Environmental Trust/

Nature Conservancy Easement

Sierra Club/Maryland 

Conservation Council Easement

Virginia

Maryland

0 1,000 2,000

Feet

Date: (2/12/2014) Source: Z:\Clients\A_D\Dominion\Cove_Point\ArcGIS\2013\07\Application\Dominion_Cove_Point_Figure_1.2.1-2.mxd

Figure 1.2.1-2

Cove Point Liquefaction Project

LNG Terminal Detail

6
LNG Terminal Boundary

Fenced Area

Virginia

Maryland

0 250 500

Feet

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4 Figure 1.2.1-3

Cove Point Liquefaction Project

Liquefaction Facilities

Sound Barrier

Area Impacted by Construction

Area Impacted by Operation

7
8

Liquefaction Equipment

The dry gas from the HRU would flow to the refrigeration system where it would be chilled to 

approximately -245 degrees Fahrenheit (°F) through a combination of heat exchangers and pressure 

reduction processes. DCP selected the Air Products (APCI) C3/split mixed refrigerant (MR) process as 

the liquefaction technology. This technology consists of a propane pre-cooled system, MR system, and a 

proprietary main cryogenic heat exchanger (MCHE). During operation, make-up refrigerants would 

come from three sources: nitrogen would be obtained from the existing nitrogen system; methane would 

be supplied from downstream of the HRU; and ethane and propane would be trucked in and stored in 

vessels. The propane and MR compressors would be driven by two new General Electric Frame 7EA gas 

turbines. 

After liquefaction, the LNG would be sent to a stripper for nitrogen removal. After nitrogen 

removal, the final LNG product would be pumped to the LNG storage tanks and then to the offshore pier 

for loading onto ships for export. The nitrogen rich stream would be used as fuel gas for the gas turbines.

LNG Unloading/Loading Facilities

The existing LNG unloading facilities would be modified to provide bi-directional loading and 

unloading of LNG to and from ships. Modifications would occur onshore within the Fenced Area, within 

the concrete-lined tunnel from the LNG Terminal to the offshore pier, and on the offshore pier. The 

Project would not require the construction of new LNG storage tanks, additional LNG loading/unloading 

piers, or dredging, and DCP stated that none of the Project-related activities at the LNG Terminal or 

existing offshore pier would involve in-water work.

For export LNG loading operations, DCP would install additional pumps onshore to provide an 

average ship loading rate of 10,200 cubic meters per hour, and new blowers would be installed on the 

offshore pier to return vapors (i.e., natural gas) displaced by the loading process into the onshore LNG 

storage tanks. DCP would also remove two unloading suction drums on the offshore pier to make room 

for the new blowers. For import LNG unloading operations, LNG carriers would use their own onboard 

pumps to unload LNG into the onshore LNG storage tanks.

DCP would also modify the LNG transfer piping in the tunnel to allow for bi-directional flow of 

LNG. This piping modification would require replacement of the tunnel’s existing expansion joints. All 

activities associated with the transfer piping modifications would take place within the existing tunnel and 

no environmental impacts are likely to occur.

Utilities and Other Facilities

As previously indicated and as described below, the Project would utilize existing and new 

utilities and other facilities to support LNG import and export operations. The Project would also include 

the removal of some existing structures within the Fenced Area to accommodate new Project facilities.

Electric Power Generation and Steam Systems

Electric power for the LNG Terminal is currently generated on-site, with only a limited 

connection to the outside power distribution grid for backup power. All of the electric power necessary to 

operate the Liquefaction Facilities would be provided by two new 65 megawatt (MW) steam turbine 

power generators located within the Fenced Area. The steam needed to drive the generators would be 

obtained from heat recovery steam generators (HRSG) installed in the refrigerant compressor gas turbine 

exhaust duct and two auxiliary boilers. In addition to driving the electric generators, steam would also 

serve low, medium, and high pressure steam systems. Heat would be removed from a portion of the 

steam system and used for process heating.
9

The existing on-site electric power system would provide supplemental and back-up power to the 

Project.

Water

Water necessary for Project construction and operation would be obtained from existing water 

wells at the LNG Terminal. As indicated in table 1.10-1 and as discussed in section 2.2.1, DCP has 

applied to the Maryland Public Service Commission (PSC) for a Certificate of Public Convenience and 

Necessity (CPCN). The CPCN application includes a request to modify the LNG Terminal’s existing 

water appropriations permit to allow for the additional groundwater use required for the Project. The 

Maryland Department of the Environment (MDE) has reviewed the request and has conditionally 

recommended granting authorization for up to an average daily withdrawal of 233,000 gallons, and 

275,000 gallons per day (gpd) during the month of maximum use. Alternative water sources are 

discussed in section 3.5.

Plant and Instrument Air Systems

The Project would include a new instrument air and plant air system independent of the existing 

LNG Terminal air systems. A second, new air system would be installed to provide redundancy.

Nitrogen

The Liquefaction Facilities would consume nitrogen for refrigerant make-up, refrigerant 

compressor seal, and other utility demands. Nitrogen would be obtained via connection to the existing 

LNG Terminal nitrogen supply.

Fuel Gas

Flash gas from the nitrogen stripper would be compressed and combined with boil off gas (BOG) 

from the existing LNG storage tanks and used as the primary fuel for the low pressure fuel systems (e.g., 

auxiliary boilers, thermal oxidizer, and flares). The remaining low pressure fuel gas would be 

compressed for use in the high pressure fuel system (i.e., turbines). Natural gas from the Cove Point 

Pipeline would supplement fuel to the gas turbines.

Flare System

Ground flares would be installed as the emission control technology for volatile organic 

compounds (VOCs) and hazardous air pollutants (HAPs). Due to site restrictions and flaring 

requirements, one ground flare pad would be installed in the northern area of the LNG Terminal and a 

second ground flare pad would be installed in the southern area of the LNG Terminal. A heat shield 

would be installed around each ground flare pad.

Fire Protection Systems

The existing LNG Terminal maintains extensive fire protection facilities. These systems would 

be expanded to serve the Project facilities and would include vapor and fire detection sensors and fire 

mitigation measures including water spray equipment. The fire protection systems associated with the 

Project are detailed in section 2.8.4.

Spill Containment Systems

The existing LNG Terminal includes an engineered system to contain potential spills of LNG. 

The Liquefaction Facilities would be installed within similar engineered systems to contain potential 
10

spills of LNG and refrigerants. The spill containment systems associated with the Project are detailed in 

section 2.8.6.

Sound Barrier

DCP would install an approximately 3,500-foot-long wall along the south and west sides of the 

Fenced Area to mitigate for sound generated by the Project. The wall would be 60 feet high, constructed 

of sound absorbing panels, and painted to blend into the surrounding landscape. Due to the surrounding 

forested area, the sound barrier would only be visible to the public at the entrance to the LNG Terminal. 

Additional discussion of the sound barrier and potential visibility from Cove Point Road in the vicinity of 

the LNG Terminal entrance is provided in section 2.4.5.

Structure Removal

DCP would remove an existing warehouse, maintenance shop, and radio tower within the Fenced 

Area to accommodate Project construction and new facilities. A new warehouse, maintenance shop, and 

radio tower would be constructed within the Fenced Area as described in section 1.3.2.

1.2.2 Virginia Facilities

Additional compression on the Cove Point Pipeline would be required to deliver the inlet gas to 

the LNG Terminal. The current maximum allowable operating pressure (MAOP) of the Cove Point 

Pipeline is 1,250 pounds per square inch gauge (psig). DCP would operate the Cove Point Pipeline 

within the current MAOP. To support the transfer of natural gas to the LNG Terminal, DCP would install 

the following new or modified facilities at the Pleasant Valley Compressor Station in Fairfax County, 

Virginia and at the Loudoun M&R Facility in Loudoun County, Virginia (figures 1.2.2-1 and 1.2.2-2, 

respectively).

Pleasant Valley Compressor Station

 Installation of four new electric-driven compressor units totaling up to 62,500 

horsepower (hp), increasing the total compression at the station up to 68,500 hp;

 Installation of equipment and facilities, including a new compressor building and 

extension of the existing compressor building, gas coolers, filter/separators, valves, 

piping, headers, electrical facilities, and a natural gas-fired boiler;

 Installation of an approximately 800-foot-long, 20-foot-high sound barrier wall along the 

eastern side of the compressor station site; and

 Installation of a 36-inch-diameter suction pipeline within the compressor station site, 

extending from the new compressors to a new tap on DCP’s 36-inch-diameter TL-522 

pipeline.

Pleasant Valley Suction/Discharge Pipelines and M&R Facility

 Installation of a new 36-inch-diameter suction pipeline extending approximately 1,200 

feet from the Pleasant Valley Compressor Station to the Pleasant Valley M&R Facility;

 Replacement of an existing 16-inch-diameter discharge pipeline with a new 36-inchdiameter discharge pipeline extending approximately 1,200 feet from the Pleasant Valley 

Compressor Station to the Pleasant Valley M&R Facility; and
Virginia

Maryland

0 250 500

Feet

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Figure 1.2.2-1

Cove Point Liquefaction Project

Pleasant Valley Compressor 

Station, Suction/Discharge 

Pipelines, and M&R Facility

Sound Barrier

Area Impacted by Construction

Area Impacted by Operation

NOVEC Substation Expansion

Pleasant Valley 

M&R Facility

Pleasant Valley 

Compressor Station Boundary

 (Nonjurisdictional)

Pleasant Valley Suction/

Discharge Pipelines

11
Virginia

Maryland

0 200 400

Feet

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4 Figure 1.2.2-2

Cove Point Liquefaction Project

Loudoun M&R Facility and 

Leesburg Compressor Station 

Contractor Staging Area

Leesburg Compressor 

Station Contractor Staging Area

Loudoun 

M&R Facility

Area Impacted by Construction

Loudoun Compressor 

Station Boundary

Leesburg Compressor 

Station Boundary

12
13

 Installation of miscellaneous piping and measurement upgrades, including additional 

meter runs, piping, fittings, and valves at the Pleasant Valley M&R Facility.

As detailed in sections 1.9 and 2.4, construction and operation of the above facilities would occur 

within the boundaries of the existing Pleasant Valley Compressor Station, Pleasant Valley M&R Facility, 

or existing pipeline right-of-way between the facilities (figure 1.2.2-1).

Loudoun M&R Facility

DCP would install miscellaneous piping and measurement upgrades, including additional meter 

runs and/or piping, fittings, and valves at the existing Loudoun M&R Facility located within the 

boundaries of the Loudoun Compressor Station (figure 1.2.2-2). No additional compression would be 

installed at the Loudoun Compressor Station.

1.2.3 Offsite Areas

DCP proposes to temporarily use two areas in Calvert County, Maryland to support construction 

of the Liquefaction Facilities (figure 1.2.1-1). DCP would also use a portion of the existing DTI 

Leesburg Compressor Station property in Loudoun County, Virginia to support construction of the 

Virginia facilities.

Offsite Area A

Offsite Area A (figure 1.2.3-1) consists of 179.4 acres of largely wooded, undeveloped land 

located on the west side of Maryland Route 2/4 approximately 1.5 miles west of the LNG Terminal. DCP

has an option to purchase 100 acres of the property from a private party, and is negotiating to lease the 

remaining 79.4 acres from Calvert County. DCP would clear and utilize 94.9 acres (53 percent) of the 

property, which DCP states is the area needed to support construction of the Liquefaction Facilities. 

Offsite Area A would accommodate parking for approximately 1,700 worker vehicles, sheltered 

warehouse space, outdoor storage racks, outdoor laydown areas, temporary buildings, and office trailers. 

DCP stated that it would donate the 100-acre privately held portion of Offsite Area A to Calvert County 

upon completion of the Liquefaction Facilities. Calvert County has not yet determined the final 

deposition of the property; however, the county has stated that the property would be replanted following 

construction, and would not be intensely or commercially developed. 

Offsite Area A is crossed by overhead electric transmission facilities owned and operated by the 

Southern Maryland Electric Cooperative (SMECO). DCP is working with SMECO to develop a plan for 

the joint use of the electric transmission right-of-way during construction of the Liquefaction Facilities.

Offsite Area B

Offsite Area B (figure 1.2.3-2) consists of an 11.0-acre vacant parcel situated on the Patuxent 

River approximately 4.5 miles south of the LNG Terminal and off of Maryland Route 2/4. Offsite Area B 

is privately owned, and DCP has obtained an option to lease the property during construction of the 

Liquefaction Facilities. 

DCP would use Offsite Area B to receive large equipment and materials delivered by barge. 

DCP would utilize approximately 5.8 acres of the site; the remaining 5.2 acres of the site would be 

undisturbed. DCP would modify the site to include a temporary road and laydown area and would 

construct a temporary pier in the Patuxent River for mooring barges and offloading equipment and 

materials. 
Offsite Area A

Boundary

Virginia

Maryland

0 250 500

Feet

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4 Figure 1.2.3-1

Cove Point Liquefaction Project

Offsite Area A

Area Impacted 

by Construction

14
Offsite Area B

Boundary

Temporary Pier

Virginia

Maryland

0 100 200

Feet

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4 Figure 1.2.3-2

Cove Point Liquefaction Project

Offsite Area B

Area Impacted 

by Construction

15
16

Leesburg Compressor Station Contractor Staging Area

DCP would temporarily use approximately 2.4 acres of developed land and 6.0 acres of mowed 

and maintained land at DTI’s Leesburg Compressor Station for material laydown, vehicle parking, and 

equipment staging support construction of the Virginia facilities (figure 1.2.2-2). The Leesburg 

Compressor Station is located immediately across Watson Road from the Loudoun Compressor Station.

1.2.4 Access Roads

DCP would utilize existing roads to access the construction workspaces and would construct 

temporary roads within Offsite Areas A and B. For construction of the Liquefaction Facilities, DCP 

would reestablish a gravel road on the LNG Terminal property that was constructed and used in Docket 

No. CP05-130 et.al. Reuse of this road would require vegetation clearing, grading, and gravel placement. 

DCP would remove the temporary roads within Offsite Areas A and B and restore the area upon 

completion of construction of the Liquefaction Facilities.

1.3 NONJURISDICTIONAL FACILITIES AND ACTIVITIES

Occasionally, proposed projects have associated facilities that do not come under the jurisdiction 

of the FERC. These “nonjurisdictional” facilities may be integral to the need for the project (e.g., a new 

or expanded power plant at the end of a pipeline that is not under the jurisdiction of the FERC) or they 

may be merely associated as a minor, non-integral component of the jurisdictional facilities that would be 

constructed and operated as part of the project. The nonjurisdictional facilities and other related activities 

for the Project are described below and cumulative impacts associated with the facilities are addressed in 

section 2.9.

1.3.1 Nonjurisdictional Facilities

Road Improvements

DCP completed a traffic impact analysis to address public concerns regarding increased traffic 

during construction of the Project and to satisfy Maryland State Highway Administration (MSHA)2and 

Calvert County Department of Public Works requirements for vehicular traffic on public roadways. In its 

traffic impact analysis, DCP recommended adding a signal at the intersection of Maryland Route 2/4 and

Maryland Route 497 and constructing a 200-foot-long right turn lane with a 150-foot-long taper along 

eastbound Maryland Route 497 at Cove Point Road. The MSHA and Calvert County approved the 

recommendations in the analysis. The purpose of these road improvements would be to accommodate 

construction and operation traffic and deliveries of large pieces of equipment. The improvements would 

be constructed by DCP but owned and operated by the State of Maryland. Permits and approvals required 

for the road improvements consist of an Access Permit from the MSHA, a Calvert County Grading 

Permit, and a Notice of Intent (NOI) from the MDE. DCP has received the required permits and began 

construction of the road improvements in April 2014. 

The transport of large equipment from Offsite Area B to the LNG Terminal would also require 

potential modifications to utilities and obstructions along the transfer route. Utility modifications may 

include relocation of poles, guy wires and cables, and power and telecommunications wiring, as well as 

relocation of planned municipal improvements (e.g., road, water, sewer) along Cove Point Road. Utilities 

could be relocated to new poles and/or beneath existing roadways in order to obtain clearance for 

 

2 The MSHA is a part of the Maryland Department of Transportation, which is one of the Reviewing State 

Agencies for the CPCN.
17

transported loads. Modifications to traffic signals, signage, and road crossings may also be required. 

DCP would coordinate with the MSHA and Calvert County regarding potential modifications prior to the 

start of construction. 

Calvert County Sewer Extension

DCP plans to extend the existing Calvert County septic sewer system approximately 2 miles to 

the LNG Terminal entrance. The new sewer line would be designed and installed by contractors under 

contract to DCP, and all work would be performed under the guidance of the Calvert County Department 

of Public Works, which would own and operate the sewer system. This sewer system would be designed 

to serve the DCP Terminal operations; it would not be designed to serve the construction workforce. 

During construction, the additional workforce would be provided with portable toilet facilities.

The new sewer line would be collocated with existing rights-of-way for the majority of its length 

and would impact approximately 1.7 acres of land during construction. Permits and approvals for the 

sewer line extension consist of a Utility Permit from the MSHA, a Sewer Construction Permit and NOI 

from MDE, approval from MDE to change the sewer category (to be obtained by Calvert County), and a 

Grading Permit and Utility Cut Permit from Calvert County. Except as noted, DCP or its construction 

contractors would obtain all necessary permits. DCP submitted permit applications to the state and 

county agencies; to date, DCP has received the Utility Permit from the MSHA. The sewer extension 

would be completed in 2014.

Calvert County Sewer Service Internal to the LNG Terminal

The existing sewage facilities on the offshore pier require periodic pumping to a barge, and air 

separation units at the LNG Terminal collect a condensate that requires treatment prior to discharge to an 

outfall. To eliminate these actions, DCP plans to construct a new sewer system at the LNG Terminal and 

connect the system to the Calvert County sewer extension described above. Permits and approvals for the 

onsite sewer system have been submitted to Calvert County and MDE, and consist of a Grading Permit 

and System Access Permit from the County, and an NOI from MDE. The onsite sewer system would be 

designed, installed, and operated by DCP. 

Electric Substation Expansion

The existing electrical substation at the Pleasant Valley Compressor Station would be expanded 

to support the additional compressor units proposed by DCP. The expansion would permanently impact 

0.9 acre within the fence line of the compressor station and would be constructed, owned, and operated by 

the Northern Virginia Electric Cooperative. Permits and approvals necessary for the substation expansion 

consist of an Electrical Permit, Grading Permit, and Plan Approval from Fairfax County. 

Truck Loading/Unloading

The truck loading/unloading facility would serve to unload make-up refrigerants trucked to the 

LNG Terminal during operation and load condensate product into tanker trucks for delivery into the 

market place. Construction and operation of the truck loading/unloading facility at the LNG Terminal is 

jurisdictional and is analyzed throughout this EA. However, the loaded tanker trucks would be nonjurisdictional once they leave the LNG Terminal. These trucks would be subject to regulation by the 

Federal Motor Carrier Safety Administration and the DOT’s Pipeline and Hazardous Materials Safety 

Administration (PHMSA). DCP estimates that, on average, two trucks per day would be required to 

transport refrigerant and condensate products.
18

1.3.2 Other Related Activities

DCP would conduct the following related activities in accordance with all applicable permits and 

approvals would be obtained prior to conducting the work: 

 An existing 19,500 square-foot warehouse and 1-acre storage yard in the Calvert County 

Industrial Park in Prince Frederick, Maryland would be used to temporarily store stock 

from an existing warehouse in the Fenced Area that would be removed as part of the 

Project. DCP has completed installation of a fence and security measures, and has begun 

relocation of materials from the LNG Terminal to the temporary facility.

 An approximately 9,600 square-foot building would be built within the northeast corner 

of the Fenced Area for use as a temporary maintenance shop during construction of the 

Liquefaction Facilities, and as a warehouse following construction. DCP would also 

construct a new radio tower next to the new building. Permits for the warehouse have 

been submitted to Calvert County, and to federal, state, and county agencies for the radio 

tower; however, construction has not yet begun on either facility.

 A new, permanent maintenance shop would be constructed near the current 

administration building within the Fenced Area. Permits for the warehouse have been 

submitted to Calvert County; however, construction has not yet begun on the 

maintenance shop.

 Temporary security fencing is currently being installed within the Fenced Area to 

separate work zones and secure areas during construction of the Liquefaction Facilities. 

Upon completion of construction, the temporary fencing would be removed, portions of 

the existing security fence would be relocated, and new, permanent security fencing 

would be installed within the Fenced Area.

No Commission authority is needed for these activities. DCP would complete the activities at its 

own risk and expense. 

1.4 PROJECT PURPOSE AND NEED

DCP’s stated purpose of the Project is to liquefy for export domestically produced natural gas. 

DCP asserts that the LNG Terminal is ideally located to provide access to abundant and diverse domestic 

supply sources through the Cove Point Pipeline, which connects to the interstate natural gas transmission 

systems of Transcontinental Gas Pipeline Company, Columbia Gas Transmission, and DTI. According to 

DCP, these interconnects would allow feed gas for the Project to be sourced from a wide variety of 

regions in the U.S. depending on market forces and circumstances at any given time. DCP has fully 

contracted the proposed bi-directional service at the LNG Terminal with two customers, Pacific Summit 

Energy, LLC and GAIL Global (USA) LNG LLC. These customers have entered into a 20-year 

agreement for the planned export/import services at the LNG Terminal, as well as a 20-year service 

agreement for firm transportation on the Cove Point Pipeline. DCP states that the Project customers 

would be responsible for procuring their own gas supplies from anywhere in the gas market, and 

transporting such supplies to the LNG Terminal for liquefaction and export. DCP would not own the gas 

or the capacity at the LNG Terminal.

A number of commentors questioned the need for the Project on the assertion that the United 

States should not export its natural gas resources, and that doing so would result in adverse economic and 

environmental impacts. As discussed in sections 1.1 and 1.5.1, the DOE-FE determines whether the
19

proposed import or export of natural gas is not inconsistent with the public interest. DOE-FE’s orders 

granting export authorization address the economic impacts. This EA addresses the environmental 

impacts of the facilities proposed before the Commission. 

1.5 SCOPE OF THIS ENVIRONMENTAL ASSESSMENT

The topics addressed in this EA include alternatives; geology; soils; groundwater; surface waters; 

wetlands; vegetation; wildlife and aquatic resources; special status species; land use, recreation, special 

interest areas, and visual resources; socioeconomics (including transportation and traffic); cultural 

resources; air quality and noise; reliability and safety; and cumulative impacts. The EA describes the 

affected environment as it currently exists, discusses the environmental consequences of the Project, and 

compares the Project’s potential impact with that of various alternatives. The EA also presents our

recommended mitigation measures.

The environmental consequences of constructing and operating the Project would vary in duration 

and significance. Four levels of impact duration were considered: temporary, short-term, long-term, and 

permanent. Temporary impact generally occurs during construction with the resource returning to 

preconstruction condition immediately after restoration or within a few months. Short-term impact could 

continue for up to 3 years following construction. Long-term impacts would last more than 3 years, but 

the affected resource would recover to pre-construction conditions. A permanent impact could occur as a 

result of any activity that modifies a resource to the extent that it would not return to preconstruction 

conditions during the life of the Project, such as the construction of aboveground facilities. An impact 

would be considered significant if it would result in a substantial adverse change in the physical 

environment.

The Energy Policy Act of 2005 (EPAct 2005) provides that the FERC shall act as the lead agency 

for coordinating all applicable authorizations related to jurisdictional natural gas facilities and for 

purposes of complying with NEPA. The FERC, as the “lead federal agency,” is responsible for 

preparation of this EA. This effort was undertaken with the participation and assistance of the DOE-FE, 

USCG, DOT, COE, and MDNR as “cooperating agencies” under NEPA. Cooperating agencies have 

jurisdiction by law or special expertise with respect to environmental impacts involved with a proposal. 

The roles of the FERC, DOE-FE, USCG, DOT, COE, and MDNR in the Project review process are 

described below. The EA provides a basis for coordinated federal decision making in a single document, 

avoiding duplication among federal agencies in the NEPA environmental review processes. In addition to 

the lead and cooperating agencies, other federal, state, and local agencies may use this EA in approving or 

issuing permits for all or part of the proposed Project. Federal, state, and local permits, approvals, and 

consultations for the proposed Project are discussed in section 1.10.

1.5.1 Federal Energy Regulatory Commission

Based on its authority under the NGA, the FERC is the lead agency for preparation of this EA in 

compliance with the requirements of NEPA, the Council on Environmental Quality’s regulations for 

implementing NEPA (40 CFR Parts 1500-1508), and FERC regulations implementing NEPA (18 CFR 

380). 

As the lead federal agency for the Cove Point Liquefaction Project, the FERC is required to 

comply with section 7 of the Endangered Species Act (ESA), as amended, the Magnuson-Stevens Fishery 

Conservation and Management Act, section 106 of the National Historic Preservation Act (NHPA), and 

section 307 of the Coastal Zone Management Act. Each of these statutes has been taken into account in 

the preparation of this EA. The FERC will use this document to consider the environmental impacts that 

could result if it authorizes the Project. 
20

1.5.2 U.S. Department of Energy Role

The DOE must meet its obligation under section 3 of the NGA to authorize the import and export 

of natural gas, including LNG, unless it finds that the import or export is not consistent with the public 

interest. By law, under section 3(c) of the NGA, applications to export natural gas to countries with 

which the United States has FTAs that require national treatment for trade in natural gas are deemed to be 

consistent with the public interest and the Secretary of Energy must grant authorization without 

modification or delay. In the case of LNG export applications to non-FTA countries, section 3(a) of the 

NGA requires DOE to conduct a public interest review and to grant the applications unless DOE finds 

that the proposed exports will not be consistent with the public interest. Additionally, NEPA requires 

DOE to consider the environmental impacts of its decisions on non-FTA export applications. In this 

regard, DOE acts as a cooperating agency with the FERC as the lead agency in this EA pursuant to the 

requirements of NEPA. 

As stated in section 1.1, the DOE-FE has granted conditional authorization for export to FTA and 

non-FTA nations from the Cove Point facilities. The DOE will not make a final decision on applications 

to export LNG to non-FTA countries until DOE has met all of its statutory responsibilities. In accordance 

with 40 CFR 1506.3, after an independent review of the EA, the DOE may adopt it prior to issuing a 

Record of Decision on DCP’s application for authority to export LNG.

1.5.3 U.S. Coast Guard Role

The USCG exercises regulatory authority over LNG facilities that affect the safety and security of 

port areas and navigable waterways under Executive Order 10173; the Magnuson Act (50 United States 

Code (USC) 191); the Ports and Waterways Safety Act of 1972, as amended (33 USC 1221, et seq.); and 

the Maritime Transportation Security Act of 2002 (46 USC 701). The USCG is responsible for matters 

related to navigation safety, vessel engineering and safety standards, and all matters pertaining to the 

safety of facilities or equipment located in or adjacent to navigable waters up to the last valve 

immediately before the receiving tanks. The USCG also has authority for LNG facility security plan 

review, approval and compliance verification as provided in 33 CFR 105, and siting as it pertains to the 

management of vessel traffic in and around the LNG facility.

As required by its regulations, the USCG is responsible for issuing a Letter of Recommendation 

(LOR) as to the suitability of the waterway for LNG marine traffic. As described in this EA, the annual 

frequency of ship traffic for the Project is estimated to be 85 LNG vessels per year, which would not 

exceed the previously approved ship traffic of up to approximately 200 vessels per year in Dockets CP05-

130, et al., and DCP would not accept LNG carriers larger than previously authorized in Docket CP09-60. 

In a letter to the USCG dated May 23, 2012, DCP detailed the proposed Project modifications and stated 

that no additional waterway impacts would result beyond the 200 ship transits already assumed in the 

current Waterway Suitability Assessment (WSA). In a letter dated July 2, 2012, the USCG stated that a 

new or revised LOR would not be required for the Project, and that DCP’s current WSA and LOR dated 

July 29, 2008 are adequate for the service associated with the proposed Project. 

1.5.4 U.S. Department of Transportation Role

Under 49 USC 60101, the DOT has prescribed the minimum federal safety standards for LNG 

facilities. Those standards are codified in 49 CFR 193 and apply to the siting, design, construction, 

operation, maintenance, and security of LNG facilities. The National Fire Protection Association (NFPA) 

Standard 59A, “Standard for the Production, Storage, and Handling of Liquefied Natural Gas,” is 

incorporated into these requirements by reference, with regulatory preemption in the event of a conflict. 

In accordance with the 1985 Memorandum of Understanding on LNG Facilities and the 2004 Interagency 
21

Agreement on the safety and security review of waterfront LNG import/export facilities, the DOT 

participates as a cooperating agency. The DOT does not issue a permit or license but, as a cooperating 

agency, assists FERC staff in evaluating whether an applicant’s proposed design would meet the DOT 

requirements. DOT staff has reviewed FERC staff’s analysis and provided comments on our conclusions 

regarding compliance with Part 193 regulations.

1.5.5 U.S. Army Corps of Engineers Role

The COE elected to cooperate in preparing this EA because it has jurisdictional authority 

pursuant to section 404 of the Clean Water Act (CWA) (33 USC 1344), which governs the discharge of 

dredged or fill material into waters of the United States, and section 10 of the Rivers and Harbors Act (33 

USC 403), which regulates any work or structures that potentially affect the navigable capacity of 

navigable waters of the United States. Although this EA addresses environmental impacts associated 

with the Project as they relate to the COE’s jurisdictional permitting authority, it does not serve as a 

public notice for any COE permits or take the place of the COE’s permit review process. Through the 

coordination of this EA, the COE will obtain the views of the public and natural resource agencies prior 

to reaching its decisions on the Project.

1.5.6 Maryland Department of Natural Resources Role

The MDNR has relevant expertise regarding the environmental impacts of the Project and is 

required under the Natural Resources Article section 3-304 of the Maryland Code to evaluate the 

suitability of sites being proposed for electric generation facilities. 

On April 1, 2013, DCP filed an application with the Maryland PSC for a CPCN for the Project’s 

proposed electric generating facilities. The Secretary of the MDNR, in coordination with six executive 

branch state agencies (hereafter referred to as the Reviewing State Agencies3), is tasked to assess the 

potential environmental and socioeconomic impacts of the application and coordinate with other state 

agencies to advise the PSC of the suitability of the site for the proposed facilities. The Power Plant 

Research Division (PPRP), a unit within the MDNR, conducts the state review and agency coordination 

process. In January 2014, the PPRP released its draft environmental review of the proposed electric 

generating facilities and initial recommended license conditions for the CPCN.4 On April 17, 2014, the 

PPRP released its final recommended license conditions for the CPCN. DCP confirmed it would accept 

the recommended license conditions in the Maryland CPCN and we have included additional discussion 

of the recommended measures that DCP would adopt throughout this EA.

1.6 PUBLIC REVIEW AND COMMENT

On June 1, 2012, DCP filed a request to utilize our pre-filing process, and we approved DCP’s 

request on June 26, 2012, in Docket No. PF12-16-000. We participated in three public open houses 

sponsored by DCP in the Project area in July 2011 to explain our environmental review process to 

interested stakeholders. On September 24, 2012, we issued an NOI entitled Notice of Intent to Prepare 

an Environmental Assessment for the Planned Cove Point Liquefaction Project, Request for Comments on 

Environmental Issue, Notice of Onsite Environmental Review, and Notice of Public Scoping Meetings. 

 

3 The Reviewing State Agencies for the CPCN consist of: the Maryland Departments of the Environment, Natural 

Resources, Transportation, Planning, Business and Economic Development, and Agriculture; and the Maryland 

Energy Administration.

4 The Maryland PSC Case Jacket (Case Number: 9318) for the proposed generating station is available online at 

the Maryland PSC’s Website at: 

http://webapp.psc.state.md.us/Intranet/Casenum/CaseAction_new.cfm?CaseNumber=9318.
22

The NOI was published in the Federal Register5and was sent to over 720 parties including federal, state, 

and local officials; agency representatives; conservation organizations; local libraries and newspapers; 

Native American groups; and property owners affected by the proposed facilities. 

We conducted two public scoping meetings in the Project area to provide an opportunity for 

agencies and the general public to learn more about the Project and to participate in the environmental 

analysis by identifying issues to be addressed in the EA. A total of 40 speakers presented comments at 

the meetings held on October 9, 2012, in Lusby, Maryland, and on October 10, 2012, in Ashburn, 

Virginia. The transcripts of the public scoping meetings and all written scoping comments are part of the 

public record for the Project and are available for viewing on the FERC Internet website 

(http://www.ferc.gov).6 We also held an on-site environmental review of the Loudoun Compressor 

Station area on October 10, 2012, which was attended by approximately 26 members of the public.

Table 1.6-1 summarizes the environmental issues identified during the scoping process. 

Substantive environmental issues raised by commentors are addressed in applicable sections of the EA. 

During the pre-filing process, we received numerous comments related to increased compression at the 

Loudoun Compressor Station, which was part of DCP’s initially proposed Project scope. The majority of 

these comments were from residents of the Greene Mill Preserve neighborhood, which is nearby to the 

north and east of the Loudoun Compressor Station. However, DCP’s final proposal includes only minor 

modifications to the existing Loudoun M&R Facility and does not include increased compression at the 

Loudoun Compressor Station. Construction of the Loudoun M&R Facility is expected to result in 

limited, short-term impacts. As such, comments specifically related to the potential increased 

compression at the Loudoun Compressor Station are no longer within the scope of this Project and, 

therefore, have not been addressed in this EA.

TABLE 1.6-1

Issues Identified in the Scoping Process

Issue/Summary of Comment

EA Section 

Addressing Comment

GENERAL/PROJECT DESCRIPTION 

Impacts on septic systems at the LNG Terminal 1.3.1

Boiling-liquid-expanding-vapor explosions from pressurized storage tanks and tanker trucks 1.3.1

Project purpose and need 1.4

Project requires Environmental Impact Statement 1.5

Project’s relationship to shale gas development and fracking 1.5

GEOLOGY AND SOILS

Impacts on geological and fossil resources 2.1.1

WATER RESOURCES, FISHERIES, AND WETLANDS

Impacts on drinking water 2.2.1

Potential groundwater impacts during operation at the Liquefaction Facilities 2.2.1

Potential river water intrusion into aquifers 2.2.1

Impacts on surface water quality, including the Chesapeake Bay and the Patuxent River 2.2.2

Increased sedimentation into surface waterbodies 2.2.2

Impacts from ballast water discharge, including the introduction of invasive species 2.2.2, 2.3.3

Shoreline erosion from increased shipping 2.2.2

 

5 See Federal Register Volume 77, Number 189, dated September 28, 2012, pages 59,601-59,603.

6 Using the “eLibrary” link, select “General Search” from the eLibrary menu and enter the docket number 

excluding the last three digits in the “Docket Number” field (i.e., PF12-16 and CP13-113). Select an appropriate 

date range. 
23

TABLE 1.6-1 (cont’d)

Issues Identified in the Scoping Process

Issue/Summary of Comment

EA Section 

Addressing Comment

Impacts on federally managed and migratory fisheries and Essential Fish Habitat 2.2.3

Impacts on Chesapeake Bay fisheries and aquatic species 2.2.3

Impacts on wetlands associated with the Chesapeake Bay, Patuxent River, and Offsite Area A 2.2.4

VEGETATION

Impacts on forest due to tree loss, including fragmentation 2.3.1

Introduction of invasive species 2.3.1

WILDLIFE AND THREATENED AND ENDANGERED SPECIES

Project impacts on wildlife and wildlife habitat 2.3.2

Noise impacts on aquatic species at Offsite Area B 2.2.3, 2.3.3

Impacts on state-listed threatened and endangered species, including Torrey's Mountain-mint, Grove 

sandwort, Purple milkweed

2.3.3

Impacts on the Elklick Diabase Flatwoods Conservation site 2.3.1, 2.4.2

Impacts on natural heritage resources, including Piedmont Upland Depression Swamp, Northern 

Hardpan Basic Oak-Hickory Forest, Northern Piedmont Mafic Barren

2.3.1

LAND USE, VISUAL RESOURCES, AND RECREATION

Impacts of the Liquefaction Facilities on nearby residences 2.4.3

Impacts on the Chesapeake Bay, including tourism, fishing, and recreational boating 2.4.2

Potential impacts on the Elklick Woodlands State Natural Area Preserve near the Pleasant Valley 

Compressor Station

2.4.2

Potential impacts on Calvert Cliffs State Park adjacent to the LNG Terminal property 2.4.2

Potential impacts on other parks near the LNG Terminal 2.4.2

Potential impacts on the Calvert Marine Museum near Offsite Area B 2.4.2

Visual impacts from the LNG Terminal 2.4.5

Impacts on Hellen Creek Hemlock Preserve near Offsite Area A 2.4.2

SOCIOECONOMICS 

Project will benefit foreign countries, not local communities 2.5.1, 2.5.6

Project will benefit local communities, including providing employment and increased tax revenue 2.5.1, 2.5.6

Project will provide limited benefits to communities 2.5.1, 2.5.6

Impacts on local emergency providers 2.5.3

Impacts on the Chesapeake Bay shipping channel 2.5.4

Impacts on Port of Baltimore shipping 2.5.4

Impacts of increased LNG vessel traffic 2.5.4

Impacts from traffic 2.5.4

Impacts on property values 2.5.5

Impacts on local fishing and tourism industries 2.4.2, 2.5.2

CULTURAL RESOURCES

Potential impacts on the historic community of Solomons 2.6.1

AIR QUALITY AND NOISE

Greenhouse gas emissions must be assessed 2.7.1

Air impacts from construction equipment 2.7.1

Air impacts from operation of the Liquefaction Facilities and Pleasant Valley Compressor Station 2.7.1

Purchase of air offsets in local area 2.7.1

Noise from machinery and construction activities 2.7.2

Noise from operation of the Liquefaction Facilities 2.7.2

RELIABILITY AND SAFETY

FERC’s role in establishing siting guidelines 2.8.2

Comments that the LNG Terminal has historically operated safely 2.8.3

Gas detectors at air intakes are not sufficient to eliminate an ignition source 2.8.3

Ensure site design, equipment separation, and operational process are safe 2.8.4
24

TABLE 1.6-1 (cont’d)

Issues Identified in the Scoping Process

Issue/Summary of Comment

EA Section 

Addressing Comment

Control and monitoring systems and integrity management programs 2.8.4

Impacts on the safe operation of the existing LNG Terminal during construction 2.8.4

Comments on using the quantitative risk assessment method 2.8.5

The tank release analysis in the final EIS for the Cove Point Expansion Project was based on a 1-hour 

release; and that all credible scenarios should be reviewed

2.8.6

Propane release must be taken into consideration 2.8.6

Impacts from a release of LNG or natural gas and the need for remote siting 2.8.6

Toxic impacts of benzene 2.8.6

Vapor clouds become explosive due to tightly packed equipment and the sound abatement wall 2.8.6

Limited evacuation route from the vicinity of the LNG Terminal 2.8.7

Potential impacts from terrorism 2.8.8

Impacts from a potential incident on an LNG tanker 2.8.8

Comment that there are no U.S. flagged LNG carriers 2.8.8

Comment that U.S. Coast Guard does not currently provide safety escorts for LNG vessels 2.8.8

CUMULATIVE IMPACTS

Potential cumulative impacts from air emissions 2.9.7

ALTERNATIVES

Alternatives to mitigate pollution 3.2

Alternative to reduce operating footprints of the facilities 3.4

Analyze electric compressors at the Liquefaction Facilities to reduce emissions 3.4

Consider No Action Alternative 3.7

We received comments during the scoping period recommending that an EIS, rather than an EA, 

be prepared to assess the impact of the Project. An EA is a concise public document for which a federal 

agency is responsible that serves to provide sufficient evidence and analysis for determining a finding of 

no significant impact. The Commission’s regulations under 18 CFR 306(b) state that “If the Commission 

believes that a proposed action...may not be a major federal action significantly affecting the quality of 

the human environment, an EA, rather than an EIS, will be prepared first. Depending on the outcome of 

the EA, an EIS may or may not be prepared.” In preparing this EA, we are fulfilling our obligation under 

NEPA to consider and disclose the environmental impacts of the Project. As noted above, this EA 

addresses the impacts that could occur on a wide range of resources should the Project be approved and 

constructed. Also, the USCG, DOE-FE, DOT, COE, and MDNR have special expertise with respect to 

certain environmental impacts associated with DCP’s proposal, and assisted in preparing this EA. Based 

on our analysis, the extent and content of comments received during the scoping period, and considering 

that the Project facilities would be largely collocated with existing facilities, we conclude in section 4 that 

the impacts associated with this Project can be sufficiently mitigated to support a finding of no significant 

impact and, thus, an EA is warranted. 

Commentors also assert that authorization to export natural gas will spur the development of 

natural gas derived from shale formations and, therefore, the environmental impacts associated with shale 

gas development should be included in the environmental review of the Project. More specifically, one 

commentor noted that Pacific Summit, one of DCP’s customers for the proposed import/export services at 

the LNG Terminal, has contracted with Cabot Oil & Gas Corporation (Cabot) to obtain natural gas for 

export from the Marcellus Shale region. The commentor believes that Cabot may need to drill additional 

wells to meet its contractual obligations to Pacific Summit and other customers in the region, and that the 

environmental impacts associated with the additional drilling should be included in our analysis. 

Whereas the Project could export natural gas derived from shale formations, DCP states that Project 
25

customers would be responsible for procuring their own gas supplies from anywhere in the gas market 

and transporting such supplies to the LNG Terminal for liquefaction and export. In addition, specific 

details, including the timing, location, and number of additional production wells that may or may not be 

drilled, are speculative. As such, impacts associated with the production of natural gas that may be 

sourced from various locations and methods for export by the Project are not reasonably foreseeable or 

quantifiable. Furthermore, our authority under the NGA and NEPA review requirements relate only to 

natural gas facilities that are involved in interstate commerce. Thus, the facilities associated with the 

production of natural gas are not under FERC jurisdiction. 

1.7 CONSTRUCTION, OPERATION, AND MAINTENANCE

1.7.1 General Procedures

DCP has committed to design, construct, operate, and maintain the Liquefaction Facilities in 

accordance with DOT regulations in 49 CFR 193, which apply to LNG facilities; NFPA Standard 59A, 

“Standard for the Production, Storage, and Handling of Liquefied Natural Gas;” USCG regulations in 33 

CFR 127; and applicable federal and state environmental regulations. DCP also committed that the 

Virginia facilities would be designed, constructed, operated, and maintained to conform to the 

requirements of the DOT in 49 CFR 192, Transportation of Natural and Other Gas by Pipeline: 

Minimum Federal Safety Standards and applicable federal and state environmental regulations.

DCP would construct, restore, and maintain the Project in conformance with the measures 

described in our Upland Erosion Control, Revegetation, and Maintenance Plan (Plan) and Wetland and 

Waterbody Construction and Mitigation Procedures (Procedures), which were developed to minimize the 

environmental impact of construction and operation of interstate natural gas transmission facilities. DCP 

also developed and would implement site-specific Erosion and Sediment Control Plans (E&SCPs) and 

Stormwater Management Plans (SMPs) in compliance with the MDE’s 2011 Maryland Standards and 

Specifications for Soil Erosion and Sediment Control and 2000 Maryland Stormwater Design Manual 

(Revised 2009) (for facilities in Maryland) and the Virginia Department of Conservation and Recreation 

(VDCR) 1992, Third Edition, Virginia Erosion and Sediment Control Handbook (for facilities in 

Virginia).7 The preliminary E&SCP and SMP developed for the Liquefaction Facilities and Offsite Areas 

A and B were submitted to the Calvert County Department of Community Planning and Building and the 

Calvert County Soil and Water Conservation District for review and approval. Comments received to 

date from these agencies requested additional documentation but have not required design changes. The 

E&SCP and SMP for the Virginia facilities would be submitted to the Loudoun and Fairfax County Soil 

and Water Conservation Districts for review and approval prior to construction. Because the Project 

would require construction in the tidal waters of the Chesapeake Bay, DCP would conform with 

compliance and monitoring requirements specified in the COE permits, MDE tidal wetlands license, and/

or water quality certification. DCP would implement the erosion and sediment control best management 

practices (BMPs) specified in the above plans and procedures immediately after initial disturbance of soil, 

and maintain these practices throughout construction. 

 

7 DCP’s E&SCP and SMPs were provided as attachments to Resource Report 2 in its April 1, 2013 Application 

and are available for viewing on the FERC Internet website (http://www.ferc.gov). Using the “eLibrary” link, 

select “General Search” from the eLibrary menu, enter the selected date range and “Docket No.” excluding the 

last three digits (i.e., CP13-113), and follow the instructions. On the results page that appears, locate 

Category/Accession 20130401-5045. Under the Files, select the PDF files titled “PUBLIC - Vol I RR2 Part 1 of 

3.PDF,” “PUBLIC - Vol I RR2 Part 2 of 3.PDF,” and “PUBLIC - Vol I RR2 Part 3 of 3.PDF.” Direct access can 

be obtained by entering the Accession Number (20130401-5045) into the “Numbers” field of the “Advanced 

Search” option from the eLibrary menu. The plans are also available for public inspection at the FERC’s Public 

Reference Room in Washington, DC (call (202) 502-8317 for instructions).
26

DCP would also design and implement a Project-specific Spill Prevention, Control, and 

Countermeasures Plan that would specify procedures and measures to avoid and minimize potential 

impacts from spills of fuel or other hazardous substances during Project construction and operation. 

Further, DCP would implement the facility design, operating, and security procedures specified in 40 

CFR 112 and would fully comply with the provisions and procedures outlined in MDE’s Oil Operations 

Permit applicable to aboveground storage tanks with a capacity of 10,000 gallons or greater.

1.7.2 Liquefaction Facilities

Construction

Construction of the Liquefaction Facilities would impact approximately 68.4 acres within the 

131-acre Fenced Area (figure 1.2.1-3), and would generally proceed along the following sequence:

 Mobilization – necessary personnel and equipment would be mobilized to the LNG 

Terminal by road for each phase of construction;

 Installation and Maintenance of Erosion Control Measures – erosion and sediment 

controls would be established, inspected, and maintained throughout construction; 

fencing would be installed to delineate the extent of the construction workspace;

 Clearing, Grubbing, and Topsoil Removal – the workspace would be prepared for 

construction, including the removal of approximately 11.4 acres of trees as discussed in 

section 2.3.1; topsoil would be removed and segregated for use during restoration of 

appropriate areas;

 Demolition – an existing warehouse, maintenance shop, and radio tower would be

removed to accommodate other Project elements;

 Rough Grading – grading, cut, and fill would establish the rough elevations throughout 

the construction work area; 150 feet of an intermittent stream, 866 feet of an ephemeral 

stream, and less than 0.1 acre of wetland within the Fenced Area would be permanently 

filled as discussed in sections 2.2.2 and 2.2.4;

 Pile Installation – pilings to support foundations and equipment would be installed in 

accordance with civil engineering and geotechnical requirements;

 Underground Utilities – underground utilities including water, fire water, electric, and 

communication lines would be installed;

 Foundations – foundations would be constructed for equipment, buildings and pipe racks 

in accordance with engineered specifications;

 Erection – equipment, buildings, the sound barrier wall, and other facilities would be 

constructed in accordance with engineered specifications; none of the new facilities 

would exceed the height of existing facilities;

 Testing – appropriate testing would be completed to ensure the integrity and safety of the 

various systems including hydrostatic testing of piping, tanks, and other equipment;

meggering of electrical cables; and equipment calibrations;
27

 Commissioning and Start-up – various systems would be commissioned and started in 

accordance with detailed plans to ensure their readiness; and

 Final Cleanup, Stabilization, and Restoration – final cleanup, grading/stabilization, 

revegetation, and installation of permanent stormwater controls would proceed in 

accordance with approved plans.

Operation

Upon completion of the Project, the LNG Terminal would be capable of the bi-directional import 

and regasification of LNG, and the liquefaction of natural gas and export of LNG. Both services would 

utilize the existing offshore pier and Cove Point Pipeline as well as common facilities and systems

including the LNG storage tanks.

DCP would update existing operations and maintenance plans for the LNG Terminal to include 

procedures relative to the Project, and would develop an Operations Manual that addresses specific 

procedures for the safe operation of the Liquefaction Facilities in accordance with 33 CFR 127.

DCP anticipates that an additional 93 staff, including administrative personnel, would be required 

at the LNG Terminal when the Liquefaction Facilities are operational. DCP has training programs inplace for new operating personnel that address routine operations and monitoring procedures as well as 

safe startup, shutdown, cool down and purging processes. DCP would develop new training protocols to 

ensure that all new and existing personnel understand the operating and safety procedures related to the 

Liquefaction Facilities. Section 2.8.7 further discusses Project operating procedures.

We received comments concerning the volume of LNG ship traffic that would occur during 

Project operation. The volume of ship traffic for LNG import has historically varied due primarily to 

market demand, and DCP expects that LNG export activity may also vary depending on demand. 

However, the annual frequency of ship traffic for the Project is estimated to be 85 LNG vessels per year, 

which would not exceed the previously approved ship traffic of up to approximately 200 vessels per year 

in Dockets CP05-130, et al., and DCP would not accept LNG carriers larger than previously authorized in 

Docket CP09-60. After reviewing the Cove Point Liquefaction Project, the USCG Sector Baltimore 

concurred that the Project should not result in an increase in the size and/or frequency of LNG marine 

traffic beyond that envisioned in the current WSA for the LNG Terminal, and that the WSA and LOR are 

adequate for the service associated with the Project. Other potential impacts associated with the LNG 

ship traffic for the Project are discussed in sections 2.2.2, 2.3.3, and 2.8.8.

Maintenance

Routine facility maintenance and minor overhauls would be conducted by full-time DCP 

personnel, and more substantial equipment maintenance may be conducted by contract personnel. 

Vegetation maintenance and inspection and maintenance of permanent erosion control measures would be 

conducted in accordance with our Plan and Procedures and site-specific E&SCPs and SMPs.

1.7.3 Offsite Areas

Construction, Operation, and Maintenance

As previously indicated, DCP would temporarily utilize Offsite Areas A and B in Maryland and 

the developed area within the existing Leesburg Compressor Station in Virginia to support Project 

construction. The sites would be restored upon completion of Project construction in accordance with our 

Plans and Procedures, permit requirements, and landowner agreements.
28

Construction for the temporary use of the offsite areas would follow a similar sequence as 

described for the Liquefaction Facilities including mobilization; installation and maintenance of erosion 

control measures; vegetation clearing and grubbing; topsoil removal and segregation; grading; and 

cleanup and restoration.

Offsite Area A

The preparation of Offsite Area A would include the phased removal of trees and other vegetation 

from 94.9 acres of the 179.4-acre site. As discussed in sections 2.2.2, 2.2.4, 2.3.1, and 2.3.3, DCP would 

preserve the existing vegetation within 100 feet of wetlands, waterbodies, and special status species to 

avoid or minimize impacts on those resources. The only exception to the 100-foot-wide buffer would 

involve the construction of a temporary, gravel road within Offsite Area A across a minor, intermittent 

stream and 0.2 acre of associated riparian vegetation. Based on the site configuration, orientation of the

affected waterbody, and traffic considerations on Maryland Route 2/4, these impacts would be 

unavoidable. To minimize impacts, DCP would install a bottomless culvert over the intermittent stream, 

implement other measures in its E&SCP, and restore the riparian vegetation upon completion of Project 

construction. DCP would also preserve a 100-foot vegetation buffer along Maryland Route 2/4 for visual 

screening. Preparation of Offsite Area A would include construction of sheltered warehouse space, 

outdoor storage racks, outdoor laydown areas, temporary buildings, and office trailers. Temporary 

underground utilities (e.g., electricity, water, and communications) would be installed to support 

operations.

Deliveries to Offsite Area A would be via truck, with direct access off of Maryland Route 2/4. 

Upon receipt, materials would be offloaded and stored until needed at the LNG Terminal. Most deliveries 

to the LNG Terminal would utilize open, flatbed trailers; permits would be obtained as required for all 

transportation by truck. Offsite Area A would also be utilized as the personal vehicle parking area for the 

construction management and labor workforce. Buses would be used to transport workers between 

Offsite Area A and the LNG Terminal.

Maintenance and inspection of erosion and stormwater control measures would occur in 

accordance with our Plan and Procedures and site-specific E&SCPs and SMPs.

We received other comments concerning the environmental impacts associated with the use of 

Offsite Area A. The environmental impacts associated with the preparation and use of Offsite A, and 

DCP’s proposed measures to avoid or minimize impacts, are detailed in section 2.0, and alternatives 

considered to Offsite Area A are discussed in section 3.0.

Offsite Area B

The preparation of Offsite Area B would impact 5.8 acres of the 11.0-acre site and would include 

construction of a temporary road and temporary pier in the Patuxent River for mooring barges and 

offloading equipment and materials.

The temporary road would extend across Offsite Area B from Solomon Islands Road to the 

temporary pier. Construction of the road would require the excavation of approximately 14,000 yards of 

soil to create a safe grade; this soil would be stored on-site until construction of the Liquefaction Facilities 

is completed, at which time the original grade of the site would be restored. The road would be surfaced 

with either crane mats or stone bedding.

Based on a bathymetry survey conducted by DCP, the pier would extend approximately 166 feet 

from the shore to reach sufficient water depth to avoid dredging. The pier would be constructed of steel 

beams and timber decking supported on 24- to 36-inch-diameter steel piles that would be driven using a 
29

vibratory hammer to the extent possible; an impact hammer would be used to complete pile installation if 

necessary. As many as 24 piles would be installed to support the pier. Up to four mooring dolphins

would also be installed near the pier in the Patuxent River. The pier and mooring dolphins would be 

removed upon completion of construction of the Liquefaction Facilities. Any piles that could not be 

completely removed would be cut-off at or below the mud line. Following removal of the pier 

components, and based on a recommendation from the Reviewing State Agencies in their recommended 

license conditions for Maryland’s CPCN, DCP would utilize suitable materials from the pier and the LNG 

Terminal site as artificial reef components. The design and location of the artificial reef would be 

approved by the MDNR, and ownership of the reef would be transferred to the MDNR after its placement 

is complete. Section 2.2.3 includes additional discussion of the proposed artificial reef. 

During construction of the Liquefaction Facilities, DCP estimates that 42 shipments would be 

received via barge at Offsite Area B, requiring approximately 150 truck loads to transport equipment and 

materials to the LNG Terminal or Offsite Area A. The largest component of the Liquefaction Facilities to 

be received at Offsite Area B would be approximately 150 feet long and weigh approximately 330 tons. 

The required permits and approvals associated with barge operations would be obtained several weeks in 

advance of each transportation event.

DCP would maintain Offsite Area B in accordance with the provisions of our Plan and 

Procedures and site-specific E&SCPs and SMPs.

We received comments concerning environmental impacts associated with Offsite Area B and the 

temporary pier. Environmental impacts associated with the construction and use of Offsite Area B, 

including the temporary pier, and DCP’s proposed measures to avoid or minimize impacts, are discussed 

in section 2.0. Alternatives considered to Offsite Area B are discussed in section 3.0.

Leesburg Compressor Station Contractor Staging Area

DCP would use approximately 2.4 acres of developed land and 6.0 acres of mowed and 

maintained land within its existing Leesburg Compressor Station property to support construction of the 

Virginia facilities. The staging area would be prepared and maintained in accordance with our Plan and 

Procedures and DCP’s site-specific E&SCPs and SMPs.

1.7.4 Virginia Facilities

Construction, Operation, and Maintenance

Pleasant Valley Compressor Station

Construction of the Pleasant Valley Compressor Station expansion would impact 22.2 acres

within the 37-acre property owned by DCP. After mobilizing to the site, the general sequence for 

constructing the expansion facilities would include the installation of erosion, sediment, and stormwater 

control measures in accordance with our Plan and Procedures and as specified in DCP’s E&SCPs and 

SMPs; clearing and grading of the work area; installation of foundations; installation and hydrostatic 

testing of aboveground and underground piping; erection of buildings and structures, including the sound 

barrier wall; installation of equipment; start-up and testing; and final cleanup and stabilization.

The proposed expansion would include two new 20,000 hp compressor units, one new 15,000 hp 

compressor unit, and one new 7,500 hp compressor unit. All of the new compressors would be electric

driven and would be located in new buildings or additions designed to reduce operating noise (e.g., sound 

insulated walls, roof panels, and doors). Other equipment, acoustic treatments, and operational 

procedures would be implemented to further reduce operating noise (section 2.7.2). Construction at the 
30

Pleasant Valley Compressor Station would also include new gas coolers, filter/separators, valves, and 

electrical facilities. Northern Virginia Electric Cooperative would also expand its existing electrical 

substation on the site as described in section 1.3.1.

Operation of the expanded compressor station would impact 2.3 acres of land that is not currently 

utilized in operating the facility. Most areas in and around the new or expanded compressor buildings, 

and associated piping, would be covered with crushed rock or similar material to minimize the amount of 

maintenance required. Parking and drive areas damaged during construction would be restored and the 

remaining disturbed areas would be seeded with a grass in accordance with our Plan and DCP’s sitespecific E&SCP. DCP would operate and maintain the new facilities in accordance with applicable DOT 

safety standards in 49 CFR 192 and applicable state and federal environmental regulations. Standard 

operations would include calibration, maintenance, and inspection of equipment; monitoring of pressure, 

temperature, and vibration data; and routine buildings and grounds maintenance. No new permanent staff 

would be required to operate the expanded facility.

Pleasant Valley Suction/Discharge Pipelines and Pleasant Valley M&R Facility

As described in section 1.2.2, the Pleasant Valley Suction/Discharge Pipelines would include the 

installation of a new, 36-inch-diameter suction pipeline and the replacement of an existing 16-inchdiameter discharge pipeline with a new 36-inch-diameter pipeline. Construction of the pipelines and 

associated Pleasant Valley M&R Facility modifications would impact approximately 3.3 acres within 

DCP’s existing 150-foot-wide pipeline easement and on the Pleasant Valley Compressor Station property. 

The new pipelines would be installed using a standard upland construction process consisting of 

surveying; clearing and grading the workspace, including topsoil removal and segregation; installation of 

erosion and sediment control measures; trenching; pipe stringing, bending, assembly, welding, and 

inspection; pipe lowering and backfilling; hydrostatic testing; and cleanup and restoration. For 

installation of the new 36-inch-diameter discharge pipeline, the existing 16-inch-diameter discharge 

pipeline would first be excavated and removed, and the new 36-inch-diameter pipeline would be installed 

in the vacated trench.

The workspace for the new pipelines and modified M&R facility would be restored and 

maintained in accordance with our Plan and DCP’s site-specific E&SCP, and maintained in accordance 

with applicable DOT safety standards in 49 CFR 192 and applicable state and federal environmental 

regulations.

Loudoun M&R Facility

Modifications at the Loudoun M&R Facility would include the installation of meter runs, fittings, 

valves, and miscellaneous piping and measurement upgrades. All of the work would occur within the 

1.9-acre fenced area around the site, which contains equipment or has been graded and covered with 

gravel.

The workspace for the modified M&R facility would be restored and maintained in accordance 

with our Plan and DCP’s site-specific E&SCP, and maintained in accordance with applicable DOT safety 

standards in 49 CFR 192 and applicable state and federal environmental regulations.

1.8 ENVIRONMENTAL COMPLIANCE INSPECTION AND MONITORING

DCP has committed to obtaining all the necessary environmental permits and approvals (section 

1.10) and would construct, operate, and maintain the proposed facilities in compliance with permit 

conditions and other applicable federal and state regulations and guidelines. Prior to construction, DCP 
31

would submit an Implementation Plan to the FERC for review and approval. The Implementation Plan 

would describe how DCP would maintain environmental compliance with applicable regulations and 

permit requirements; detail the environmental training program for workers; and identify the role and 

responsibilities of Environmental Inspectors (EIs), which would include:

 ensuring compliance with the requirements of the Plan and Procedures, environmental 

conditions of the FERC approval, applicable mitigation measures, other environmental 

permits and approvals, and environmental requirements in landowner agreements;

 verifying that the limits of authorized construction work areas and locations of access 

roads are properly marked before clearing;

 verifying the location of signs and highly visible flagging marking the boundaries of 

sensitive resource areas, waterbodies, wetlands, or areas with special requirements along 

the construction work area;

 identifying E&SCP and soil stabilization needs in all areas;

 ensuring restoration of contours and topsoil;

 determining the need for and ensuring that erosion controls are properly installed, as 

necessary to prevent sediment flow into wetlands, waterbodies, and sensitive areas, and 

onto roads;

 inspecting and ensuring the maintenance of temporary erosion control measures at least 

on a daily basis in areas of active construction or equipment operation, on a weekly basis 

in areas with no construction or equipment operation, and within 24 hours of each 0.5 

inch of rainfall;

 keeping records of compliance; and

 identifying areas that should be given special attention to ensure stabilization and 

restoration after the construction phase.

DCP would conduct training for its construction personnel, including EIs, contractors, and their 

employees, regarding proper field implementation of its E&SCPs; Spill Prevention, Control, and 

Countermeasures Plan; and other Project-specific plans and mitigation measures. The training would 

cover Project environmental documents and all Project-specific conditions contained in the Commission 

approval and other applicable federal, state, and local permits and approvals.

We would also conduct routine inspections during construction and restoration of the Project 

facilities as well as regular annual safety inspections of the Liquefaction Facilities during the operating 

life of the facilities. 

After construction, DCP would conduct follow-up inspections of all disturbed upland areas after 

the first and second growing seasons to determine the success of restoration. To ensure the restoration of 

all areas affected by the Project, we would continue to conduct oversight inspection and monitoring 

following construction as outlined in the Plan. If it is determined that post-construction monitoring is not 

adequate to assess the success of restoration, DCP would be required to extend its post-construction 

monitoring in site-specific areas of concern. All compliance inspection reports would be available for 

public review on the FERC’s Internet website using the eLibrary link.
32

1.9 LAND REQUIREMENTS

Construction of the Project would impact approximately 204.9 acres of land, including 

aboveground facility sites, offsite support areas, access roads, and pipeline right-of-way. Operation of the 

facilities would impact 15.4 acres that are not currently used in operating existing facilities. Table 1.9-1 

identifies the land requirements for each Project facility and land use is further discussed in section 2.4.

TABLE 1.9-1

Summary of Land Requirements

State/County/Facility Property Size (acres)a

Land Affected During 

Construction (acres)

Land Affected During 

Operation (acres)

MARYLAND

Calvert County

Liquefaction Facilities 1,017.0 68.4 b 13.1 c

Offsite Area A 179.4 94.9 d 0.0 e

Offsite Area B 11.0 5.8

f 0.0

Maryland Subtotal NA 169.1 13.1

VIRGINIA

Fairfax County

Pleasant Valley Compressor Station 37.0 22.2

g 2.3 h

Pleasant Valley Suction/Discharge Pipelines and 

Pleasant Valley M&R Facility

3.5 3.3 0.0

Loudoun County

Loudoun M&R Facility 39.0 1.9 i 0.0

Leesburg Compressor Station Contractor 

Staging Area

74.4 8.4 i 0.0

Virginia Subtotal NA 35.8 2.3

Project Total NA 204.9 15.4

____________________

a The property size represents the total land that is owned or leased by DCP and DTI. Construction and operation of the 

proposed facilities would take place within the owned or leased property boundaries.

b

Includes 0.35-acre impact associated with re-establishment of a previously existing access road on the LNG Terminal 

property but outside of the Fenced Area.

c The Liquefaction Facilities would occupy 59.5 acres within the existing Fenced Area of the LNG Terminal. However,

approximately 46.5 acres of the Liquefaction Facilities would be located on land that is currently utilized for operation of 

the LNG Terminal. The remaining approximately 13.1 acres of the Liquefaction Facilities would impact land that is 

currently unaffected by operation of the LNG Terminal.

d Based on information provided by DCP to the FERC; however, the Maryland DNR has stated that DCP would affect 94.5 

acres of land at Offsite Area A. The final area affected would be confirmed prior to construction.

e Offsite Area A would not be used in the operation of the Liquefaction Facilities but would result in converting 92.7 acres of 

upland forest and 1.3 acres of successional woodland to open land.

f Does not include 0.2 acre associated with construction of the temporary pier.

g Does not include 0.9 acre for the nonjurisdictional substation that would be constructed by the Northern Virginia Electric 

Cooperative within the Pleasant Valley Compressor Station site.

h The expansion of the Pleasant Valley Compressor Station would occupy 3.0 acres within the existing compressor station 

property. However, 0.7 acre of the expansion would be located on land that is currently utilized for operation of the 

compressor station. The remaining 2.3 acres of the expansion facilities would impact land that is currently unaffected by 

operation of the compressor station.

i

Includes reuse of existing access roads. Does not include 2.2 acres currently occupied by buildings and other structures. 
33

1.10 PERMITS, APPROVALS, AND REGULATORY CONSULTATIONS

Table 1.10-1 identifies the major federal, state, and local environmental permits, approvals, and 

regulatory clearances for the Project.

TABLE 1.10-1

Major Environmental Permits, Licenses, Approvals, and Certificates for 

Construction, Operation, and Maintenance of the Project

Agency Permit/Approval/Clearance Status

FEDERAL

Federal Energy Regulatory 

Commission

Natural Gas Act Section 3 Authorization and 

Section 7 Certificate of Public Convenience 

and Necessity

Application submitted April 1, 2013

U.S. Department of Energy, 

Office of Fossil Energy

Authorization to export LNG to Free Trade 

Agreement Countries

Application submitted September 1, 2011; 

authorization granted by DOE-FE in 

Order No. 3019 on October 7, 2011

Authorization to export LNG to Non-Free Trade 

Agreement Countries

Application submitted October 3, 2011; 

conditional authorization granted by DOEFE on in Order No. 3331 on September 

11, 2013

U.S. Department of the Army 

Corps of Engineers (COE), 

Baltimore District

Clean Water Act (CWA) Section 404 and 

Rivers and Harbors Act Section 10 permits

Application submitted April 1, 2013; 

approval dated April 29, 2014

COE, Norfolk District CWA Section 404 permit Application submitted April 1, 2013; 

approval dated October 18, 2013

U.S. Fish and Wildlife Service 

(FWS); Maryland Field Office

Endangered Species Act (ESA) Section 7 

consultation, Fish and Wildlife Coordination Act 

consultation, Migratory Bird Treaty Act 

consultation, Bald and Golden Eagle 

Management Act consultation

Informal consultation initiated June 14, 

2012; FWS final determination dated May 

30, 2013

FWS; Virginia Field Office ESA Section 7 consultation, Fish and Wildlife 

Coordination Act consultation, Migratory Bird 

Treaty Act consultation, Bald and Golden 

Eagle Management Act consultation

Informal consultation initiated January 2, 

2013; FWS final determination dated 

August 15, 2013

U.S. Department of Commerce, 

National and Atmospheric 

Administration, National Marine 

Fisheries Service (NMFS)

Consultation under ESA Section 7 Informal consultation initiated June 14, 

2012; NMFS concurrence dated 

September 11, 2013

Consultation under the Magnuson-Stevens 

Fishery Conservation and Management Act

Informal consultation initiated June 14, 

2012; NMFS concurrence dated February 

25, 2013

U.S. Environmental Protection 

Agency

CWA Section 401, Water Quality Certification 

review, CWA Section 402, National Pollutant 

Discharge Elimination System (NPDES) 

review, CWA Section 404 review, CWA 

Stormwater Discharge Permit review

In conjunction with state permit 

applications (see below)

U.S. Coast Guard (USCG) Letter of Recommendation Waterway Suitability Assessment request 

letter submitted May 23, 2012; USCG 

response and Letter of Recommendation 

dated July 2, 2012

U.S. Department of Defense

(DOD)

Project consultation Consultation initiated May 2, 2012; DOD 

response received February 22, 2013

Federal Aviation Administration Notice of Proposed Construction or Alteration DCP anticipates initiating consultation 

February 2014; DCP anticipates

response second quarter 2014

Advisory Council on Historic 

Preservation

Opportunity to comment under Section 106 

National Historic Preservation Act (NHPA)
34

TABLE 1.10-1 (cont’d)

Major Environmental Permits, Licenses, Approvals, and Certificates for 

Construction, Operation, and Maintenance of the Project

Agency Permit/Approval/Clearance Status

MARYLAND

Maryland Department of the 

Environment

CWA Section 401, Water Quality Certification Application submitted April 1, 2013; DCP 

anticipates approval May 28, 2014

NPDES Permit for Stormwater Discharge (LNG 

Terminal, Offsite Areas A and B)

Application submitted April 1, 2013; 

approval dated December 2, 2013

NPDES Surface Water Discharge Permit 

(industrial) (modification to existing permit)

Application submitted December 9, 2013; 

approval dated February 11, 2014

Nontidal Wetlands Permit Application submitted April 1, 2013; DCP 

anticipates approval May 28, 2014

Tidal Wetlands License Application submitted April 1, 2013; DCP 

anticipates approval May 28, 2014

Coastal Zone Management Consistency 

Certification

Consultation initiated April 1, 2013; DCP 

anticipates approval May 28, 2014

Waterways Construction Permit Application submitted April 1, 2013; DCP 

anticipates approval May 28, 2014

General Discharge Permit for Hydrostatic 

Testing (tanks and pipes)

Application submitted October 2013; 

approval dated October 2013 (no permit 

required)

Maryland Department of Natural 

Resources

Maryland Natural Heritage Program 

consultation

Application submitted June 14, 2012; 

response received August 29, 2013; DCP 

anticipates final response May 2014

Maryland Historical Trust Section 106 NHPA consultation Consultation initiated June 14, 2012; DCP 

concurrences received September 23,

and November 21, 2013

Maryland Public Service 

Commission

Certificate of Public Convenience and 

Necessity – Air Permit, Water Appropriations 

Permit (construction); Water Appropriations 

Permit (operation)

Application submitted April 1, 2013; DCP 

anticipates approval May 23, 2014

Maryland State Highway 

Administration

Commercial/Industrial/Residential Subdivision 

Access Permit

DCP submitted application February 12, 

2014; approval dated March 5, 2014

Critical Area Commission for the 

Chesapeake and Atlantic Coastal 

Bays

Critical Area Approval DCP anticipates initiating consultation 

July 16, 2013; approval dated October 

22, 2013

VIRGINIA

Virginia Department of 

Environmental Quality

CWA Section 401, Water Quality Certification Application submitted April 1, 2013; 

approval dated April 26, 2013

Coastal Zone Management Consistency 

Certification

Application submitted April 1, 2013; DCP 

approval dated October 3, 2013

Virginia Water Protection Permit Application submitted April 1, 2013; 

approval dated April 26, 2013 (no permit 

required)

Virginia Department of Game and 

Inland Fisheries

Fish and Wildlife Coordination Act Review Consultation initiated September 26, 

2012; response dated February 24, 2014

Virginia Department of Historic 

Resources

Section 106 NHPA consultation Consultation initiated December 21, 

2012; concurrence dated May 29, 2013

Virginia Department of 

Conservation and Recreation

General permit for Discharge of Stormwater for 

Construction Activities (Loudoun M&R Facility

and Pleasant Valley Compressor Station)

Application submitted April 1, 2013; 

approval dated May 1, 2013

Fish and Wildlife Coordination Act Review Consultation initiated October 19, 2012; 

review response dated October 24, 2012. 

Consultation update initiated July 29, 

2013; review response dated October 31, 

2012.

Virginia Department of Agriculture 

and Consumer Services

Fish and Wildlife Coordination Act Review Consultation initiated September 26, 

2012; review response dated October 24, 

2012 
35

TABLE 1.10-1 (cont’d)

Major Environmental Permits, Licenses, Approvals, and Certificates for 

Construction, Operation, and Maintenance of the Project

Agency Permit/Approval/Clearance Status

LOCAL

Calvert County Department of 

Community Planning and Building

Critical Area Form, Buffer Management Plan Consultation submitted July 16, 2013; 

review response dated October 22, 2013

Forest Conservation Plans (Liquefaction 

Facilities and Offsite Area A)

Consultations submitted July 1 and 17, 

2013; review response dated December 

6, 2013 (Liquefaction Facilities); review 

response dated January 9, 2014 (Offsite 

Area A)

Calvert County Division of 

Inspections and Permits 

Review of Stormwater Management Plan 

(SMP), Erosion and Sediment Control Plan 

(E&SCP), and Site Plan for Grading Permits

(Liquefaction Facilities and Offsite Areas A and 

B)

Initial submittals April 1, 2013; DCP 

anticipates final reviews by June 4, 2014 

Calvert County Division of Water 

and Sewer

Water and Sewer Commercial Permit DCP submittal dated January 15, 2014; 

DCP anticipates permit by May 31, 2014

Calvert County Department of 

Public Safety

Fire Marshall Plan Review DCP submittal dated April 1, 2014; DCP 

anticipates review by May 31, 2014

Calvert County Department of 

Public Works

Commercial Access Permit DCP submittal dated April 1, 2014; DCP 

anticipates permit by May 31, 2014

Fairfax County Department of 

Public Works

Permit Application Form (including equipment 

worksheet), Grading Permit, Property Owner 

Affidavit, Permit Authorization Affidavit, 

Statement of Special Inspections, Accessibility 

Compliance Form, Electrical Energy 

Certification Form

DCP anticipates submittal July 2015; 

DCP anticipates final approvals by 

December 2015

Review of SMP, E&SCP, and Site Plan DCP anticipates submittal July 2015; 

DCP anticipates final approvals by 

December 2015

Fairfax County Department of 

Planning and Zoning

2232 Application DCP anticipates submittal July 2015; 

DCP anticipates final approvals by 

December 2015

Fairfax County Fire and Rescue 

Department

Building Information Form DCP anticipates submittal July 2015; 

DCP anticipates final approvals by 

December 2015

Loudoun County Department of 

Building and Development

Building Permit and Land Development Permit DCP anticipates submittal July 2015; 

DCP anticipates final approvals by 

December 2015

Electrical Permit, Fire Suppression Permit, Gas 

Permit, Grading Permit, Mechanical Permit, 

Plumbing Permit, Soils Permit; review of SMP 

and E&SCP

DCP anticipates submittal July 2015; 

DCP anticipates final approvals by 

December 2015

1.11 FUTURE PLANS AND ABANDONMENT

DCP states that it has no plans for future expansion or abandonment of the Project facilities. If 

expansion is proposed in the future, DCP would seek the appropriate federal, state, and local 

authorizations. At the end of the useful life of the Project facilities, DCP would obtain the necessary 

permission to abandon the facilities in accordance with regulations that exist at the time and any 

landowner requirements.
36

2.0 ENVIRONMENTAL ANALYSIS

The environmental consequence of constructing and operating the Cove Point Liquefaction 

Project facilities would vary in duration and significance. Four levels of impact duration were 

considered: temporary, short-term, long-term, and permanent. A temporary impact would generally 

occur during construction, with the resource returning to preconstruction conditions almost immediately 

afterward. A short-term impact could continue for up to 3 years following construction. An impact was 

considered long-term if the resource would require more than 3 years to recover. A permanent impact 

could occur as a result of an activity that modifies a resource to the extent that it would not return to 

preconstruction conditions during the life of the Project, such as the construction and operational impact 

of the Liquefaction Facilities. We8considered an impact to be significant if it would result in a 

substantial beneficial or adverse change in the physical environment and the relationship of people with 

the environment.

In this section, we discuss the affected environment, general construction and operational 

impacts, and proposed mitigation measures for each resource. We also discuss the design and 

construction of the facility to resist natural hazards. DCP, as part of its proposal, agreed to implement 

certain measures to reduce impacts on environmental resources. We evaluated the proposed mitigation 

measures to determine whether additional measures would be necessary to reduce impacts. Where we 

identified the need for additional mitigation, the measures appear as bulleted, boldfaced paragraphs in the 

text. We will recommend that these measures be included as specific conditions to authorizations that the 

Commission may issue to DCP. Conclusions in this EA are based on our analysis of the environmental 

impact and the following assumptions:

 DCP would comply with all applicable federal laws and regulations;

 the proposed facilities would be constructed as described in section 1.0 of this document; 

and

 DCP would implement the mitigation measures included in the applications and 

supplemental filings to the FERC.

2.1 GEOLOGY AND SOILS

2.1.1 Geologic Setting, Mineral Resources, and Geologic Hazards

Geologic Setting

Maryland Facilities

The Liquefaction Facilities and Offsite Areas A and B lie within the Atlantic Coastal Plain 

Physiographic Province (the Coastal Plain), a relatively low-lying region with elevations reaching a few 

hundred feet above mean sea level. Much of the terrain is crossed by numerous streams that readily erode

the underlying geologic materials, depositing sediment as alluvial fans, deltas, and marine mud layers. 

The Coastal Plain is underlain by a wedge-shaped mass of unconsolidated gravel, sand, silt, and clay 

deposited in non-marine, marginal marine, and marine environments of Tertiary and Quaternary age. 

These deposits pinch out against crystalline bedrock of the Eastern Piedmont Physiographic Province to 

the west and continue offshore under the Chesapeake Bay to the east where they are more than 8,000 feet

thick (MDNR, 2009). 

 

8

“We,” “us,” and “our” refer to the environmental staff of the Commission’s Office of Energy Projects.
37

Information from the existing wells at the LNG Terminal (section 2.2.1) and geotechnical soil 

borings determined that the Fenced Area is underlain primarily by sand to a depth of at least 90 feet. The 

deepest excavation associated with construction of the Liquefaction Facilities would be approximately 20 

feet. Thus, work within the Fenced Area would not be expected to encounter consolidated geologic 

material or bedrock. Grading and other work to prepare Offsite Areas A and B for temporary use during 

construction of the Liquefaction Facilities would also not be expected to encounter consolidated geologic 

materials. Thus, blasting is not expected to be required for any of the Project facilities in Maryland. Any 

blasting, if necessary, would be conducted according to DCP’s blasting plan, which requires compliance 

with state blasting codes and local requirements and the use of state-licensed blasting contractors. We 

reviewed DCP’s blasting plan and find it acceptable.

The majority of new facilities within the Fenced Area, including stormwater management 

structures, would be in areas that were previously modified for industrial use. Construction and operation 

of the Liquefaction Facilities, and the temporary use of Offsite Areas A and B, would comply with the 

erosion control, revegetation, and restoration provisions of our Plan and Procedures and DCP’s sitespecific E&SCPs and SMPs to be approved by Calvert County. Upon completion of construction, the 

surface of Offsite Area A would be restored to pre-construction conditions with the exception of 

stormwater management facilities, which would be left in place; Offsite Area B would be restored to preconstruction conditions. Thus, construction and operation of the Liquefaction Facilities and the 

temporary use of Offsite Areas A and B would not have a significant impact on existing geologic 

conditions. 

Virginia Facilities

The Pleasant Valley Compressor Station, Pleasant Valley Suction/Discharge Pipelines, Pleasant 

Valley M&R Facility, Loudoun M&R Facility, and the DTI Leesburg Compressor Station Contractor 

Staging Area are located in the Northern Piedmont Physiographic Province (the Piedmont Province). The 

Piedmont Province has gently rolling topography with elevations ranging from 200 to 300 feet above sea 

level in the east to 800 to 900 feet above sea level in the west. The terrain becomes more rugged with 

proximity to the Blue Ridge Province to the west. 

The bedrock of the Piedmont Province comprises igneous and metamorphic rocks that range from 

the Proterozoic to Paleozoic era, which are overlain by Triassic sedimentary and igneous rock formed 

during the early stages of rifting associated with the opening of the Atlantic Ocean. Rivers and streams 

carrying sand, silt, and mud flowed into these lowland rift basins burying swamps and marshes, later 

producing small coal measures in the Piedmont Province. Near-surface bedrock within the Piedmont 

Province is often strongly weathered due to the humid climate, with as much as 65 feet of saprolite 

(weathered igneous and metamorphic rock) covering the bedrock. Outcrops are commonly restricted to 

stream valleys where saprolite has been removed by erosion (William and Mary, Department of Geology, 

ND).

The bedrock in proximity to the Pleasant Valley Compressor Station consists of sandstone from 

the Mesozoic Newark Supergroup. Bedrock near the Loudoun M&R Facility consists of an Upper 

Triassic pebble, cobble, and boulder conglomerate formation. DCP intends to conduct a geotechnical 

evaluation in 2015 to further characterized geologic conditions and assist in the final design of 

foundations for the proposed expansion of the Pleasant Valley Compressor Station.

DCP stated that bedrock was encountered during construction of the Pleasant Valley facilities but, 

to its knowledge, the rock was removed by conventional methods and no blasting was required. Thus, 

DCP does not expect that blasting would be required for any of the Project facilities in Virginia. Any 
38

blasting, if necessary, would be conducted according to DCP’s blasting plan, which requires compliance 

with state blasting codes and local requirements and the use of state-licensed blasting contractors.

The majority of new facilities in Virginia would be in areas that were previously disturbed or 

modified for industrial use. Construction and operation of the Pleasant Valley Compressor Station 

modifications, Pleasant Valley Suction/Discharge Pipelines, Pleasant Valley M&R Facility, and Loudoun 

M&R Facility, as well as the temporary use of the DTI Leesburg Compressor Station Contractor Staging 

Area, would comply with the erosion control, revegetation, and restoration provisions of FERC’s Plan 

and Procedures and DCP’s site-specific E&SCPs and SMPs to be approved by Loudoun and Fairfax 

County officials. Thus, construction and operation of the Project facilities in Virginia would not have a 

significant impact on existing geologic conditions. 

Mineral Resources

Maryland Facilities

There are no oil or natural gas wells at or near the Liquefaction Facilities or Offsite Areas A and 

B according to the MDE Mining in Maryland Maps (2010). These areas are not currently viewed as 

prospective drilling locations for oil and gas (USGS, 2012a).

Commercially extractable non-hydrocarbon mineral resources at or near Cove Point are limited to 

iron, sand, gravel, titanium, and zirconium (USGS, 2012b). However, there are no active mines at or 

within 0.25 mile of the LNG Terminal and no potentially exploitable mineral resources have been 

identified at or near the proposed Project facilities. Therefore, no impacts on mineral resources would be

expected during construction and operation of the Liquefaction Facilities and during use of Offsite Areas 

A and B.

Virginia Facilities

Historical mining produced a variety of commodities including copper, iron, dimension stone, 

roadstone, dolostone, lime, and marble in Fairfax and Loudoun Counties (Virginia Department of Mines, 

Minerals, and Energy, 2006). However, there are no active or historic mines located within 0.25 mile of

any of the Project facilities in Virginia. According to the USGS Energy Resources Program, there is no 

historical or current production of oil or gas in Fairfax or Loudoun Counties (USGS, 2012c). Therefore, 

no impacts on mineral resources would be expected during construction and operation of the facilities in 

Virginia.

Geologic Hazards

Potential geologic hazards associated with the Project include seismicity and surface faulting, 

landslides, subsidence, flooding, and tsunamis.

Seismicity and Surface Faulting

Seismic earthquakes are the result of sudden movement along a fault, which can result in 

damaging ground motions or secondary effects including landslides and soil liquefaction. DCP 

conducted a seismic review for the LNG Terminal and determined that no active or inactive faults are 

located near the LNG Terminal or Offsite Areas A and B (MDNR, 2007). For the purpose of seismic risk 

analysis at the LNG Terminal, the most significant seismic zones are the Central Virginia Seismic Zone, 

centered approximately 125 miles southwest from the LNG Terminal, and the Giles County Seismic 

Zone, centered approximately 250 miles southwest from the LNG Terminal. The most recent earthquake 
39

to affect the East Coast was a magnitude 5.8 event on August 23, 2011. This earthquake was centered 

approximately 100 miles west-southwest from the LNG Terminal and caused light damage to structures in 

Washington, D.C., and other areas, but did not damage the LNG Terminal, according to DCP. 

Probabilistic hazard analysis, which is based on historical seismicity and geologic conditions in a region, 

indicates that the peak ground acceleration predicted for Calvert County, Maryland could produce weak 

shaking and light to very light damage. The USGS estimates the peak ground accelerations on a rock site

in Calvert County that has a 2 percent probability of being exceeded in 50 years (USGS, 2005) is 

approximately 6 percent of the acceleration of gravity (0.06 g). Peak round accelerations in this range can 

be amplified by a factor of 2 or more on soil sites. As discussed in section 2.1.2, the Liquefaction 

Facilities would be designed and constructed in accordance with NFPA 59A and other engineering 

standards, which would further reduce the potential for a seismic event to impact the facilities.

Extensive literature reviews performed by DCP indicate that there are no known Quaternary 

faults in the Project area (Cove Point facility) and surrounding regions. We received a comment 

regarding concerns about the Moran Landing Fault (located over 2 miles north of the Cove Point facility) 

crossing over DCP gas pipelines; however, there was no evidence that this fault is active. These DCP 

pipelines are not part of this Project. Furthermore, geologic cross sections developed from boring logs at 

the Project site indicate that the contact between the Calvert Formation and the overlying Choptank/St. 

Mary’s Formation has not been offset by fault displacement at the site. These data indicate that faulting 

has not occurred in the Project area since the Miocene. Therefore, we consider the possibility of 

seismically induced faulting in the Project area to be remote. 

Historical earthquake records for Fairfax and Loudoun Counties show no active or inactive faults 

near the Pleasant Valley Compressor Station, Pleasant Valley Suction/Discharge Pipelines, Pleasant 

Valley M&R Facility, Loudoun M&R Facility, and the DTI Leesburg Compressor Station Contractor 

Staging Area. Probabilistic hazard analysis indicates that the peak ground acceleration predicted for 

Fairfax and Loudoun Counties could produce light damage to buildings and structures. The August 23, 

2011 magnitude 5.8 earthquake was centered approximately 70 miles south-southwest from the proposed 

Virginia facilities but did not damage DCP’s existing facilities.

Landslides

The LNG Terminal and Offsite Areas A and B lie within an area of relatively low local 

topographic relief with a low to moderate incidence of landslides (USGS, 2012d). Soils within the 

Fenced Area are designated as urban with no slopes; therefore, no landslide exposure is anticipated within 

the Liquefaction Facilities. The steeper banks associated with wetlands and streams at Offsite Area A 

could exhibit slope failure; however, DCP would observe a 100-foot-wide buffer around wetlands and

waterbodies, thereby avoiding steeper slopes and preserving vegetation which would further reduce the 

potential for localized slope failures to occur. Offsite Area B is relatively flat and would not be subject to 

landslide risk.

The proposed facilities in Virginia also occur in areas with relatively low relief characterized by 

low landslide susceptibility (USGS, 2012d).

Subsidence

Ground settlement due to design level seismic events are not predicted to affect the structures at 

the site. Karst terrain, including sinkholes, can develop in areas where carbonate bedrock units occur near 

the land surface. We received a comment stating concerns regarding sinkholes located over 3 miles from 

the LNG Terminal at the Calvert Cliffs Nuclear Power Plant; however, our research indicates that none of 

the Liquefaction Facilities are underlain by near-surface carbonate bedrock units and no karst terrain is 
40

known to occur in proximity to the proposed facilities (MDE, 2010; USGS, 1976). In addition, none of 

the proposed facilities would be located near active or historical underground mines (MDE, 2010; 

Virginia Department of Mines, Minerals, and Energy, 2012; USGS, 2012e) and DCP has not experienced 

any instances of ground subsidence or collapse at any of its existing facilities where the proposed Project 

would be constructed and operated. However, in their recommended license conditions for the Maryland 

PSC CPCN, the Reviewing State Agencies (through PPRP) recommended that DCP fund a subsidence 

monitoring program in the Project area. The Maryland Geological Survey (a part of MDNR) would 

conduct the monitoring. Subsidence due to liquefaction, karst terrain, or mine collapse is not likely to 

cause significant impacts on the Liquefaction Facilities.

Flooding

A review of the Federal Emergency Management Agency (FEMA) Flood Insurance Rate Maps 

(FIRM) showed no designated flood zones at the Liquefaction Facilities, Offsite Area A, Pleasant Valley 

Compressor Station, Pleasant Valley Suction/Discharge Pipelines, Pleasant Valley M&R Facility, 

Loudoun M&R Facility, or DTI Leesburg Compressor Station Contractor Staging Area. Offsite Area B is 

located within a FEMA flood Zone “AE,” which is based on the base flood elevation from the Patuxent 

River. Activities at Offsite Area B during construction would not affect the flood storage capacity at this

location because no permanent aboveground structures would be located within the FEMA FIRM 

boundary and the area would be restored to preconstruction conditions to the extent possible following 

construction. 

Based on regional conditions, the potential for flash flooding to significantly impact construction 

or operation of the Project is low. DCP would monitor local weather conditions during construction to 

anticipate and plan for significant weather events during construction. Stormwater runoff during 

construction and operation of Project facilities would be managed through implementation of DCP’s sitespecific E&SCPs and SMPs which would be approved by appropriate local officials. 

We received comments regarding the potential for tropical storm surge to impact the LNG 

Terminal and Liquefaction Facilities in light of rising sea level, which commentors quote may be as great 

as 3.4 feet along coastal Maryland by the end of the century. Although DCP’s greater LNG Terminal 

property borders the Chesapeake Bay, the Fenced Area in which the Liquefaction Facilities would be 

located is situated inland. The elevation of the Fenced Area varies from approximately 70 to 130 feet 

above mean sea level (National Geodetic Vertical Datum 1929), with the majority of the existing and 

proposed facilities located at an elevation of more than 110 feet above mean sea level. Thus, tropical 

storm surge would not be likely to impact the industrialized Fenced Area and proposed Liquefaction 

Facilities. Storm surge and sea level rise impacts related to climate change are addressed in section 2.9.9.

Tsunamis

Maximum tsunamis inundation elevations at the site are judged to be less than maximum storm 

surge elevations. Therefore, a tsunami hazard would not be likely to impact the industrialized Fenced 

Area and proposed Liquefaction Facilities.

2.1.2 Design and Construction of the Cove Point Liquefaction Facilities and Pleasant Valley 

Compressor Station

Natural hazards, including those related to geology and foundation conditions, could affect the 

design and construction of the Liquefaction Facilities and Pleasant Valley Compressor Station. Our 

review and analysis of DCP’s proposed design and construction of the Project is provided below.
41

Geotechnical Site Characterization of the Liquefaction Facilities

Two geotechnical investigations were performed at the Liquefaction Facility. The investigation 

performed in June 2012 consisted of 9 soil borings and 19 cone penetration tests and the results were 

presented in a GZA GeoEnvironmental Inc. (GZA) report dated July 2012. A supplemental investigation 

was performed due to changes in the locations of some of the facilities and included 9 test borings drilled 

between July 15 and August 2, 2013. The results of this investigation were presented in a GZA 

supplemental report dated August 28, 2013. The subsurface conditions consist of Upper Sand and Lower 

Sand. The Upper Sand is present at depths ranging from approximately 6 to 18 feet and blow counts 

ranging from 0 to 21 feet. The fines content ranges from 10 to 47 percent. The Lower Sand is present 

below the Upper Sand and blow counts range between 2 and 55. Zones of loose sands were encountered 

in three of the six borings in the supplemental investigation. 

Groundwater was encountered between depths of 13 to 46 feet below ground surface or 

elevations of 56 to 96 feet above sea level. 

Site Grading 

The Liquefaction Facilities site would be cleared, grubbed, and prepared using standard 

earthmoving and compaction equipment. Up to 40 feet of fill would be placed in ravine areas on the site 

to raise the ground level to the finished grade elevation, which ranges between 100 and 130 feet above sea 

level. Where the fill is deepest (greater than 20 feet), settlement is expected during construction and over 

the design life of the facility. At some locations near the fenced boundaries of the construction area, 

retaining walls (either rigid or mechanical stabilized earth) would be constructed. Based on explorations 

at the site, the water table elevation is expected to range between 56 and 96 feet and, therefore, should not 

affect site preparation activities or construction of foundations. 

Foundations

After site preparation at the Liquefaction Facilities, foundations would be excavated for the 

installation of new equipment. One commentor expressed concerns that the vibration of the heavy

equipment could cause soil weakness, ruptured gas lines, and sinkholes. The GZA supplemental report 

recommends that gas turbine and Compressor Train, HRSG, steam turbines, and auxiliary boilers could 

be supported on mat foundations. However, considering the criticality of the equipment and the fact that 

loose sands are particularly susceptible to dynamic loadings including earthquake, DCP would use pile 

foundations for gas turbines, HRSG, and steam turbines to ensure settlement and vibration control. If 

settlement criteria are not satisfied, other structures may be supported on deep foundations such as auger 

cast piles, driven precast piles, and drilled minipiles. 

Facility and Structure Design

The Liquefaction Facilities would be constructed to satisfy the design requirements of 49 CFR 

193, NFPA 59A-2001, 2006 International Building Code and American Society of Civil Engineers 

(ASCE) 7-05. For seismic design, the facility would be designed to satisfy the requirements of NFPA 

59A-2006 and ASCE 7-05.

Wind Design

Section 2.8.4 includes the discussion of facility design for wind speed.
42

Seismic Design Ground Motions

Geotechnical investigations of the Liquefaction Facilities site determined that the site is

classified as Site Class D (firm soil) in accordance with the International Building Code and the ASCE 

7-05. Sites with soil conditions of this type will experience significant amplifications of surface 

earthquake ground motions.

GZA performed a site-specific seismic hazard study for the site. The study concluded that 

earthquake ground motions at ground surface at the site that have 2 percent probability of being exceeded 

in 50 years have a 0.2-second spectral acceleration value of 0.174 g, while the 1.0-second spectral 

acceleration at the site is 0.102 g (GZA, 2013). These predicted spectral accelerations are relatively low 

compared to other locations in the United States.

Construction and operation of the Project would not materially alter the geologic conditions of the 

Project area, and the Project would not affect mining of resources during construction or operation. 

Blasting is not anticipated during construction of the Project. The Project would not be affected by any 

significant geologic hazards, including areas of seismic activity or subsidence. DCP committed to 

conducting geotechnical studies to determine general subsurface conditions at the Pleasant Valley

Compressor Station site and develop engineering designs for the proposed foundations. Based on DCP’s 

proposal, including implementation of the FERC Plan and Procedures, DCP’s E&SCPs, and our 

recommended mitigation measures, we conclude that impacts on geological resources would be 

adequately minimized and would not be significant, and that the potential for impacts on the Pleasant 

Valley Compressor Station from geologic hazards would also be minimal. 

The design of the Liquefaction Facilities is currently at the Front-End Engineering Design 

(FEED) level of completion. A feasible design has been proposed, and DCP would conduct a significant 

amount of detailed design work if the Project is authorized by the Commission. Information regarding 

the development of the final design would need to be reviewed by FERC staff in order to ensure that the 

final design addresses the requirements identified in the FEED. Therefore, we recommend that:

 DCP should file the following information, stamped and sealed by the professional 

engineer-of-record, with the Secretary of the Commission (Secretary) for review 

and written approval by the Director of the Office of Energy Projects (OEP):

a. structure and foundation design drawings and calculations of the 

Liquefaction Facilities;

b. foundation and pile design drawings and calculations for all vibratory 

equipment, including gas turbines, HRSGs, steam generators, and 

compressors supported on piles; and

c. quality control procedures to be used for design and construction.

In addition, DCP should file, in its Implementation Plan, the schedule for producing 

this information. 

DCP intends to conduct a geotechnical evaluation in 2015 to further characterize geologic 

conditions and assist in final design of foundations for the proposed expansion of the Pleasant Valley 

Compressor Station. This work still remains to be completed and reviewed by FERC before the Pleasant 

Valley Compressor Station facility should be authorized to proceed with any construction activities. 

Because this investigation has not been completed, we recommend that: 
43

 Prior to starting any work on the Pleasant Valley Compressor Station, DCP should 

file the results of the geotechnical investigation, foundation recommendations, 

Project design, and construction details with the Secretary for review and written 

approval by the Director of OEP.

In conclusion, the Project is located in an area that presents several potential challenges related to 

geology, foundation conditions, and natural hazards; however, these conditions can be effectively 

managed through proper engineering design or shown to be minimal through additional evaluation. The 

recommendations included in this section ensure DCP would mitigate and or manage associated 

geological impacts on the proposed Project, and thus resultant impacts would be minor.

2.1.3 Soils

Soil Resources

Construction of the proposed Project would affect a total of 204.9 acres of land. A total of 

approximately 162.4 acres of soils would be affected during construction; the remaining approximately 

42.3 acres of land is covered by previously constructed surfaces and buildings at DCP’s existing facilities 

and is not included in the discussion of soils impacts. Operation of the proposed facilities would result in 

a total change of 15.4 acres of land and associated soils from a non-developed status to a 

commercial/industrial land use type.

The Project facilities would be underlain by 33 soil series. Appendix A lists the soil series that 

would be affected by construction and operation of the Project, as well as soil limitations related to 

erosion, compaction, revegetation potential, and prime farmland.

The majority of soils that would be affected by the Project facilities are considered to have a 

slight erosion hazard potential, low compaction potential, and high revegetation potential. The depth to 

bedrock is generally more than 20 inches, with the depth to bedrock for the majority of the Project 

facilities being more than 80 inches. About 25.6 acres of the total 162.4 acres of soils affected by 

construction of the Project are considered prime farmland; however, no active agricultural land or 

residential land is affected by the Liquefaction Facilities, Offsite Area A, or the facilities in Virginia. 

Offsite Area B is part of a larger parcel that also includes cropland; however, the portion of Offsite Area 

B that would be used during construction consists of mowed/maintained land and is not currently used for 

agricultural purposes. In addition, only 0.5 acre of Offsite Area B is considered prime farmland.

Soils affected by the Project were assessed for wind erodibility and water erosion potential. As 

shown in appendix A, soils affected by the Project are in Wind Erodibility Groups ranging from 1 to 8, 

with 1 being the highest potential for wind erosion and 8 being the lowest (U.S. Department of 

Agriculture, ND). The soils at the Liquefaction Facilities and Offsite Area A have moderate to high 

potentials for wind erosion, while the soils at the remaining facilities (Offsite Area B and the facilities in 

Virginia) are considered to have low potential for wind erosion. 

The majority of soils affected by construction of the Project are considered to have a low 

potential for erosion from water, with the exception of 9.0 acres at the Liquefaction Facilities and 46.3 

acres at Offsite Area A that would be affected during construction that are considered to have a high 

water erosion potential. 
44

Impacts and Mitigation

The primary impacts of the Project on soils would be an increased potential for erosion and 

potentially reduced revegetation of disturbed areas. To limit the effects of erosion, DCP would 

implement best management practices outlined in FERC’s Plan and Procedures and detailed in sitespecific E&SCPs and SMPs. DCP’s site-specific plans would be reviewed and approved by appropriate 

local officials and would comply with the provisions of the Maryland Standards and Specifications for 

Soil Erosion and Sediment Control and the 1992, Third Edition, Virginia Erosion and Sediment Control 

Handbook. Appropriate erosion and sediment control devices would be implemented and maintained at 

all times during the period of construction, as well as following the completion of construction until 

revegetation has occurred. Following restoration and clean-up, the disturbed areas would be monitored to 

maintain erosion control structures and to repair any erosion that occurs. 

Most soils within the Project workspaces have moderate to high revegetation potential, with areas 

of steep slopes being the most difficult to establish vegetation following construction. At Offsite Area A, 

most steep slopes would be avoided by DCP’s implementation of a 100-foot-wide buffer around wetlands 

and waterbodies, in which no vegetative clearing or soil disturbance would occur. For other disturbed 

areas, DCP would implement topsoil stripping and segregation over the entire Project workspace to 

improve revegetation success following construction. DCP would cover or otherwise manage the topsoil 

stockpiles during the course of construction and then replace the topsoil for restoration, as needed. Soil 

grading would be implemented to restore compacted or rutted soils to pre-construction conditions and 

disturbed areas would be planted with native species. Restoration would also include the removal of 

gravel used to stabilize temporary roads and laydown areas within approved workspaces. 

By implementing the above construction and restoration procedures, the Project would not result 

in any significant, long-term impacts on soils.

2.2 WATER RESOURCES, FISHERIES, AND WETLANDS

2.2.1 Groundwater

Existing Groundwater Resources

The Project areas in Maryland are within the Coastal Plain Physiographic Province and overlie 

five aquifers comprised of Tertiary and Quaternary unconsolidated gravel, sand, silt, and clay deposits 

that pinch out against irregular crystalline rocks of the Piedmont Physiographic Province to the west. The 

five hydrogeologic formations include, in order of increasing depth, the Surficial Aquifer, the Piney Point 

Aquifer, the Aquia Aquifer, the Upper Patapsco Aquifer, and the Lower Patapsco Aquifer (Hansen, 1996; 

Achmad and Hansen, 1997; and Drummond, 2007). 

The Surficial Aquifer is composed of upland and lowland deposits and is recharged primarily by 

precipitation within the Project area. Water in the Surficial Aquifer either moves short distances before 

discharging into local streams or springs, or percolates into deeper aquifers (USGS, 1997).

The Piney Point Aquifer is approximately 135 feet deep at the LNG Terminal and is recharged by 

leakage from the Surficial Aquifer. The Piney Point Aquifer is primarily used by small water users, such 

as self-supplied domestic users and small businesses. Water levels in this aquifer have decreased over 

time as water withdrawals have increased (USGS, 1997).

The Aquia Aquifer occurs at a depth of 650 to 700 feet at the LNG Terminal and is the primary 

groundwater source in Calvert County. The aquifer is recharged by precipitation in Anne Arundel and 
45

Prince George’s Counties, Maryland, more than 20 miles northwest from the Project area. Water levels in 

the Aquia Aquifer have declined at a rate of about 0.5 foot per year since 1980 (Drummond, 2001).

The Upper Patapsco Aquifer is typically 600 to 980 feet deep in the region, and the Lower 

Patapsco Aquifer occurs at a depth of approximately 1,400 feet at the LNG Terminal. These aquifers are 

not significant water sources in southern Calvert County because of their depth and the availability of 

groundwater from the shallower Piney Point and Aquia Aquifers (USGS, 1997).

Groundwater withdrawals make up the majority of consumptive water use in Calvert County. 

Groundwater withdrawals in 2000 averaged 7.01 million gallons per day (mgd), of which 3.69 mgd were 

from self-supplied domestic withdrawals, 2.30 mgd were for municipal supply, 0.55 mgd for commercial 

and industrial use, 0.41 mgd for thermoelectric power generation, and 0.06 mgd for irrigation (USGS, 

2010). 

The Project facilities in Virginia are within the Mesozoic Lowlands Region of the Piedmont 

Physiographic Province (Bailey, 1999). The geology in the area consists of sandstone, shale, diabase 

dikes, and basalt flows deposited in half grabens and grabens during rifting that produced the Atlantic 

Ocean (The College of William and Mary, Department of Geology, ND). The Culpeper Basin is the 

primary aquifer in the region and lies at depths of 200 to 600 feet deep. Recharge of the Culpeper Basin 

is the result of precipitation in Loudoun and Fairfax Counties, Virginia (CH2M Hill, 2008). 

Groundwater is an important source of drinking water for residents in the Project areas in 

Virginia. In Loudoun County in 1998, 2.24 mgd of groundwater was withdrawn for private domestic 

supply, 1.81 mgd for public water supply, 0.25 mgd for commercial and industrial use, and 0.06 mgd for 

agricultural use. In Fairfax County in 1998, 2.60 mgd was withdrawn for private domestic supply, 1.09 

mgd for commercial and industrial uses, and 0.76 mgd for public water supply (Solley et al., 1998).

Sole Source Aquifers

The U.S. Environmental Protection Agency (EPA) defines a principal, or sole source, aquifer as 

one that supplies at least 50 percent of the drinking water consumed in the area overlying the aquifer. 

None of the Project facilities are located within an EPA-designated sole source aquifer or a statedesignated primary aquifer. 

Water Supply Wells and Springs 

Table 2.2.1-1 identifies potable water supply wells and springs within 150 feet of the proposed 

Project construction workspaces. DCP owns and operates three wells within the Fenced Area of the LNG 

Terminal, one well within the boundary of the Pleasant Valley Compressor Station, and one well within 

the fenceline of the Loudoun M&R Facility. Two wells within the Fenced Area are capped and no longer 

operational. 

DCP also identified a well within the Offsite Area B property, but outside the proposed work 

limits of the site. According to the landowner, the well was installed during construction of the nearby 

Maryland Route 2/4 bridge but subsequently collapsed and has since been out of use. There are no other 

private, public or community water systems within 150 feet of the Project.

DCP identified several wetlands at Offsite Area A that receive their hydrology from groundwater 

seeps. These seep wetlands are discussed in section 2.2.4. 
46

TABLE 2.2.1-1

Potable Water Supply Wells and Springs within 150 feet of Proposed Project Construction Workspaces

State/County/Facility Well Type Approximate Location Relative to Project

MARYLAND

Calvert County

Liquefaction Facilities DCP – Private Within Fenced Area

DCP – Private Within Fenced Area

DCP – Private Within Fenced Area

DCP – Capped and 

Abandoned

Within Fenced Area

DCP – Capped and 

Abandoned

Within Fenced Area

VIRGINIA

Fairfax County

Pleasant Valley Compressor Station DCP – Private Within compressor station property

Loudoun County

Loudoun M&R Facility DCP – Private Within Loudoun M&R Facility fenceline

Impacts and Mitigation

DCP has two permits from the MDE to appropriate groundwater from the three wells at the LNG 

Terminal. One permit provides for the average withdrawal of 40,000 gpd on a yearly basis and 60,000 

gpd per month of maximum use from the well completed in the Lower Patapsco Aquifer. The second 

permit provides for the average withdrawal of 10,000 gpd on a yearly basis and 60,000 gpd per month of 

maximum use from the two wells completed in the Aquia Aquifer. 

To support construction and operation of the Liquefaction Facilities, in its application to the 

Maryland PSC, DCP has applied for an appropriation of additional water from the well completed in the 

Lower Patapsco Aquifer.9 More specifically, DCP has requested authorization to withdraw an additional 

40,000 gpd average on a yearly basis and 60,000 gpd per month of maximum use during construction of 

the Liquefaction Facilities, and a total of 250,000 gpd average on a yearly basis and 375,000 gpd per 

month of maximum use during operation of the Liquefaction Facilities. However, in their recommended 

license conditions for the Maryland PSC CPCN, the Reviewing State Agencies (through PPRP)

recommended a reduced water withdrawal of 233,000 gpd annual average and a monthly maximum of 

275,000 gpd. In its testimony to the PSC on January 29, 2014, DCP agreed to the recommended water 

withdrawal limits. 

DCP states that the additional groundwater needed during construction would be utilized for 

fugitive dust suppression, hydrostatic testing of equipment and piping, and steam flushing. The majority 

of the additional groundwater needed during operation of the Liquefaction Facilities would be utilized in 

the steam turbine system, with secondary needs including fire suppression, operation of the LNG 

vaporizer, drinking water, and general maintenance. DCP does not propose changes to the existing 

allocation from the Aquia Aquifer and would abandon one of the two wells completed in the aquifer.

DCP analyzed the potential drawdown of the Lower Patapsco Aquifer based on its initially 

proposed increase in water use. In the analysis, DCP compared the results of a 2008 pump test of the 

 

9 DCP’s application to the Maryland PSC was provided as an attachment to its June 20, 2013 Supplemental Filing 

and is available for viewing on the FERC Internet website in the Project’s docket (http://www.ferc.gov), 

Accession 20130620-5137. Under the Files, select the PDF file titled “Att 1- 04-01-13 CPCN 

Application.PDF.” 
47

onsite well to the drawdown from the increased water use predicted by the AQTESOLV software model. 

This comparison demonstrated a good fit between the observed and predicted drawdown levels in the well 

and concluded that the requested 250,000 gpd annual average withdrawal would result in 

approximately17.5 feet of drawdown at the well, and the requested 375,000 gpd for the month of 

maximum use would result in approximately 26.2 feet of drawdown at the well. In the maximum 

pumping scenario, the elevation of the water level in the onsite well would be approximately 46 feet 

below mean sea level (bmsl). However, because DCP would limit its water withdrawal to the amounts 

recommended by the Reviewing State Agencies, the resulting drawdown at the well would be less than 

DCP’s initial estimates. 

The primary criterion that the MDE uses in evaluating water appropriation permit applications in 

a confined aquifer in the Maryland Coastal Plain is the 80 percent management level, which is defined as 

80 percent of the total available drawdown measured from the pre-pumping water level to the top of the 

aquifer. The MDE implements the 80 percent management level to prevent reduction in capacity for 

users, infiltration of poor quality waters, and possible land subsidence. Based on regional information, 

the 80 percent management level for the Lower Patapsco Aquifer in the vicinity of the LNG Terminal 

occurs at an approximate elevation of 1,090 feet bmsl (Drummond, 2007). Thus, under the maximum 

pumping scenario proposed by DCP, the predicted water level in the onsite well would remain 

approximately 1,044 feet above the 80 percent management level for the Lower Patapsco Aquifer. 

Utilizing site-specific information including a static water level of 20 feet bmsl results in an elevation of 

1,028 feet bmsl for the 80 percent management level. In this case, the predicted water level in the onsite 

well would remain 982 feet above the 80 percent management level in the maximum use scenario. Based 

on the predicted drawdown for construction and operation of the Liquefaction Facilities and the 

substantial capacity of the Lower Patapsco Aquifer, DCP’s water withdrawal from the Lower Patapsco 

Aquifer as recommended by the Reviewing State Agencies would not significantly impact the aquifer or 

other groundwater users in the area. In addition, because the Piney Point Aquifer and Aquia Aquifer are 

the primary groundwater sources for Calvert County, DCP’s water withdrawal from the Lower Patapsco 

Aquifer would not significantly impact other groundwater users in the area. Alternative sources for the 

water needed to construct and operate the Liquefaction Facilities are discussed in section 3.5.

We received a comment during the scoping period that declining water levels in the Lower 

Patapsco aquifer could lead to river-water intrusion. As described above, DCP’s water withdrawal from 

the Lower Patapsco Aquifer, as recommended by the Reviewing State Agencies, would remain above the 

80 percent management level in the maximum use scenario and, therefore, would not significantly impact 

the aquifer or other groundwater users in the area.

New piping and other equipment would be hydrostatically tested to ensure its integrity before 

being placed into service. DCP estimates that 300,000 gallons of water would be required to complete 

testing of piping and other equipment for the Liquefaction Facilities. Test water would be obtained from 

wells at the LNG Terminal or from a local public water supply. Hydrostatic test water for the Pleasant 

Valley Compressor Station, the Pleasant Valley Suction/Discharge Pipelines, and the Pleasant Valley

M&R Facility would be obtained from a public water supply and trucked to each facility. DCP estimates 

that 200,000 gallons of water would be required to complete testing at these facilities. DCP would use 

1,000 gallons of water from its existing well at the Loudoun M&R Facility for hydrostatic testing of new 

piping and equipment. The small volumes of private and public water would not impact the source 

aquifers or other groundwater users in the appropriation area. DCP would obtain all necessary permits to 

appropriate and discharge hydrostatic test water. 

Project construction would not result in significant groundwater impacts because the majority of 

construction would involve shallow, temporary, and localized excavation or grading. The depth to 

groundwater in the Project area would generally be below structure foundation or pipeline trench 
48

excavation depths. Geotechnical soil borings within the Fenced Area at the LNG Terminal encountered 

groundwater at depths below the deepest excavation or footing for the Liquefaction Facilities, and DCP 

does not expect to encounter groundwater in any other Project excavations. Should shallow groundwater 

be encountered, local water table elevations could be affected by dewatering and increased turbidity in the 

water table could occur. Shallow aquifers could also sustain impacts from changes in overland flow 

regimes and recharge fluctuations caused by facility construction and clearing and grading of the 

proposed pipeline right-of-way. These impacts would be minor, temporary, and localized to the 

construction area. DCP would minimize these impacts by implementing erosion control and water 

management practices described in our Plan and Procedures and its E&SCPs.

Shallow groundwater and surficial aquifers could be vulnerable to contamination caused by 

inadvertent surface spills of hazardous materials or fuels used during construction. DCP would 

implement measures in its Spill Prevention and Contaminant Control Plan to minimize the potential for 

groundwater impacts associated with an inadvertent spill of fuel, oil, and other hazardous fluids, which 

include:

 pumps operating within 100 feet of a waterbody or wetland boundary would use 

appropriate secondary containment systems to prevent spills;

 bulk storage of hazardous materials, including chemicals, fuels, and lubricating oils have 

appropriate secondary containment systems to prevent spills;

 ensuring that each construction crew has on hand sufficient supplies of absorbent and 

barrier material to allow the rapid containment and recovery of spilled materials and 

knows the procedures for reporting spills and unanticipated discoveries of contamination; 

 ensuring each construction crew has sufficient tools and materials to stop leaks; and

 implementing the training, inspection, loading and unloading, oil transfer, and security 

measures outlined in 40 CFR 112. 

Because operational water use for the proposed Liquefaction Facilities would not affect 

groundwater availability, ground disturbances would generally be temporary and limited to the ground 

surface, erosion controls and storm water management would be implemented, and natural ground 

contours and vegetation would be restored, we conclude the Project would not result in any significant 

impacts on groundwater resources or users of groundwater in the Project area.

2.2.2 Surface Water

Existing Surface Water Resources

A total of 11 waterbodies were identified within the Project sites (see table 2.2.2-1). 

Surface Waters at the LNG Terminal

The LNG Terminal property borders the Chesapeake Bay, which is the nation’s largest estuary. 

The Chesapeake Bay watershed encompasses over 64,000 square miles and includes parts of New York, 

Pennsylvania, West Virginia, Maryland, and the District of Columbia. The MDE has designated the 

Chesapeake Bay as Use II – Support of Estuarine and Marine Aquatic Life and Shellfish Harvesting 

(Code of Maryland Regulations [COMAR] 26.08.02.02.B(3)). At the existing offshore pier, the 

Chesapeake Bay has been further classified into two special use subcategories: “Open Water Fish and 

Shellfish (Open Water)” and “Seasonal Deep Water Fish and Shellfish (Deep Water).” 
49

TABLE 2.2.2-1

Impacts on Waterbodies within the Project Sites

State/County/Facility Stream ID a Stream Flow

Construction 

Impacts

Operation

Impacts

MARYLAND

Calvert County

LNG Terminal WUS1 Ephemeral 

Intermittent 

1,035 feet 

115 feet

1,035 feet 

115 feet

Offsite Area A WUS2 Perennial - -

WUS3 Intermittent - -

WUS4 Intermittent 102 feet -

WUS5 Intermittent - -

WUS5A Perennial - -

Offsite Area B Patuxent 

River/

WUS6

Perennial 0.15 acre -

VIRGINIA

Fairfax County

Pleasant Valley Compressor Station WUS12 Intermittent - -

WUS13 Intermittent - -

Pleasant Valley Suction/Discharge 

Pipelines

WUS14 Intermittent - -

____________________

a Stream IDs were assigned during DCP’s field surveys.

The Chesapeake Bay is classified as impaired for its nutrient special use and biological life 

designations. At the existing offshore pier, the Chesapeake Bay does not support its aquatic life use 

classification due to its low biotic integrity scores and low dissolved oxygen concentrations. The existing 

LNG Terminal is not a source of nutrients to the Chesapeake Bay (MDE, 2012).

Freshwater stream WUS1 is within the Fenced Area of the LNG Terminal and is classified as 

ephemeral in its upper reach and intermittent as the stream leaves the Fenced Area. WUS1 is a tributary 

to Grays Creek, which is a tributary to the Chesapeake Bay. 

The LNG Terminal is within the Middle Central Chesapeake Bay Mesohaline within the “02-13-

10 West Chesapeake Bay Area” watershed, as designated by the MDE (COMAR 26.08.02.08), and 

Hydrologic Unit Code (HUC) watershed 12-020600040408, as designated by the USGS (2012f). The 

MDE has designated streams and tributaries located in and adjacent to the LNG Terminal as “Use I: 

Water Contact Recreation and Protection of Nontidal Warm Water Aquatic Life” (COMAR 

26.08.02.02.B(1)). 

Surface Waters at Offsite Area A

Two perennial and three intermittent streams were identified within Offsite Area A during field 

surveys in April and June 2012. These streams either flow north or south from Offsite Area A because 

the center of the site forms a slight hill crest. Offsite Area A is within the Lower Patuxent River 

Mesohaline reach of the Patuxent River within the “02-13-11 Patuxent River Area” watershed (MDE, 

COMAR 26.08.02.08), and HUC watershed 12-020600060603 (USGS, 2012f). The MDE has designated 

streams and tributaries located in and adjacent to Offsite Area A as “Use I: Water Contact Recreation and 

Protection of Nontidal Warm Water Aquatic Life” (COMAR 26.08.02.02.B(1)). There are no water 

quality issues of concern for the streams located on or adjacent to Offsite Area A (MDE, 2012).
50

Surface Waters at Offsite Area B

Offsite Area B is located along the Patuxent River near its confluence with the Chesapeake Bay. 

The Patuxent River is the largest and longest river entirely within Maryland, and provides a wide variety 

of commercial and recreation uses. No other waterbodies were identified at Offsite Area B. 

Offsite Area B is within the same MDE- and USGS-designated watershed as Offsite Area A. The 

MDE has designated the Patuxent River as Use II – Support of Estuarine and Marine Aquatic Life and 

Shellfish Harvesting (COMAR 26.08.02.02.B(3)). At Offsite Area B, the Patuxent River has been further 

classified into three special use subcategories: “Migratory Spawning and Nursery,” “Shallow Water 

Submerged Aquatic Vegetation,” and “Open Water Fish and Shellfish Use.” The segment of the lower 

Patuxent River in the vicinity of Offsite Area B is listed as impaired for fishing and aquatic life and 

wildlife because of high mercury and polychlorinated biphenyls (PCBs) concentrations in fish tissue, as 

well as low fish and benthic index of biotic integrity scores. There are no known sources of mercury or 

PCBs in the vicinity of Offsite Area B.

Offsite Area B is located within the Bay Critical Area, which is defined as all land within 1,000 

feet of the mean high water line of tidal waters, the landward edge of tidal wetlands, and all waters of and 

lands under the Bay and its tributaries. Based on current Calvert County zoning maps, Offsite Area B is 

classified as a limited development area, which permits limited new or redevelopment of land within the 

Critical Area as long as water quality is not impacted and existing natural areas are conserved.

Surface Waters at the Pleasant Valley Compressor Station and Suction/Discharge Pipelines

Two intermittent streams are located at the Pleasant Valley Compressor Station, and one 

intermittent stream is crossed by the Pleasant Valley Compressor Station Suction/Discharge Pipelines. 

These three streams flow into Bull Run and are in the Potomac-Shenandoah watershed as designated by 

the VDCR and HUC watershed 12-020700100703 (USGS, 2012f). There are no water quality issues of 

concern for the streams on or adjacent to the Pleasant Valley Compressor Station or the Pleasant Valley 

Suction/Discharge Pipelines (Virginia Department of Environmental Quality (VDEQ) and VDCR, 

2012)).

Surface Waters at the Loudoun M&R Facility

No waterbodies were identified within the Loudoun M&R Facility. However, one perennial 

stream channel is approximately 150 feet from the Loudoun M&R Facility. This perennial stream is a 

tributary to Howsers Branch, which is classified as “Class III—Nontidal waters (Coastal and Piedmont 

Zones)” (Virginia Administrative Code Title 9 Agency 25 Chapter 260 Section 390). All Virginia State 

waters are designated for recreational uses, and for the propagation and growth of a balanced, indigenous 

population of aquatic life, wildlife, and the production of edible and marketable natural resources. 

Howsers Branch is impaired for its designated use of recreation because of high Escherichia coli (E. coli) 

concentrations (VDEQ and VDCR, 2012). The Loudoun M&R Facility is in the Potomac-Shenandoah 

watershed as designated by the VDCR and HUC watershed 12-020700080701 (USGS, 2012f). 

Surface Waters at the Leesburg Compressor Station Contractor Staging Area

No waterbodies were identified at the Leesburg Compressor Station Contractor Staging Area. 

This staging area is within the same MDE- and USGS-designated watershed as the Loudoun M&R 

Facility.
51

Sensitive Waterbodies

The Chesapeake Bay and Patuxent River are considered sensitive due to their designated 

impairments, fisheries and recreational uses, and the habitat they provide to estuarine aquatic and 

sensitive species. Howsers Branch, which is approximately 1.1 miles downstream of the Loudoun M&R 

Facility, is considered sensitive due to high E. coli concentrations. Project activities would not contribute 

to E. coli concentration levels in Howsers Branch.

None of the waterbodies within the Project areas are known to contain contaminated sediment 

(FERC, 2006; EPA, 1998).

Surface Water Use

There are no potable surface water intakes within 3 miles downstream of any waterbody 

identified within the Project sites. The nearest major surface water withdrawal to the LNG Terminal and 

Offsite Areas A and B is the large cooling water intake at the Calvert Cliffs Nuclear Power Plant 

approximately 4.0 miles north of the LNG Terminal. 

Hydrostatic Testing

As stated in section 2.2.1, new piping and other equipment at the LNG Terminal, Pleasant Valley 

Compressor Station, the Pleasant Valley Suction/Discharge Pipelines, the Pleasant Valley M&R Facility, 

and the Loudoun M&R Facility would be hydrostatically tested to ensure its integrity before being placed 

into service. Once testing is complete, the test water would be transported to an appropriate wastewater 

treatment facility for disposal, or a permit would be obtained from the MDE or VDEQ to discharge test 

water. 

The discharge of hydrostatic test water to a surface waterbody could result in erosion, increased 

turbidity, or changes in water temperature and oxygen levels. These impacts could in turn degrade 

aquatic habitat and result in injury or death to aquatic species located in receiving waters. However, no 

significant water quality impacts are anticipated as a result of discharge from hydrostatic testing because 

only new pipe free of chemicals or lubricant would be tested and no water additives would be used unless 

approved by the appropriate state agency. In addition, hydrostatic test water discharges must comply with 

state effluent limitations and general permit conditions, which typically require measures to restrict flow 

volumes or velocities and other protection measures. By implementing the hydrostatic testing procedures 

summarized above, and obtaining and complying with required state permits, we conclude that the 

impacts associated with hydrostatic test water withdrawal and discharge would be minor and temporary.

Impacts and Mitigation

During construction, clearing and grading of vegetation could increase erosion along stream 

banks. Alteration of the natural drainage or compaction of soils by heavy equipment near stream banks

during construction may accelerate bank erosion and the transportation of sediment carried by overland 

flow into the waterbodies. The extent of the impact would depend on precipitation events, sediment 

loads, stream velocity, turbulence, stream bank composition, and sediment particle size, as well as the 

length of time that a disturbed area is not stabilized. Increased sediment loading and turbidity levels, 

reduced dissolved oxygen concentrations, stream warming, and introduction of chemical discharges from 

inadvertent spills of fuels/lubricants may also affect streams.

To minimize potential impacts on surface waters during construction, DCP would implement our 

Plan and Procedures and its E&SCPs, which conform to the MDE’s 2011 Maryland Standards and 
52

Specifications for Soil Erosion and Sediment Control and the VDCR’s 1992, Third Edition, Virginia 

Erosion and Sediment Control Handbook. DCP would also implement its SMPs, which were designed to 

comply with the Calvert County Stormwater Management Ordinance, the MDE’s 2000 Maryland 

Stormwater Design Manual (Revised 2009), and the VDEQ’s stormwater management requirements. As 

previously stated, DCP would implement a Project-specific Spill Prevention and Contaminant Control

Plan to minimize potential soil and water quality impacts associated with an inadvertent spill of fuel, oil, 

and other hazardous fluids.

DCP would implement the measures and plans described above at all the Project sites. Sitespecific impacts not described above, and the measures DCP would implement to minimize site-specific 

impacts, are described in the following sections. No surface waters would be impacted at the Pleasant 

Valley Compressor Station, Pleasant Valley Suction/Discharge Pipelines, Pleasant Valley M&R Facility, 

Loudoun M&R Facility, or the Leesburg Compressor Station Contractor Staging Area.

LNG Terminal

Construction of the Liquefaction Facilities would permanently fill 971 feet of the upper reach of 

waterbody WUS1 and an additional 179 feet of WUS1 that flows through a culvert. DCP consulted with 

the COE which determined that no mitigation would be required for this impact as it falls below 

mitigation requirement thresholds. The loss of this stream segment would affect DCP’s ability to control 

and manage stormwater within the existing Fenced Area of the LNG Terminal; however, DCP would 

implement site-specific SMPs and E&SCPs that are designed to control and manage stormwater at the site 

after construction of the Liquefaction Facilities. These plans have been submitted to Calvert County for 

review and approval. By implementing a site-specific SMP and E&SCP, we conclude that construction 

of the Liquefaction Facilities would not result in significant impact on surface water resources.

Several comments were received regarding the potential for the wake from LNG ships to erode 

the shoreline near the Cove Point lighthouse. As part of the Pier Reinforcement Project and Cove Point 

Expansion Project, DCP analyzed the potential for LNG vessels to contribute to shoreline erosion in the 

vicinity of the LNG Terminal and Cove Point lighthouse. We and the USCG concurred that the waves 

generated by LNG ships would not erode the Cove Point peninsula shoreline and would be within the 

normal range of waves due to wind and other boat and ship traffic.

Offsite Area A

DCP would maintain a 100-foot-wide non-disturbance buffer, delineated by two rows of super silt 

fence, spaced 3 to 4 feet apart, around all waterbodies within Offsite Area A with the exception of WUS4. 

DCP proposes to construct a temporary access road across intermittent stream WUS4 which would allow 

access to the western portion of Offsite Area A. DCP would install a bottomless culvert over WUS4 to 

minimize impacts on the stream channel while the temporary access road is in use. After Project 

activities are complete, DCP would remove the access road and bottomless culvert and restore the 

streambed, as necessary, to its original condition. In addition, DCP would plant trees adjacent to the 

stream according to the restoration plan that DCP prepared for Offsite Area A. As a result, no permanent 

impacts on waterbodies would occur at Offsite Area A. DCP submitted an application to the COE 

regarding impacts on WUS4. In a letter dated Aril 29, 2014, the COE authorized DCP’s proposed 

activities at Offsite Area A, and DCP has stated it would comply with the conditions provided in the COE 

permit. By maintaining a 100-foot-wide buffer around all waterbodies, installation of the two rows of 

super silt fence around each buffer, implementing site-specific E&SCPs and SMPs, and complying with 

COE requirements, we conclude that surface water impacts at Offsite Area A would be temporary and 

adequately reduced.
53

Offsite Area B

The construction of the access road and parking/laydown at Offsite Area B could increase 

stormwater runoff to the Patuxent River. To minimize potential erosion and stormwater impacts, DCP 

would implement our Plan and Procedures and its SMPs and E&SCPs. DCP would also comply with the 

conditions of a COE section 10/404 Permit, a Maryland tidal Wetlands License and Water Quality 

Certification, and a Maryland general discharge permit for construction activities, which would further 

minimize potential erosion and stormwater impacts on the Patuxent River.

As described in section 1.7.3, DCP proposes to construct a temporary barge offloading pier that 

would extend 166 feet into the Patuxent River. The temporary pier would be up to 40 feet wide and 

supported by up to 24 hollow steel piles approximately 36 inches in diameter. DCP estimates that 

installation of the piles would take 15 days. Pier construction, pile driving, and pier removal could 

suspend river sediment, increase local turbidity, and produce acoustic waves that could impact aquatic 

species (section 2.2.3). During use of Offsite Area B, DCP estimates that 42 barge deliveries would be 

made to the pier over the course of 18 months, and propeller wash from the barge traffic could increase 

sedimentation and turbidity in the vicinity of the pier. The pier would be removed from the river at the 

conclusion of the Project, and Offsite Area B would be restored to its prior use. No river dredging is 

proposed for this Project and no permanent impacts would occur at Offsite Area B. Based on the 

relatively small scale of construction and limited incidence and duration of use, and by implementing 

measures to protect water quality, we conclude that construction and use of Offsite Area B would be 

temporary on the Patuxent River, and would be adequately minimized.

Ballast Water

The proposed Project would enable DCP to liquefy natural gas and transfer the LNG to ships for 

export. As discussed in section 1.2.1 DCP was authorized to receive 200 LNG ships at the LNG Terminal

in the Cove Point Expansion Project EIS. However, DCP estimates that only 85 LNG vessels per year 

would call at the LNG Terminal for export as part of operation of the Liquefaction Facilities. 

During the LNG transfer process, LNG ships would discharge ballast water to maintain a constant 

draft at berth. Ballast water is water that is collected and carried by ships to provide balance, stability, 

and trim during transport. Ballast water is typically pumped into ballast tanks when a ship has delivered a 

cargo to a port and is departing with less cargo weight. We received several comments regarding ballast 

water discharge and impacts on aquatic resources in the Chesapeake Bay. The discharge of ballast water 

from ships could potentially affect marine organisms through the unintentional introduction of nonindigenous aquatic organisms. LNG ships discharging ballast water must comply with several U.S. laws, 

regulations, and policies that establish a national mandatory ballast water management program for all 

vessels equipped with ballast water tanks that enter or operate within U.S. waters. These laws, 

regulations, and policies include:

 USCG regulations (33 CFR 151, subpart D);

 Nonindigenous Aquatic Nuisance Prevention and Control Act of 1990;

 National Invasive Species Act of 1996;

 National Aquatic Invasive Species Act of 2003;

 National Ballast Water Management Program;

 Navigation and Vessel Inspection Circular 07-04, Change 1; and 

 Shipboard Technology Evaluation Program.

The USCG has inspection and regulatory enforcement jurisdiction over all shipping in U.S. 

waters. To minimize and avoid potential impacts on wildlife species that could result from ballast water 
54

discharges, the USCG implements mandatory ballast water management requirements for all ships 

entering U.S. waters from outside the Exclusive Economic Zone of the U.S. and has developed and 

enforces a nationwide Ballast Water Management Program. Under the current Ballast Water 

Management Program, international ships entering U.S. ports and intending to discharge ballast water 

must either carry out ballast water exchange at least 200 nautical miles offshore or retain ballast water on 

board. The USCG recently approved new rules (Federal Register Vol. 77, No. 57) that outline standards 

for eliminating various sizes and concentrations of organisms in discharged ballast water. These new 

standards must be achieved by shippers in a phased timeframe. For newly constructed ships, the new 

rules became effective in December 2013. For existing vessels greater than 5,000 cubic meters ballast 

water capacity, the new rules become effective in 2016, which is prior to the in-service date of the 

proposed Project. The new rules and discharge standards provide more consistent control over the 

concentrations of organisms than the current ballast water exchange program and would significantly 

minimize the introduction and establishment of nonindigenous species. However, we acknowledge the 

potential still exists for nonindigenous species to be introduced into the Chesapeake Bay during ballast 

water discharges.

Every vessel has the potential to transport invasive species on its hull. The USCG has developed 

responses to exotic/invasive species associated with foreign vessels and its Office of Operating and 

Environmental Standards developed Mandatory Practices for All Vessels with Ballast Tanks on All 

Waters of the United States. The mandatory practices include requirements to rinse anchors and anchor 

chains during retrieval to remove organisms and sediments at their place of origin and to remove fouling 

organisms that may be affixed to ship hulls, piping, and tanks. The removal of organisms would be 

conducted on a regular basis and the disposal of any removed substances would be in accordance with 

local, state, and federal regulations. However, we acknowledge the potential still exists for 

nonindigenous species to be introduced into the Chesapeake Bay by ship hull transport.

Depending on the source of the ballast water, discharged ballast water could have a higher or 

lower salinity than the Chesapeake Bay. Salinity at the existing offshore pier ranges between 5 and 18 

parts per thousand (ppt) depending on tidal influences and water flows volumes. More dense, higher 

salinity discharges would sink to the bottom of the Chesapeake Bay and naturally mix with the lower 

density water in the Chesapeake Bay. Conversely, lower salinity discharges would remain at the surface 

of the Chesapeake Bay and naturally mix with the higher density waters of the Chesapeake Bay.

Dissolved oxygen levels in the discharged ballast water may differ from the ambient dissolved 

oxygen levels in the Chesapeake Bay. Dissolved oxygen levels are an important aspect of the respiration 

of aquatic marine organisms. Dissolved oxygen levels in water can be influenced by many factors 

including water temperature, water depth, phytoplankton, wind, and current. In a water column profile, 

there is a direct correlation in a decrease in dissolved oxygen relating to an increase in depth. Factors that 

influence this stratification include sunlight attenuation for photosynthetic organisms that can produce 

oxygen, wind, wave, and current that results in mixing.

The introduction of ballast water would not significantly affect water temperature and pH levels 

in the Chesapeake Bay. Because ballast water is stored in the ship’s hull below the waterline, water 

temperatures would not deviate much from ambient temperatures of the Chesapeake Bay. The pH of the 

ballast water may vary slightly from that of the Chesapeake Bay.

The potential variation of salinity, dissolved oxygen, water temperature, and pH between the 

ballast water and the Chesapeake Bay would not have discernable impacts on water resources or existing 

aquatic organisms. Additionally, compliance with laws, regulations, and policies regarding ballast water 

discharges would minimize potential impacts on the Chesapeake Bay, including the introduction of 

nonindigenous species. Therefore, ship traffic and ballast water discharges would not have any 
55

noticeable, long-term impact on the Chesapeake Bay or aquatic resources beyond those that have already 

occurred within the Chesapeake Bay.

2.2.3 Fisheries Resources

Existing Fisheries Resources

Freshwater fishery resources in the vicinity of the Project are limited to warm water habitats. No 

coldwater or coolwater fisheries are near the Project. Warmwater fish species within and downstream of 

the Project areas generally include small fishes such as darters, shiners, and dace. The Patuxent River and

the Chesapeake Bay provide estuarine habitat for a variety of warmwater and anadromous fish, as well as 

shellfish such as oysters and crabs. Aquatic species at each Project site are described below.

LNG Terminal

The existing offshore pier is located approximately 1.1 miles from the Chesapeake Bay shoreline. 

Approximately 350 warmwater and anadromous fish species, including commercial and recreational fish 

and game species, are known to occur in the Chesapeake Bay (Chesapeake Bay Program, 2012). Many of 

these species occur at some location or season in the waters near the offshore pier. The offshore pier 

provides shade and hard structure habitat for fish and prey species in the Chesapeake Bay and, therefore, 

fish congregate in greater numbers near the pier. Fishing is not permitted at any time within the 500-yard 

safety and security zone around the offshore pier. 

Oyster and crab populations are stressed within the Chesapeake Bay and receive special 

management attention from Maryland and Virginia. The existing offshore pier is generally in water too 

deep to support oysters, which prefer habitat from 8 to 35 feet deep (Chesapeake Bay Program, 2008). 

Although oysters are stocked throughout the Chesapeake Bay, the nearest natural oyster bars are about 1.5

miles north of the offshore pier (MDNR, 2012). The blue crab is found in shallow Chesapeake Bay water 

during the warmer months and in deeper water (greater than 30 feet) during the winter months (MDNR, 

2012; Schaffner and Diaz, 1988). Because blue crabs prefer shallow habitat during the warmer months, it 

is likely that they are only found near the offshore pier during the winter months.

Stream WUS1 within the Fenced Area of the LNG Terminal does not support fish populations. 

Offsite Area A

Offsite Area A includes two perennial stream (WUS2 and WUS5A) and three intermittent 

streams (WUS3, WUS4, and WUS5). WUS2 could support small populations of creek chubsucker, 

Eastern mud minnow, Eastern mosquito fish, tessellated darter, and blacknose dace (Hook and Bullet, 

2012). Stream WUS5, a tributary of Hellen Creek, could support small fish populations during periods of 

flow. WUS3, WUS4, and WUS5A do not support fish populations.

Offsite Area B

The Patuxent River supports approximately 75 species of fish, including several recreational and 

commercial species. Construction of the temporary pier would take place in shallow shoreline waters 

between 0 and 30 feet in depth. Several fish species, including commercial and recreational species, 

could be present near the proposed pier. Waters near the pier also support oyster beds and provide blue 

crab habitat during warmer months. In addition, the temporary pier at Offsite Area B would be within a 

Natural Oyster Bar in the Patuxent River. 
56

Other Facilities

No streams or aquatic habitat would be impacted at the Pleasant Valley Compressor Station,

Pleasant Valley Suction/Discharge Pipelines, Pleasant Valley M&R Facility, Loudoun M&R Facility, or 

the Leesburg Compressor Station Contractor Staging Area.

Managed Fish Species and Essential Fish Habitat

Essential Fish Habitat (EFH) is defined as “those waters and substrate necessary to fish for 

spawning, breeding, feeding, or growth to maturity” (16 USC 1802 (10)). Under the Magnuson-Stevens 

Fishery Conservation and Management Act, federal action agencies that fund, permit, or carry out 

activities that may adversely affect EFH are required to consult with National Oceanic and Atmospheric 

Administration, National Marine Fisheries Service (NMFS) regarding potential adverse impacts of their 

actions on EFH, and respond in writing to any NMFS and Fishery Management Council conservation 

recommendations. Although absolute criteria have not been established for conducting EFH 

consultations, NMFS recommends consolidation of EFH consultations with interagency coordination 

procedures required by other statutes, such as NEPA, in order to reduce duplication and improve 

efficiency. 

According to the NMFS Guide to Essential Fish Habitat Designations in the Northeastern United 

States, EFH has been designated in the Chesapeake Bay and in the Patuxent River for nine managed fish 

species. The life stages for these managed fish are presented in table 2.2.3-1.

TABLE 2.2.3-1

NMFS Managed Fish Species Near the LNG Terminal and Offsite Area B

Species

Life Stages a

Eggs Larvae Juvenile Adult

Windowpane flounder (Scopthalmus aquosus) C, P C, P

Bluefish (Pomatomus saltatrix) C, P C, P

Atlantic butterfish (Peprilus triacanthus) C C C C

Summer flounder (Paralicthys dentatusi) C, P C, P C, P

Black sea bass (Centropristus striata) C C

King mackerel (Scomberomorus cavalla) C, P C, P C, P C, P

Spanish mackerel (Scomberomorus maculates) C, P C, P C, P C, P

Cobia (Rachycentron canadum) C, P C, P C, P C, P

Red drum (Sciaenops occelatus) C, P C, P C, P C, P

____________________

a C = Life stage for the managed fish species is present in the Chesapeake Bay near the existing offshore pier.

P = Life stage for the managed fish species is present in the Patuxent River near Offsite Area B.

Source: http://www.nero.noaa.gov/hcd/est.htm#MARYLAND

Impacts and Mitigation

Construction impacts on fisheries resources may include direct contact by construction equipment 

with fish and other aquatic organisms; alteration or removal of adjacent riparian vegetation and aquatic 

habitat cover; introduction of pollutants; and an increase in sedimentation and turbidity. These impacts 

would result from the permanent filling and diversion of streams, the temporary loss of riparian 

vegetation, and an increase of impervious surfaces and stormwater runoff. Sediment loading and turbidity 

within and immediately downstream of work areas has the greatest potential to impact aquatic resources. 
57

With the exception of the Patuxent River, no stream known to contain fisheries resources would 

be directly impacted by Project activities. DCP’s commitment to buffer wetlands and waterbodies at 

Offsite Area A and implement our Plan and Procedures, its SMPs and E&SCPs, and comply with 

applicable state and federal permits, would further minimize potential impacts on any fisheries resources 

within or downstream of the Project area. As recommended by the Reviewing State Agencies in their 

recommended license conditions for Maryland’s CPCN, DCP would not conduct in-water work at Offsite 

Area A between March 1 and June 15 of any year to protect spawning resident and anadromous fish. 

Construction and use of the temporary pier in the Patuxent River at Offsite Area B could suspend 

river sediment, increase local turbidity, and produce acoustic waves that could impact aquatic species. As 

discussed in section 2.2.2, pile installation using a vibratory hammer would be completed in 

approximately 15 days, and approximately 42 barge trips would be required to delivery materials to the 

Project site over an 18 month period. If impact hammering is necessary to achieve sufficient pile depth, 

DCP would utilize internal strike cushions to ensure pile driving stays within sound limits specified by 

NMFS. As recommended by the Reviewing State Agencies in their recommended license conditions for 

Maryland’s CPCN, DCP would not conduct work within the Patuxent River between December 16 and 

March 14 and between June 1 and September 30 of any year. Additionally, NMFS has concluded that the 

Project would not impact federally listed species within the Chesapeake Bay or Patuxent River (see 

section 2.3.3). 

Recent field studies by MDNR and DCP indicated that the maximum anticipated area of impact 

on the Natural Oyster Bar associated with Offsite Area B would be approximately 2 acres. Based on the 

Reviewing State Agencies’ recommended license conditions, DCP agreed to prepare and implement an 

Oyster Bar Mitigation Plan that would restore hard bottom and plant oyster shells in the vicinity of 

temporary barge pier. As part of the plan, DCP has agreed to provide 4 acres planting of spat-on-shell as 

mitigation for the Project (2:1 compensation), and would support additional surveys of the Natural Oyster 

Bar. DCP would also not conduct work within the Patuxent River between December 16 and March 14 

and between June 1 and September 30 of any year, as recommended by the Reviewing State Agencies in 

their recommended license conditions for the CPCN. DCP provided its draft Oyster Bar Mitigation Plan 

to the MDNR on March 28, 2014. Additionally, DCP has agreed to prepare and implement an artificial 

reef development plan that would utilize suitable construction waste materials to generate an artificial reef 

near Offsite Area B. These plans would be reviewed and approved by the MDNR and other applicable 

agencies prior to implementation. In addition, we recommend that:

 DCP should file the final Oyster Bar Mitigation Plan, approved by the MDNR, and 

artificial reef development plan before implementation of the plans.

Based on the scale of construction and limited incidence and duration of use, and by 

implementing measures to protect aquatic resources, we determined that construction and use of Offsite 

Area B would result in temporary impacts on the Patuxent River and aquatic resources, and would be 

adequately minimized. 

NMFS indicated that juvenile and adult summer flounder and bluefish are the managed species of 

concern for the Project (Nichols, 2012). DCP submitted an EFH Assessment to NMFS on December 17, 

2012. The assessment concluded that the proposed action would not have a substantial adverse effect on

EFH or species with designated EFH in the Project area; direct, secondary, and cumulative impacts on 

EFH and associated species would be minimal; and the Cove Point Liquefaction Project would comply 

with the Magnuson-Stevens Fishery Conservation and Management Act. On February 25, 2013, NMFS 

stated it has no concerns with the finding of the assessment. Upon reviewing relevant fisheries 

information and analyzing potential fisheries impacts, we conclude that the Project would not 

significantly affect EFH or managed fish species.
58

We concluded in section 2.2.2 that ballast water discharges associated with operation of the 

Liquefaction Facilities would not have any noticeable, long-term impacts on the Chesapeake Bay or 

aquatic resources. Additionally, DCP’s EFH Assessment concluded that ballast water discharges would 

only have a temporary, minor effect on local water quality, and NMFS had no concerns with this finding. 

Because no in-water work is proposed at the existing offshore pier and LNG ship traffic would not exceed 

the previously approved vessel frequency as a result of this Liquefaction Project, we conclude that the 

Project would have no substantial impact on managed species, EFH, or other aquatic species in the 

Chesapeake Bay.

2.2.4 Wetlands

Existing Wetland Resources

DCP delineated wetlands within the Project areas using the COE’s Wetlands Delineation Manual 

(COE, 1987), the Regional Supplement to the Corps of Engineers Wetland Delineation Manual: 

Northcentral and Northeast Region (COE, 2011), and the Regional Supplement to the Corps of Engineers 

Wetland Delineation Manual: Eastern Mountains and Piedmont Region (COE, 2012). Wetlands were 

classified according to Cowardin et al. (1979). Plant species identified during wetland surveys included 

an overstory of red maple, sweetgum, black gum, and sweetbay magnolia. Understory species included 

highbush blueberry, common spike rush, false nettle, soft rush, green bulrush, shallow sedge, sensitive 

fern, lizard tail, and coastal sweet pepperbush.

LNG Terminal

One wetland (Wetland 1) was delineated within the Fenced Area at the LNG Terminal. Wetland 

1 is located directly below the outfall of an existing stormwater pond on the western portion of the Fenced 

Area. Wetland 1 appears to receive the majority of its hydrology from the stormwater pond as well as the 

surrounding steep slopes, and may act as the headwaters of an intermittent stream channel that is offsite to 

the west. 

Offsite Area A

Seven wetlands (Wetlands 2 – 8) were identified at Offsite Area A, all of which receive their 

hydrology from groundwater seeps. Wetlands 2 and 3 are located on the westernmost portion of the site. 

Wetland 4 is a large wetland complex consisting of multiple groundwater wetland seeps along stream

WUS4. Wetland 5 is a small isolated depression near the center of the site and receives hydrology from 

both surface runoff and groundwater. Wetland 6 originates as a groundwater seep on the southwest 

corner of the site and drains to Wetland 2. Wetland 7 consists of wetland seeps along stream WUS5. 

Wetland 8 is a large wetland complex which receives hydrology from a system of groundwater seeps 

along stream WUS5A. 

Offsite Area B

The shoreline of the Patuxent River (WUS6) from the mean high tide and the streambed of the 

river is classified as tidal wetland (COMAR 26.24.01.02-52). The shoreline comprises sand and large 

angular rock with no vegetation. The remaining portion of Offsite Area B site is on uplands, and no other 

wetland areas would be impacted according to the site plan designs submitted by DCP on August 1, 2013.
59

Pleasant Valley Compressor Station, Suction/Discharge Pipelines, and M&R Facility

One wetland is within the Pleasant Valley Compressor Station site. Wetland 18 is along the 

eastern bank of stream WUS13 on the eastern portion of the site. 

One wetland would be crossed by the Pleasant Valley Suction/Discharge Pipelines. Wetland 17 

is along the existing gravel site access road and continues off-site to the south across the existing utility 

right-of-way. The wetland appears to receive the majority of its hydrology from streams WUS13 and 

WUS14, as well as surficial runoff from the surrounding uplands. 

No wetlands are present at the Pleasant Valley M&R Facility.

Loudoun M&R Facility and Leesburg Compressor Station Contractor Staging Area

There are no wetlands within the proposed construction workspace at the Loudoun M&R Facility 

or the Leesburg Compressor Station Contractor Staging Area.

Impacts and Mitigation

The Project would temporarily impact less than 0.09 acre of emergent wetland, 0.23 acre of 

forested wetland, and less than 0.01 acre of subtidal estuarine wetland; and would permanently affect 0.06 

acre of forested wetland. Wetland impacts for the Project are summarized in table 2.2.4-1. 

TABLE 2.2.4-1

Summary of Wetlands Affected by the Project

County/State/Facility Wetland ID

Cowardin 

Classification a

Wetland Size 

(acre)

Construction 

Impacts

Operational 

Impacts

Calvert County, Maryland

LNG Terminal Wetland 1 PFO 0.06 0.06 0.06

Offsite Area A Wetland 2 PEM/PFO 0.64 - -

Wetland 3 PEM/PFO 0.06 - -

Wetland 4 PFO 5.07 0.17 -

Wetland 5 PFO 0.03 - -

Wetland 6 PEM/PFO 0.50 - -

Wetland 7 PFO 0.72 - -

Wetland 8 PFO 0.76 - -

Offsite Area B WUS6 E1UBL <0.01 <0.01 -

Fairfax County, Virginia

Pleasant Valley 

Suction/Discharge Pipelines

Wetland 17 PEM 0.11 0.02 -

Pleasant Valley Compressor 

Station

Wetland 18 PFO 0.06 - -

Wetland 17 PEM 0.11 b 0.07 -

Project Total: 8.01 0.32 0.06

____________________

a PEM = Palustrine emergent wetland

PFO = Palustrine forested wetland

E1UBL = Estuarine subtidal unconsolidated bottom wetland

b Wetland 17 would be temporarily impacted by construction at the Pleasant Valley Compressor Station and the Pleasant 

Valley Suction/Discharge Pipelines. The acreage of Wetland 17, 0.11 acre, is added only once in the Project total 

wetland size.
60

Construction and operation of the Liquefaction Facilities would result in the permanent loss of 

0.06 acre of forested Wetland 1. Through consultation with the COE, it was determined that mitigation 

would not be required for this wetland loss. In a letter dated April 29, 2014, the COE confirmed that the 

permanent wetland fill at the Liquefaction Facilities is authorized under the Maryland State Programmatic 

General Permit-4. 

Installation of the internal access road at Offsite Area A would temporarily impact 0.17 acre of 

emergent Wetland 4. DCP would maintain a 100-foot construction buffer around the remaining wetlands 

at Offsite Area A, delineated by two rows of super silt fence, spaced 3 to 4 feet apart. DCP would remove 

the access road once Offsite Area A is no longer required for the Project and restore Wetland 4 to its preconstruction condition. DCP submitted a joint permit application to the COE and MDE in April 2013 to 

obtain approval to temporarily impact Wetland 4. In a letter dated April 29, 2014, the COE confirmed 

that the temporary wetland impact at Offsite Area A is authorized under the Maryland State 

Programmatic General Permit-4.

Installation of the piles at the offloading pier would temporarily fill less than 0.01 acre of tidal 

wetland along the Patuxent River shoreline. Upon completion of the Project, the pier and piles would be 

removed and the tidal wetland and shoreline would be restored to original conditions. DCP submitted a 

joint permit application to the COE and MDE in April 2013 to obtain approval to construct the temporary 

pier. In a letter dated April 29, 2014, the COE provided its authorization of the pier installation based on 

current water depths, and specified that propeller dredging is not authorized.

Construction of the Pleasant Valley Compressor Station would temporarily impact 0.07 acre of 

Wetland 17, while installation of the Pleasant Valley Suction/Discharge Pipelines would temporarily 

affect 0.02 acre of Wetland 17. Wetland 17 would be restored following construction activities at the 

compressor station and pipeline. DCP submitted a joint permit application to the COE and VDEQ in 

April 2013 to obtain approval to temporarily impact Wetland 17. On October 18, 2013, the COE 

provided written concurrence that the temporary impacts on wetland 17 satisfy the criteria of Nationwide 

Permit #12. Because the COE approved the activities under its nationwide permit program, the VDEQ 

stated is would not issue a permit for the Project, and 401 water quality certification is granted through 

the COE’s nationwide permit program.

DCP would minimize wetland impacts by implementing best management practices in our 

Procedures and its SMPs and E&SCPs, as well as obtaining and complying with all necessary COE and 

state permits regarding wetland impacts. We conclude wetland impacts would be small in nature and 

would be minimized appropriately by implementing the construction, restoration, and mitigation 

measures proposed by DCP and required by the COE and state agencies through the joint permit 

application process. 

2.3 VEGETATION AND WILDLIFE

2.3.1 Vegetation

Existing Vegetation Resources

Existing upland vegetation resources were documented during environmental field surveys

conducted in 2012. Major upland cover types affected by the Project include upland forest and open land. 

A description of the upland forest and open land vegetation types affected by the Project is provided in 

table 2.3.1-1. Wetland vegetation communities that would be affected by the Project are discussed in 

section 2.2.4. 
61

The primary vegetation cover type that would be affected by the Project is upland forest. This 

community covers about 81 percent of the affected Project area, mostly at Offsite Area A. The remainder 

of the Project would affect mowed/maintained upland (14 percent), old field/pioneer (3 percent), and 

upland successional woodland (2 percent). Table 2.3.1-2 summarizes the approximate acreage of upland 

vegetation communities that would be affected by the Project.

TABLE 2.3.1-1

Upland Vegetation Cover Types Found within the Project Area

Vegetation 

Community General Description Common Species Location of Vegetation Community

Upland 

Forest

Tulip Poplar Forest Forest type dominated by American holly, 

black cherry, black gum, common 

pawpaw, and ironwood.

Fenced Area

Mixed Oak Forest Forest type dominated by white oak, 

chestnut oak, northern red oak, black oak,

and scarlet oak.

Fenced Area, Offsite Area A

American Beech/Red 

Maple Forest

Forest type dominated by American 

beech, red maple, and tulip poplar.

Offsite Area A

Virginia Pine Forest Forest type dominated by Virginia pine, 

sweetgum, tulip poplar, American holly, 

American beech, black oak, common 

greenbrier, Virginia pine, lowbush 

blueberry, sassafras, and mountain laurel.

Offsite Area A

Oak-Hickory Forest Forest type dominated by white oak, 

chestnut oak, northern red oak, tulip 

poplars, black gum, and southern red oak.

Pleasant Valley Compressor Station, 

Pleasant Valley Suction/Discharge 

Pipelines, Loudoun M&R Facility

Successional 

Woodland

Consists of very young forest that may 

eventually mature into a deciduous 

species dominated forest.

Offsite Area A, Offsite Area B

Open Land Old Field/Pioneer Vegetation dominated by Chinese bushclover, bull thistle, Japanese bristlegrass, 

yellow fox tail, crabgrass, sweetgum, 

broomsedge bluestem, tall prairie grass,

and common blackberry.

Fenced Area Offsite Area A, Offsite Area 

B, Pleasant Valley Compressor Station, 

Pleasant Valley Suction/Discharge 

Pipelines, Loudoun M&R Facility, 

Leesburg Compressor Station Contractor 

Staging Area

Mowed/Maintained 

Upland

In industrial facilities, vegetation consists

primarily of maintained lawns and a 

limited amount of scrub-shrub 

communities.

Offsite Area B, Pleasant Valley 

Compressor Station, Leesburg

Compressor Station Contractor Staging 

Area

____________________

a General habitat characterization is based on the categorization by Maryland’s State Forest Conservation Technical 

Manual (Third Edition 1997).

Vegetation Communities of Special Concern or Value

Seven specimen trees as designated by the MDNR were identified during field studies at Offsite 

Area A. DCP has designed the workspace at Offsite Area A to include 100-foot-wide setbacks from 

sensitive resources including specimen trees. DCP would delineate the 100-foot buffers with double rows 

of super silt fence, separated by 3 to 4 feet. Therefore, no specimen trees would be impacted by the 

Project.

St. Paul’s Branch, on the eastern side of Offsite Area A, flows into Hellen Creek and is upstream 

of Hellen Creek Hemlock Preserve, an isolated stand of Canadian hemlock that is the southernmost 

hemlock forest of the eastern United States. Some species of plants and animals found within this 

preserve are more typical of Appalachian forest.

The Pleasant Valley Compressor Station, Pleasant Valley Suction/Discharge Pipelines, and 

Pleasant Valley M&R Facility are within the 1,680-acre Elklick Diabase Flatwoods Conservation Site. 
62

Conservation sites designate geographic areas where one or more rare plant, animal, or natural 

communities are known to occur and may require additional review for potential conservation action. 

The Elklick Diabase Flatwoods Conservation Site has been ranked as a site of very high significance (B2) 

due to the potential for species of concern to occur including Torrey’s mountain-mint, grove sandwort, 

and purple milkweed. These species were not observed during surveys conducted at the facilities in the 

summer and fall of 2012 or the spring of 2013 (section 2.3.3).

TABLE 2.3.1-2

Project Impacts on Upland Vegetation (acres)

State/Project Site

Upland Forest

Mowed/Maintained 

Upland Old Field/Pioneer

Upland Successional 

Woodland

Const. a Oper. b Const. a Oper. b Const. a Oper. b Const. a Oper. b

Maryland

Fenced Area 11.8 11.4 0.0 0.0 1.7 1.7 0.0 0.0

Offsite Area A 94.0

c 0.0 0.0 0.0 0.0 0.0 1.9 0.0

Offsite Area B 0.0 0.0 5.7 0.0 0.0 0.0 0.2 0.0

Virginia

Pleasant Valley 

Compressor Station

6.7 0.3 6.3 1.9 2.8 0.1 0.0 0.0

Pleasant Valley Suction/

Discharge Pipelines and 

M&R Facility

0.0 0.0 1.9 0.0 0.0 0.0 0.0 0.0

Loudoun M&R Facility <0.1 0.0 0.0 0.0 0.1 0.0 0.0 0.0

Leesburg Compressor 

Station Contractor Staging 

Area

0.0 0.0 6.0 0.0 0.0 0.0 0.0 0.0

Project Total 113.4 11.7 19.9 1.9 4.6 1.8 2.1 0.0

____________________

a Const. = Construction Impacts. Includes impacts associated with all areas within the construction workspace limits. 

This includes the total of the existing pipeline right-of-way, new permanent pipeline right-of-way, temporary workspace 

areas, additional temporary workspace areas, and staging areas.

b Oper. = Operational Impacts. Includes impacts associated with the permanent clearing or removal of vegetation to 

construct Project facilities.

c Based on information provided by DCP to the FERC; however, the Maryland DNR has stated that DCP would affect 

93.6 acres of upland forest at Offsite Area A. The final area affected would be confirmed prior to construction.

Construction and operation impacts are not cumulative.

The Elklick Diabase Flatwoods Conservation Site is also considered important due to the 

potential presence of habitat types of concern including the Piedmont Upland Depression Swamp, 

Northern Hardpan Basic Oak-Hickory Forest, and Northern Piedmont Mafic Barren. Summer and fall 

surveys in 2012 determined these habitats were not present at the Pleasant Valley Compressor Station site 

or the Pleasant Valley Suction/Discharge Pipelines. DCP has consulted with the VDCR and Virginia 

Department of Agriculture and Consumer Services (VDACS) regarding the potential presence of the 

Northern Hardpan Basic Oak-Hickory Forest. The VDCR confirmed that the forest community at the 

Pleasant Valley Compressor Station site represents an acidic oak-hickory forest and, as such, the Project 

would not affect significant forest communities of concern (VDCR, 2013).

Impacts and Mitigation

Upland Forest and Woodland

The greatest impact on vegetation would be the clearing of forested areas because of the length of 

time required for woody vegetation to revert to its preconstruction condition. The removal of mature 

trees could also increase erosion potential, decrease the quality of habitat for forest wildlife species, and 
63

result in an increased opportunity for invasive plants to displace native species. As presented in table 

2.3.1-2, approximately 113 acres of upland forest and 2 acres of early successional woodland would be 

removed by construction of the Project. The amount of forest that would be removed at the LNG 

Terminal and Offsite Area A represents approximately 0.1 percent of the 81,000 acres of forest in Calvert 

County. Operation of the Project would result in the unavoidable, permanent loss of 11.5 acres of upland 

forest, including 11.2 acres within the Fenced Area at the LNG Terminal and 0.3 acre within the boundary 

of the Pleasant Valley Compressor Station. DCP stated that it would donate the 100-acre privately held 

portion of Offsite Area A to Calvert County and would not utilize the site after construction of the 

Liquefaction Facilities is complete. Calvert County has not yet determined the final deposition of the 

property. The county has stated that the property would be replanted following construction, and would 

not be intensely or commercially developed. If the property is allowed to revert to its previous forested 

condition, impacts on forest resources would be long term due to the time required for the area to reforest. 

Any portions of Offsite Area A that are developed would be permanently impacted. Further discussion 

about Offsite Area A restoration is provided below.

To minimize impacts on forest areas that would be cleared for construction, DCP would 

implement measures outlined in our Plan and Procedures and its E&SCPs including the installation of 

erosion control measures following initial disturbance of the soil and topsoil removal and segregation. 

Following construction, DCP would seed all disturbed areas in accordance with written recommendations 

for seed mixes, rates, and dates obtained from the local soil conservation authority or as requested by 

landowners. DCP proposes to plant suitable upland and wetland tree species, along with suitable 

herbaceous vegetation, adjacent to stream WUS4 according to the restoration plan that was submitted for 

Offsite Area A. In accordance with our Plan, DCP would monitor disturbed areas to determine the postconstruction revegetative success for a minimum of two growing seasons, and continue revegetation 

efforts until revegetation is successful. 

DCP would implement the measures in its Invasive Species Management Plans during 

construction and restoration of Project facilities in Maryland and Virginia. The plans identify existing 

invasive species at the Project sites and describe measures to prevent and control the spread of invasive 

plant species in areas disturbed by construction. The plans also include measures to monitor and control 

invasive species following construction. We reviewed DCP’s Invasive Species Management Plans and 

find them acceptable.

In Maryland, the Forest Conservation Act was enacted in 1991 to minimize the loss of 

Maryland’s forest resources during land development. The Act provides steps to identify and protect 

forests and other sensitive areas as part of a site planning process. DCP submitted Forest Conservation 

Plans for the LNG Terminal site and Offsite Area A to Calvert County for review. At the LNG Terminal, 

DCP proposes to mitigate the loss of forest within the Fenced Area through the Calvert County fee-in-lieu 

program or the purchase of transferrable development rights. The Forest Conservation Plan for the LNG 

Terminal site was approved by Calvert County on December 6, 2013. At Offsite Area A, DCP configured 

the workspace to preserve approximately 74 acres of forest, exceeding Calvert County’s minimum 

preservation requirement of 61 acres; therefore, DCP would not be required to mitigate for forest impacts 

under the Forest Conservation Act. The Forest Conservation Plan for Offsite Area A was approved by 

Calvert County on January 9, 2014. Although DCP would not be required to mitigate for forest impacts 

at Offsite Area A, DCP developed a Forest Preservation Plan for Offsite Area A that describes several 

mitigation and preservation proposals to offset the temporary and permanent loss of forest land. As 

currently proposed, DCP would mitigate for forest impacts by:

 working with Calvert County to replant trees where appropriate at Offsite Area A;
64

 preserving an additional 13.5 acres of forest beyond the 73 acres that are currently being 

conserved at Offsite Area A;

 preserving in perpetuity Offsite Area E and arranging for 88.8 acres of forest at Offsite 

Area E to be designated as Forest Retention Area;

 purchasing 88 transferrable development rights from landowners in Calvert County to be 

applied to the Offsite Area E property;

 purchasing and preserving in perpetuity the 26.2-acre Barrett Site;

 preserving in perpetuity the 9.6-acre DOH site; and

 planting 15 acres of trees and additional sites within or adjacent to Calvert County.

By minimizing tree clearing to the extent necessary, replanting trees after construction, and 

mitigating temporary and permanent tree clearing impacts in coordination with the MDNR and Calvert 

County, we conclude that forest and woodland habitats would not be significantly impacted by the 

Project. DCP provided its draft Forest Preservation Plan for Offsite Area A to the MDNR on March 28, 

2014. This plan would be reviewed and approved by the MDNR and other applicable agencies prior to 

implementation. However, to document that the Forest Preservation Plan for Offsite Area A has been 

completed as described above to offset the temporary and permanent loss of forest land at Offsite Area A, 

we recommend that:

 Prior to the use of Offsite Area A, DCP should file the final Forest Preservation Plan 

for Offsite Area A, approved by the MDNR.

Open Land

Approximately 20 acres of mowed/maintained land and 4.5 acres of old field/pioneer land would 

be impacted by construction of the Project. In general, the impact on remaining open land vegetation that 

would be removed from the construction work area would be considered short term. After cleanup and 

reseeding of the Project areas, the herbaceous components of the cover type would typically regenerate 

quickly considering the ample annual rainfall in the region. Aside from the permanent impacts noted in 

table 2.3.1-2, impacts on these cover types during facility operation would be minor because these cover 

types would be allowed to reestablish and would not be significantly altered by facility maintenance 

activities. 

Conclusion on Vegetation

Because DCP would implement measures contained in our Plan and Procedures and its E&SCPs 

and Invasive Species Management Plans, and would comply with state and local forest preservation and 

mitigation requirements, we conclude that vegetation impacts from constructing and operating the Project 

would be adequately minimized.

2.3.2 Wildlife 

Existing Wildlife Resources

The Project would cross upland and wetland habitats that support a diversity of wildlife species. 

Wildlife species are directly dependent on the existing vegetation communities and are attracted to an 
65

area if suitable cover and/or habitat are present. As described in sections 2.2.4 and 2.3.1, the proposed 

facilities would cross several distinct wetland and upland vegetation communities. Each of these 

vegetation communities provides nesting, cover, and foraging habitat for a variety of wildlife species. 

Impacts on fisheries resources are described in section 2.2.3. 

Upland Forest

The upland forests in the Project area provide moderate to high quality habitat for a variety of 

mammals, birds, amphibians, reptiles, and invertebrates. The predominance of oak is an important habitat 

component in upland forests in the Project area. Some mammals rely directly on oak mast as a food 

source, while amphibians and invertebrates rely on the soil chemistry of an oak forest. Predatory species, 

such as raptors and red fox are also attracted to oak-dominated forests and their edges due to the 

abundance and diversity of prey species. The tree and shrub layers provide food and cover for birds and 

larger mammals, such as white-tailed deer and wild turkey. Detritus on the forest floor provides food and 

cover for invertebrates, amphibians, reptiles, and smaller mammals, such as skunk, opossum, raccoons, 

squirrel, groundhogs, eastern chipmunk, and other rodents. 

Old Field

Old field habitat at the LNG Terminal, Pleasant Valley Compressor Station, and Loudoun M&R 

Facility generally provide poor to moderate wildlife habitat. Birds rely on open fields and maintained 

utility rights-of-way for nesting and foraging, while mammals may utilize old field habitat as foraging and 

denning habitat. Open fields also provide habitat for smaller species such as mice, rabbits, and voles, 

which makes this vegetation community prime hunting grounds for predator species such as foxes and 

raptors.

Mowed/Maintained Areas

Mowed and maintained land at Offsite Area B, the Pleasant Valley Compressor Station, Pleasant 

Valley Suction/Discharge Pipelines, and Leesburg Compressor Station Contractor Staging Area tend to 

provide minimal habitat for wildlife species. Wildlife diversity is often limited to species that are adapted 

to human presence and the associated anthropogenic changes to the landscape, such as paved and 

landscaped areas.

Wetlands

Wetlands provide a diverse assemblage of vegetation and an abundance of food and water sources 

for wildlife. Mammals such as mink, muskrat, raccoon, and white-tailed deer use these areas as foraging 

habitat. Many waterfowl and wading birds use wetlands and adjacent riparian habitat for nesting and 

foraging. Wetland communities are also vital habitat for many reptiles and amphibians. 

Wildlife Habitat of Special Concern or Value

Portions of Offsite Area A and forest immediately adjacent to the Fenced Area of the LNG 

Terminal are designated by Calvert County as Forested Interior Dwelling Species (FIDS) habitat. FIDS 

habitat consists of areas where interior forest is more than 300 feet from a forest edge. Delineation of 

FIDS habitat is based on the existence of forests greater than 50 acres and riparian corridors greater than 

300 feet wide (Chesapeake Bay Critical Area Commission, 2000). FIDS habitat is important to many 

wildlife species, including bird species that can only reproduce in forest interiors, including the scarlet 

tanager, barred owl, pileated woodpecker, and whip-poor-will (Chesapeake Bay Critical Area 

Commission, 2000). 
66

Impacts and Mitigation

Potential impacts on wildlife from the Project include the temporary displacement of wildlife 

from the Project areas, and potential permanent displacement of wildlife from vegetated areas that are 

permanently lost. It is expected that most wildlife, such as birds and larger mammals, would temporarily 

relocate to adjacent available habitat as construction begins. This displacement could increase 

competition between species for forage, cover, and nesting habitat. Construction could result in the 

mortality of less mobile animals such as small rodents, reptiles, amphibians, and invertebrates, which may 

be unable to escape the immediate construction area. To minimize this potential, DCP would conduct the 

clearing of Offsite Area A in 20-acre phases to provide time for wildlife to relocate from the affected 

areas.

Project construction would require clearing of vegetation from the Project areas, temporarily 

decreasing the amount of wildlife habitat and reducing protective cover and foraging habitat in the 

immediate Project area. Depending on the season, construction could also disrupt bird courting or 

nesting, including destruction of nests, eggs, and chicks within the construction work area. This would be 

a short-term impact in open land areas because the majority of these habitats would re-establish quickly, 

thus remaining available for wildlife habitat and watershed functions. Longer term impacts would result 

from the loss of forest habitat. Approximately 113 acres of forest and 2 acres of early successional 

woodland would be cleared by the Project. Approximately 60 acres of FIDS land would be cleared at 

Offsite Area A. The clearing of forest within the Fenced Area and Offsite Area A would also convert 

FIDS land adjacent to these Project areas to non-FIDS land.

The degree of construction-related impacts on wildlife that inhabit wetlands would depend on the 

particular species and the time of year of construction. Highly mobile species, such as beavers, mink, 

muskrat, and birds, would likely vacate the area during construction. Amphibians and reptiles have lower 

mobility and hibernate in soft wetland soil. Some limited mortality to these species is likely unavoidable; 

however, a silt-fence barrier would be erected and maintained in an attempt to keep these species along 

with small mammals out of active work areas. 

In summary, construction and operation of the Project would result in short-term, long-term, and 

permanent impacts on wildlife and its habitat. The large area of similar habitat surrounding the Project 

areas would allow most species to relocate from the affected areas. In addition, DCP would implement 

measures in our Plan and Procedures and its E&SCPs and Invasive Species Management Plans, and 

would comply with state and local forest preservation and mitigation requirements, which include 

monitoring of restored and planted vegetation habitats. Therefore, we conclude that the Project would not 

result in significant impacts on general wildlife species.

2.3.3 Protected Species 

Migratory Birds 

Migratory birds are species that nest in the United States during the summer and make short- or 

long-distance migrations for the non-breeding season. Neotropical migrants migrate south to the tropical 

regions of Mexico, Central and South America, and the Caribbean for the non-breeding season. 

Migratory birds are protected under the Migratory Bird Treaty Act (MBTA) (16 USC 703-711). The 

MBTA, as amended, prohibits the taking, killing, possession, transportation, and importation of migratory 

birds, their eggs, parts, or nests unless authorized under a U.S. Fish and Wildlife Service (FWS) permit. 

Bald and Golden Eagles are additionally protected under the Bald and Golden Eagle Protection Act 

(BGEPA) (16 USC 668-668d). Executive Order 13186 (66 Federal Register 3853) directs federal 

agencies to identify where unintentional take is likely to have a measurable negative effect on migratory 
67

bird populations and to avoid or minimize adverse impacts on migratory birds through enhanced 

collaboration with the FWS. Executive Order 13186 states that emphasis should be placed on species of 

concern, priority habitats, and key risk factors, and that particular focus should be given to addressing 

population-level impacts.

On March 30, 2011, the FWS and the Commission entered into a Memorandum of Understanding 

Between the Federal Energy Regulatory Commission and the U.S. Department of the Interior United 

States Fish and Wildlife Service Regarding Implementation of Executive Order 13186, “Responsibilities 

of Federal Agencies to Protect Migratory Birds” that focuses on avoiding or minimizing adverse impacts 

on migratory birds and strengthening migratory bird conservation through enhanced collaboration 

between the two agencies. This voluntary memorandum of understanding does not waive legal 

requirements under the MBTA, BGEPA, ESA, Federal Power Act, NGA, or any other statutes and does 

not authorize the take of migratory birds. 

A variety of migratory bird species, including songbirds, raptors, and waterfowl utilize the habitat 

found within the Project area. The FWS identified Birds of Conservation Concern (BCC) for various 

regions in the country in response to the 1988 amendment to the Fish and Wildlife Conservation Act, 

which mandated the FWS to identify migratory nongame birds that, without additional conservation 

actions, were likely to become candidates for listing under the ESA. The BCC lists, last updated in 2008, 

are divided by Bird Conservation Regions (BCR). Calvert County, Maryland and Fairfax County, 

Virginia are within the New England/Mid-Atlantic Coast BCR and Loudoun County, Virginia is within 

the Piedmont BCR (FWS, 2008). A total of 48 BCC are listed in the BCRs crossed by the Project, of 

which 32 are known to breed within their respective BCR. Table 2.3.3-1 lists the BCC that are known to 

breed within the Project area.

TABLE 2.3.3-1

Birds of Conservation Concern Potentially Occurring Within the Project Area

Bird of Conservation Concern a

Piedmont 

BCR

New England/

Mid-Atlantic Coast BCR

Preferred Habitat and Potential Presence at Project 

Areas

Pied-billed Grebe X Wetlands and ponds with dense vegetation, bays,

and sloughs. Habitat not impacted by Project.

American Bittern X Freshwater marshes with tall vegetation.

Occasionally use brackish marshes. Habitat not 

impacted by Project.

Least Bittern X Freshwater or brackish marshes with tall emergent 

vegetation. Habitat not impacted by Project.

Snowy Egret X Mangroves, saltwater lagoons, freshwater swamps, 

grassy ponds. Nest on isolated islands, swamps,

and marshes. Habitat not impacted by Project.

Bald Eagle X X Forest (riparian). Habitat present. No bald eagle 

nests identified during field surveys.

Peregrine Falcon X X Cliffs or man-made structures (riparian). Habitat not 

impacted by Project.

Black Rail X X Coastal salt and brackish marshes. Habitat not 

impacted by Project.

Wilson’s Plover X Ocean beaches, lagoons, and salt flats. Habitat not 

impacted by Project.

American Oystercatcher X Ocean shores and salt marshes. Habitat not 

impacted by Project.

Upland Sandpiper X Agricultural lands (dry grasslands). Habitat not 

impacted by Project.

Least Tern X Seacoasts, beaches, bays, estuaries, lagoons, 

lakes and rivers. Habitat not impacted by Project.
68

TABLE 2.3.3-1 (cont’d)

Birds of Conservation Concern Potentially Occurring Within the Project Area

Bird of Conservation Concern a

Piedmont 

BCR

New England/

Mid-Atlantic Coast BCR

Preferred Habitat and Potential Presence at Project 

Areas

Gull-billed Tern X Gravelly or sandy beaches, salt marshes, and

estuaries. Habitat not impacted by Project.

Black Skimmer X Open sandy beaches, gravel or shell bars, or mats 

of sea wrack. Habitat not impacted by Project.

Whip-poor-will X X Open woodlands. Habitat present at Offsite Area A, 

Fenced Area, and Pleasant Valley Compressor 

Station.

Red-headed Woodpecker X Open woodlands with scattered trees. Habitat 

present at Offsite Area A, Fenced Area, and 

Pleasant Valley Compressor Station.

Loggerhead Shrike X X Pasture and cropland with scattered trees and 

hedgerows. Habitat not impacted by Project.

Brown-headed Nuthatch X X Mature pine stands. Habitat not impacted by 

Project.

Bewick’s Wren X Open woodlands (riparian). Habitat present at 

Offsite Area A, Fenced Area, and Pleasant Valley 

Compressor Station.

Sedge Wren X X Moist upland sedge meadow. Habitat not impacted 

by Project.

Wood Thrush X X Moist, lowland deciduous forest. Low potential 

habitat present at Offsite Area A.

Blue-winged Warbler X X Abandoned fields, swamp, wetlands. Low potential 

habitat present at Offsite Area A.

Golden-winged Warbler X Abandoned fields with small saplings (forest edge). 

Habitat not impacted by Project.

Prairie Warbler X X Old fields/pastures with young trees. Habitat not 

impacted by Project.

Cerulean Warbler X X Mature upland oak woods (wooded hillsides along 

streams and rivers). Habitat present at Offsite Area 

A.

Worm-eating Warbler X Woodlands with dense understory. Potential habitat 

present at Offsite Area A, Fenced Area, and 

Pleasant Valley Compressor Station.

Swainson’s Warbler X Bottomland forests (cove hardwoods with dense 

deciduous understory). Habitat not impacted by 

Project.

Kentucky Warbler X X Deciduous woods of floodplains, swamps, and 

ravines. Habitat not impacted by Project.

Bachman’s Sparrow X Open pine forest. Habitat not impacted by Project.

Henslow’s Sparrow X X Ephemeral grasslands. Habitat not impacted by 

Project.

Nelson's Sharp-tailed Sparrow X Freshwater marshes, wet meadows, and salt 

marshes. Habitat not impacted by Project.

Saltmarsh Sharp-tailed Sparrow X Salt marshes. Habitat not impacted by Project.

Seaside Sparrow X Salt marshes. Habitat not impacted by Project.

____________________

a This list does not include Birds of Conservation Concern that are non-breeding in the respective bird conservation region.

Source: USFWS, 2008

The potential impacts of the Project on migratory birds, including BCC-listed birds, would 

include the temporary and permanent loss of habitat associated with the removal of existing vegetation. 

The greatest potential to impact migratory birds would occur if Project construction activities such as 

grading, tree clearing, and construction noise take place during the breeding and nesting season. This 
69

could result in the destruction of nests and mortality of eggs and young birds that have not yet fledged. 

Construction would also reduce the amount of habitat available for foraging and predator protection for 

migratory birds and would temporarily displace birds into adjacent habitats, which could increase the 

competition for food and other resources. This could result in increased stress, susceptibility to predation, 

and negatively impact reproductive success. Noise and other construction activities could affect courtship 

and breeding activities including nesting and the rearing of young. 

The loss of approximately 108 acres of upland and wetland forest within the Fenced Area of the 

LNG Terminal and Offsite Area A (see tables 2.2.4-1 and 2.3.1-2) would present a long-term impact for 

migratory birds that depend on forest. However, both the Fenced Area and Offsite Area A are surrounded 

by large, forested tracts, and the amount of forest that would be cleared represents approximately 0.1 

percent of available forest habitat in Calvert County. Thus, we conclude that the loss of forest habitat 

would not result in population-level impacts on migratory birds in the region. However, to further reduce 

the potential for the Project to impact migratory birds, especially during nesting season, and because DCP 

has not committed to any tree clearing timing restrictions, we recommend that:

 Within 7 days prior to the start of tree clearing between the dates of April 1 and 

August 31, DCP should conduct a survey to identify whether any nesting BCC birds 

are present in the Fenced Area and Offsite Area A. If nesting BCC birds are 

identified, DCP should avoid tree clearing and other Project activities within 50 feet 

of active nests until young have fledged the nest and vacated the Project area, or it is 

determined by a qualified biologist that the nest has been abandoned. 

Federal Threatened and Endangered Species

Federal agencies are required under section 7 of the ESA, as amended, to ensure that any actions 

authorized, funded, or carried out by the agency would not jeopardize the continued existence of a 

federally listed endangered or threatened species, or result in the destruction or adverse modification of 

the designated critical habitat of a federally listed species. As the lead federal agency authorizing the 

Project, the FERC is required to consult with the FWS and/or NMFS to determine whether federally listed 

endangered or threatened species or designated critical habitat are found in the vicinity of the Project, and 

to evaluate the proposed action’s potential effects on those species or critical habitats. 

For actions involving major construction activities with the potential to affect listed species or 

designated critical habitat, the lead federal agency must report its findings to the FWS and/or NMFS in a 

Biological Assessment for those species that may be affected. If it is determined that the action is likely 

to adversely affect a listed species, the federal agency must submit a request for formal consultation to 

comply with section 7 of the ESA. In response, the FWS and/or NMFS would issue a Biological Opinion 

as to whether the federal action would jeopardize the continued existence of a listed species, or result in 

the destruction or adverse modification of designated critical habitat. We have determined that the 

Project would not adversely affect federally listed endangered or threatened species or designated critical 

habitat as described in the following sections. 

Species Under FWS Jurisdiction

DCP, acting as the FERC’s non-federal representative for the purpose of complying with section 

7(a)(2) of the ESA, initiated informal consultation with the Chesapeake Bay Field Office of the FWS on 

June 14, 2012, regarding federally listed threatened or endangered species potentially occurring in or near 

the Project areas in Maryland. The FWS did not identify any federally listed threatened or endangered 

species that are known to occur in the Project area in Maryland. 
70

DCP initiated informal consultation with the Virginia Ecological Services Field Office of the 

FWS on December 26, 2012, regarding federally listed threatened or endangered species potentially 

occurring in or near the Project areas in Virginia. The FWS indicated that one federally listed threatened 

plant species, the small whorled pogonia, may occur at the Pleasant Valley Compressor Station, Pleasant 

Valley Suction/Discharge Pipelines, and Pleasant Valley M&R Facility. DCP completed a survey for the 

small whorled pogonia at the Pleasant Valley Compressor Station and in the forested area adjacent to the 

Pleasant Valley Suction/Discharge Pipelines and the Pleasant Valley M&R Facility during the preferred 

flowering period for the species in June 2013. The survey identified two areas on the compressor station 

property as marginal habitat; however, the small whorled pogonia was not found. The areas that would 

be affected by construction and operation of the Pleasant Valley Suction/Discharge Pipelines and the 

Pleasant Valley M&R Facility were not surveyed as they are unforested, maintained pipeline right-of-way 

or gravel-surfaced industrial land, neither of which are considered habitat for the small whorled pogonia. 

On August 15, 2013, the FWS agreed with DCP’s survey results and concluded the small whorled 

pogonia was not present and is not likely to be adversely affected by the Project. Therefore, we conclude

that the Project is not likely to adversely affect the small whorled pogonia.

Species Under NMFS Jurisdiction

DCP initiated informal consultation with NMFS on June 14, 2012. In a letter dated July 20, 

2012, NMFS identified the shortnose sturgeon (endangered), Atlantic sturgeon (endangered), loggerhead 

turtle (threatened), green turtle (endangered), Kemp’s ridley turtle (endangered), and the leatherback 

turtle (endangered) as known to occur in the Chesapeake Bay. As discussed in section 1.2.1, the annual

frequency of ship traffic for the Project would not exceed 200 vessels per year as previously approved in 

Dockets CP05-130, et al., and DCP would not accept LNG carriers larger than previously authorized in 

Docket CP09-60. However, DCP estimates that only 85 LNG vessels per year would call at the LNG 

Terminal for export as part of operation of the Liquefaction Facilities. As a result, we conclude that LNG 

ship traffic associated with the Project would have no effect on the shortnose sturgeon, Atlantic sturgeon 

and the four listed sea turtles. NMFS also concluded that, because the Project would not involve in-water 

work and assuming that LNG vessel traffic would not increase to the existing offshore pier, the Project 

would not likely affect the waters of the Chesapeake Bay or result in direct or indirect effects on the 

above-referenced species. 

However, at the time of the above consultation, the NMFS was not aware of DCP’s plan to utilize 

Offsite Areas A and B. On December 6, 2012, DCP informed NMFS of the proposed use of Offsite 

Areas A and B, including the construction of the temporary pier in the Patuxent River at Offsite Area B. 

The NMFS responded on December 12, 2012, that no species under NMFS jurisdiction occur at Offsite 

Area A. With regards to the temporary pier at Offsite Area B, NMFS identified the shortnose sturgeon 

and five Distinct Population Segments of the Atlantic sturgeon as potentially occurring within the vicinity 

of the pier. NMFS advised that further analysis should be conducted of the potential impact that 

construction of the temporary pier could have on the shortnose and Atlantic sturgeon, as well as the 

potential impact that increased barge traffic to the temporary pier could have on shortnose and Atlantic 

sturgeon and the four species of sea turtles noted above. 

On February 27, 2013, DCP submitted an analysis of potential Project impacts on the shortnose 

and Atlantic sturgeon. The findings are listed below.

 There is no designated critical habitat for the shortnose or Atlantic sturgeon within the 

Chesapeake Bay.

 The Project area does not contain shortnose or Atlantic sturgeon spawning areas.
71

 The shortnose and Atlantic sturgeon are rare or occasional transients in proximity to 

Offsite Area B. No shortnose sturgeon and only one Atlantic sturgeon have been 

documented in the Patuxent River as part of the Sturgeon Reward Program, a FWS and 

MDNR program initiated in 1996 that pays fisherman to report the bycatch of shortnose 

and Atlantic sturgeon.

 Temporary, minor impacts on the food web may occur as a result of construction and 

removal of the temporary pier at Offsite Area B. Forage fish and macroinvertebrates may 

be displaced from the construction area, but would be expected to return to the temporary 

pier location once it is removed.

 The shortnose and Atlantic sturgeon are highly mobile and would be displaced by noise 

and activity at the temporary pier.

 DCP would implement a ballast water management program in compliance with 

applicable laws and regulations designed to prevent water quality degradation and the 

introduction of invasive species. 

On May 1, 2013, NMFS issued a request for additional information regarding the construction 

methods that would be used to install the temporary pier at Offsite Area B. On July 3, 2013, DCP 

responded that the hollow steel piles for the pier and mooring dolphins would be installed with a vibratory 

hammer to the extent possible in approximately 15 days between September 1, 2014, and May 1, 2015. 

Due to the short duration of pile driving, the small diameter of the piles, and the localized area of impact, 

there is no anticipated need to implement sound attenuation controls that would be protective of the 

shortnose and Atlantic sturgeon, but DCP would implement measures as necessary to stay within sound 

limits specified by NMFS. 

With regard to the potential for increased barge traffic to the temporary pier to impact NMFS 

species of concern, DCP estimates that 42 barge deliveries would be made to the temporary pier during an 

18-month period, or approximately 2.3 deliveries per month. This level of traffic compares to 

approximately 167 commercial vessel transits of the Chesapeake Bay each month. 

On September 11, 2013, NMFS responded to the information that has been submitted by DCP 

and concluded that no federally listed species under NMFS jurisdiction would be exposed to any direct or 

indirect effects of the proposed Project and additional consultation under Section 7 of the ESA is not 

required. On April 8, 2014, NMFS provided further clarification that its effects determination was based 

on the proposed Project information provided by DCP as well as previous consultations that were 

completed for past Cove Point projects that assessed the effects of vessel traffic of up to 200 vessels 

annually. The vessel traffic associated with the currently proposed Project would consist of an estimated 

42 barge deliveries to the temporary pier during an 18-month period during construction and an estimated 

85 LNG vessels per year during operation, both of which would be below the previously assessed effects 

of up to 200 vessels annually. Further, DCP has stated LNG vessels and barges would be required to 

comply with its Vessel Strike Avoidance Measures and Injured and Dead Protected Species Reporting 

Plan. As such, after reviewing DCP’s and NMFS’ findings, relevant fisheries information, and analyzing 

potential Project impacts, we find that the Project would have no effect on the shortnose sturgeon, Atlantic 

sturgeon, loggerhead turtle, green turtle, Kemp’s ridley turtle, and the leatherback turtle. 

We received a comment regarding the potential for the Project to affect threatened and 

endangered species under the jurisdiction of the NMFS, including the North Atlantic right whale. DCP 

has committed to continue implementation of its Vessel Strike Avoidance Measures and Injured and Dead 

Protected Species Reporting Plan during operation of the Liquefaction Facilities, as well as during barge 
72

transit activities associated with Offsite Area B. In additional, NOAA has implemented regulations 

requiring all marine vessels greater than 65 feet in length to travel 10 knots or less, during specific 

seasonal timeframes, in right whale management zones along the East Coast. Since the vessel speed 

restrictions went into effect, no known fatal ship strikes of North Atlantic right whales have occurred in 

the management zones. Because LNG vessels and barges would be required to comply with this 

regulation, and DCP would require LNG vessels and barges to comply with its Vessel Strike Avoidance 

Measures and Injured and Dead Protected Species Reporting Plan, we find that ship and barge traffic 

related to the Project is not likely to adversely affect the North Atlantic right whale.

Bald and Golden Eagle Protection Act

The bald eagle is a large bird of prey whose range covers virtually all of North America. 

Although no longer federally listed under the ESA, the bald eagle is protected under the BGEPA and the 

MBTA. The BGEPA and MBTA prohibit killing, selling, or harming eagles or their nests; and the 

BGEPA also protect eagles from disturbances that may injure them, decrease productivity, or cause nest 

abandonment. 

Optimal roosting, foraging, and breeding habitats for the bald eagle include areas near 

waterbodies, such as lakes, rivers, and forested wetlands. Bald eagles typically prefer large trees for 

roosting and nesting. Bald eagles can be sensitive to human activity and disturbance and may abandon 

otherwise suitable habitat if disturbance is persistent (Fraser et al., 1985). The FWS did not identify any 

bald eagle nests within the vicinity of the Project area (FWS, 2012). DCP stated it would implement the 

National Bald Eagle Management Guidelines should any nesting bald eagles be identified near the Project 

areas during construction. Therefore, the Project would not have any impacts on the bald eagle.

State Threatened and Endangered Species

Maryland and Virginia have regulatory requirements for state-listed species. In Maryland, the 

MDNR, Wildlife Heritage Service is responsible for administering the state endangered species laws. In 

Virginia, three agencies are responsible for protecting threatened and endangered species: 1) the VDACS; 

2) the Virginia Department of Game and Inland Fisheries (VDGIF); and 3) the VDCR. Under a 

Memorandum of Agreement established between VDACS and the VDCR, VDCR represents VDACS in 

comments regarding potential impacts on state-listed threatened and endangered plant and insect species. 

A list of state-listed species potentially occurring in the Project area is provided in table 2.3.3-2. The 

small whorled pogonia, a federal and state-listed species, is discussed under the FWS jurisdiction section 

above.

The MDNR has also identified several rare and uncommon plant species that adjoin St. Paul’s 

Branch, including wetland plant species and odonates that are highly vulnerable to changes in hydrology, 

water chemistry, and water quality (see table 2.3.3-3).
73

TABLE 2.3.3-2

State-Listed Threatened and Endangered Species Identified in the Vicinity of the Project

Species Name Status Habitat Potential Location of Species

Presence or Absence in 

Project Area

Plant Species

Small whorled 

pogonia (Isotria 

medeoloides)

Federal 

Threatened;

Maryland 

Endangered;

Virginia 

Endangered

Hardwood stands of beech, 

birch, maple, oak, and 

hickory that have an open 

understory. Often on slopes 

near small streams.

Pleasant Valley Compressor 

Station, Pleasant Valley Suction/

Discharge Pipelines, Pleasant 

Valley M&R Facility

Not found during field surveys 

in 2013. The Project would not 

impact this species.

Thread-leaved 

gerardia (Agalinis 

setacea)

Maryland 

Endangered

Sandy habitats and along 

the coast.

LNG Terminal Not found during field surveys. 

The Project would not impact 

this species.

Potato dandelion 

(Krigia 

dandelion)

Maryland 

Endangered

Low, damp, chiefly open 

sites, prairies, fields, 

meadows, open woods, and 

roadsides, light acidic soils, 

sandstone, chert, or granite.

LNG Terminal Not found during field surveys. 

The Project would not impact 

this species.

Tobaccoweed 

(Elephantopus 

tomentosus)

Maryland 

Endangered

Open or shaded, dry to wet 

pine forests and mixed 

forests, often on sandy 

soils.

Offsite Area A Present at Offsite Area A. 

Protected by 100-foot 

avoidance buffers. The 

Project would not likely impact 

this species.

Engelmann’s 

arrowhead 

(Sagittaria 

engelmanniana)

Maryland 

Threatened

Bog, ponds, and streams 

with acid water.

Offsite Area A Not found during field surveys.

The Project would not impact 

this species.

Kidneyleaf grassof- parnassus 

(Parnassia 

asarifolia)

Maryland 

Endangered

Wet areas, bogs, swamps, 

and moist woods.

Offsite Area A Not found during field surveys. 

The Project would not impact 

this species.

Evergreen

bayberry (Morella 

carolinensis)

Maryland 

Endangered

Bogs, low pinelands, 

flatwoods, bays, savannahs, 

and pocosins.

Offsite Area A Not found during field surveys.

The Project would not impact 

this species.

Torrey’s 

mountain mint 

(Pycnanthemum 

torrei)

Maryland 

Endangered;

Virginia 

Species of 

Concern

Dry, open habitats, including 

red cedar barrens, rocky 

summits, trails, and 

roadsides.

Pleasant Valley Compressor 

Station, Pleasant Valley Suction/

Discharge Pipelines, Pleasant 

Valley M&R Facility

Not found during field surveys. 

The Project would not impact 

this species.

Purple milkweed 

(Asclepias 

purpurascens)

Virginia 

Imperiled

Rocky open woods, glades, 

prairies, stream banks, wet 

meadows and valleys, 

thickets, roadsides.

Pleasant Valley Compressor 

Station, Pleasant Valley Suction/

Discharge Pipelines, Pleasant 

Valley M&R Facility

Not found during field surveys. 

The Project would not impact 

this species.

Grove sandwort 

(Moehringia 

lateriflora)

Virginia 

Critically 

Imperiled

Open woods and gravelly 

shores.

Pleasant Valley Compressor 

Station, Pleasant Valley Suction/

Discharge Pipelines, Pleasant 

Valley M&R Facility

Not found during field surveys. 

The Project would not impact 

this species.
74

TABLE 2.3.3-2 (cont’d)

State-Listed Threatened and Endangered Species Identified in the Vicinity of the Project

Species Name Status Habitat Potential Location of Species

Presence or Absence in 

Project Area

Mussel Species

Green floater 

(Lasmigona 

subviridis)

Maryland 

Endangered;

Virginia 

Threatened

Pools and eddies with 

gravel and sand bottoms of 

smaller rivers and creeks;

smaller channels of large 

rivers or small to mediumsized streams.

Downstream of Loudoun M&R 

Facility

No surface water impacts 

proposed. The Project would 

not impact this species.

Brook floater 

(Alamidonta 

varicosa)

Maryland 

Endangered;

Virginia 

Endangered

Streams and rivers with low 

to moderate flow velocities 

and stable substrate. Found 

among boulders in sand.

Pleasant Valley Compressor 

Station, Pleasant Valley Suction/

Discharge Pipelines, Pleasant 

Valley M&R Facility

No surface water impacts 

proposed. The Project would 

not impact this species.

Reptile Species

Wood turtle

(Glyptemys 

inscupta)

Virginia 

Threatened

Streams and adjacent 

riparian uplands

Pleasant Valley Compressor 

Station, Pleasant Valley Suction/

Discharge Pipelines, Pleasant 

Valley M&R Facility

Identified in Project area; 

however, suitable habitat 

would not be impacted by the 

Project.

Bird Species

Upland 

sandpiper

(Bartramia 

longicauda)

Maryland 

Endangered;

Virginia 

Threatened

Inhabits grasslands, fallow 

fields, and meadows that 

are often associated with 

pastures, farms, or airports.

Pleasant Valley Compressor 

Station, Pleasant Valley Suction/

Discharge Pipelines, Pleasant 

Valley M&R Facility

Not identified during field 

surveys. Additional preconstruction surveys would 

identify nesting upland 

sandpipers, which would be 

protected during nesting and 

fledging. The Project is not 

likely to impact this species.

Loggerhead

shrike (Lanius 

ludovicianus)

Maryland 

Endangered;

Virginia 

Threatened

Open habitat of short 

grasses and forbs of low 

stature with bare ground 

and shrubs or low trees.

Pleasant Valley Compressor 

Station, Pleasant Valley Suction/

Discharge Pipelines, Pleasant 

Valley M&R Facility

Not identified during field 

surveys. Additional preconstruction surveys would 

identify nesting loggerhead 

shrike, which would be 

protected during nesting and 

fledging. The Project is not 

likely to impact this species.

Migrant

loggerhead 

shrike (Lanius 

ludovicianus 

migrans)

Virginia 

Threatened

Grasslands and open, 

agricultural areas 

characterized by short 

vegetation and scattered 

trees, shrubs, or 

hedgerows.

Pleasant Valley Compressor 

Station, Pleasant Valley Suction/

Discharge Pipelines, Pleasant 

Valley M&R Facility

Not identified during field 

surveys. Additional preconstruction surveys would 

identify nesting loggerhead 

shrike, which would be 

protected during nesting and 

fledging. The Project is not 

likely to impact this species.

Henslow’s 

sparrow 

(Ammodramus 

henslowii)

Maryland 

Threatened;

Virginia 

Threatened

Large, flat fields with no 

woody plants and with tall, 

dense grass, a dense litter 

layer, and standing dead 

vegetation.

Pleasant Valley Compressor 

Station, Pleasant Valley Suction/

Discharge Pipelines, Pleasant 

Valley M&R Facility

Not identified during field 

surveys. Additional preconstruction surveys would 

identify nesting Henslow’s 

sparrow, which would be 

protected during nesting and 

fledging. The Project is not 

likely to impact this species.

Insect species

Appalachian 

grizzled skipper 

(Pyrgus wyandot)

Maryland 

Endangered;

Virginia 

Threatened

Open, sparsely grassed, 

and barren areas in close 

proximity to oak or pine 

forests.

Pleasant Valley Compressor 

Station, Pleasant Valley Suction/

Discharge Pipelines, Pleasant 

Valley M&R Facility

Not identified during field 

surveys. The Project would 

not likely impact this species.
75

TABLE 2.3.3-3

Rare and Uncommon Plant Species Identified by the MDNR at St. Paul’s Branch

Species State Status

Engelmann’s Arrowhead (Sagittaria engelmanniana) Threatened

Kidneyleaf Grass-of-Parnassus (Parnassia asarifolia) Endangered

Evergreen Bayberry (Morella carolinensis) Endangered

Brown Spiketail (Cordulegaster bilineata) Watchlist/Greatest Conservation Need a

Tiger Spiketail (Cordulegaster erronea) Watchlist/Greatest Conservation Need a

____________________

a Designated Greatest Conservation Need in Maryland’s Wildlife Diversity Plan.

Only one state-listed species was identified during field surveys. DCP identified four patches of 

tobaccoweed, a Maryland state-listed endangered species, at Offsite Area A. DCP proposes to establish a 

100-foot avoidance area around each patch of tobaccoweed during use and restoration of Offsite Area A, 

delineated by two rows of super silt fence, spaced 3 to 4 feet apart. DCP would segregate, store, and 

replace topsoil adjacent to the patches of tobaccoweed to conserve seed base within the topsoil. DCP 

would also implement stormwater management and erosion and sediment control measures that will 

prevent erosion or sedimentation impacts to this species. DCP’s Invasive Species Management Plan for 

the Calvert County facilities includes measures to prevent and control the spread of invasive species. We 

conclude implementation of these measures would effectively avoid impacts on tobaccoweed populations 

at Offsite Area A. No other state-listed species were identified during field surveys. Therefore, no 

impacts are anticipated on state-listed species.

In Virginia, the VDCR identified the green floater and the aquatic community associated with the 

Little River Stream Conservation Unit as species and communities of concern potentially occurring 

downstream of the Loudoun M&R Facility. As indicated in section 2.2.2, proposed activities at the 

Loudoun M&R Facility would not directly impact any surface waterbody. In addition, DCP would 

implement provisions of the site-specific E&SCPs and SMPs to prevent water quality degradation during 

construction and operation of the Project. We conclude that implementation of these measures would 

effectively avoid impacts on the green floater and the Little River Stream Conservation Unit.

2.4 LAND USE, RECREATION, AND VISUAL RESOURCES

2.4.1 Existing Land Use

Three land use types would be affected by the Project, including open land/water, forest/

woodland, and commercial/industrial/disturbed land. The definitions of each land use type are as follows:

 Open Land/Water – includes mowed and maintained agricultural fields, maintained 

utility right-of-way, open water, and old field/shrub lands.

 Forest/Woodland – includes tree stands consisting primarily of mixed oak-hickory forest.

 Commercial/Industrial/Disturbed Land – includes the existing developed portions of the 

LNG Terminal, compressor station sites, M&R facilities, and paved roads. 

Table 2.4.1-1 summarizes the land use requirements associated with construction and operation of 

the Project. 

Impacts on land would result from clearing of the construction work area for the installation of 

Project facilities, including at the Liquefaction Facilities, Pleasant Valley Compressor Station, Pleasant 

Valley Suction/Discharge Pipelines, and Loudoun M&R Facility, as well as the use of Offsite Areas A 

and B during construction. 
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The proposed activities at the Liquefaction Facilities would take place within a 130-acre Fenced 

Area of the existing LNG Terminal, which is located within DCP’s larger 1,017-acre property. The LNG 

Terminal property is located on a ridge above the western shore of the Chesapeake Bay. The Project area

is zoned as industrial property; however, the existing land use types that would be affected by the Project 

include open land/water, forested/woodland, and commercial/industrial/disturbed land. Construction of 

the Liquefaction Facilities would affect approximately 1.7 acres of open land/water, 11.8 acres of forest 

land/woodland, and 54.8 acres of commercial/industrial/disturbed land. Operation of the Liquefaction 

Facilities would permanently convert 11.4 acres of forest land/woodland and 1.7 acres of open land/water 

to industrial use. Approximately 46.5 acres of the commercial/industrial/disturbed land would be retained 

as that land use type for operation of the Liquefaction Facilities. The remaining commercial/industrial/

disturbed land would remain as part of the LNG Terminal operations, and the remaining 0.4 acre of forest 

land/woodland would be allowed to revert to forest land/woodland.

TABLE 2.4.1-1

Land Use Affected by Construction and Operation of the Cove Point Liquefaction Project

State/County/Facility

Open Land/Water Forest/Woodland

Commercial/

Industrial/

Disturbed Total

Const. Oper. Const. Oper. Const. Oper. Const. Oper.

MARYLAND

Calvert County a

Liquefaction Facilities 1.7 1.7 11.8 11.4 54.8 46.5 68.4 13.1 b

Offsite Area A 0 0 94.0 c 0 0.9 0 94.9 0 d

Offsite Area B e 5.7 0 0.1 0 0 0 5.8 0

VIRGINIA

Fairfax County

Pleasant Valley Compressor Station f 9.3 2.0 6.7 0.3 6.2 0.7 22.2 2.3 g

Pleasant Valley Suction/Discharge 

Pipelines and Pleasant Valley M&R 

Facility

1.9 0 0 0 1.4 0 3.3 0

Loudoun County, Virginia a

Loudoun M&R Facility 0.1 0 0 0 1.8 0 1.9 0

Leesburg Compressor Station 

Contractor Staging Area h

6.0 0 0 0 2.4 0 8.4 0

Project Total 24.7 3.7 112.6 11.7 67.5 47.2 204.9 15.4

____________________

a Acreages of access roads associated with the Liquefaction Facilities, Offsite Area A, Offsite Area B, the Loudoun M&R 

Facility, and the Leesburg Compressor Station Contractor Staging Area are included in the construction and operations 

totals of the respective facilities.

b The Liquefaction Facilities would occupy 59.5 acres within the existing Fenced Area of the LNG Terminal. However, 46.5

acres of the Liquefaction Facilities would be located on land that is currently utilized for operation of the LNG Terminal. 

The remaining 13.1 acres of the Liquefaction Facilities would impact land that is currently unaffected by operation of the 

LNG Terminal.

c Based on information provided by DCP to the FERC; however, the Maryland DNR has stated that DCP would affect 93.6 

acres of forest/woodland at Offsite Area A. The final area affected would be confirmed prior to construction.

d Offsite Area A would not be used during the operation of the Liquefaction Facilities, but would result in converting 94.0

acres of forest to open land.

e Does not include 0.2 acre of temporary open water impacts associated with the pier.

f

Includes 0.9 acre for the nonjurisdictional substation that would be constructed by the Northern Virginia Electric 

Cooperative within the Pleasant Valley Compressor Station site.

g The expansion of the Pleasant Valley Compressor Station would occupy 3.0 acres within the existing compressor station 

property. However, 0.7 acre of the expansion would be located on land that is currently utilized for operation of the 

compressor station. The remaining 2.3 acres of the expansion facilities would impact land that is currently unaffected by 

operation of the compressor station.

h

Includes reuse of the existing access road. The Leesburg Compressor Station includes 4.6 acres of commercial/industrial 

land; however, 2.2 acres of commercial/industrial land are currently occupied by buildings and other structures and would 

not be used during construction.

Note: The totals shown in this table may not equal the sum of addends due to rounding.
77

Offsite Area A would be located within a 179.4-acre currently undeveloped (primarily forested) 

area approximately 1.5 miles from the LNG Terminal. During construction, approximately 94.9 acres of 

the site would be cleared and utilized at Offsite Area A, including approximately 94.0 acres of forest land/

woodland and 0.9 acre of commercial/industrial/disturbed land. Offsite Area A would not be used during 

the operation of the Liquefaction Facilities, but its use during construction would result in the conversion 

of 94.0 acres of forest to open land. Offsite Area A is currently owned by a private party (100 acres) and 

Calvert County (79.4 acres). DCP has an option to purchase the privately owned 100-acre portion of 

Offsite Area A, and is negotiating to lease the remaining 79.4 acres from Calvert County. Following 

construction activities, DCP has stated it would donate the 100-acre parcel to Calvert County (giving the 

County ownership of the entire 179.4-acre parcel) and restore the site in accordance with the wishes of the 

County.

Offsite Area B would be located within an 11.0-acre property of undeveloped land approximately 

4.5 miles from the LNG Terminal. Construction activities at Offsite Area B would affect approximately 

5.7 acres of open land and 0.1 acre of forest land/woodland. In addition, the temporary pier would be 

located on approximately 0.2 acre of open water in the Patuxent River. Following construction activities, 

Offsite Area B would be allowed to revert to its previous use and the temporary pier would be removed.

The proposed activities at the Pleasant Valley Compressor Station would be conducted within 

DCP’s property boundary. Construction at the Pleasant Valley Compressor Station would affect 

approximately 9.3 acres of open land, 6.7 acres of forest land/woodland, and 6.2 acres of commercial/

industrial/disturbed land. Following construction, approximately 2.0 acres of open land, 0.3 acre of forest 

land/woodland, and 0.7 acre of commercial/industrial/disturbed would be retained for operation of the 

new compressor station facilities. The remaining land uses would be allowed to revert to their previous 

use. Construction of the Pleasant Valley Suction/Discharge Pipelines and M&R Facility would affect 

approximately 1.9 acres of open land and 1.4 acres of commercial/industrial/disturbed. The temporary 

construction right-of-way associated with the Pleasant Valley Suction/Discharge Pipelines and M&R 

Facility would be allowed to revert to its preconstruction use. The land retained as permanent right-ofway would be allowed to revert to its preconstruction use; however, certain activities such as the 

construction of aboveground structures, or the planting or cultivation of trees, would continue to be 

prohibited in the permanent right-of-way.

Construction activities at the Loudoun M&R Facility would take place within the boundary of 

DCP’s Loudoun Compressor Station property. Approximately 0.1 acre of open land and 1.8 acres of 

commercial/industrial/disturbed land would be affected during construction. No additional land would be 

required outside the existing facility for operation of the Loudoun M&R Facility. 

Approximately 6.0 acres of open land and 2.4 acres of commercial/industrial/disturbed land 

would be used for equipment staging and parking at the Leesburg Compressor Station site during 

construction. All land would be allowed to revert to previous use after the completion of construction. 

2.4.2 Recreation and Special Interest Areas

Liquefaction Facilities

The 1,017-acre property owned by DCP surrounding the Liquefaction Facilities is subject to four 

conservation agreements that preclude or restrict development. These include a grant to the County 

Commissioners of Calvert County for an easement for recreation purposes on which the county has 

constructed ball fields, an aquatic center, and other recreational facilities (Cove Point Park); an easement 

to Cove Point Beach Association, Inc., allowing beach-related recreational activities; a conservation 

easement granted to the Maryland Environmental Trust and The Nature Conservancy with restrictive 
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covenants precluding development outside the industrial portions of the LNG Terminal site; and an 

agreement between DCP, the Sierra Club, and the Maryland Conservation Council which limits activities 

to the 130-acre Fenced Area within DCP’s larger property. 

The Calvert Shore Oyster Sanctuary is located just offshore from the LNG Terminal. In 

Maryland, the oyster sanctuary program is overseen by the MDNR, and the harvest of oysters within the 

sanctuary is prohibited. The sanctuary extends along the shoreline from Cove Point, north approximately 

5.5 miles, and is approximately 3,300 feet wide in the area of the offshore LNG pier. No in-water 

activities are proposed at the LNG pier as part of the Project and, therefore, no impacts on the Calvert 

Shore Oyster Sanctuary would occur.

Recreational areas with 0.25 mile of the LNG Terminal include the Calvert Cliffs State Park, 

Cove Point Park, and recreational fishing in the Chesapeake Bay. Calvert Cliffs State Park is adjacent to 

DCP’s 1,017-acre LNG Terminal property but is separated from the Fenced Area by at least 1,600 feet of 

heavily forested land. Calvert Cliffs State Park includes over 13 miles of hiking trails and more than 1 

mile of shoreline along the Chesapeake Bay. Neither the hiking trails nor the shoreline are located within 

0.25 mile of the Fenced Area. Use of the park is restricted to daytime hours. 

Cove Point Park is located largely within the 1,017-acre LNG Terminal property owned by DCP, 

but is separated from the Fenced Area by at least 600 feet of heavily forested land. The park includes a 

pool, baseball and soccer fields, basketball and tennis courts, a playground, and areas for walking or 

jogging. The portion of the park nearest to the Liquefaction Facilities includes patches of forested land, 

two baseball diamonds, and parking areas. The park is open year-round and its use is restricted to 

daytime hours. 

Construction-related noise and visual impacts could occur on nearby recreational users but would 

be limited to the time of construction. Operation of the Liquefaction Facilities could also result in visual 

and noise impacts on nearby recreational users. However, construction and operation of the Liquefaction 

Facilities would occur within an existing industrial facility that is surrounded by dense forest, which 

would prevent or reduce these impacts. In addition, the Liquefaction Facilities would be visually 

consistent with the industrial appearance of existing facilities, and none of the proposed facilities would 

exceed the height of existing facilities within the Fenced Area. DCP would also install a sound barrier 

around a portion of the Liquefaction Facilities to shield surrounding areas from operation sights and 

sounds. Also, as discussed in section 2.7.2, DCP would be required to operate the facility in compliance 

with minimum noise criteria. Visual resources are discussed further in section 2.4.5. 

The Maryland Environmental Trust and The Nature Conservancy easement includes the 150-acre 

Cove Point Marsh, which is a Maryland Natural Heritage Area. Cove Point Marsh is managed by the 

Cove Point Natural Heritage Trust, a partnership between DCP, the Sierra Club, and the Maryland 

Conservation Council. DCP has worked with the Cove Point Natural Heritage Trust to fund preservation 

efforts at Cove Point Marsh, including a beach and marsh restoration Project associated with DCP’s Pier 

Reinforcement Project. Construction and operation of the Liquefaction Facilities would take place 

entirely within the Fenced Area, and operation of the new facilities would be consistent with the current 

operations at the LNG Terminal. In addition, as discussed above, the Cove Point Marsh is within the 

existing Maryland Environmental Trust and The Nature Conservancy easement, which precludes 

development activities from occurring on that land. As such, the proposed Project would not affect the 

Cove Point Marsh.

Recreational fishing takes place in the Chesapeake Bay in the vicinity of the LNG Terminal and 

Calvert Cliffs State Park, as well as outside the 500-yard safety and security zone around the offshore 

pier. No in-water work is proposed at the existing offshore pier during construction of the Project, and 
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LNG ship traffic would not exceed the currently approved frequency to the LNG Terminal. In addition, 

DCP would implement measures contained in its approved E&SCPs and SMPs to minimize impacts on 

surface water quality during construction and operation of the Liquefaction Facilities. As a result, no 

additional impacts on recreational fishing in the Chesapeake Bay would occur due to the Project.

Offsite Area A

No conservation or natural, recreational, or scenic areas are located within 0.25 mile of Offsite 

Area A. We received comments from the MDNR regarding potential impacts on the Hellen Creek 

Hemlock Preserve. The Preserve consists of approximately 120 acres of marshes, forest, and streams. 

The Preserve is located approximately 1 mile southwest of Offsite Area A; therefore, no impacts on the 

Hellen Creek Hemlock Preserve would occur with the use of Offsite Area A during construction of the 

Liquefaction Facilities.

Offsite Area B

Offsite Area B is located adjacent to the Patuxent River, which is used for recreational fishing, 

oystering, and boating. The Solomons Island Boat Launch and Fishing Pier, a recreation area owned by 

Calvert County and leased to a private operator, is located adjacent to Offsite Area B. The area includes 

trailer parking and boat ramps with four docks that extend up to 100 feet in the Patuxent River. An 

estimate of 5,000 boat launches occur from the Solomons Island Boat Launch each year, with the busiest 

times being weekends between Memorial Day and Labor Day (Calvert County Natural Resources 

Division, 2013). Designated natural oyster bars are also located in the Patuxent River approximately 560 

feet offshore as discussed in section 2.2.3. In addition, we received comments regarding potential 

impacts regarding use of the pier during local events. 

Use of Offsite Area B would affect approximately 5.8 acres of an 11.0-acre site. The property 

where Offsite Area B would be located is currently used as overflow parking for the Calvert Marine 

Museum. DCP has stated that its use of Offsite Area B would not preclude continued use of the site as 

overflow parking for large events at the Calvert Marine Museum. In addition, DCP would work to 

schedule activities at Offsite Area B so that it would not interfere with use of the site for overflow 

parking.

Construction of the temporary barge offloading pier, as well as unloading operations at the pier 

during construction of the Project, may result in limits to the use of the immediate area for recreation. 

DCP estimates that 42 barge deliveries would be made to the pier over the course of 18 months, which 

would equate to an average of about 2.3 barge deliveries per month. Following construction, the pier 

would be removed from the river and Offsite Area B would be restored to its prior use. In addition, no 

river dredging is proposed for this Project. Based on the relatively small scale of construction and limited 

incidence and duration of use, we conclude that construction and use of the temporary pier at Offsite Area 

B would result in only temporary and minor impacts on recreational uses on the Patuxent River.

Pleasant Valley Compressor Station, Suction/Discharge Pipelines, and M&R Facility

The Pleasant Valley Compressor Station, Suction/Discharge Pipelines, and M&R Facility are

within the 1,680-acre Elklick Diabase Flatwoods Conservation Site, and a portion of the Suction/

Discharge Pipelines and M&R Facility workspaces would abut the 226-acre Elklick Woodlands Natural 

Area Preserve. As discussed in section 2.3.1, the Elklick Diabase Flatwoods Conservation Site is 

designated by the VDCR due to the presence of rare plant communities in the area. However, none of the 

plant species of concern were identified in the Project work areas. In addition, the VDCR has concluded 
80

that there would be no impacts on sensitive forested areas on the compressor station property (VDCR, 

2013) (see section 2.3.1). 

The Elklick Woodlands Natural Area Preserve is managed by the Fairfax County Park Authority

and protected by a conservation easement held by the Northern Virginia Conservation Trust. The Fairfax 

County Park Authority has a management objective to “establish communication with Dominion land 

managers to establish areas of common interest and to coordinate, plan, and monitor land management 

practices on the [existing pipeline] right-of-way to benefit both Elklick Woodlands and the right-of-way”

(Fairfax County Park Authority, 2009). In a letter dated August 20, 2013, Fairfax County confirmed that 

the proposed Project would take place within DCP’s existing easements and not impact the conservation 

easement and provided details on permit requirements that would be implemented by the county for the 

proposed activities. Further, in response to the county, DCP has stated it would obtain the appropriate 

permits to complete the work. 

The Elklick Woodlands Natural Area Preserve has no public access facilities; thus, recreational 

use would be limited in proximity to the Pleasant Valley Compressor Station and associated facilities. As 

noted above, the Elklick Woodlands Natural Area Preserve abuts a portion of the proposed Pleasant 

Valley Suction/Discharge Pipelines and M&R Facility workspaces, but is separated from the Pleasant 

Valley Compressor Station itself by at least 500 feet of dense forest. For recreational users of the Elklick 

Woodlands Natural Area Preserve, this forest buffer would largely eliminate visual impacts and reduce 

noise impacts associated with construction and operation at the compressor station itself. Operating noise 

impacts would be further reduced by the sound barrier wall that DCP would install along the eastern 

boundary of the compressor station. Recreational users that approach the Pleasant Valley Suction/

Discharge Pipelines and M&R Facility could experience increased noise and visual impacts during active 

construction, but these impacts would be limited to the time of construction. Operation of the Pleasant 

Valley Suction/Discharge Pipelines and M&R Facility would be unchanged from current pipeline and 

M&R operations. Based on the above discussion, construction and operation of the Pleasant Valley 

Compressor Station, Suction/Discharge Pipelines, and M&R Facility would not result in significant noise 

or visual impacts on recreational users in the Elklick Woodlands Natural Area Preserve. Visual resources 

are discussed further in section 2.4.5.

The properties located directly south of the Pleasant Valley Compressor Station, Suction/

Discharge Pipelines, and M&R Facility are zoned as a residential conservation district. This zoning type 

is established to protect water courses, stream valleys, marshes, forest cover in watersheds, aquifer 

recharge areas, rare ecological areas, and areas of natural scenic vistas; to minimize impervious surface 

and to protect the quality of water in public water supply watersheds; to promote open, rural areas for the 

growing of crops, pasturage, horticulture, dairying, floriculture, the raising of poultry and livestock, and 

for low density residential uses (Fairfax County Zoning Ordinance Article 3-C01). The Pleasant Valley 

Compressor Station and the surrounding properties are located within water supply protection areas, 

which promote public health, safety, and welfare through the protection of public water supplies from 

water pollution. Because DCP would develop and implement site-specific E&SCPs and SMPs to 

minimize impacts on water resources (see section 2.2.1), we conclude that construction and operation of 

the Pleasant Valley Compressor Station, Suction/Discharge Pipelines, and M&R Facility would not result 

in impacts on water supply protection areas.

Loudoun M&R Facility and Leesburg Compressor Station Contractor Staging Area

Construction and operation at the Loudoun M&R Facility would take place within DCP’s existing 

property boundaries. The closest public land to the Loudoun M&R Facility is the Banshee Reeks Nature 

Preserve, which is approximately 0.5 mile northwest of the facility. As such, the proposed Project would 

not affect recreational activities at the Banshee Reeks Nature Preserve.
81

The Greene Mill Preserve residential development is located approximately 0.25 mile northeast 

from the Loudoun M&R Facility. Construction and operation of the Loudoun M&R Facility would take 

place within DCP’s existing property boundaries and would represent a minor alteration of DCP’s 

existing facilities. As such, the proposed Project would not significantly affect the Greene Mill Preserve 

development. 

The existing Leesburg Compressor Station would be used as a contractor staging area during 

construction of the Project. The closest public land to the Leesburg Compressor Station Contractor 

Staging Area is the Banshee Reeks Nature Preserve, which is approximately 0.5 mile northwest of the 

station. As such, we conclude recreational activities in the area would not be affected by the temporary 

use of the Leesburg Compressor Station Contractor Staging Area. 

2.4.3 Existing Residences and Planned Future Developments

Liquefaction Facilities

Approximately 145 residences are located within 0.5 mile of the Fenced Area. The nearest 

residences to the Liquefaction Facilities are located across Cove Point Road approximately 300 feet south 

of the Fenced Area. In addition, a 37-lot residential development, referred to as Hidden Treasure, is being 

developed south of Cove Point Road, south of the Fenced Area of the LNG Terminal. The majority of the 

lots in Hidden Treasure have been sold and developed; however, some remain unsold, including at least 

one within 0.25 mile of the LNG Terminal. 

Temporary impacts on nearby residential areas could include inconvenience caused by noise and 

dust generated from construction equipment and traffic congestion associated with the transport of 

equipment, materials, and construction workers between the LNG Terminal and Offsite Areas A and B.

Impacts from noise and dust during construction would diminish with distance from these areas and 

would be limited to the time of construction which would typically occur during daylight hours (7:00 a.m. 

to 6:00 p.m.), 6 days per week.

As discussed in section 2.5.4, DCP would implement measures at nearby traffic intersections to 

reduce potential impacts on traffic and public safety during Project construction. By implementing these 

measures, traffic flow impacts that do arise would be minor and temporary. In addition, the transport of 

large equipment would occur at night to minimize potential impacts on local traffic. The vehicles used to 

transport this equipment would have noise levels consistent with other large trucks that travel on 

Maryland Route 2/4. 

Potential impacts on nearby residences during operation of the Liquefaction Facilities would be 

mitigated, in part, by the installation of a sound barrier around the facility to shield surrounding areas 

from operation sights and sounds. DCP would install the sound barrier on the western and southern sides 

of the Fenced Area behind the existing tree/vegetative buffer. The sound barrier would be approximately 

3,500 feet long and 60 feet high and would be made of sound absorbing panels with a non-corroding 

exterior shell material. The sound barrier’s panels would be filled with acoustical material to absorb the 

sounds from the Liquefaction Facilities. In order to minimize the visual impacts from the sound barrier 

on nearby residences and recreational users, DCP would select a color for the sound barrier that blends in 

with the natural vegetation. DCP is consulting with the Calvert County Department of Planning and 

Zoning regarding the materials and placement for the sound barrier. We conclude that the installation of 

DCP’s proposed sound barrier would adequately reduce potential impacts on nearby residences from the 

addition of the proposed Liquefaction Facilities to DCP’s existing LNG Terminal. Section 2.4.5 includes 

additional discussion of visual impacts associated with the sound barrier. Section 2.7.2 includes 

additional discussion of impacts from noise.
82

Offsite Area A

The nearest residence to Offsite Area A is approximately 150 feet west from the property 

boundary. DCP’s clearing and grading plan for Offsite Area A would provide for at least 150 feet of 

mature forest to remain between the residence and the temporary operating area of Offsite Area A and, as 

noted above, construction activities would be limited to daylight hours. Therefore, no significant impacts 

on nearby residences would occur during use of Offsite Area A. 

The Patuxent Business Park is a planned commercial development located approximately 230 feet 

from Offsite Area A. Some infrastructure (e.g., roads and stormwater management facilities) has been 

developed within the Patuxent Business Park site, but no buildings are currently located on the property. 

Use of Offsite Area A during construction would not preclude the planned nearby development, and no 

significant impacts on the development would occur. 

Offsite Area B

The nearest residence to Offsite Area B is that of the current property owner, approximately 160 

feet east of the site. No residences are located within 50 feet of the property and no nearby developments 

have been identified. DCP would lease the property, which includes only the mowed and maintained 

portion of the existing landowner’s property. Potential impacts could include dust and noise during 

construction from the earthwork required to prepare the site, and associated with the offloading and 

transport of equipment to the Liquefaction Facilities site. However, these impacts would be temporary 

during the period of construction. Therefore, we conclude that use of Offsite Area B would not result in 

significant impacts on nearby residences. 

Pleasant Valley Compressor Station, Suction/Discharge Pipelines, and M&R Facility

The Pleasant Valley Compressor Station, Suction/Discharge Pipelines, and M&R Facility are 

located in a sparsely populated area of Fairfax County, Virginia. No existing or planned residences are 

located within 0.25 mile of the existing compressor station site. No significant impacts on residences are 

expected during construction or operation of the proposed facilities. To further reduce potential impacts 

on the adjacent areas, DCP would install a sound barrier along the eastern fenceline of the Pleasant Valley 

Compressor Station behind the existing tree/vegetative buffer. The sound barrier would be approximately 

800 feet long and 20 feet high and made of sound absorbing panels with a non-corroding exterior shell 

material. To minimize the visual impacts from the sound barrier on adjacent areas, DCP would select a 

color for the sound barrier that blends in with the natural vegetation. Visual resources are discussed 

further in section 2.4.5.

Loudoun M&R Facility and Leesburg Compressor Station Contractor Staging Area

The nearest residence to the Loudoun M&R Facility is 65 feet west along State Route 860. In 

addition, a nearby residential subdivision, Greene Mill Preserve, is being developed within 0.25 mile of 

the Loudoun M&R Facility. The nearest Greene Mill Preserve residence is located approximately 1,620 

feet to the northeast of the site.

During the scoping process we received numerous comments from the residents of Greene Mill 

Preserve expressing concern with the potential for DCP to install additional compression at the Loudoun 

Compressor Station. Although customer receipt points for the natural gas capacity on the Cove Point 

Pipeline to be delivered to the LNG Terminal have not been finalized, DCP stated that the Project would 

not include increased compression at the Loudoun Compressor Station. Rather, the proposed Project 

would consist of installation of miscellaneous piping and meter upgrades at the Loudoun M&R Facility. 
83

Construction of the Loudoun M&R Facility may result in minor, short-term impacts on the transportation 

network in the Project area as existing public roadways would be used to transport construction 

equipment and materials, and workers to the site. However, due to the short-term nature of the 

construction, traffic flow impacts would be minor and temporary. Additional discussion of traffic impacts 

is provided in section 2.5.4. Because the modifications at the Loudoun M&R Facility would be relatively 

minor and take place within DCP’s existing industrial facility, no additional impacts on nearby residences 

or developments would occur during operation of the Project.

The nearest residence to the Leesburg Compressor Station Contractor Staging Area is located 70 

feet away. No planned developments have been identified within 0.25 mile of the site. Activities at the 

site would occur within the existing industrial property boundary and would be consistent with the current 

activities at the Leesburg Compressor Station. As such, we conclude that the temporary use of the 

Leesburg Compressor Station would not result in significant impacts on nearby residences or 

developments.

2.4.4 Coastal Zone Management

The Project facilities in Maryland and the Pleasant Valley Compressor Station, Suction/Discharge 

Pipelines, and M&R Facility in Virginia would be located within a coastal zone management area. The 

Federal Coastal Zone Consistency requirements are overseen by the MDE in Maryland and by the VDEQ 

in Virginia. DCP submitted its Coastal Use Permit applications for Coastal Zone Consistency 

Determinations to the MDE and VDEQ on April 1, 2013. DCP received its coastal zone consistency 

determination from the VDEQ on October 3, 2013, and anticipates a response from the MDE in late May

2014. Therefore, we recommend that:

 Prior to construction, DCP should file documentation of concurrence from MDE 

that the Liquefaction Facilities are consistent with the Maryland Coastal Zone 

Management Program. 

2.4.5 Visual Resources

Liquefaction Facilities

The proposed Liquefaction Facilities would be constructed entirely within the existing Fenced 

Area, an existing 130-acre industrial area within DCP’s 1,017-acre LNG Terminal property. Construction 

of the Liquefaction Facilities would result in visual impacts associated with site and tree clearing within 

the existing Fenced Area. Potential visual impacts associated with operation of the Liquefaction Facilities 

would occur from the increase of industrial facilities and lighting within the site, as well as the operation 

of the two ground flares. 

Visually sensitive areas near the Liquefaction Facilities include historic landmarks (i.e., 

Middleham Chapel and Cove Point Lighthouse), residences, Cove Point Road, Cove Point Park, and the 

Governor Thomas Johnson Bridge over the Patuxent River. Views of the existing facility are largely 

screened from these areas by existing forests and topography, except for the crest of the bridge, which is 

approximately 5.2 miles from the site. As such, we conclude that construction of the proposed Project

would not result in significant visual impacts on nearby areas.

The surrounding tree cover would prevent most views of the Fenced Area except along Cove 

Point Road near to the LNG Terminal. However, the new Liquefaction Facilities would be consistent 

with the industrial nature of the existing facility and, therefore, would not represent a significant change 

in the viewshed during operation. In addition, DCP would install a sound barrier along the western and 
84

southern fence lines of the Liquefaction Facilities that would shield the surrounding areas from noise 

impacts associated with the operation of the Project, including ground flares (see section 2.4.3). The 

sound barrier would also act as a visual barrier to the facilities from Cove Point Road.

We received comments regarding potential visual impacts of the sound barrier from Cove Point 

Road. The sound barrier would generally be screened from views along Cove Point Road by the existing 

vegetation between the road and the edge of the Fenced Area where the barrier would be installed. 

However, during seasons of minimum foliage on the trees, the sound barrier may be visible from the road. 

To minimize the visual impact of the sound barrier, DCP would select a color that blends in with the 

natural vegetation. Whereas the sound barrier may be visible from Cove Point Road at certain times of 

the year, we have determined it would reduce the overall visual impact of the Project by screening views 

of the facilities from the road. We also find that the noise reduction benefit of the sound barrier on the 

surrounding area during operation would outweigh the potential seasonal visual impacts associated with 

the sound barrier. In addition, as part of their final recommended license conditions for the Maryland 

CPCN, the Reviewing State Agencies recommended that DCP develop a landscaping plan that addresses 

the visibility of the proposed sound barrier from Cove Point Road near the LNG Terminal site entrance, 

including photo simulations of the site entrance before and after new landscaping is in place, and during 

seasons of peak and minimum foliage. We conclude that preparation of the landscaping plan would 

address concerns regarding the visual impacts of the sound barrier from Cove Point Road. However, to 

document that the landscaping plan required by the Maryland CPCN has been completed as described 

above, we recommend that:

 Prior to construction, DCP should file the final landscaping plan, approved by the 

MDNR, for the LNG Terminal sound barrier.

Additional nighttime lighting would be installed in conjunction with operation of the Liquefaction 

Facilities. DCP would minimize nighttime visual impacts by employing a lighting design that limits the 

potential for light pollution outside of the Fenced Area. Lighting would typically be positioned 

downward toward the work areas, and utilized only where necessary for operations, safety, and security. 

Dusk to dawn lighting would be utilized where possible to eliminate use of continuous yard lighting. As 

part of their recommended license conditions for the Maryland CPCN, the Reviewing State Agencies

recommended that DCP develop a lighting distribution plan in coordination with the PPRP and the 

Calvert County Department of Planning and Zoning for operation that would reduce intrusive night 

lighting and avoid undue glare onto adjoining properties. We agree that DCP’s lighting design, with 

input from the PPRP and the Calvert County Department of Planning and Zoning, would reduce potential 

visual impacts on the surrounding areas. However, to document that the lighting distribution plan has 

been completed as described above, we recommend that:

 Prior to construction, DCP should file the final lighting distribution plan for the 

Liquefaction Facilities, approved by the MDNR, with the Secretary for review and 

written approval by the Director of OEP.

Offsite Area A

Visual impacts associated with the use of Offsite Area A during construction would include 

removal of existing forest vegetation, as well as earthwork and grading associated with site preparation. 

No visually sensitive areas, including scenic roads or rivers, are in the vicinity of Offsite Area A. DCP 

would maintain a 100-foot buffer of trees along the eastern boundary of the site to screen the site from 

Maryland Route 2/4. In addition, use of the site would be temporary and limited to the period of 

construction. As such, we find that the use of Offsite Area A would not result in significant visual 

impacts.
85

Offsite Area B

Visual impacts associated with the use of Offsite Area B during construction would include 

removal of existing vegetation, as well as earthwork and grading. Offsite Area B is located within an 

undeveloped open area along the Patuxent River. No scenic or unique viewsheds are associated with the 

site. Temporary impacts on visual resources would occur during the construction phase from the 

Governor Thomas Johnson Bridge and from users of the Patuxent River and Calvert Marine Museum. 

Construction of the temporary barge offloading pier at the site would be consistent with other shoreline 

piers and marinas in the area. Use of the site for equipment unloading and contractor parking would 

result in minor visual impacts on the surrounding area, and would be temporary and limited to the period 

of construction. As such, we find that the use of Offsite Area B would not result in significant visual 

impacts.

Pleasant Valley Compressor Station, Suction/Discharge Pipelines, and M&R Facility

The proposed additional compression at the Pleasant Valley Compressor Station, construction of 

the Pleasant Valley Suction/Discharge Pipelines, and modifications to the Pleasant Valley M&R Facility

would occur entirely within DCP’s existing industrial facilities or maintained pipeline right-of-way. As 

such, no permanent changes to the current visual aspects of the surrounding area would be expected. 

DCP would maintain existing trees and woodlands along the property boundaries and would add 

additional vegetative screening where necessary when developing the station facilities to help conceal the 

station facilities from public view at locations that are directly adjacent to the site. In addition, DCP 

would install a visual and sound barrier along the eastern fenceline of the compressor station site to shield 

the surrounding area from visual and noise impacts during operation of the Project (see section 2.4.3). 

DCP would minimize nighttime visual impacts by employing a lighting design that would limit

the potential for light pollution outside of fenced areas. Lighting would typically be positioned 

downward toward the work areas, and utilized only where necessary for operations and safety. Dusk to 

dawn lighting would be utilized where possible to eliminate use of continuous yard lighting. 

With implementation of these measures combined with the distance of the views, we conclude 

that operation of the facilities associated with the Pleasant Valley Compressor Station would not result in 

significant visual impacts.

Loudoun M&R Facility and Leesburg Compressor Station Contractor Staging Area

No visually sensitive areas, including scenic roads or rivers, have been identified at the Loudoun 

M&R Facility. The proposed modifications would occur within the existing Loudoun M&R Facility, 

which is located on existing industrial parcels. No additional lighting would be added at the Loudoun 

M&R Facility. The modifications would be consistent with the current visual character of the M&R 

Facility; therefore, no significant visual impacts would be anticipated. 

The Leesburg Compressor Station Contractor Staging Area would be used for temporary 

construction laydown, parking, and staging during the period of construction. Activities at the site would 

occur within the existing industrial property boundary and would be consistent with the current views at 

the Leesburg Compressor Station. As such, we find that the temporary use of the Leesburg Compressor 

Station would not result in significant visual impacts. 
86

2.5 SOCIOECONOMICS

Construction and operation of the Project could impact socioeconomic resources in the area. 

Some of these potential effects are related to the number of construction workers that would work on the 

Project and their impact on population, public services, and temporary housing during construction. 

Other potential effects are related to construction, such as increased traffic or disruption of normal traffic 

patterns. Other effects associated with the Project include increased property tax revenue, increased job 

opportunities, and increased income associated with local construction employment. The primary 

potential socioeconomic effects of the Project would be from construction and operation of the proposed 

Liquefaction Facilities in Calvert County, Maryland and the activities associated with the Pleasant Valley 

Compressor Station in Fairfax County, Virginia. The proposed modifications at the Loudoun M&R 

Facility and use of the Leesburg Compressor Station Contractor Staging Area in Loudoun County, 

Virginia, would occur within existing developed facilities and would represent relatively minor activities. 

Construction and operation of these facilities would not have a significant socioeconomic impact and, 

therefore, they are not discussed further in this section. 

We received a number of comments in support of the Project based primarily on socioeconomic 

impacts, including increased employment, increased tax revenue, improved U.S. trade balance, and 

improved access to market for domestically produced natural gas. Comments in support of the Project 

were filed by U.S. Senator Cardin (D-MD), U.S. Congressmen Hoyer (D-MD) and Harris (R-MD), three 

members of the Maryland House of Delegates, one member of the Maryland Senate, the Calvert County 

Board of Commissioners, the St. Mary’s County Board of Commissioners, the Calvert County Chamber 

of Commerce, the Calvert County Tourism Advisory Commission, the Tri-County Council of Southern 

Maryland, Maryland Conservation Council, and Calvert Cliffs Nuclear Power Plant, along with various 

trade unions and groups.

The Sierra Club and Cove of Calvert Homeowners Association raised concern that construction 

and operation of the Liquefaction Facilities could result in adverse socioeconomic impacts on surrounding 

communities and homeowners, including reduced property values. Homeowners near the Loudoun 

Compressor Station also voiced concern that increased compression originally proposed to be installed at 

the station could adversely impact property values and other resources. However, DCP’s final proposal 

includes only minor modifications to the existing Loudoun M&R Facility and does not include increased 

compression at the Loudoun Compressor Station.

2.5.1 Population, Economy, and Employment

Table 2.5.1-1 provides a summary of selected demographic and socioeconomic conditions for 

affected communities in the Project area.

Construction of the Project would temporarily increase the population in the general Project area. 

Construction of the Liquefaction Facilities would occur over a 3-year period, between March 2014 and 

March 2017. The construction workforce would likely come from the general Project region, but may not 

be local due to the specialized construction experience required. Construction of the Liquefaction 

Facilities would require an average of 610 workers per quarter over the 3-year period of construction, 

with a peak workforce of between 1,045 and 1,441 workers per quarter between the third quarter 2015 

and the second quarter 2016. With the export service that the Liquefaction Facilities would provide, 

operation at the LNG Terminal would require a total of about 200 employees, an approximate increase of 

93 when compared to the current operational workforce of 107. The total population change during 

construction and operation would equal the total number of non-local workers plus any family members 

accompanying them. Based on the population of Calvert County, the additional people that would 

relocate to the area during construction of the Liquefaction Facilities would represent a temporary 
87

population increase of about 0.7 percent based on the average of 610 workers per quarter and about 1.6 

percent based on the highest peak of 1,441 workers (in the third quarter 2015), assuming all temporary 

construction workers relocate to the Project area. Operation of the Liquefaction Facilities would result in 

a population increase of about 0.1 percent based on the addition of 93 new permanent employees. As 

such, the temporary and permanent workers associated with construction and operation of the 

Liquefaction Facilities would not result in a significant change in the population. 

TABLE 2.5.1-1

Existing Economic Conditions in the Project Area

County/State

Population 

(2010) a

Population 

Density 

(persons/sq. 

mile) (2010) b

Per Capita 

Income (2007-

2011) c

Civilian 

Workforce 

(2007-2011) c

Unemployment 

Rate (percent) 

(2007-2011) c

Top Three 

Industries 

(2007-2011) 

c, d

Maryland 5,773,552 594.8 $35,751 3,137,066 7.3 E, Pr, Pu

Calvert County 88,737 416.3 $37,321 47,794 5.3 E, Pu, Pr

Virginia 8,001,024 202.6 $33,040 4,109,104 6.5 E, Pr, R

Fairfax County 1,081,726 2,766.8 $50,145 604,317 4.7 Pr, E, Pu

Loudoun County 312,311 605.8 $46,493 168,756 4.3 Pr, E, R

____________________

a Source: U.S. Census Bureau, 2010.

b Source: U.S. Census Bureau, 2013.

c Source: U.S. Census Bureau, 2007-2011a.

d E = Educational services, and health care and social assistance

Pr = Professional, scientific, and management, and administrative and waste management services

Pu = Public administration

R = Retail trade 

A short-term decrease in the unemployment rate could occur as a result of hiring local workers 

for construction and increased demands on the local economy in and near Calvert County. As noted 

earlier, the estimated 93 additional employees required to operate the LNG Terminal upon completion of 

the Liquefaction Facilities would have a positive, permanent impact on the unemployment rate and 

economy of the area. 

Construction activities at the Pleasant Valley Compressor Station, Suction/Discharge Pipelines, 

and M&R Facility would occur between January 2016 and December 2017. Construction would require 

an average of 98 workers per quarter over the 2-year period of construction, with a peak workforce of 150 

workers per quarter between the third quarter 2015 and the second quarter 2016. A decrease in the 

unemployment rate could result from the hiring of local workers for construction and increased demands 

on the local economy. Given the relatively short construction period and in our experience, most nonlocal workers would not be accompanied by their families. Based on the population of Fairfax County, 

the additional people that might temporarily relocate to the area would represent a temporary population 

increase of less than 0.1 percent based on the peak workforce of 150 workers, assuming all temporary 

construction workers relocate to the Project area. As such, the temporary workers associated with 

construction of the Pleasant Valley Compressor Station and associated facilities would not result in a 

significant change in the population. Operation of the new facilities in association with the Pleasant 

Valley Compressor Station would not require any additional permanent workers and, thus, no long term 

or permanent impacts on population or employment in Virginia would occur.

Construction of the proposed Project would result in a temporary increase in the local purchase of 

goods and services in the counties and regions affected by the Project. DCP estimates that construction of 

the Liquefaction Facilities (including use of Offsite Areas A and B) would generate about $1.2 billion of 

business sales for companies in Calvert County and approximately $515 million in business sales by other 
88

establishments in the State of Maryland. During operation of the Liquefaction Facilities, DCP estimates 

that annual business sales of $54 million in Calvert County and $12 million in the State of Maryland 

would occur between 2017 and 2040. 

DCP estimates that construction of the Pleasant Valley Compressor Station and associated 

facilities would generate about $148 million of business sales for companies in Fairfax County. 

Operation of the Pleasant Valley facilities would not be expected to have a significant impact on local 

businesses.

2.5.2 Housing

Housing statistics for the counties affected by the Project are presented in table 2.5.2-1.

TABLE 2.5.2-1

Housing Statistics by County in the Project Area

County/State

Owner 

Occupied 

(2007-2011) 

a

Renter 

Occupied 

(2007-2011)

a

Median Monthly 

Housing Costs 

(2007-2011) a

For 

Seasonal 

or 

Occasional 

Use (2010)

b

Vacant 

Housing 

Units 

(2007-

2011) a

Rental 

Vacancy 

Rate 

(2007-

2011) a

Number of 

Hotels/

Motels/

B&Bs c

Number of 

Campgrounds/

RV Parks c

Owner 

Occupied

Renter 

Occupied

Maryland 1,461,708 666,669 2,066 2,178 55,786 240,791 8.1 818 38

Calvert 25,513 4,868 565 575 1,275 3,180 5.5 12 2

Virginia 2,046,845 944,180 1,782 408 80,468 354,873 6.9 1,868 248

Fairfax 273,783 111,787 2,612 725 2,062 20,824 4.8 67 2

Loudoun 78,987 20,774 2,873 749 665 7,795 7.9 63 0

____________________

a Source: U.S. Census Bureau, 2007-2011b. 

b Source: U.S. Census Bureau, 2010. 

c Sources: State of Maryland, 2013; Commonwealth of Virginia, 2013.

Temporary housing availability varies seasonally and geographically within the counties and 

communities near the proposed facilities and is available in the form of daily, weekly, and monthly rentals 

in motels, hotels, and campgrounds. The demand for temporary housing in the Project area is generally 

greatest during the summer months when tourism is at its height. Table 2.5.2-1 also provides the vacant 

housing units and median monthly housing costs along with the number of hotels/motels in the counties 

where Project facilities would be located. Other temporary housing is available in the Project vicinity, 

such as bed and breakfast facilities, apartments, and vacation properties, as well as those in other towns/

cities within commuting distance of the Project. Therefore, the availability of temporary housing is 

substantially greater than presented in table 2.5.2-1.

Construction of the Project could affect the availability of housing in the Project area. The 

Project would likely have a short-term positive impact on the area rental industry through increased 

demand and higher rates of occupancy. The primary impact on local housing would be from the 

relocation of construction workers to the Project area for work on the Liquefaction Facilities, which 

would result in a temporary increase in the local population. The counties within a 25-mile radius of the 

existing LNG Terminal include approximately 1,600 hotel rooms, in addition to the other types of 

housing identified in table 2.5.2-1. However, because construction activities at the Liquefaction Facilities 

would occur over an approximately 3-year period, most workers who relocate to the area would be 

expected to find housing in long-term rental situations, rather than hotels. Therefore, although 

construction activities would occur during peak tourism seasons, we find that the temporary influx of 

workers would not compete with tourists who travel to the area. In the event that rental accommodations 
89

are limited, we expect that the number of hotels, motels, and other accommodations in the region would 

be sufficient for the number of workers on the Project.

2.5.3 Public Services

A wide range of public services and facilities are offered in the counties affected by the Project, 

including hospitals, full-service law enforcement, paid and volunteer fire departments, and schools. The 

number of non-local workers and associated family members anticipated to enter the area would likely be 

small relative to the current populations in the Project area (see table 2.5.1-1). This would result in minor, 

temporary, or no impact on local community facilities and services, such as police, fire, and medical 

services. The counties, cities, and towns in the Project vicinity presently have adequate infrastructure and 

services to meet the needs of the non-local workers and family members.

Short-term impacts on public services could include the need for localized police assistance to 

control traffic flow during construction activities. Also, construction-related injuries could occur as a 

result of accidents or emergencies. In the event of a construction accident, DCP could require police, fire, 

and medical services, depending on the type of emergency. We conclude that the demand for police, fire, 

and medical services would not exceed the existing capabilities in the Project area because these services 

would only be used on an emergency basis. The nearest fire station to the Liquefaction Facilities is 

approximately 1.2 miles away on Little Cove Point Road in Lusby, Maryland. The nearest fire station to 

the Pleasant Valley Compressor Station is approximately 2.7 miles to the east. These emergency services 

are located in reasonable proximity to the Project area. 

We received comments regarding the ability of local emergency providers to handle an incident at 

the LNG Terminal. DCP has established a history of assisting fire departments in areas where its existing 

facilities are located, including at the LNG Terminal. DCP has provided assistance to local emergency 

providers through training and general support, and would continue this practice with the ongoing 

operations at the LNG Terminal and other Project facilities.

2.5.4 Transportation and Traffic

We received comments concerning the volume of LNG ship traffic that would occur during 

Project operation. The LNG ship traffic to the LNG Terminal would vary yearly depending on LNG 

demand. The volume of ship traffic for LNG import has historically varied due primarily to market 

demand, and DCP expects that LNG export activity may also vary depending on demand. However, the 

annual frequency of ship traffic for the Project is estimated to be 85 LNG vessels per year, which would 

not exceed the previously approved ship traffic of up to approximately 200 vessels per year in Dockets 

CP05-130, et al., and DCP would not accept LNG carriers larger than previously authorized in Docket 

CP09-60. After reviewing the Cove Point Liquefaction Project, the USCG Sector Baltimore concurred 

that the Project should not result in an increase in the size and/or frequency of LNG marine traffic beyond 

that envisioned in the current WSA for the LNG Terminal, and that the WSA and LOR are adequate for 

the service associated with the Project. We agree.

We also received comments about the potential effect of LNG export on ship traffic to the Port of 

Baltimore and the federal navigation channels in the Chesapeake Bay. DCP’s proposed export of LNG 

would not affect the federal navigation channels within the Chesapeake Bay or the route that ships 

currently use to travel to DCP’s existing offshore pier because the volume and size of currently authorized 

LNG ship traffic would not change. Similarly, the Project would not affect existing ship traffic to and 

from the Port of Baltimore. If the maximum authorized ship traffic to the LNG Terminal occurs, it would 

only account for approximately 1.6 percent of commercial ship traffic transiting past the LNG Terminal 

annually. 
90

DCP estimates that 42 barge deliveries would be made to the temporary offloading pier at Offsite 

Area B over the course of 18 months, which, on average, equates about 2.3 barge arrival per month. 

Based on the relatively small scale of construction and limited incidence and duration of use, we conclude

that construction and use of Offsite Area B would result in only temporary and minor impacts on shipping 

in the Chesapeake Bay and Patuxent River.

The local road and highway system in the vicinity of the Liquefaction Facilities and Pleasant 

Valley Compressor Station consists of interstate highways, U.S. highways, state highways, secondary 

state highways, county roads, and private roads. Most public roads in the vicinity of the Project are 

paved. Construction of the Project could result in minor, short-term impacts along some roads and 

highways due to the movement and delivery of equipment, materials, and workers. Maps included in 

section 1.0 depict the roads that DCP would use to access the construction right-of-way. 

We received comments regarding potential impacts on traffic using Cove Point Road, which 

provides the only access to the LNG Terminal, and through the surrounding neighborhood. The primary 

increase in traffic associated with construction at the LNG Terminal would be due to construction 

workers traveling to and from the work site. However, most construction workers would park at Offsite 

Area A and would be transported to the LNG Terminal site by bus or shuttle, thereby reducing the amount 

of traffic on Cove Point Road. In addition, transport of the large equipment from Offsite Area A would 

occur at night to minimize potential impacts on traffic. The vehicles used to transport this equipment 

would have noise levels consistent with other large trucks that travel on Maryland Route 2/4. 

We also received comments regarding the impacts of Project-related traffic from Offsite Area B 

to the LNG Terminal or Offsite Area A. According to DCP, approximately 150 truck loads would 

originate from Offsite Area B during the course of construction of the Liquefaction Facilities. DCP 

would transport large equipment at night to minimize potential impacts on traffic by the slow moving 

vehicles. These vehicle movements would likely require support in the form of an escort. Further, the 

movement of large equipment and materials would be subject to local highway use permits. DCP has 

agreed to implement the Reviewing State Agencies’ recommended license conditions for the CPCN 

related to traffic, including requirements that DCP consult with the MSHA and Calvert County 

Department of Public Works regarding potential impacts on traffic and the development of appropriate 

measures to reduce impacts. Therefore, we conclude that DCP’s use of local roads during construction to 

transport equipment and materials from Offsite Area B would result in only a temporary and short-term 

impact on local traffic.

DCP completed a traffic impact analysis with recommendations that satisfy the Maryland State 

Highway Administration Guidelines and Adequate Public Facilities Ordinance requirements of Calvert 

County. The recommendations include installation of a traffic signal at the intersection of Maryland 

Route 2/4 and Maryland Route 497 (Cove Point Road). The traffic impact analysis also recommends the 

construction of a 200-foot right turn lane with a 150-foot taper along eastbound Maryland Route 497 at 

Little Cove Point Road. DCP’s Traffic Impact Analysis has been approved by the State Highway 

Administration and Calvert County, and shows that the intersections that would be affected during 

construction activities at the Liquefaction Facilities (with the proposed improvements) would be sufficient 

to carry the proposed construction traffic. DCP’s implementation of the recommended roadway 

improvements would reduce potential impacts on traffic in the vicinity of the LNG Terminal during 

construction of the Liquefaction Facilities. In addition, DCP’s continued consultations with the MSHA 

and Calvert County related to the Reviewing State Agencies’ recommended license conditions for the 

CPCN would result in additional measures to reduce potential traffic impacts. 
91

2.5.5 Property Values

The majority of comments received regarding property values were related to the potential 

addition of compression at the Loudoun Compressor Station. However, as noted in section 2.5, DCP now 

proposes to construct only minor modifications at the Loudoun M&R Facility, none of which would 

include additional compression. We also received one comment from the Cove of Calvert Homeowners 

Association, located near the proposed Liquefaction Facilities, regarding potential impacts on property 

values in the area resulting from the additional operational activities at the LNG Terminal.

DCP’s proposed Liquefaction Facilities would be located entirely within the Fenced Area of the 

existing LNG Terminal, which is an operating industrial facility. As discussed in section 2.4.3, the 

existing LNG Terminal is partially screened from the nearest residences across Cove Point Road and, in 

addition, DCP would install a 60-foot-tall sound barrier along the southern and western edges of the 

Fenced Area to shield surrounding, occupied areas from operation sights and sounds. The proposed 

sound barrier would be painted an appropriate color to blend in with the surrounding vegetation, and 

would be further shielded from adjacent views by the existing forested area around the LNG Terminal. 

Furthermore, DCP’s LNG Terminal has operated in southern Calvert County for more than 30 years. 

Over that time the county’s population has grown by more than 250 percent. Of 377 residential structures 

within 1 mile of the DCP facility (as of 2011), 323 were built after the facility commenced operations in 

1978 (PPRP, 2014). This suggests that housing demand has not been significantly affected by proximity 

to DCP. Because the nearest residences to the Liquefaction Facilities are already near to an in-use 

industrial facility, and DCP would implement various measures to shield the new facilities from adjacent 

areas, we conclude the proposed Liquefaction Facilities would not result in a significant impact on nearby 

property values.

As discussed in section 2.4.3, construction activities at Offsite Areas A and B are not expected to 

result in significant impacts on nearby residences. The nearest resident to Offsite Area A is 

approximately 150 feet west from the property boundary and the nearest resident to Offsite Area B is that 

of the current property owner, approximately 160 feet east of the site. Construction activities at the 

offsite areas would be temporary, during the period of construction. Following construction, DCP would 

donate the 100-acre Offsite Area A parcel to Calvert County and restore the site in accordance with the 

wishes of the landowner. Offsite Area B would be restored and allowed to revert to its previous use, and 

the temporary pier would be removed. Therefore, we conclude use of Offsite Areas A and B would not 

significantly impact nearby property values.

Similar to the proposed Liquefaction Facilities, the proposed modifications in association with the 

Pleasant Valley Compressor Station would take place within DCP’s existing in-use compressor station 

site and maintained pipeline right-of-way. Operation of the Project would be consistent with current use 

at the site. Although no existing residences are located within 0.25 mile of the Pleasant Valley 

Compressor Station, DCP would install a 20-foot-tall sound barrier along the eastern fence line of the site 

behind the existing tree/vegetative buffer. The proposed sound barrier would be painted an appropriate 

color to blend in with the surrounding vegetation. Because few residences are located near the Pleasant 

Valley Compressor Station, and with the installation of the proposed sound barrier, we conclude that 

operation of the Pleasant Valley Compressor Station and associated facilities would not result in a

significant impact on nearby property values.

2.5.6 Tax Revenues

As noted in section 2.5, we received multiple comments regarding the potential benefits of 

construction and operation of the Liquefaction Facilities on the local economy, including increased tax 

revenues for Calvert County. Conversely, we received comments that the Project would not result in 
92

significant benefits to the local economy, and that the proposed export of LNG could result in adverse 

economic impacts throughout the United States, including increased natural gas prices. As discussed in 

section 1.5.1, the DOE-FE determines whether the export of natural gas is not inconsistent with the public 

interest and considers economic and other factors in making its decision on whether to authorize proposed 

exports. For the Project, DOE-FE issued Order No. 3019 on October 7, 2011, authorizing DCP to export 

LNG to FTA nations in accordance with section 3(c) of the NGA as amended by section 201 of the 

Energy Policy Act of 1992. On September 11, 2013, DOE-FE issued Order No. 3331 conditionally 

authorizing DCP to export LNG to non-FTA nations in accordance with section 3(a) of the NGA as 

amended by section 201 of the Energy Policy Act of 1992.

Construction of the Liquefaction Facilities and use of Offsite Areas A and B would generate a 

total of approximately $11.6 million in Calvert County income taxes during the period of construction 

between 2014 and 2017, and a total of $4.3 million in Calvert County income taxes during operations 

(between 2017 and 2040). In addition, the State of Maryland would collect income and sales taxes during 

construction and operation of the Project, including estimated totals of $24.3 million in income taxes and 

$12.4 million in sales taxes during construction (between 2014 and 2017), and totals of $8.6 million in 

income taxes and $4.4 million in sales taxes during operations (between 2017 and 2040). 

In addition to income and sales taxes generated from construction and operation of the Project, 

the additional Liquefaction Facilities constructed at the LNG Terminal would be subject to additional 

property taxes for Calvert County, estimated to be approximately $40 million per year for the life of the 

Project.

Construction and operation of the new facilities associated with the Pleasant Valley Compressor 

Station would result in additional property taxes for Fairfax County, Virginia. DCP’s investment in its 

existing facilities is expected to result in an annual property tax payment to the county of $746,000.

2.5.7 Environmental Justice

An environmental justice analysis is conducted in accordance with Executive Order 12898, 

“Federal Actions to Address Environmental Justice in Minority Populations and Low Income 

Populations” to consider disproportionately high and adverse impacts on minority or low-income 

populations in the surrounding community resulting from programs, policies, or activities of federal 

agencies. Issues considered include human health or environmental hazards, the natural or physical 

environment, and associated social, economic, and cultural factors. 

All of the proposed operating facilities would be constructed within DCP’s existing, industrial 

properties. No significant adverse environmental impacts inside or outside of these properties would be 

anticipated. Use of Offsite Areas A and B would be temporary and short-term, and these areas would be 

allowed to revert to previous uses or would be restored in accordance with the landowner’s request. 

Construction and operation of the Project would not disproportionately affect any population group, 

including low-income and minority populations, and no environmental justice issues would occur as a 

result of construction or operation of the Project. In addition, the Project would have positive 

socioeconomic effects on the population in the Project area because it would generate new temporary jobs 

and economic activity in the region, and provide continuing and increased tax payments during its 

operational life.

2.6 CULTURAL RESOURCES

Section 106 of the NHPA, as amended, requires the FERC to take into account the effect of its 

undertakings on properties listed, or eligible for listing, on the NRHP, and to afford the Advisory Council 
93

on Historic Preservation (ACHP) an opportunity to comment. DCP, as a non-federal party, is assisting us 

in meeting our obligations under section 106 and the implementing regulations found in 36 CFR 800.

2.6.1 Cultural Resources Investigations

Maryland

Liquefaction Facilities

Construction and operation of the Liquefaction Facilities would occur within the footprint of 

DCP’s existing fenced area, which was previously surveyed for cultural resources. In a letter dated 

October 1, 2012, the Maryland State Historic Preservation Office (SHPO) indicated that the Terminal 

facility required no further investigation. We agree.

Offsite Area A 

DCP completed a cultural resources survey of Offsite Area A and provided a Phase I report 

(Maymon, Roth, et al., 2013) to the FERC, the SHPO, and the Calvert County Department of Community 

Planning and Building. Two historic archaeological sites (18CV301 and 18CV505) and one isolated find 

were identified during the survey. All three resources were recommended as not eligible for the NRHP. 

In a letter dated April 26, 2013, the SHPO concurred with DCP’s recommendations. 

In a letter dated May 29, 2013, the Calvert County Department of Community Planning and 

Building requested additional testing of site 18CV505. DCP completed Phase II archaeological testing 

and assessed the site as eligible for the NRHP (Evans et al., 2013). Avoidance of the site, including a 50-

foot buffer, was recommended. DCP indicated it would avoid the site using the 50-foot buffer. In a letter 

dated September 5, 2013, the Calvert County Department of Community Planning and Building 

concurred with DCP’s recommendations. In a letter dated November 21, 2013, the SHPO also concurred 

with DCP’s recommendations, and recommended that protective fencing be placed around the buffer area 

during construction. We agree with the SHPO. Therefore, we recommend that:

 Prior to construction, DCP should install protective fencing around the buffer area 

for site 18CV505 at Offsite Area A.

Offsite Area B

DCP completed a cultural resources survey of the terrestrial portion of Offsite Area B and 

provided a Phase I report (Maymon, Roth, et al., 2013) to the FERC and SHPO. No cultural resources 

were identified. In a letter dated April 26, 2013, the SHPO recommended that deep testing be conducted 

if grading along the proposed haul road would exceed 2 feet below ground surface, to determine if intact 

buried archaeological deposits were present. DCP completed deep testing of the haul road area and found 

that the majority of the area had been previously disturbed by cutting and infilling, and it was unlikely 

that significant cultural components remained intact within the area. No further archaeological 

investigations were recommended. DCP submitted its revised Phase I report to the FERC and SHPO. In 

a letter dated November 21, 2013, the SHPO concurred with DCP’s recommendations. We also agree.

DCP completed an underwater archaeological survey where the temporary offloading pier would 

be installed within the Patuxent River and provided the survey report (Schmidt et al., 2013) to the FERC 

and SHPO. Ten targets were recorded; four of these were identified as potential cultural resources and 

one was identified as a hazard. DCP recommended that these five targets be avoided by Project activities. 

In a letter dated April 26, 2013, the MHT concurred with the recommendations and also requested that 
94

two additional targets be avoided. DCP subsequently modified the pier alignment to avoid all but two of 

the targets (6 and 8) and conducted additional underwater surveys of these two locations. Based on the 

additional surveys, DCP concluded that these two targets consisted of modern debris and recommended 

no additional work (Schmidt et al., 2013, as revised). DCP’s revised report was submitted to the FERC 

and SHPO, and in a letter dated September 23, 2013, the SHPO concurred with DCP’s recommendations. 

However, the Reviewing State Agencies’ recommended license conditions for Maryland’s CPCN 

included minimum recommended avoidance distances from the five identified targets, and DCP has 

agreed to maintain the recommended distances during construction. We agree with the SHPO.

Virginia

Pleasant Valley Compressor Station, Suction/Discharge Pipelines, and M&R Facility

Portions of the Pleasant Valley Compressor Station and all workspaces associated with the 

Pleasant Valley Suction/Discharge Pipelines and M&R Facility were previously surveyed and no 

additional field work was recommended for these areas. In a letter dated February 21, 2013, the Virginia 

SHPO concurred that no additional archaeological survey was warranted. DCP completed an 

archaeological survey for those portions of the Pleasant Valley Compressor Station not previously 

surveyed. No cultural resources were identified. DCP submitted a Phase I report (Maymon, Williams, et 

al., 2013) to the FERC and SHPO, and in a letter dated May 29, 2013, the SHPO concurred that no 

additional archaeological investigations were warranted. We also agree.

Loudoun M&R Facility and Leesburg Compressor Station

The proposed construction workspaces within the existing Loudoun M&R Facility and Leesburg 

Compressor Station were previously surveyed for cultural resources and none were found. In a letter 

dated February 21, 2013, the SHPO concurred that no additional archaeological survey was warranted. 

We agree with the SHPO.

We received several comments regarding potential cultural resources that may be directly or 

indirectly affected by the Project, including Riticor House, Watson/Old Carolina Road, rock art sites, 

standing architecture, “sacred landscapes on historic trails,” and the Battle of Gilbert’s Corner for the 

Virginia components of the Project, and the Calvert County Marine Museum, and the historic community 

of Solomons for the Maryland components of the Project. The concerns about the potential resources in 

Virginia were made in regard to the originally proposed expansion of the Loudoun Compressor Station. 

The compressor station component has subsequently been withdrawn from the Project. Additionally, the 

Riticor House and Watson/Old Carolina Road were addressed in DCP’s report, and while in the general 

Project vicinity, would not be affected by the Project. No information was provided or found regarding 

rock art sites, standing architecture, “sacred landscapes on historic trails,” or the Battle of Gilbert’s 

Corner, and none of these were identified in the Project area. The Calvert County Marine Museum and 

the historic community of Solomons were also addressed in DCP’s report and would not be impacted by 

the use of Offsite Area B. As discussed above, in letters dated April 26, 2013 and May 29, 2013, the 

Maryland and Virginia SHPOs, respectively, concurred with the recommendations in the survey reports

that no additional investigations were required. We agree.

2.6.2 Native American Consultation

We sent our NOI to the Patawomeck Indians of Virginia, the Cedarville Band of Piscataway 

Indians, the Piscataway/Conoy Confederacy and Subtribes, the Piscataway Indian Nation, Inc., the 

Virginia Council on Indians, and the Maryland Commission on Indian Affairs. We sent our Project 

Update Notice to the same tribes and agencies listed above, as well as the Delaware Tribe of Indians, 
95

Delaware Nation, Tuscarora Nation of New York, Shawnee Tribe of Oklahoma, and Eastern Shawnee 

Tribe of Oklahoma. No responses have been received to date.

In addition to our contacts with the tribes, DCP contacted the Delaware Tribe of Indians, 

Delaware Nation, Tuscarora Nation of New York, Shawnee Tribe of Oklahoma, and Eastern Shawnee 

Tribe of Oklahoma in a letter dated January 11, 2013, to introduce the proposed Project and request 

comments regarding the potential for the Project to affect resources of tribal concern. DCP also followedup with letters dated September 30, 2013. The Tuscarora Nation and the Delaware Nation responded and 

indicated that they had no objection to the Project, but requested to be consulted on any findings during 

construction. No further responses have been received from the tribes. 

2.6.3 Unanticipated Discovery Plan

DCP prepared an Unanticipated Discovery Plan to deal with the unanticipated discovery of 

cultural resources and human remains during construction. We requested revisions to the plan. DCP 

provided a revised plan which we find acceptable.

2.6.4 Compliance with the National Historic Preservation Act

The Virginia and Maryland SHPOs and the FERC agree that the Project, with the 

recommendation described above, would not affect historic properties. Therefore, consultation under 

section 106 of the NHPA is complete.

2.7 AIR QUALITY AND NOISE

2.7.1 Air Quality

Air quality in Calvert County, Maryland and Loudoun and Fairfax Counties, Virginia would be 

affected by construction of the Project. During construction of the Project, short-term emissions would be 

generated by operation of equipment, land disturbance, and increased traffic from worker and delivery 

vehicles. Operation of the Liquefaction Facilities and Pleasant Valley Compressor Station would result in 

long-term air emissions. This section of the EA addresses the construction and operating emissions from 

the Project, as well as projected impacts and compliance with regulatory requirements.

Existing Environment

The existing LNG Terminal and Offsite Areas A and B are located in Calvert County, Maryland, 

which has a temperate climate. The area experiences average annual precipitation between 43.0 and 45.9 

inches and monthly average daily temperatures range from 26.8 °F in January to 90.6 °F in July. 

The climates of both Loudoun and Fairfax Counties, Virginia are similar to that of Calvert County. 

Table 2.7.1-1 illustrates the climate parameters of the three counties affected by the proposed Project.
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TABLE 2.7.1-1

Climate Data for Project Area

County Monitor

U.S. 

Cooperative 

Observer 

Program 

(COOP) ID

Approximate 

Distance and 

Direction from 

Project Facility

Average Daily 

Minimum 

Temperature: 

January (°F)

Average Daily 

Maximum 

Temperature: July 

(°F)

Annual 

Precipitation 

(inches)

Calvert

Royal Oak 2 

SSW, MD 187806 26 miles NE 28.4 88.0 45.87

Colonial Beach, 

VA 441913 32 miles SW 26.8 90.6 42.69

Vienna, MD 189140 33 miles NE 27.1 88.7 43.00

Warsaw 2NW, 

VA 448894 35 miles SW 27.8 88.1 43.85

Loudoun

Lincoln, VA 444909 8.5 miles NW 20.8 87.1 43.21

Mount Weather, 

VA 445851 16.5 miles NW 21.0 79.9 43.29

Washington 

Dulles 

International, VA

448903 7 miles SE 21.9 87.4 41.8

Fairfax

Vienna, VA 448737 13 miles NE N/A N/A 45.12

Warrenton 3 SE, 

VA 448888 18.5 miles SW 23.5 84.2 43.36

Washington 

Dulles 

International, VA

448903 7 miles SE 21.9 87.4 41.8

Reagan National 

Airport, VA 448906 25 miles E 27.3 88.3 39.35

Ambient air quality is protected by federal and state regulations. Under the Clean Air Act

(CAA) and its amendments, the EPA has established National Ambient Air Quality Standards (NAAQS)

for carbon monoxide (CO), lead (Pb), nitrogen dioxide (NO2), ozone, particulate matter less than 10 

microns (PM10), particulate matter less than 2.5 microns (PM2.5), and sulfur dioxide (SO2). The NAAQS 

include primary standards, which are designed to protect human health, including the health of sensitive 

subpopulations such as children and those with chronic respiratory problems. The NAAQS also include 

secondary standards designed to protect public welfare, including economic interests, visibility, vegetation, 

animal species, and other concerns not related to human health. 

Individual states may set air quality standards that are at least as stringent as the NAAQS. 

Maryland has adopted all of the NAAQS in Title 26, Subtitle 11, Chapter 4, Section 2 of the Code of 

Maryland Regulations (COMAR 26.11.04.02) In addition, Maryland has defined a State Ambient Air 

Quality Standard for fluorides (COMAR 26.11.04.01). The State Ambient Air Quality Standard for 

fluorides, however, is not applicable to this Project because no emissions of fluorides are expected. Virginia 

has adopted all of the NAAQS in the Title 9, Agency 5, Chapter 30 of the Virginia Administrative Code. 

The NAAQS are summarized in table 2.7.1-2 below.
97

TABLE 2.7.1-2

National Ambient Air Quality Standards

Pollutant Averaging Period

NAAQS

Primary Secondary

SO2

3-hour a None 0.5 ppm (1300 μg/m3)

1-hour b 75 ppb (196 μg/m3)

PM10 24-hour c 150 μg/m3 150 μg/m3

PM2.5

Annual d 12 μg/m3 15 μg/m3

24-hour e 35 μg/m3 35 μg/m3

NO2

Annual Mean f 53 ppb (100 μg/m3) 53 ppb (100 μg/m3)

1-hour g 100 ppb (188 μg/m3) None

CO

8-hour a 9 ppm (10,000 μg/m3) None

1-hour a 35 ppm (40,000 μg/m3) None

Ozone 8-hour h 0.075 ppm 0.075 ppm

Lead Rolling 3-month f 0.15 μg/m3 0.15 μg/m3

____________________

a Not to be exceeded more than once per year.

b Compliance based on 3-year average of 99th percentile of daily maximum 1-hour average at each monitor within an area.

c Not to be exceeded more than once per year on average over 3 years.

d Compliance based on 3-year average of weighted annual mean PM2.5 concentrations at community-oriented monitors.

e Compliance based on 3-year average of 98th percentile of 24-hour concentrations at each population-oriented monitor within 

an area.

f Not to be exceeded.

g Compliance based on 3-year average of the 98th percentile of the daily maximum 1-hour average at each monitor within an 

area.

h Compliance based on 3-year average of fourth-highest daily maximum 8-hour average ozone concentrations measured at 

each monitor within an area.

Ppb = parts per billion

μg/m3 = micrograms per cubic meter

ppm = parts per million

The EPA and state and local agencies have established a network of ambient air quality monitoring 

stations to measure and track the background concentrations of criteria pollutants across the U.S. This data 

is then used by regulatory agencies to compare the air quality of an area to the NAAQS. To characterize the

background air quality in the region surrounding the Project, data were obtained from representative air

quality monitoring stations. These monitoring stations are located near the proposed Liquefaction

Facilities and provide information on regional ambient air quality conditions. A summary of the regional

ambient air quality monitoring data from the 3-year period (2009 to 2011) for the Project area is

presented in table 2.7.1-3.

Air quality control regions (AQCRs) are areas established for air quality planning purposes in 

which implementation plans describe how ambient air quality standards would be achieved and 

maintained. AQCRs were established by the EPA and local agencies, in accordance with section 107 of 

the CAA, as a means to implement the CAA and comply with the NAAQS through State Implementation 

Plans (SIPs). The AQCRs are intra- and interstate regions such as large metropolitan areas where 

improvement of the air quality in one portion of the AQCR requires emission reductions throughout the 

AQCR. Each AQCR, or portion thereof, is designated based on compliance with the NAAQS. AQCR 

designations fall under three main categories as follows: “attainment” (areas in compliance with the 

NAAQS); “nonattainment” (areas not in compliance with the NAAQS); or “unclassifiable.” 

Unclassifiable areas are treated as attainment areas for the purpose of permitting a stationary source of 

pollution. Areas that have been designated nonattainment but have since demonstrated compliance with 

the ambient air quality standard(s) are designated maintenance for that pollutant. Maintenance areas may 
98

be subject to more stringent regulatory requirements to ensure continued attainment of the NAAQS 

pollutant.

The Maryland facilities are also within the Northeast Ozone Transport Region (OTR). The OTR 

(42 USC §7511c) includes 11 northeastern states in which ozone transports from one or more states and 

contributes to a violation of the ozone NAAQS in one or more other states. States in this region are required 

to submit a SIP, stationary sources are subject to more stringent permitting requirements, and various 

regulatory thresholds are lower for the pollutants that form ozone, even if they meet the ozone NAAQS.

TABLE 2.7.1-3

Ambient Air Quality Concentrations in the Project Area

Pollutant Monitor a Site ID

Distance from 

LNG Terminal Averaging Period Value (μg/m3) Year

SO2

A 24-003-00-30 52 miles NW 1-hour 41.1 2009-2011

A 24-003-00-30 52 miles NW 3-hour 54.8 2009

PM10 A 24-003-00-30 52 miles NW 24-hour 25 2011

PM2.5

B 51-059-0030 46 miles NW 24-hour 24.0 2009-2011

B 51-059-0030 46 miles NW annual 9.6 2009-2011

NO2

C 51-153-0009 73 miles NW annual 56.4 2009-2011

C 51-153-0009 73 miles NW 1-hour 10.3 2011

CO

A 24-003-00-30 52 miles NW 1-hour 1,489 2011

A 24-003-00-30 52 miles NW 8-hour 1,146 2010

Ozone

C 51-153-0009 73 miles NW 1-hour 175 2010

C 51-153-0009 73 miles NW 8-hour 136 2009-2011

Lead B 51-059-0030 46 miles NW 3 month 0.006 2009

____________________

a Monitoring Station Designations:

A = Howard University’s Beltsville Laboratory; 12003 Old Baltimore Pike; Beltsville, Maryland.

B = Lee District Park; between Telegraph Road and Kings Highway; Groveton, Virginia.

C = James S. Long Park; Prince William County, Virginia.

The Liquefaction Facilities would be located in Calvert County, Maryland, which is in attainment 

for PM10, PM2.5, NO2, CO, and Pb, and is within the Washington, DC AQCR designated nonattainment for 

ozone. The Virginia facilities are in Loudoun and Fairfax Counties, which are in attainment for PM10, PM2.5

(24-hour standard), NO2, CO, and Pb. However, both Virginia Counties are also within the Washington, 

DC AQCR and are designated nonattainment for ozone and PM2.5 (annual standard). 

Greenhouse gases (GHGs) occur in the atmosphere both naturally and as a result of human 

activities, such as the burning of fossil fuels. These gases are the integral components of the atmosphere’s 

greenhouse effect that warms the earth’s surface and moderates day/night temperature variation. In general, 

the most abundant GHGs are water vapor, CO2, methane, nitrous oxide (N2O), and ozone. On December 7, 

2009, the EPA expanded its definition of air pollution to include six well-mixed GHGs, finding that the 

presence of the following GHGs in at the atmosphere endangers public health and public welfare currently 

and in the future: CO2, methane, N2O, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride. 

As with any fossil-fuel fired project or activity, the Project would contribute GHG emissions. The 

principle GHGs that would be produced by the Project are CO2, methane, and N2O. No fluorinated gases 

would be emitted by the Project. Emissions of GHGs are quantified and regulated in units of carbon dioxide 

equivalents (CO2e). The CO2e unit of measure takes into account the global warming potential (GWP) of 

each GHG. The GWP is a ratio relative to CO2 that is based on the properties of the GHG’s ability to 

absorb solar radiation as well as the residence time within the atmosphere. Thus, CO2 has a GWP of 1, 
99

methane has a GWP of 25, and N2O has a GWP of 298. To obtain the CO2e quantity, the mass of the 

particular chemical is multiplied by the corresponding GWP, the product of which is the CO2e for that 

chemical. The CO2e value for each of the GHG chemicals is summed to obtain the total CO2e GHG 

emissions. In compliance with EPA’s definition of air pollution to include GHGs, we have provided 

estimates of GHG emissions for construction and operation, as discussed throughout this section. Impacts 

from GHG emissions (climate change) are discussed in more detail under the Cumulative Impacts section of 

this EA. 

Permitting/Regulatory Requirements

The CAA, as amended in 1977 and 1990, is the basic federal statute governing air pollution. The 

provisions of the CAA that are potentially relevant to the Project include the following, which are 

discussed further below:

 Prevention of Significant Deterioration (PSD);

 Nonattainment New Source Review (NNSR);

 Title V Operating Permits;

 New Source Performance Standards (NSPS);

 National Emission Standard for Hazardous Air Pollutants for Source Categories

(NESHAP);

 Chemical Accident Prevention Provisions; 

 General Conformity; 

 GHG Reporting Rule; and

 State Regulations.

For the purposes of air permitting, the Liquefaction Facilities and LNG Terminal (existing LNG 

equipment) are considered a single stationary source for determining the regulatory applicability.

The Project would not involve any new operational air emission sources or emission increases at the 

Pleasant Valley M&R Facility or the Loudoun M&R Facility. Therefore, regulatory applicability is only 

discussed for the Liquefaction Facilities and the modified Pleasant Valley Compressor Station, with the 

exception of the General Conformity requirements, which apply to construction and operation emissions 

from mobile and stationary sources for the entire Project.

Prevention of Significant Deterioration

Separate procedures have been established for federal pre-construction air permit review of certain 

large proposed projects in attainment areas versus nonattainment areas. Federal preconstruction review for

affected sources located in attainment areas is called PSD. This process is intended to keep new major 

sources or major modifications of air emission sources from causing deterioration of existing air quality

below acceptable levels. Federal preconstruction review for affected sources located in nonattainment areas 

is commonly referred to as NNSR, which contains stricter thresholds and requirements. NNSR is discussed 

later in this section.
100

The PSD regulations (40 CFR 52.21) define a major source as any source type belonging to a list 

of named source categories that emit or have the potential to emit 100 tons per year (tpy) or more of any 

regulated pollutant or 250 tpy for sources not among the listed source categories. The LNG Terminal is 

an existing major PSD source because potential emissions for NO2 and CO are currently over the Major 

Source Threshold (MST). Under the PSD permitting program, a physical change or change in the method 

of operation at existing major sources would be subject to PSD if it results in an increase in emissions 

higher than the established Significant Emission Rate (SER) for that pollutant. PSD review is triggered if 

emissions resulting from a modification to an existing major source exceed 100 tpy for CO; 40 tpy each 

for nitrogen oxides (NOx), VOCs, and SO2; 15 tpy for PM10; or 10 tpy for PM2.5. 

As shown in table 2.7.1-6, the Liquefaction Facilities exceed PSD SER thresholds for NO2, CO, 

PM, PM10, and PM2.5. Fluorides and total reduced sulfur emissions are negligible for the Liquefaction 

Facilities due to the nature of the emission generating activities. The PSD permitting process is being 

completed by the Maryland PSC, the MDNR, and PPRP in parallel with our environmental review. DCP’s 

PSD application was included in its FERC application and elements of that application are summarized in 

this EA. 

Table 2.7.1-7 identifies that the increases in annual emissions from the Pleasant Valley Compressor 

Station are below the PSD MSTs; therefore, the Pleasant Valley Compressor Station would not be subject to 

PSD permitting. 

On May 13, 2010, the EPA issued a PSD GHG Tailoring Rule. The rule tailored specific 

applicability thresholds for GHG sources. The rule covers an estimated 70 percent of GHG emissions from 

stationary sources but does not apply to smaller sources such as apartment buildings and schools. Beginning 

on July 1, 2011, an existing industrial facility (of a non-listed source category) is subject to PSD review for 

GHGs if: 1) it is already subject to PSD review of non-GHG emissions (for another NSR pollutant) and 

would increase its GHG emissions by 75,000 tpy CO2e or more and greater than zero tpy on a mass basis; 2) 

the existing potential GHGs emissions are equal to or greater than 100,000 tpy CO2e and 250 tpy on a mass 

basis and GHG emissions as a result of the Project would increase by 75,000 tpy CO2e or more and greater 

than zero tpy on a mas basis; or 3) the existing source is minor for PSD (including GHGs) and the 

modification alone would result in equal to or greater than 100,000 tpy CO2e and 250 tpy of GHGs on a 

mass basis. The LNG Terminal is an existing PSD major source of GHG emissions and the Liquefaction 

Facilities have estimated CO2e emissions increase above 75,000 tpy and greater than zero tpy GHG 

emissions on a mass basis. Therefore, the Liquefaction Facilities would be subject to the PSD GHG 

Tailoring Rule, and DCP included a GHG Best Available Control Technology (BACT) Analysis as part of 

its PSD permit application.

The potential impact on protected Class I areas must also be considered in the PSD review process. 

Areas of the country are categorized as Class I, Class II, or Class III. Class I areas are designated

specifically as pristine natural areas or areas of natural significance, including wilderness areas and 

national parks, and are afforded special protection under the CAA. Class III designations, intended for

heavily industrialized zones, can be made only on request, and must meet all requirements outlined in 40

CFR 51.166. The remainder of the United States is designated as Class II. The Federal Land Managers’ 

Air Quality Related Values Work Group (FLAG) 2010 (FLAG, 2010) guidance states that a ratio of 

visibility-affecting emissions to distance (Q/d) value of 10 or less indicates that Air Quality Related Values 

analyses should not be required. Visibility-affecting pollutants are defined by the Federal Land Managers 

as: SO2, NO2, PM10, and sulfuric acid mist (H2SO4). The nearest Class I area to the Project is Shenandoah 

National Park located about 158 kilometers from the LNG Terminal. Based on the minimum distance to a 

Class I area in this Project and the projected visibility-affecting emissions, the Q/d value would be 

substantially less than 10. Therefore, a PSD Class I analysis was not completed. 
101

Nonattainment New Source Review

In nonattainment areas, a separate procedure has been established for federal pre-construction air 

permit review of certain large proposed projects; known as NNSR. NNSR applicability is determined 

separately and independently from PSD review. The applicability of the NNSR permitting program is based 

on the major source status of the facility and emissions increase from the Project. A physical modification 

or a change in the method of operation of an existing major source is subject to NNSR if the alteration 

would result in a significant emission increase of affected pollutants. Each NNSR pollutant and its 

precursor(s) are reviewed individually and compared to the applicable MST to determine major source 

status on a pollutant-by-pollutant basis. For each pollutant that is subject to NNSR permitting, the applicant 

must assess the following items in the NNSR permit application to the extent they are applicable:

 Lowest Achievable Emission Rate (LAER);

 Alternatives Analysis; and

 Purchasing of Emission Offsets.

Because the Liquefaction Facilities would be located in an area designated nonattainment for ozone, 

the Project has been evaluated for NNSR applicability with regards to the precursors of ozone, NOx and 

VOC. Both NOx and VOC have an NNSR SER limit of 25 tpy. As shown in table 2.7.1-6, the potential 

emissions increases from the Project are 279.3 tpy for NOx and 33.3 tpy for VOC. Therefore, the Project is 

subject to NNSR for NOx and VOC emissions. 

The Pleasant Valley Compressor Station is also located in an area designated nonattainment for 

ozone and PM2.5 (annual). As such, NNSR applicability was evaluated for NOx, VOC, and PM2.5. The 

potential emissions of the existing equipment at the Pleasant Valley Compressor Station would be below the 

MST for these pollutants. Emissions from the Project at the Pleasant Valley Compressor Station were 

compared to the applicable MSTs in order to determine NNSR applicability. As shown in table 2.7.1-7, 

potential emissions resulting from the Project at the Pleasant Valley Compressor station would be below the 

MSTs. The Project at the Pleasant Valley Compressor Station would not be subject to NNSR permitting.

Title V Operating Permit

The Title V Operating Permit program, as described in 40 CFR Part 70, requires major stationary 

sources of air emissions to obtain an operating permit within 1 year of initial facility startup. To 

determine if a facility is required to obtain a Title V permit, the potential emissions of criteria 

pollutants, HAPs, or GHGs from the entire facility are compared to the Title V MSTs of each pollutant. 

If emissions of any pollutant exceed the applicable MST, the facility must obtain a Title V permit. The 

MSTs for determining the need for a Title V Operating Permit are a potential to emit 100 tpy or more 

of any criteria pollutant, 10 tpy of any individual HAP, or 25 tpy of total HAPs (in aggregate).

The EPA also promulgated the Title V GHG Tailoring Rule, which established permitting 

thresholds for GHG emissions under the Title V program. Sources with an existing Title V permit or new 

sources obtaining a Title V permit for non-GHG pollutants are required to address GHGs. New sources and 

existing sources not previously subject to Title V that have a potential to emit equal to or greater than 

100,000 tpy CO2e would become subject to Title V requirements. 

The existing LNG Terminal is considered an existing Title V major source and currently operates 

under a Title V permit (Permit number 24-009-00021). The facility would remain subject to the Title V 

program upon completion of the Liquefaction Facilities and DCP would be required to apply for a 

modification to the existing Title V permit to include the new facilities associated with the Project. The 

Liquefaction Facilities would be subject to the Title V GHG Tailoring Rule. 
102

The Pleasant Valley Compressor Station is currently below and would remain below the Title V 

MSTs after completion of the Project. Therefore, the modified facility would not be subject to Title V 

permitting as a result of the Project. The Compressor Station would not be subject to the Title V GHG 

Tailoring Rule. 

New Source Performance Standards

The NSPS, codified in 40 CFR Part 60, require new, modified, or reconstructed sources to control 

emissions as specified in the applicable source category provisions. Any source that is subject to provisions 

under an NSPS subpart is also subject to the general monitoring, reporting, and record keeping provisions 

of NSPS Subpart A, except as noted in the applicable subpart. This section outlines the applicability of 

NSPS subparts for the Project facilities.

NSPS Subpart D, Standards of Performance for Fossil Fuel-Fired Steam Generators, applies to all 

fossil fuel-fired steam generating units rated at more than 250 million British thermal units per hour 

(MMBtu/hr). The auxiliary boilers associated with the electric generation for the Liquefaction Facilities are 

rated at 435 MMBtu/hr and, thus, are potentially subject to the requirements of NSPS Subpart D. However, 

units constructed after June 19, 1986 are exempt from NSPS Subpart D per 40 CFR 60.40b(j). As such, this 

regulation is not applicable to the Project.

NSPS Subpart Db, Standards of Performance for Industrial-Commercial-Institutional Steam 

Generating Units, applies to all steam generating units with a heat capacity of more than 29 MW (100 

MMBtu/hr). The auxiliary boilers associated with the electric generation for the Liquefaction Facilities are 

subject to the requirements of NSPS Subpart Db. The new natural gas boiler at the Pleasant Valley 

Compressor Station would be 5.1 MMBtu/hr. Therefore, it would not be subject to this regulation.

Per 40 CFR 60.44b(a), the auxiliary boilers associated with the Liquefaction Facilities would need 

to meet an emission limit of 86 nanograms of pollutant per Joule (ng/J) of NOx (0.20 pounds per million 

British thermal units (lb/MMBtu)). These emission limits apply at all times including startup, shutdown, 

and malfunction. DCP would also be required to install a continuous emissions monitoring system (CEMS) 

for NOx and either oxygen or CO2 on each of the auxiliary boilers. DCP would also be required to conduct 

performance testing in accordance with 40 CFR 60.46b(c).

NSPS Subpart Kb, Standards of Performance for Volatile Organic Liquid Storage Vessels, applies 

to storage vessels that are constructed, reconstructed, or modified after July 23, 1984, with a capacity

greater than 75 cubic meters (19,800 gallons) that would store volatile organic liquids. The Liquefaction 

Facilities would include eight tanks that are potentially subject to NSPS Subpart Kb: the four propane makeup tanks, the two ethane make-up tanks, and the two condensate storage tanks. NSPS Subpart Kb has an 

exemption (codified in 40 CFR 60.110b(d)(4)) for vessels with a design capacity less than 1,589.874 cubic 

meters used for petroleum or condensate stored, processed, or treated prior to custody transfer. The two 

condensate storage tanks would meet this exemption and are, therefore, not subject to NSPS Subpart Kb.

The other six tanks would be subject to NSPS Subpart Kb. The four propane make-up tanks and the two 

ethane make-up tanks would be subject to the requirements of 40 CFR 60.112b(b) because they each have a 

storage capacity of more than 75 cubic meters and contain a volatile organic liquid with a true vapor 

pressure more than 76.6 kilopascals. To comply with these requirements, DCP would not vent emissions to 

the atmosphere from the tanks during normal operations. However, in the case of an emergency, the tanks 

could vent to a flare with a control efficiency of at least 95 percent.

The new tanks at the Pleasant Valley Compressor Station would be well below the NSPS Subpart 

Kb applicability volume threshold; therefore, the tanks would not be subject to this regulation.
103

NSPS Subpart IIII, Standards of Performance for Stationary Compression Ignition Internal 

Combustion Engines, applies to stationary compression ignition internal combustion engines manufactured 

after certain dates dependent on engine type. The fire pump engines at the Liquefaction Facilities would be 

subject to NSPS Subpart IIII because they would be NFPA-certified fire pumps manufactured after July 1, 

2006 and ordered after July 11, 2005. The generator at the Liquefaction Facilities would be subject to NSPS 

Subpart IIII because it would be a stationary compression ignition internal combustion engine manufactured 

after April 1, 2006 and ordered after July 11, 2005.

The fire pump engines would be required to comply with emission standards in Table 4 to NSPS 

Subpart IIII. As an emergency use engine, the generator would be required to meet the applicable emission 

limitations in 40 CFR 60.4202. DCP would demonstrate compliance with the NSPS Subpart IIII emission 

limits by purchasing engines certified to the applicable emission limits. In addition, diesel combusted in the 

fire pump engines and generator would meet the requirements of 40 CFR 60.4207.

NSPS Subpart KKKK, Standards of Performance for Stationary Combustion Turbines, applies to 

stationary combustion turbines with a maximum heat input equal to or greater than 10 MMBtu per hour, 

which were constructed, modified, or reconstructed after February 18, 2005. NSPS Subpart KKKK

regulates emissions of NOx and SO2. The two new combustion turbines proposed as part of the 

Liquefaction Facilities would meet the capacity and construction date triggers and would be subject to NSPS 

Subpart KKKK. The microturbines at the Pleasant Valley Compressor Station would be less than 1 

MMBtu/hr and, therefore, would not be subject to this regulation.

The natural gas-fired combustion turbines proposed at the Liquefaction Facilities must limit NOx

emissions from the turbines to 15 parts per million (ppm) at 15 percent O2 or 54 ng/J (0.43 pound per 

megawatt-hour) of useful output. Emissions of SO2 must also be limited to 110 ng/J (0.90 lb/MMBtu) of 

heat input or fuel must be limited to fuel that contains total potential sulfur emissions less than 26 ng/J 

(0.060 lb/MMBtu). DCP would demonstrate compliance with NSPS Subpart KKKK by installing a NOx

CEMS meeting the requirements on 40 CFR 60.4345 and burning natural gas with sulfur content below the 

aforementioned limit. 

National Emission Standards for Hazardous Air Pollutants

The NESHAPs, codified in 40 CFR Parts 61 and 63, regulate the emissions of HAPs from 

existing and new sources. 

Part 61 NESHAP regulations apply to the following eight compounds listed as HAPs prior to the 

CAA Amendments of 1990: asbestos, benzene, beryllium, coke oven emissions, inorganic arsenic, mercury, 

radionuclides, and vinyl chlorides.

The regulations list emission limits and operating parameters that must be followed for specified 

sources that emit these compounds. The emission sources included in the Project would not emit these 

pollutants. As such, the Project has no requirements under the 40 CFR 61 NESHAP regulations.

The 1990 CAA Amendments established a list of 189 HAPs, resulting in the promulgation of 40 

CFR 63 NESHAP (Part 63). Part 63, also known as the Maximum Achievable Control Technology 

(MACT) standards, regulates HAP emissions specific source types located at major or area sources of 

HAPs. The existing LNG Terminal and Pleasant Valley Compressor Station are not major sources for 

HAPs, because HAP emissions are below the MST of 10 tpy of any single HAP or 25 tpy of all HAPs

in aggregate. The LNG Terminal (including the Liquefaction Facilities) and the Pleasant Valley 

Compressor Station would remain minor sources of HAPs after the Project. NESHAPs apply to sources in 

specifically regulated industrial source categories [CAA Section 112(d)] or on a case-by-case basis [Section 
104

112(g)] for major sources not regulated as a specific industrial source type. Below is a detailed discussion 

of the NESHAP regulations that are potentially applicable to the Liquefaction Facilities. In addition to the 

source type-specific regulations, any source which is subject to a subpart of 40 CFR 63 is also subject to the 

general provision of NESHAP Subpart A, unless otherwise noted in the applicable subpart.

The following NESHAP subparts were identified as potentially applicable to the Project based on 

source type: Subpart HHH, Subpart EEEE, Subpart YYYY, and Subpart DDDDD. However, these 

subparts are not applicable because the LNG Terminal, including the Project, would not be a major source 

of HAP emissions.

NESHAP Subpart Y, National Emission Standards for Marine Tank Vessel Loading Operations, 

applies to new sources with an initial startup date after September 20, 1999 having a potential to emit less 

than 10 tons individual HAP and 25 tons combined HAPs. Per 40 CFR 63.560(d)(5), this rule does not 

apply to marine tank vessel loading operations that exclusively transfer liquids containing organic HAPs as 

impurities, as defined in 40 CFR 63.561. The Liquefaction Facilities would meet this exemption; therefore, 

this rule is not applicable to the Project. 

NESHAP Subpart ZZZZ, National Emission Standards of Hazardous Air Pollutants for Stationary 

Reciprocating Internal Combustion Engines (RICE) applies to stationary RICE at major and area sources of 

HAPs. Although the LNG Terminal would be a minor source of HAPs, the fire pump engines and the 

generator at the Liquefaction Facilities would be constructed after June 12, 2006 at an area source of HAPs 

and would be subject to Subpart ZZZZ. As discussed above, the engines would be subject to NSPS Subpart 

IIII. Therefore, these engines satisfy the requirements under Subpart ZZZZ. 

Chemical Accident Prevention Provisions

The chemical accident prevention provisions, codified in 40 CFR Part 68, are federal regulations 

designed to prevent the release of hazardous materials in the event of an accident and minimize potential 

impacts if a release does occur. The regulations contain a list of substances (including methane, propane, 

and ethylene) and threshold quantities for determining applicability to stationary sources. If a stationary 

source stores, handles, or processes one or more substances on this list in a quantity equal to or greater than 

specified in the regulation, the facility must prepare and submit a risk management plan (RMP). An RMP is 

not required to be submitted to the EPA until the chemicals are stored onsite at the facility. 

If a facility does not have a listed substance on-site, or the quantity of a listed substance is below the 

applicability threshold, the facility does not have to prepare an RMP. However, if there is any regulated 

substance or other extremely hazardous substance onsite, the facility still must comply with the 

requirements of the General Duty Clause in Section 112(r)(1) of the 1990 CAA. The General Duty Clause

is as follows:

“The owners and operators of stationary sources producing, processing, handling and storing 

such substances have a general duty to identify hazards which may result from such releases using 

appropriate hazard assessment techniques, to design and maintain a safe facility, taking such steps as 

are necessary to prevent releases, and to minimize the consequences of accidental releases which do 

occur.” 

Stationary sources are defined in 40 CFR Part 68 as any buildings, structures, equipment, 

installations, or substance-emitting stationary activities that belong to the same industrial group, are 

located on one or more contiguous properties, and are under control of the same person (or persons under 

common control) from which an accidental release may occur. However, the definition also states that 

the term stationary source does not apply to transportation, including storage incidental to transportation, 
105

of any regulated substance or any other extremely hazardous substance. The term transportation includes 

transportation subject to oversight or regulation under 49 CFR parts 192, 193, or 195. Based on these 

definitions, the LNG Terminal and Liquefaction Facilities are subject to 49 CFR Part 193. Therefore, 

these facilities would not be required to have an RMP. We have included an analysis of the proposed 

design’s compliance with Part 193, including overpressure modeling, in section 2.8.6.

General Conformity

The EPA promulgated the General Conformity Rule on November 30, 1993, and amended it in 

2006 and 2010 to implement the conformity provision of Title I, Section 176(c)(1) of the CAA. The 

purpose of this rule is to ensure that emissions from projects that require federal action are 

consistent with the approved SIP. Consistent with the rule, the following terms are used in this 

document:

 General Conformity applicability analysis is the calculating and compiling of 

emissions data for comparison to the applicability thresholds in order to determine 

whether a General Conformity Determination is required.

 General Conformity Determination is the evaluation (made after a General 

Conformity applicability analysis is completed) that a federal action conforms to the 

applicable implementation plan (e.g., SIP) and meets the requirements of this 

subpart.

The General Conformity Rule is codified in Title 40 CFR Part 93, Subpart B, Determining 

Conformity of General Federal Actions of State of Federal Implementation Plans. Any project that 

requires federal action must evaluate the applicability of the General Conformity Rule for those emissiongenerating activities resulting from the project and are located in an area that is designated as 

nonattainment or a maintenance area. A General Conformity Determination must be completed by the

lead federal agency if a federal action is likely to result in direct and indirect emissions (construction and

operation) that would exceed the General Conformity applicability threshold levels of the pollutant(s) for 

which an air basin is in nonattainment or maintenance. According to the General Conformity

regulations, the portion of an action that includes major or minor new or modified stationary sources that 

require a permit under the NSR program (Section 110(a)(2)(c) and Section 173 of the CAA) or the PSD 

program (title I, part C of the CAA) are exempt and are deemed to have conformed.

Section 176(c)(1) of the CAA (Title 40 CFR 51.853) states that a federal agency cannot approve 

or support any activity that does not conform to an approved SIP. Conforming activities or actions 

should not, through additional air pollutant emissions:

 Cause or contribute to new violations of the NAAQS in any area;

 Increase the frequency or severity of any existing violation of any NAAQS; or

 Delay timely attainment of any NAAQS or interim emission reductions.

A General Conformity applicability analysis is required for parts of the Project occurring in 

counties identified as nonattainment or maintenance for regulated pollutants. Calvert County, Maryland is 

designated as a nonattainment area for ozone, and Loudoun and Fairfax Counties, Virginia are designated as 

nonattainment areas for ozone and PM2.5. NOx and VOC are precursors to the formation of ozone and are 

thus treated as nonattainment pollutants. The Project is located within the OTR. Any activity resulting in 

100 tpy of NOx or 50 tpy of VOC emissions from non-permitted emissions-generating activities associated 

with the Liquefaction Facilities or the Pleasant Valley Compressor Station modifications must undergo a 

General Conformity Determination. Because SO2 and NOx are precursors to PM2.5, any emission increase 
106

of 100 tpy for more of PM2.5, SO2, or NOx from non-permitted emissions-generating activities associated 

with the Pleasant Valley Compressor Station would also trigger a General Conformity Determination. 

Construction activities associated with the Project would generate air emissions; specifically, 

increased on-road vehicle travel, construction equipment engines, off-road vehicle travel, earthmoving 

fugitives, barges delivering equipment, and off-shore marine vessels, including tugboats. Emissions from 

each of these activities were estimated for each of the three Project sites for each calendar year of 

construction.

Non-permitted operational emissions are those emissions that are not required to be regulated as 

part of the air quality permitting process. DCP has identified three sources of non-permitted operational 

emissions associated with the Project (all from the Liquefaction Facilities): new permanent employees 

commuting to the facility; waste haulers; and marine vessels. These non-permitted operational emission 

sources would only be noteworthy for the Liquefaction Facilities. The non-permitted operational emissions 

from the modifications at the Pleasant Valley Compressor Station would be negligible.

Table 2.7.1-4 summarizes the Project emissions from construction and non-permitted emissionsgenerating activities.

TABLE 2.7.1-4

Total Construction and Non-Permitted Project Emissions Summary

Year a

Emissions (tons/year)

NOx SO2 VOC PM2.5

2014 171.13 0.00 15.38 0.00

2015 326.94 0.00 35.00 0.00

2016 230.91 0.79 32.80 5.82

2017 – Construction 123.14 0.03 16.43 0.66

2017 – Operation (non-permitted) – LNG Terminal 77.23 0.00 2.29 0.00

2017 (Total) 200.37 0.03 18.72 0.66

2018 & Beyond – Operation (non-permitted) – LNG 

Terminal

77.23 0.00 2.29 0.00

Conformity Applicability Threshold 100 100 50 100

____________________

a Project construction would occur between 2014 and 2017, followed by operation of the facilities. Only the Liquefaction 

Facilities would have any notable non-permitted operational emissions (marine vessels, employee commuter vehicle traffic, 

and waste haul truck traffic).

N/A Not Applicable

As shown in table 2.7.1-4, the Project triggers a General Conformity Determination for years 2014 

through 2017 for construction-related NOx emissions. A detailed Draft General Conformity Determination, 

issued concurrently with this EA is included in appendix B. This determination describes the regulations for 

determining applicability and demonstrating conformity. As noted in the Draft General Conformity 

Determination, DCP has committed to fully offsetting the project construction NOx emissions through the 

purchase of emission reduction credits from within the Washington, DC AQCR. DCP has stated that 625 

tons for NOx emission reduction credits have been purchased. 

This amount far exceeds the projected non-permitted emissions. As described above, in order to 

achieve improved air quality within a non-attainment area, reductions are required throughout the entire 

AQCR. The amount of emission reduction credits purchased would result in a net decrease in NOx

emissions within the AQCR during construction of the Project. 
107

Although DCP stated it purchased these credits, it has not provided final documentation that it has 

purchased these offsets. Therefore, to allow the Commission staff to issue a final General Conformity 

Determination, we recommend that:

 Prior to construction, DCP should file the following information for the issuance of a 

final General Conformity Determination:

a. an updated estimation of Project emissions for each calendar year of 

construction and initial start-up based on the current Project schedule at that 

time; 

b. a record of NOx offsets obtained and demonstrate that this amount is equal to 

the amount required under the General Conformity regulation; and

c. letters from MDE and VDEQ concurring that the offset requirements for the 

Project have been met.

The Project would result in construction-related emissions from barge traffic in other AQCRs in 

addition to the Washington, DC AQCR. The barges would pass through other AQCRs that are 

nonattainment for ozone (precursors NOx and VOC) and PM2.5 (precursors NOx and SO2). Total emissions 

of these pollutants and their precursors from barges in any AQCR do not exceed the General Conformity 

thresholds. As such, a General Conformity Determination is not required for barge emissions in other 

AQCRs.

Greenhouse Gas Reporting Rule

On September 22, 2009, the EPA issued the final Mandatory Reporting of Greenhouse Gases 

rule, establishing the Greenhouse Gas Reporting Program (GHGRP) codified in 40 CFR Part 98. Since 

2011, the GHGRP has required large direct emitters of GHGs, and certain suppliers (e.g., of fossil fuels, 

petroleum products, industrial gases, and CO2) to report GHGs. Subpart C of Title 40 CFR Part 98 

applies to combustion units and Subpart W applies to petroleum and natural gas systems, including: both 

onshore and offshore petroleum and natural gas production; onshore natural gas processing; natural gas 

transmission compression; underground natural gas storage; liquefied natural gas storage, and import and 

export facilities that emit greater than or equal to 25,000 metric tons of GHGs, as CO2e, per year.

According to EPA’s GHGRP webpage, “EPA’s Greenhouse Gas Reporting Program will help us better 

understand where greenhouse gas emissions are coming from and will improve our ability to make 

informed policy, business and regulatory decisions” (EPA, 2012). 

Emissions of GHG pollutants associated with the construction and operation of the Project were 

calculated. In addition, GHG emissions were converted to total CO2e emissions based on GWP of each 

pollutant. GHG emissions associated with operation of the Project, as discussed earlier, are shown in 

table 2.7.1-6 and 2.7.1-7. 

The GHGRP does not apply to construction emissions; however, we have included the 

construction emissions in table 2.7.1-5 for accounting and disclosure purposes. Based on the emission 

estimates summarized in table 2.7.1-6, the GHG emissions associated with the Liquefaction Facilities 

may potentially exceed 25,000 metric tpy. However, the GHGRP does not require emission control 

devices and is strictly a reporting requirement for stationary sources based on actual emissions. If the 

actual emissions from the Liquefaction Facilities are equal to or greater than 25,000 metric tpy, DCP 

would be required to comply with all applicable requirements of 40 CFR Part 98. 
108

State Regulations

The MDE is the lead air permitting authority for the Liquefaction Facilities, and the VDEQ 

administers the federal and state air quality standards for the facilities in Virginia. The applicable state 

regulations for each facility are summarized below. State regulations that are not applicable are not 

included in the summary below.

Liquefaction Facilities

Maryland state air quality regulations are codified in COMAR Tile 26, Subtitle 11. The Project 

would be required to obtain an air quality permit prior to initiating construction. This section discusses the 

applicability of state air quality regulations to the Project. Facilities also trigger review by other states if

the project location is within 50 miles of an adjacent state’s border. The Liquefaction Facilities would be 

located within 50 miles of the border of Delaware and Virginia. The air permitting authorities of these 

states will have the opportunity to review and comment on the application and subsequent permits.

The existing LNG Terminal currently operates under permit number 24-009-00021. DCP would be

required to obtain an air permit prior to initiating construction or modifying the site. To this end, DCP is 

seeking a CPCN from Maryland PSC. The process of obtaining the CPCN will involve the review and 

implementation of state regulations, inclusive of requirements for PSD and NNSR. The state regulations 

summarized below are those that would establish emission limits or other restrictions that may be in 

addition to those required under federal regulations.

COMAR 26.11.06, General Emission Standards, Prohibitions, and Restrictions, establishes 

emission standards for various pollutants from certain source types. These emissions standards include 

limits on opacity, PM, SO2, and odor/nuisance.

COMAR 26.11.09, Control of Fuel-Burning Equipment, Stationary Internal Combustion Engines, 

and Certain Fuel-Burning Installations, establishes emission limits for various pollutants from certain types 

of fuel burning units. The combustion turbines, auxiliary boilers, fire pumps, and emergency generator meet 

the definition of fuel-burning equipment and would potentially be subject to the opacity, PM, SO2, and NOx

requirements of this chapter.

COMAR 26.11.15 and 16, Toxic Air Pollutants and Procedures Related to Requirements for Toxic 

Air Pollutants, establishes MDE’s program for toxic air pollutants (TAPs). The existing LNG Terminal 

emits TAPs, as defined by COMAR 26.11.16. As such, DCP must demonstrate compliance with the TAP 

regulations. The Liquefaction Facilities must quantify emissions of each TAP; identify, install, and operate 

BACT for toxics on new and reconstructed source(s) of TAP emissions (COMAR 26.11.15.05); and 

demonstrate that emissions of TAPs (total allowable emissions from the premises) would not adversely 

impact public health beyond the property line (COMAR 26.11.15.06). 

Pleasant Valley Compressor Station

Virginia Administrative Code, Title 9, Agency 5, Chapter 50, New and Modified Stationary 

Sources, contains provisions that generally determine methods of compliance for new and modified 

stationary sources including testing and continuous monitoring requirements. Due to the insignificant 

nature of the Project activities at the Pleasant Valley Compressor Station, these regulations would not 

apply. Other provisions of this Chapter include reporting and recordkeeping requirements, and opacity 

and odor standards. DCP would be required to comply with these standards.
109

Impacts and Mitigation

The Project would produce air pollutant emissions from both construction and operation. 

Construction of the Liquefaction Facilities would occur over a period of less than 4 years. Construction at 

the Pleasant Valley Compressor Station (including the Pleasant Valley Suction/Discharge Pipelines and 

M&R Facility) and Loudoun M&R Facility would occur over a period of less than 2 years. Therefore, the

air quality impacts of Project construction are considered short-term. Following construction, air quality 

would not revert back to previous conditions, but rather would transition to operational emissions after

commissioning and initial startup of the Project facilities.

Construction Impacts and Mitigation

Construction of the Project would result in short-term increases in emissions of some pollutants 

from the use of fossil fuel-fired equipment and the generation of fugitive dust due to earthmoving activities. 

There may also be some temporary indirect emissions attributable to construction workers commuting to 

and from work sites during construction, from barges transporting construction materials, and from on-road 

and off-road construction vehicle traffic. Large earth-moving equipment and other mobile equipment are 

sources of combustion-related emissions, including criteria pollutants (i.e., NOx, CO, VOC, SO2, and PM10) 

and small amounts of HAPs.

TABLE 2.7.1-5

Total Construction Emissions Summary

Year

Emissions (tons/year)

NOx CO SO2 VOC PM10 PM2.5 GHG (CO2e) HAPs

2014 171.13 182.99 9.44 15.38 57.54 26.76 32,497 3.01

2015 325.12 388.30 106.29 34.98 73.25 37.59 57,781 6.83

2016 230.91 385.55 12.38 32.49 49.03 25.27 45,727 6.35

2017 123.14 158.89 8.45 16.43 69.78 20.37 32,253 3.20

The majority of air emissions produced during construction activities would be PM10 and PM2.5 in 

the form of fugitive dust. Fugitive dust would result from land clearing, grading, excavation, concrete work, 

and vehicle traffic on paved and unpaved roads. The quantity of fugitive dust generated by constructionrelated activities depends on several factors, including the size of area disturbed; the nature and intensity of 

construction activity; surface properties (such as the silt and moisture content of the soil); the wind speed; 

and the speed, weight, and volume of vehicular traffic. Emissions would be greater during dry periods and 

in areas of fine-textured soils subject to surface activity. 

Several commenters are concerned about dust generation during construction. Table 2.7.1-5 

includes the emissions associated with fugitive dust generation. In addition, DCP has prepared a Fugitive 

Dust Control Plan to identify emission reduction measures that may be implemented to achieve the emission 

reductions assumed in calculating the Project construction emissions (such as water suppression, covering 

storage piles, covering truck loads during transit, limiting on-site vehicle speed, measures to reduce trackout on public roads, etc.). However, we do not believe the Fugitive Dust Control Plan sufficiently describes 

how DCP would implement these measures to ensure adequate mitigation of fugitive dust emissions that 

would occur in the same area over a multi-year period (e.g., identification of speed limits, usage of speed 

limit signage, use of gravel at construction entrances to reduce track-out). In addition, DCP has not 

provided any information about accountability or individuals with authority regarding fugitive dust 

mitigation. Therefore, we recommend that:

 Prior to construction, DCP should file a revised Fugitive Dust Control Plan with the 

Secretary, for review and written approval by the Director of OEP. The plan 
110

should specify the precautions that DCP would take to minimize fugitive dust 

emissions from construction activities and identify additional mitigation measures to 

control fugitive dust emissions of Total Suspended Particulates, PM10, and PM2.5, 

including: 

a. identifying how DCP would implement these measures (e.g., identification of 

speed limits, usage of speed limit signage, use of gravel at construction 

entrances to reduce track-out);

b. clarifying that the EI has the authority to determine if/when water or a 

palliative needs to be used for dust control; and

c. clarifying that the EI has the authority to stop work if the contractor does 

not comply with dust control measures.

Work at the Liquefaction Facilities and Offsite Areas A and B may result in some increase in traffic 

volumes on local public roads; however, construction work would typically occur during daylight hours 

(7:00 a.m. to 6:00 p.m.), 6 days per week. Transport of large equipment would occur at night to minimize 

potential impacts to traffic by the slow movement of oversized and overweight equipment. Most 

construction workers would park at Offsite Area A and be transported to the Liquefaction Facilities site by 

bus or shuttle. The emissions from the construction traffic are included in the construction emissions. 

Construction related emission estimates were based on a typical construction equipment list, hours 

of operation, and vehicle miles traveled by the construction equipment and supporting vehicles for each area 

of the Project. Construction activities at the Pleasant Valley Compressor Station, Pleasant Valley 

Suction/Discharge Pipelines, Pleasant Valley M&R Facility, and Loudoun M&R Facility are also expected 

to occur in calendar years 2016 and 2017. These emission-generating activities would include earthmoving, 

construction equipment exhaust, on-road vehicle traffic, and off-road vehicle traffic. Construction 

emissions from the Project are summarized above in table 2.7.1-5.

Construction of the Project would occur over a four-year period, resulting in short-term impacts 

on air quality. Once construction activities in an area are completed, fugitive dust and construction 

equipment emissions would subside. Conditions after completion of construction would transition to 

operational-phase emissions after commissioning and initial startup of the facility. 

Operational Impacts and Mitigation

The Project would include the installation of the following stationary point sources of air pollutants 

at the LNG Terminal:

 Two GE Frame 7 natural gas turbines, each rated at 1,062 MMBtu/hr, equipped with SCR 

and an oxidation catalyst;

 Two auxiliary natural gas boilers, each rated at 435 MMBtu/hr, equipped with SCR and an 

oxidation catalyst;

 One diesel emergency generator, rated at 1,550 hp;

 Five fire pump diesel engines, each rated at 350 hp;

 One thermal oxidizer equipped with a burner rated at 56 MMBtu/hr, equipped with SCR 

and an oxidation catalyst;
111

 Two ground flares;

 Tanks to support the process, emissions control equipment, and combustion equipment. 

Most tank sizes range from 12,000 to 67,000 gallons, except small 750-gallon process 

tanks, and four large 102,500-gallon propane make-up tanks; and

 Other process and liquefaction equipment with minimal environmental impacts.

The Project would also include the installation of the following stationary point sources of air

pollutants at the Pleasant Valley Compressor Station:

 One natural gas-fired boiler rated at 2.5 MMBtu/hr;

 Two microturbines, rated at 80 hp and used for emergency purposes;

 One 3,000-gallon waste fluid tank; and

 One 1,000-gallon coolant tank containing water and ethylene glycol.

The Project would also include miscellaneous piping and measurement upgrades at the Loudoun 

M&R Facility; however, there are no new emissions sources as part of the Project at this site. 

We received several comments about the magnitude of criteria pollutant and GHG emissions from 

the Liquefaction Facilities and stating the belief that this Project would become one of the largest GHG 

emitters in the State of Maryland when compared to actual emissions from other facilities. The potential to 

emit from the existing LNG Terminal, the Liquefaction Facilities, and Pleasant Valley Compressor Station 

are summarized in tables 2.7.1-6 and 2.7.1-7. The emissions identified in these tables represent the 

maximum potential to emit, and are not directly comparable to past actual emissions from the LNG 

Terminal or other regional sources because the emissions below represent continuous operation (8,760 

hours per year) of the emission sources at their full capacity. Past actual emissions are based on the actual 

load conditions and operating hours, which may be notably lower than those used to estimate the potential 

to emit. In addition, all new major air emission sources must obtain the appropriate PSD or NNSR permit 

to adequately protect air quality. The criteria pollutant emissions that trigger NNSR must be controlled to 

LAER levels and offsets must be obtained. The criteria pollutant emissions that trigger PSD review must 

be controlled to BACT levels and modeled to demonstrate compliance with ambient air quality standards. 

New GHG sources subject to PSD review must control the emissions to BACT levels. These air 

permitting programs are included in the state SIPs that account for industrial growth while reducing 

overall emissions in the state to meet air quality goals. The impacts associated with the criteria pollutant 

emissions are presented below under Air Dispersion Modeling and for GHG emissions are presented in 

the climate change discussion in section 2.9.9. 

The Maryland PSC has reviewed DCP’s proposed BACT and LAER analysis for the Liquefaction 

Facilities, including the combustion turbines, auxiliary boilers, emergency internal combustion engines, 

flares, and thermal oxidizers. Methods for reducing emissions of NOx, CO, VOCs, and PM10/PM2.5 for each 

of these sources were evaluated based on technical feasibility. DCP would reduce normal operating 

emissions of NOx from the gas turbines, auxiliary boilers, and thermal oxidizer through the use of SCR; 

CO and VOC emissions would be controlled through the use of oxidation catalysts; and particulate matter 

(PM, PM10, and PM2.5) would be reduced through the use of good combustion practices and burning only 

pipeline quality natural gas and fuel gas. The emergency generators and fire pump engines would utilize 

good combustion practices and ultra-low-sulfur diesel fuel to reduce emissions, especially PM and SO2

emissions. Emissions from the flares would be reduced through good combustion practices (such as 

maintenance of proper combustion efficiency). The resulting BACT and LAER emission rates are equal to 

or more stringent than any NSPS, NESHAP, and/or BACT emission standards applicable to these emission 

sources. The BACT determinations for GHG emissions are discussed with climate change in section 2.9.9. 
112

The emissions presented in table 2.7.1-6 include the Maryland PSC’s proposed BACT and LAER pollutant 

limitations or measures for the various Liquefaction Facility sources.

TABLE 2.7.1-6

Liquefaction Facilities Potential Emissions Summary

Emission 

Source NO2 CO SO2 PMa PM10

b PM2.5b H2SO4 H2S VOC HAPs GHGs

Existing LNG 

Terminal

278.8 813.55 1.84 67.60 67.60 67.60 N/D N/D 33.8 8.2 1,355,859

Combustion 

Turbines

102.0 37.9 2.1 31.0 61.3 61.3 3.2 1.1 9.8 10.6 1,089,376

Thermal 

Oxidizer

6.2 2.3 0.3 3.1 4.0 4.0 0.5 0.2 0.1 0.2 386,177

Auxiliary 

Boilers

50.8 45.2 0.2 19.7 51.8 51.8 0.2 0.1 4.2 0.0 446,213

Flares 110.0 49.6 0.0 1.1 4.5 4.5 0.0 0.0 14.8 0.3 64,859

Fire Pumps 0.5 0.6 0.2 0.0 0.0 0.0 0.0 0.0 0.2 0.0 104

Generator 3.8 2.2 0.0 0.1 0.1 0.1 0.0 0.0 0.3 0.0 444

Leaking 

Components

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2.5 0.0 66

Existing Frame 

5 Turbines

6.0 8.8 0.0 0.7 2.5 2.5 0.0 0.0 1.2 0.7 43,749

Total Increase 279.3 146.6 2.8 55.7 124.2 124.2 4.0 1.4 33.3 11.8 2,030,988

PSD SERs 

(tpy)

40 100 40 25 15 10 7 10 NA NA 75,000

NNSR SERs 

(tpy)

NA NA NA NA NA NA NA NA 25 NA NA

Over SER? Yes Yes No Yes Yes Yes No No Yes Yes Yes

____________________

a Values include filterable emissions only

b Values include filterable and condensable emissions

N/D No Data Available

Note: The totals shown in this table may not equal the sum of addends due to rounding.

TABLE 2.7.1-7

Pleasant Valley Compressor Station Potential Emissions Summary (tons/year)

Emission Source NO2 NOx CO SO2 PM10 PM2.5 VOC GHGs

Two Microturbines 0.26 0.26 0.69 0.00 0.3 0.30 0.01 824

One Boiler 1.05 1.05 0.88 0.01 0.08 0.08 0.06 1,258

Fugitive Emissions - - - - - - 0.68 240

Tanks - - - - - - Neg. -

Total Increase 1.31 1.31 1.57 0.01 0.38 0.38 0.74 2,321

Existing Facility 2.54 2.54 2.20 0.01 0.77 0.77 2.64 5,073

Total After Project 3.85 3.85 3.77 0.02 1.15 1.15 3.38 7,394

PSD MST (tons/year) 250 NA 250 250 250 NA NA 100,000

NNSR MST (tons/year) NA 100 NA NA NA 100 50 NA

Title V MST (tons/year) 100 NA 100 100 100 100 100 100,000

Over MST? No No No No No No No No

____________________

Neg. Negligible

In addition to limiting operational emissions from Liquefaction Facilities to BACT and LAER 

levels, DCP is also required to offset operational NOx and VOC emissions under NNSR at a ratio of 1.3 to 1 
113

(i.e., 1.3 tons of offsets per ton of emissions from the Liquefaction Facilities). The PPRP has identified that 

DCP already obtained sufficient NOx and VOC offsets for the operational NOx and VOC emissions. We 

received comments requesting these offsets be purchased locally. These offsets are purchased as a result of 

the NNSR review process and the Maryland PSC has authority for approval of the offsets. However, as 

discussed above, in order to improve air quality at one location, reductions are necessary throughout the 

AQCR. Therefore, these emission offsets are not required to be obtained from sources within the same 

county but rather within the same AQCR. 

Air Dispersion Modeling

In order to provide a more thorough evaluation of potential air quality in the vicinity of the Project, 

air dispersion modeling analyses were completed for the CPCN/air permit application to the Maryland PSC 

and for the FERC application. The CPCN/air permit modeling was completed for demonstrating 

compliance with the PSD review requirements in order to obtain an air permit. That modeling showed that 

the Liquefaction Facilities’ stationary emission sources would not cause or significantly contribute to an 

exceedance of an ambient air quality standard or ambient air increment. 

We received several comments requesting that impacts from LNG carriers be included as part of the 

Project and that the modeling analysis consider worst case emissions. Although the Project would not 

include any additional LNG carriers above those previously evaluated in the Pier Reinforcement and Cove 

Point Expansion Projects, we requested the DCP provide a separate modeling analysis (FERC Modeling). 

The FERC Modeling differs from the PSD modeling because it included marine vessel emissions while 

docked at the existing offshore pier at the LNG Terminal, in addition to stationary sources. After

construction of the Project, the LNG Terminal and Liquefaction Facilities could operate under one of two

scenarios (liquefaction or regasification). Market demands would determine the utilization of either

liquefaction or regasification facilities. The regasification facilities were previously evaluated and

authorized through FERC and MDE permitting. Because the LNG Terminal would have the capability of 

being bidirectional, for short-term averaging periods, the FERC Modeling assumed the worst case scenario 

of LNG import at the dock simultaneously with either liquefaction or gasification operations at the terminal. 

Because this operating scenario cannot be sustained long-term (the LNG tanks would become full), this 

scenario is considered conservative for the long-term modeled averaging periods. In addition, the LNG 

Terminal would average less than one vessel per day, resulting in a low likelihood of two vessels docked at 

one time. Although the modeling assumed one vessel at the dock at a time, the modeling made several 

conservative assumptions including: always importing LNG at the dock (importing requires the use of 

additional pumps onboard the LNG carriers that are not used for exporting), using the worst case fuel, and 

assuming continuous operation. Further, the most stringent short-term standards (1-hour NO2 and 1-hour 

SO2) are percentile standards. The Project would include intermittent emission sources that were modeled 

as continuous sources at their peak short term NOx and SO2 emission rates rather than average emission 

rates. This results in conservative results when compared to the percentile based short-term standards.

The modeling was performed using the AERMOD dispersion modeling program. The AERMOD 

modeling program is a Gaussian plume dispersion model that includes the building profile input program 

PRIME version for estimating impacts from building wake effects and terrain data for estimating the 

impacts of changing elevation on ground level pollutant concentrations. The modeling for NO2 was 

performed using the plume volume molar ratio method (PVMRM) for estimating NO2 concentrations by 

simulating the conversion of NOx to NO2. We reviewed the model selection, input parameters, and 

assumptions and agree with DCP’s modeling methodology.

In the first step of the FERC Modeling, DCP modeled the emissions from the Project (including 

marine vessels) and compared the highest modeled concentration for each pollutant and averaging period 

to the significant impact levels (SILs). If the highest modeled concentration for any pollutant/averaging 
114

period is below the SIL, the source is presumed not to cause or contribute to an exceedance of the NAAQS 

and no further modeling is necessary. A summary of the significant modeling is provided in table 2.7.1-8. 

As shown in table 2.7.1-8, the modeled CO 1-hour and 8-hour concentrations are the only results 

that were below the SILs. As such, refined modeling to demonstrate compliance with the NAAQS were 

performed for all other pollutants and averaging periods. For the cumulative NAAQS analysis, the Project 

(including marine vessels) and other off-site sources were modeled. To account for additional sources that 

may not have been modeled but that may contribute to background pollutant levels in the Project area, 

monitoring data from representative monitoring sites were added to the modeling results prior to 

comparison to the NAAQS.

TABLE 2.7.1-8

LNG Terminal SIL Analysis Summary a

Pollutant Averaging Period Modeled Concentration (μg/m3) SIL (μg/m3)

CO 1-hour 867.3 2,000

CO 8-hour 177.2 500

PM10 24-hour 11.8 5

PM2.5 24-hour 8.9 1.2

PM2.5 Annual 1.3 0.3

SO2 1-hour 74.5 7.8

SO2 3-hour 121.7 25

SO2 24-hour 45.6 5

SO2 Annual 3.9 1

NO2 1-hour 228.7 7.5

NO2 Annual 4.6 1

Lead 3-month 0.00047 NA

____________________

a Both gasification (LNG Terminal) and liquefaction (Liquefaction Facilities) were modeled in the FERC modeling analysis for 

demonstrating compliance with the ambient air quality standards. Under the liquefaction scenario, some gasification 

equipment were modeled that operate in a back-up capacity to the liquefaction equipment. 

μg/m3 = micrograms per cubic meter

The refined NAAQS analysis demonstrated that the Liquefaction Facilities’ emissions sources 

(onshore stationary and marine vessel emissions at the pier) would not cause or significantly contribute to an 

exceedance of a standard with the exception of one receptor located on the Calvert Cliffs Nuclear Power 

Plant property. This receptor is located on restricted industrial property that is, therefore, not categorized as 

“ambient air.” EPA guidance specifies that Calvert Cliffs cannot cause an exceedance on its own property. 

Therefore, the emissions from the Calvert Cliffs Nuclear Power Plant are allowed to be subtracted from the 

modeling. Upon removal of the Calvert Cliffs Nuclear Power Plant emissions from the modeled 

concentration at this receptor, the modeled concentration was below the standard. The results of the 

NAAQS analysis are provided in table 2.7.1-9. The modeling demonstrates compliance with the NAAQS. 

We reviewed the FERC Modeling and agree with the conclusions presented.

Because the proposed Project is located in an ozone nonattainment area, we evaluated the need for 

an ozone modeling analysis. The Project would be required to offset the NOx and VOC emissions from the 

stationary sources at the facility at a 1.3 to 1 ratio; resulting in a net emission decrease of ozone precursors. 

Further, because ozone impact modeling is a regional scale assessment tool, rather than a local impact 

identifier, the regional emission reductions within the AQCR to offset the Project emissions can reasonably 

be expected to improve the regional ozone concentrations. Therefore, additional modeling was not required. 
115

TABLE 2.7.1-9

LNG Terminal NAAQS Analysis Summary a

Pollutant Averaging Period Modeled Concentration (μg/m3)

b NAAQS (μg/m3

)

PM10 24-hour 34.4 150

PM2.5 24-hour 34.8 35

PM2.5 Annual 11.8 12

SO2 1-hour 195.997 196

SO2 3-hour 174.5 1,300

SO2 24-hour 65.1 365

SO2 Annual 10.88 80

NO2 1-hour 187.9 188

NO2 Annual 20.8 100

Lead 3-month 0.072 0.15

____________________

a Both gasification (LNG Terminal) and liquefaction (Liquefaction Facilities) were modeled in the FERC modeling analysis for 

demonstrating compliance with the ambient air quality standards. Under the liquefaction scenario, some gasification 

equipment were modeled that operate in a back-up capacity to the liquefaction equipment. 

b Modeled concentration includes the ambient monitored (background) concentration.

μg/m3 = micrograms per cubic meter

SIL = Significant Impact Level.

In addition to the cumulative NAAQS analysis discussed above, DCP submitted in its CPCN/air 

permit application to the Maryland PSC an increment consumption analysis and an Additional Impacts 

Analysis to satisfy PSD permitting requirements for the Liquefaction Facilities. The results of these 

analyses are provided below to disclose further impacts associated with the Liquefaction Facilities. 

PSD increment is the amount of pollution an area is allowed to increase. PSD increments are 

intended to prevent the air quality in attainment areas from deteriorating to the level set by the NAAQS. 

The PSD increment analysis is used to determine whether a proposed project would cause or contribute to 

an exceedance of an applicable PSD increment in conjunction with other existing sources. Federal PSD 

guidelines specify allowable changes in air pollutant concentrations due to industrial expansion in an area. 

The PSD SIL modeling results submitted to the Maryland PSC showed that the predicted maximum 

1-hr NO2, 24-hour PM2.5, and annual PM2.5 concentrations exceed the respective SILs. There is no 1-hour 

NO2 PSD increment; however, a comprehensive PSD increment analysis was required for PM2.5 emissions 

as part of the PSD permit application submitted to the Maryland PSC. 

DCP’s CPCN/air permit application was the first PSD application submitted following the PM2.5

major source baseline date October 20, 2010 and the PM2.5 trigger date of October 20, 2011. Therefore, 

DCP was the only source that needed to be considered in the PM2.5 increment analysis. The modeled 24-

hour and annual PM2.5 concentrations of 3.7 micrograms per cubic meter (μg/m3) and 0.56 μg/m3are below 

the respective PSD increments of 9 μg/m3and 4 μg/m3. 

DCP also submitted to the Maryland PSC an Additional Impacts Analysis as required by the PSD 

regulations. For the growth analysis, no significant commercial, residential, or industrial growth is expected 

as a result of construction/operation of the Liquefaction Facilities. 

Secondary air quality standards are set under the CAA for the protection of public welfare, 

including protection against decreased visibility and damage to animals and vegetation, including crops. 

The NAAQS analysis demonstrated that the Liquefaction Facilities would comply with applicable 
116

secondary NAAQS; therefore, any impacts on vegetation, animals, and other public welfare concerns would 

not be significant.

DCP also reviewed the Project for local visibility impacts and toxic air pollutant concentrations. 

The local visibility impacts were assessed consistent with the EPA’s Workbook for Plume Visual Impact 

Screening and Analysis to determine potential visibility impairment at Calvert Cliffs State Park. The 

analysis was completed using the VISCREEN model and demonstrated that the Project would not cause 

visibility impairment in the Calvert Cliffs State Park. PPRP and MDE agree with DCP’s visibility analyses 

and conclude that it appropriately and conservatively accounts for potential visibility impairment due to the 

proposed Project. We agree with PPRP and MDE.

The toxic air pollutant assessment was completed in accordance with Maryland air permitting 

regulations that require implementation of Best Available Control Technology for Toxics (T-BACT) and 

limits TAP pollutant concentrations at and beyond the facility property line. Fuel burning equipment are 

exempt from these requirements. The primary sources of TAP emissions that would be subject to these 

regulations would be the flares, thermal oxidizer, ammonia slip emissions (from units using SCR emission 

control), and fugitive emissions (equipment leaks). DCP demonstrated in the Maryland CPCN application 

that these sources would comply with both of the TAP requirements. The flares and thermal oxidizer are 

control devices for other emission sources. Their TAP emissions would be minimized through the use of an 

oxidation catalyst (thermal oxidizer) and good operating practices including maintaining proper combustion 

efficiency (flares). There are no add-on control technologies for controlling ammonia slip from SCR 

systems, meanwhile SCR is BACT/LAER for NOx emissions from these sources. Ammonia slip would be 

minimized through good operating practices, including not injecting ammonia into the SCR system until it 

reaches proper operating temperature. The fugitive emissions from the Project would be minimized through 

the use of an LDAR program to minimize leaks. The TAP emissions that were subject to ambient air impact 

assessment were completed using AERMOD, which demonstrated that the Project’s TAP emissions would 

be well below the allowable ambient levels (AALs). PPRP and MDE concurred with DCP’s proposed 

T-BACT determinations and verified that the TAPs analysis are adequate to demonstrate compliance with 

the Maryland TAPs regulations. We agree with PPRP and MDE.

2.7.2 Noise

Construction and operation of the Project facilities would affect the local noise environment in 

the Project area. The ambient sound level of a region, which is defined by the total noise generated 

within the specific environment, is usually comprised of sounds emanating from both natural and artificial 

sources. At any location, both the magnitude and frequency of environmental noise may vary 

considerably over the course of the day and throughout the week, in part due to changing weather 

conditions and the impacts of seasonal vegetative cover.

Two measurements used by some federal agencies to relate the time-varying quality of 

environmental noise to its known effects on people are the equivalent sound level (Leq) and the day-night 

sound level (Ldn). The Leq is an A-weighted sound level containing the same sound energy as the 

instantaneous sound levels measured over a specific time period. Noise levels are perceived differently, 

depending on length of exposure and time of day. The Ldn takes into account the duration and time the 

noise is encountered. Specifically, in the calculation of the Ldn, late night to early morning (10:00 p.m. to 

7:00 a.m.) noise exposures are penalized +10 decibels (dB), to account for people’s greater sensitivity to 

sound during the nighttime hours. The A-weighted scale (dBA) is used because human hearing is less 

sensitive to low and high frequencies than mid-range frequencies. For an essentially steady sound source 

that operates continuously over a 24-hour period and controls the environmental sound level, the Ldn is 

approximately 6.4 dB above the measured Leq. 
117

In 1974, the EPA published its Information on Levels of Environmental Noise Requisite to 

Protect Public Health and Welfare with an Adequate Margin of Safety. This document provides 

information for state and local governments to use in developing their own ambient noise standards. The 

EPA has indicated that an Ldn of 55 dBA protects the public from indoor and outdoor activity 

interference. We have adopted this criterion and use it to evaluate the potential noise impacts from the 

proposed Project at noise sensitive areas (NSAs), such as residences, schools, or hospitals. Due to the 10 

dBA nighttime penalty added prior to calculation of the Ldn, for a facility to meet the Ldn 55 dBA limit, 

it must be designed such that actual constant noise levels on a 24-hour basis do not exceed 48.6 dBA Leq

at any NSA. Also, in general, a person’s threshold of perception for a perceivable change in loudness on 

the A-weighted sound level is about 3 dBA, whereas a 5 dBA change is clearly noticeable, and a 10 dBA 

change is perceived as either twice or half the loud. Maryland noise regulations (COMAR 26.02.03) 

require that the sound level at residential property lines should not exceed 65 dBA during the day (7:00 

a.m. to 10:00 p.m.) or 55 dBA at night (10:00 p.m. to 7:00 a.m.). 

For “periodic noise,” which is defined as “a noise possessing a repetitive on-and-off characteristic 

with a rapid rise to maximum and a short decay not exceeding two seconds,” the allowable levels under 

Maryland noise regulations are 60 dBA during the day and 50 dBA at night. For construction, the noise 

standard is 90 dBA during daytime hours [COMAR 26.02.03.02.B(2)]; however pile driving between the 

hours of 8:00 a.m. and 5:00 p.m. and motor vehicle traffic on public roads are exempted from compliance 

with this noise standard [COMAR 26.02.03.02.C(2)(e) and (i)]. 

Fairfax County, Virginia noise regulations (Fairfax County Code Section 108-4) establish specific 

prohibited activities as well as maximum permissible sound pressure levels based on land use at the noise 

source property line or the receiving area. The Fairfax County noise ordinance specifically prohibits 

operating or causing to be operated any equipment used in construction, repair, alteration, or demolition

work on buildings, structures, streets, alleys, or appurtenances thereto in the outdoors between the hours

of 9:00 p.m. and 7:00 a.m. the following day, except that no such activity shall commence prior to 9:00

a.m. on Sundays and federal holidays. The noise ordinance also limits sound pressure levels to 55 dBA in 

residential areas, 60 dBA in commercial areas, and 72 dBA in industrial areas. However, despite the 

maximum permissible sound pressure levels, the operation of power equipment between the hours of 7:00 

a.m. and 9:00 p.m. the same day is permitted as long as it does not constitute a noise disturbance (Fairfax 

County, 2012). Because the construction activities for the Pleasant Valley Compressor Station would be 

limited to daytime hours, the noise is not expected to exceed the FERC noise guideline (which is an Ldn

metric) or the Fairfax County noise regulation (which allows noise from construction as long as it is 

within the allowable daytime hours). 

The construction activities at the Loudoun M&R Facility and Leesburg Compressor Station 

Contractor Staging Area would be temporary, intermittent, and occur primarily during daytime hours. 

Therefore, these construction activities would be insignificant and are not discussed further in this section.

Existing Noise Conditions

Liquefaction Facilities and Offsite Areas A and B

The existing LNG Terminal is surrounded by undeveloped forest, owned by DCP and held within a 

conservation easement. Nearby land uses include undeveloped State Park forest, residential areas, 

recreational fields, and the Chesapeake Bay. Cove Point Road lies approximately 300 feet south of the 

Fenced Area. A residential area exists to the south of this road. To the west, the Fenced Area is 

approximately 750 feet from the nearest recreation fields at Cove Point Park. To the north, the closest 

boundary of Calvert Cliffs State Park is approximately 1,200 feet away, and to the east, the Chesapeake Bay 
118

lies approximately 1,500 feet away. New equipment associated with the Project would be installed to the 

west and south of currently operating units and would be located entirely within the Fenced Area.

DCP conducted sound survey measurements of the existing LNG Terminal at the two closest NSAs

on March 9, 2010 following construction of the Cove Point Expansion Project. This noise survey 

represented 100 percent send-out capacity and the LNG Terminal equipment was operated at full load 

conditions. NSA 1 is a residence directly across Cove Point Road from the LNG Terminal, about 300 feet 

south of the Fenced Area. NSA 2 is within the Calvert County Park Easement, owned by DCP, on the north 

side of Cove Point Road about 200 feet southwest of the Fenced Area. There are several neighborhoods 

southwest through southeast of the LNG Terminal. These two NSAs represent the closest NSAs to the LNG 

Terminal. Residences, schools, churches, and other NSAs are farther away than the identified NSAs, and 

noise levels from the LNG Terminal would be further attenuated. During the noise survey, the highest Ldn

levels measured were 45.2 dBA and 42.7 dBA at NSA 1 and NSA 2, respectively. 

Pleasant Valley Compressor Station

The land uses surrounding the Pleasant Valley Compressor Station include mostly undeveloped, 

privately owned land (primarily forested), with some residential development. The property to the north and 

east of the Pleasant Valley Compressor Station is currently undeveloped forest. To the south and west of the 

compressor station, the land is currently undeveloped forest with DCP’s existing pipeline right-of-way. The 

nearest residences are 1,800 feet southwest of the station (referred to as NSA-S6) and 3,300 feet west of the 

station (referred to as NSA-S8).

In February 2013, DCP conducted noise surveys at the Pleasant Valley Compressor Station 

property lines and nearest NSAs. The Ldn sound levels measured at the nearest NSAs were 41.8 dBA (NSAS6) and 46.5 dBA (NSA-S8). Because the Fairfax County noise ordinance regulates noise levels at the 

property line, measurements were also taken at the compressor station property lines. The Leq sound levels 

for the Pleasant Valley Compressor Station were only audible at the east and southwest property lines with 

Leq sound levels at 49.3 dBA and 44.6 dBA, respectively. The compressor station was not audible at the 

other property line locations or the NSAs. 

Impacts and Mitigation

Construction Noise Impacts and Mitigation

Construction of the Project facilities would involve operation of general construction equipment and 

noise would be generated during the installation of the Project components. Measures to mitigate 

construction noise would include compliance with federal regulations limiting noise from trucks, proper 

maintenance of equipment, and ensuring that sound muffling devices provided by the manufacturer are kept 

in good working condition. Noise levels would increase in the immediate vicinity of the construction 

activities; however, the noise would be localized and temporary. Nighttime noise levels are not expected

to increase during construction because most construction activities would be limited to daylight hours. 

Nighttime activities would consist of clean-up and staging of materials, which generate less noise than other 

construction activities.

Construction of the Liquefaction Facilities would take approximately 4 years. Construction of the 

modifications to the Pleasant Valley Compressor Station (including the Pleasant Valley Suction/Discharge 

Pipelines and M&R Facility) and Loudoun M&R Facility would take less than 2 years. Construction noise 

would be highly variable because of the types of equipment in use at a construction site change with the 

construction phase and the types of activities. Noise from construction activities may be noticeable at 
119

nearby NSAs; however, construction equipment would be operated on an as-needed basis during the shortterm construction period. 

Noise generated by site preparation at Offsite Areas A and B would be from the use of heavy 

equipment during clearing, grading, and restoration activities within the limits of disturbance. In addition, 

noise would be generated during the use of Offsite Area B for unloading equipment and supplies from 

barges at the temporary pier and the transport of material from the offsite area to the LNG Terminal. In 

order to limit potential impacts on adjacent properties during site preparation and barge offloading, DCP 

would limit site preparation activities to occur from dawn to dusk. Noise would also be generated by the 

approximately 150 truckloads originating from Offsite Area B during the course of construction of the 

Liquefaction Facilities. DCP’s transport of large equipment would typically occur at night to minimize 

potential impacts on traffic by the slow moving vehicles. However, the noise generated by the Projectrelated truck traffic would be short-term, temporary, and intermittent. DCP would perform the loudest and 

most persistent noise generating activities (e.g., tree clearing, stump grinding, hoe ram demolition) during 

daylight hours. Nighttime construction noise generating activities would primarily consist of truck traffic.

Site preparation of the temporary pier at Offsite Area B would include pile driving during daylight 

hours. Pile driving is expected to be the loudest of the construction activities at Offsite Area B. The initial 

pile installation would be completed using a vibratory hammer, with an impact hammer used for final pile 

driving to the required design depth. The pile driving would be performed for intermittent periods of time 

over a 2- to 3-week period. Removal of the temporary pier at the end of the Project would be similar in 

duration, and a vibratory hammer would be used to extract the piles during daytime hours. 

We received comments concerning noise from the construction of the Liquefaction Facilities. 

Construction equipment typically emits noise between 70 and 95 dBA at 50 feet (Federal Highway 

Administration, 2006). The construction noise impacts would be highly variable based on the specific 

equipment in use, number of equipment in use, and the location of the equipment (relative to the noise 

receptor). Based on the types of construction equipment that may be used for construction of the 

Liquefaction Facilities (e.g., trucks, graders, dozers, backhoe), the noise impacts of the construction at the 

nearest NSAs would be below 55 dBA Ldn and 90 dBA Lday. These noise levels are based on the 

implementation of sound mitigation in the form of temporary sound walls around the site perimeter (i.e., 

block line of sight from source to receiver), and/or around the sound source, capable of a 15 dBA reduction, 

which DCP has committed to installing, as well as the presence of soft ground (vegetative ground cover) 

between the source and the NSA. 

Commissioning of the Liquefaction Facilities would include the lighting of the facility flares and 

running them for a period of 2 to 3 days or more. Based on vendor data, these flares would emit about 100 

dBA at 50 feet. The estimated maximum noise level attributable the flares would be 58 dBA Leq and 60 

dBA Leq at the two closest NSAs, which exceeds our noise criterion of 55 dBA Ldn. This is equivalent to the 

sound of an air conditioner located 20 feet away, and normal conversation can be maintained. 

Commissioning activities are expected to occur 24 hours per day; however, DCP has committed to not 

operating the ground flares during nighttime hours without appropriate noise mitigation measures, which 

may include operational limitations, to ensure that the 55 dBA Ldn limit is not exceeded. Because the details 

of the mitigation have not been finalized, we recommend that:

 Prior to commissioning of the Liquefaction Facilities, DCP should file with the 

Secretary the specific noise mitigation measures that would be used on the ground 

flares and a noise analysis demonstrating that the noise from all of the equipment 

operated during commissioning (including ground flares) would not exceed an Ldn

of 55 dBA at the nearby NSAs.
120

Noise generated by construction at the Pleasant Valley Compressor Station would be from the use 

of heavy construction equipment during clearing, grading, trenching, pipe installation, backfilling, and 

restoration activities within the limits of disturbance. In order to limit potential impacts on adjacent 

properties, DCP would limit construction activities to occur from dawn to dusk, typically between the hours 

of 7:00 a.m. and 9:00 p.m., 7 days per week.

Construction activities associated with the proposed Project would result in temporary increases in 

ambient noise levels. Based on the anticipated noise levels attributable to short terms construction activities 

and with the implementation of DCP’s noise mitigation measures, we conclude that noise impact from the 

Project would be in compliance with applicable noise regulations. 

Operational Noise Impacts and Mitigation

Liquefaction Facilities

We received several comments concerning the operational noise impacts from the Liquefaction 

Facilities. Operation of the Liquefaction Facilities would involve numerous noise generating sources 

including, but not limited to, several pumps, flares, blowers, compressors, turbines, turbine intakes, coolers 

fans, condenser fans, and combustion units (boiler, gas turbine, thermal oxidizer, and generator). 

Noise level data for the major facility sources were obtained from equipment vendors and/or from 

measurements of similar sources at other facilities. DCP performed computer modeling using CadnaA 

noise modeling program to predict sound levels that would be generated by operation of the Project. This 

program uses the octave band sound power levels (i.e., the emission levels) of individual sound sources to 

calculate the sound pressure level at the defined receiving site(s). The sound level from each individual 

source at the receiving site (1.5 meters above the ground) are then combined resulting in the cumulative 

sound level at the receiving site. 

Based on the noise modeling analysis, the Liquefaction Facilities would meet the applicable FERC 

and Maryland noise requirements. The following mitigation measures were assumed for the modeling 

analysis:

 Acoustical buildings – numerous equipment would be located inside acoustical buildings 

that would have a noise reduction coefficient of 0.91 and meet specified interior absorption 

and interior to exterior transmission losses.

 Piping noise control – all suction piping from the KO Drum to the compressor body would 

be installed within the compressor building and insulated with ISO Class C insulation (per 

ISO 15665). The discharge piping, to the extent practical, would be installed within the 

compressor building and insulated with Class D insulation (i.e., 2-inch-thick glass or 

mineral fiber insulation covered with a impervious layer with a surface density of 1.0 

pound per square foot; followed by another 2-inch-thick layer of glass or mineral fiber 

insulation with an impervious outer layer of 2.0 pound per square foot.)

 Sound barrier – a 60-foot-high, approximately 3,500-foot-long wall along the south and 

west sides of the Fenced Area constructed of material with a minimum STC of 33 dBA and 

a noise reduction coefficient 0.8.
121

The results of the modeling analysis are summarized in table 2.7.2-1.

TABLE 2.7.2-1

Sound Level Predictions – Liquefaction Facilities

Noise Sensitive Area

Existing 

Sound Level 

Ldn (dBA)

Estimated Facility 

Continuous Sound 

Level Leq

Calculated Sound 

Level Attributable to 

Facility Ldn (dBA)

Calculated Total 

Sound Level at 

NSAs Ldn (dBA)

Increase 

Over Existing 

Sound Level 

Ldn (dBA)

NSA1 (460 feet S) 45.2 46.0 52.4 53.2 8.0

NSA2 (760 feet SW) 42.7 45.3 51.7 52.2 9.5

As indicated in table 2.7.2-1, the noise attributable to the Liquefaction Facilities with implementing 

noise mitigation would be below FERC’s criteria of an Ldn of 55 dBA and Maryland noise regulations. 

Sounds levels would be similar to a typical suburban rea or office and normal conversation can be easily 

maintained. However, to ensure that the actual noise levels resulting from operation of the Liquefaction 

Facilities are not significant, we recommend that:

 DCP should file a full load noise survey at the Liquefaction Facilities with the 

Secretary no later than 60 days after placing the Liquefaction Facilities in service. 

If a full load condition noise survey is not possible, DCP should provide an interim 

survey at the maximum possible operation within 60 days of placing the 

Liquefaction Facilities in service and file the full load operational survey within 6 

months. If the noise attributable to the operation of all of the equipment at the LNG 

Terminal, under interim or full load conditions, exceeds an Ldn of 55 dBA at any 

nearby NSAs, DCP should file a report on what changes are needed and should 

install the additional noise controls to meet the level within 1 year of the in-service 

date. DCP should confirm compliance with the above requirement by filing a 

second noise survey with the Secretary no later than 60 days after it installs the 

additional noise controls.

Pleasant Valley Compressor Station

Noise would generally be produced on a continuous basis at the Pleasant Valley Compressor 

Station by the compressor units and associated air handling units. Noise level data for the main noise 

sources are based on vendor quotes, equipment size, power information, and from experiences with 

similar equipment in compressor station facilities.

A noise analysis for the Pleasant Valley Compressor Station was completed using sound level data 

for the specific equipment planned for the facility and calculations for the noise attenuation over distance. 

The results of the noise analysis are summarized in table 2.7.2-2 for the impacts at the closest NSAs (for 

compliance with the FERC 55 dBA Ldn noise criterion) and highest impacts at the facility property lines (for 

the Fairfax County 55 dBA Leq noise ordinance).

As shown in table 2.7.2-2, the noise level from the modified Pleasant Valley Compressor Station 

with implementing noise mitigation would be below 55 dBA Ldn at the nearest NSAs and 55 dBA Leq at the 

property lines.
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TABLE 2.7.2-2

Sound Level Predictions – Pleasant Valley Compressor Station

Receiving Area

Calculated Ldn

attributable to new

equipment (dBA)

Existing 

Sound Level 

(dBA)

Total Ldn 

(dBA)

Estimated 

Increase 

(dBA)

Calculated Leq

attributable to new 

equipment (dBA)

Calculated 

Total Leq

(dBA)

NSA – S6 (1,800 feet SW) 41.8 40.4 (Ldn) 44.2 0.1 NA NA

NSA – S8 (3,300 feet W) 46.5 33.4(Ldn) 46.7 0.2 NA NA

Property Line – S12 (600 

feet SW)

NA 44.6 (Leq) NA NA 46.2 48.5

Property Line – S15 (450 

feet N)

NA 35.6 (Leq) NA NA 49.2 49.4

The noise analysis assumed that the turbine compressor unit would be enclosed in an acoustically 

designed building with the following noise controls:

 acoustically treated compressor building (e.g., insulated wall, roof panels, doors);

 muffler on the exhaust of the turbine, as well as acoustic insulation on the exhaust pipe 

from the building wall to the exhaust muffler inlet flange (including expansion joint);

 air cleaner/silencer on the air intake of the turbine, as well as acoustic insulation on the 

intake cleaner outlet flange (including expansion joint);

 adequate cooling to allow full load operation of the turbine unit with all doors closed:

o air handling units;

o ventilation air inlet mufflers in the air paths between air handling units and the 

compressor building wall;

o wall air inlet fans;

o ventilation air inlet mufflers located in the walls of the compressor building 

directly outside of the wall air inlet fans to reduce the sound from the turbine 

compressor unit that escapes through these openings; and

o compressor station building ventilation system with roof air discharge hoods with 

mufflers located under each ventilation air discharge hood (but above the roof) to 

reduce sound from the turbine compressor unit that escapes through these 

openings;

 limitations on maximum noise from the lube oil cooler;

 aboveground sections of the unit suction, discharge and bypass lines (including metal 

pipe supports) of the turbine compressor unit would be acoustically insulated if required; 

and

 limitations on the maximum A-weighted sound level from the silenced unit blow down 

vent.
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In addition, DCP would install an approximately 800-foot-long, 20-foot-high sound barrier wall 

along the eastern side of the compressor station site to reduce impacts from noise generated by operation of 

Pleasant Valley Compressor Station on the surrounding area.

As indicated in table 2.7.2-2, the noise attributable to the modified Pleasant Valley Compressor 

Station would be below our criteria of an Ldn of 55 dBA and the Fairfax County noise requirement of 55 

dBA Leq at the property line. Additionally, the estimated noise increase at the nearby NSAs would range 

from 0.1 to 0.2 dBA, which is below the 3 dBA threshold of noticeable difference for humans. However, to 

ensure that the actual noise levels resulting from operation of the modified Pleasant Valley Compressor 

Station are not significant, we recommend that:

 DCP should file noise surveys with the Secretary no later than 60 days after placing 

the modified Pleasant Valley Compressor Station in service. If a full load condition 

noise survey is not possible, DCP should provide an interim survey at the maximum 

possible horsepower load and provide the full load survey within 6 months. If the 

noise attributable to the operation of all of the equipment at the compressor station, 

under interim or full horsepower load conditions, exceeds an Ldn of 55 dBA at any 

nearby NSAs, DCP should file a report on what changes are needed and should 

install the additional noise controls to meet the level within 1 year of the in-service 

date. DCP should confirm compliance with the above requirement by filing a 

second noise survey with the Secretary no later than 60 days after it installs the 

additional noise controls.

Blow downs

We received comments concerning the noise from blow downs. In addition to normal operational 

noise, there may also be sources of noise due to maintenance or emergency operation. Specifically, 

emergencies and maintenance activities involve blow downs (depressurizing/emptying station equipment to 

remove natural gas). Based on information from DCP, the blow downs at the Pleasant Valley Compressor 

Station are typically infrequent and may be silenced or unsilenced. Annual testing of the emergency 

shutdown (ESD) system would be required and may include unsilenced blow downs. DCP typically 

attempts to provide advanced notice to nearby residents at least 2 hours before the activity begins. 

Unsilenced ESD blow downs typically last 1 to 2 minutes. Other activations of the ESD system due to an 

emergency are very infrequent (on average less than once per year).

Silenced blow down events are more frequent for schedule maintenance of the compressor 

equipment. These scheduled events may occur multiple times per year. DCP blow down silencers would 

reduce the gas velocity of the exiting gas and muffle the resulting noise to limit the noise 60 dBA at 50 feet. 

DCP would not plan to provide notifications for these silenced blow downs.

2.8 RELIABILITY AND SAFETY

2.8.1 Virginia Facilities 

The pressurization of natural gas at a compressor station involves some risk to the public in the 

event of an accident and subsequent release of gas. The greatest hazard is a fire or explosion following a 

leak, or rupture at the facility. Methane, the primary component of natural gas, is colorless, odorless, and 

tasteless. It is not toxic, but is classified as a simple asphyxiate, possessing a slight inhalation hazard. If 

breathed in high concentration, oxygen deficiency can result in serious injury or death.
124

The DOT is mandated to provide pipeline safety under Title 49, U.S.C. Chapter 601. The DOT’s 

PHMSA, Office of Pipeline Safety (OPS) administers the national regulatory program to ensure the safe 

transportation of natural gas and other hazardous materials by pipeline. It develops safety regulations and 

other approaches to risk management that ensure safety in the design, construction, testing, operation, 

maintenance, and emergency response of pipeline facilities. Many of the regulations are written as 

performance standards which set the level of safety to be attained and allow the pipeline operator to use 

various technologies to achieve safety. PHMSA ensures that people and the environment are protected 

from the risk of pipeline incidents. This work is shared with state agency partners and others at the 

federal, state, and local level. 

The US DOT provides for a state agency to assume all aspects of the safety program for intrastate 

facilities by adopting and enforcing the federal standards. A state may also act as DOT's agent to inspect 

interstate facilities within its boundaries; however, the DOT is responsible for enforcement actions. OPS 

federal inspectors perform inspections on interstate natural gas pipeline facilities in Maryland. 

The DOT pipeline standards are published in Parts 190-199 of Title 49 of the CFR. Part 192 

specifically addresses natural gas pipeline safety issues, including compressor stations.

The modifications at the Pleasant Valley Compressor Station must be designed, constructed, 

operated, and maintained in accordance with the DOT Minimum Federal Safety Standards in 49 CFR Part 

192. The regulations are intended to ensure adequate protection for the public and to prevent facility 

accidents and failures. 

Part 192.163 – 192.173 of 49 CFR specifically addresses design criteria for compressor stations, 

including emergency shutdowns and safety equipment. Part 192 also requires a pipeline operator to 

establish a written emergency plan that includes procedures to minimize the hazards in an emergency. 

Additionally, the operator must establish a continuing education program to enable the public, 

government officials, and others to recognize an emergency at the facility and report it to appropriate 

public officials. DCP would provide the appropriate training to local emergency service personnel before 

the facilities are placed in service. 

The construction and operation of the modified Pleasant Valley Compressor Station would 

represent a minimum increase in risk to the nearby public. With implementation of the required design 

criteria for the compressor station modifications, the Pleasant Valley Compressor Station would be 

constructed and operated safely.

2.8.2 Regulatory Agencies

Three federal agencies share regulatory authority over the siting, design, construction, and 

operation of LNG import terminals: the USCG, the DOT, and the FERC. The USCG regulates the safety 

of an LNG facility’s marine transfer area and LNG marine traffic, and regulates security plans for the 

entire LNG facility and LNG marine traffic. Those standards are codified in 33 CFR Parts 105 and 127. 

The DOT establishes federal safety standards for siting, construction, operation, and maintenance of 

onshore LNG facilities, as well as for the siting of marine cargo transfer systems at waterfront LNG 

plants. Under federal law, the DOT is the lead federal agency with the authority to establish remote siting 

requirements. Those standards are codified in 49 CFR 193. Under the NGA and delegated authority 

from the DOE, the FERC authorizes the siting and construction of LNG import and export facilities.

In 1985, the FERC and DOT entered into a memorandum of understanding (MOU) regarding the 

execution of each agency’s respective statutory responsibilities to ensure the safe siting and operation of 
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LNG facilities. In addition to the FERC’s existing ability to impose requirements to ensure or enhance 

the operational reliability of LNG facilities, the MOU specified that the FERC may, with appropriate 

consultation with DOT, impose more stringent safety requirements than those in Part 193.

In February 2004, the USCG, DOT, and the FERC entered into an Interagency Agreement to 

ensure greater coordination among these three agencies in addressing the full range of safety and security 

issues at LNG terminals, including terminal facilities and tanker operations, and maximizing the exchange 

of information related to the safety and security aspects of the LNG facilities and related marine 

operations. Under the Interagency Agreement, the FERC is the lead federal agency responsible for the 

preparation of the analysis required under NEPA for impacts associated with terminal construction and 

operation. The DOT and USCG, when necessary, participate as cooperating agencies. All three agencies 

have some oversight and responsibility for inspection and compliance during the facility’s operation.

As part of the review required for a FERC authorization, we must ensure that all proposed LNG 

facilities would operate safely and securely. The design information that must be filed in the application 

to the Commission is specified by 18 CFR 380.12 (m) and (o). The level of detail necessary for this 

submittal requires the Project sponsor to perform substantial front-end engineering of the complete 

facility. The design information is required to be site-specific and developed to the extent that further 

detailed design would not result in changes to the siting considerations, basis of design, operating 

conditions, major equipment selections, equipment design conditions, or safety system designs which we 

considered during our review process. FERC’s filing regulations also require each applicant to identify 

how its proposed design would comply with DOT’s siting requirements of 49 CFR 193, Subpart B. As 

part of our NEPA review, we use this information from the applicant, developed to comply with DOT’s 

regulations, to assess whether or not a facility would have a public safety impact. As a cooperating 

agency, DOT assists FERC staff in evaluating whether an applicant’s proposed siting meets the DOT 

requirements. If a facility is constructed and becomes operational, the facility would be subject to DOT’s 

inspection program. Final determination of whether a facility is in compliance with the requirements of 

49 CFR 193 would be made by DOT staff.

In accordance with 33 CFR 127, the USCG has reviewed the proposed liquefaction facilities and 

stated that the existing WSA and LOR are adequate for the service associated with the proposed 

modifications. A copy of the correspondence between DCP and the USCG is included in Appendix 1-B 

of Resource Report 1.10

2.8.3 Hazards

Before liquefaction, DCP would pre-treat the feed gas for the removal of mercury, hydrogen 

sulfide (H2S), and CO2. The hazards associated with the removal of these substances from the feed gas 

stream result from the physical and chemical properties, flammability, and/or toxicity of mercury, H2S, 

and amine. DCP proposes a design capacity to handle up to 20 micrograms per normal cubic meter 

(μg/Nm3) mercury, 4 parts per million by volume (ppm-v) H2S, and 2 mole percent CO2. However, lower 

quantities and concentrations of these substances would be expected in the natural gas feed stream and 

would not pose a hazard to the public. Mercury would be removed from the feed gas stream by 

adsorption in the Mercury Removal Unit. H2S and CO2 would be removed from the feed gas stream in 

the Acid Gas Removal Unit using 50 percent aqueous diglycolamine (amine) solution. As the CO2 and 

H2S are removed by the amine solution, these substances would accumulate within the amine solution and 

reduce the effectiveness of the system. Therefore, the amine solution would be regenerated periodically, 

where an acid gas stream with concentrations up to 190 ppm-v H2S and 96 mole percent CO2 would be 

separated from the contaminated amine solution and routed to the Sulfur Removal Unit and Thermal 

 

10 Accession number: 20130401-5045.
126

Oxidizer for further treatment prior to discharging to the atmosphere. DCP would need to replace the 

Mercury Removal and Sulfur Removal beds by the end of their service life. Maintenance and safety 

procedures would cover the proper replacement and disposal of these beds. The amine solution would be 

contained, as discussed under “Impoundment Sizing” in section 2.8.6, and handled at temperatures below 

the point at which it could produce enough vapors to form a flammable mixture. Therefore, the amine 

solution would not pose a significant hazard to the public, which would have no access to the on-site 

areas.

DCP would install a Heavy Hydrocarbon Removal Unit (HRU) to condense pentane and heavier 

hydrocarbons that may be present in the feed gas. During this removal process, natural gas liquid (NGL)

would be extracted and handled on-site at temperature and pressure conditions under which a loss of 

containment would result primarily in a vapor release and the ability to produce damaging overpressures. 

The resulting stabilized condensate, which includes pentane and heavier hydrocarbons, would be stored 

on-site at atmospheric pressure and temperature. Due to the temperature and pressure conditions under 

which the stabilized condensate would be stored and handled, a loss of containment would primarily 

result in a liquid release. However, DCP proposes to partially bury and mound the stabilized condensate 

storage tank under minimum 2-feet of soil. The liquid spill would be contained within the buried area and 

would not present an offsite hazard to the public. The principal hazards associated with the storage and 

sendout of condensate would result from loss of containment and the flammability and toxicity of the 

substances used or produced in the heavy hydrocarbon removal system.

The principal hazards associated with the liquefaction and storage of LNG and refrigerants result 

from loss of containment, vapor dispersion characteristics, flammability, and the ability to produce 

damaging overpressures. A loss of the containment provided by storage tanks or process piping would 

result in the formation of flammable vapor at the release location, as well as from any LNG or liquid 

flammable refrigerant that pooled. Releases occurring in the presence of an ignition source would most 

likely result in a fire at the vapor source. A spill without ignition would form a vapor cloud that would 

travel with the prevailing wind until it either dispersed below the flammable limits or encountered an 

ignition source. In some instances, ignition of a vapor cloud may produce damaging overpressures. 

These hazards are described in more detail below.

Loss of Containment

A loss of containment is the initial event that results in all other potential hazards. The initial loss 

of containment can result in a liquid and/or gaseous release with the formation of vapor at the release 

location, as well as from any liquid that pooled. The fluid released may present low or high temperature 

hazards, and may result in the formation of flammable vapors. The extent of the hazard will depend on 

the material released, the storage and process conditions, and the volumes released.

DCP would store the following on-site: LNG at atmospheric pressure and at a cryogenic 

temperature of approximately -260 °F; liquid ethane at approximately 130 psig and -30°F; liquid propane 

at ambient temperature and elevated pressures (similar to the conditions typically used in propane storage 

and distribution); and stabilized condensate at ambient temperature and pressure.

The MR process stream would consist of methane, ethane, propane, and nitrogen. Cryogenic 

temperatures as low as -258°F would occur within the MR process stream used to liquefy the feed gas. 

The temperature of NGL in the heavy hydrocarbon removal process stream would be as low as -67°F. 

Loss of containment of LNG, mixed refrigerant liquid (MRL), and NGL could lead to the release of both 

liquid and vapor into the immediate area. Exposure to either cold liquid or vapor could cause freeze 

burns and, depending on the length of exposure, more serious injury or death. However, spills would be 

contained to on-site areas and the cold state of these releases would be greatly limited due to the 
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continuous mixing with the warmer air. The cold temperatures from the release would not present a 

hazard to the public, which would not have access to on-site areas.

LNG and MRL are cryogenic liquids that would quickly cool any materials contacted by the 

liquid on release, causing extreme thermal stress in materials not specifically designed for such 

conditions. These thermal stresses could subsequently subject the material to brittleness, fracture, or 

other loss of tensile strength. These temperatures, however, would be accounted for in the design of 

equipment and structural supports, and would not be substantially different from the hazards associated 

with the storage and transportation of liquid oxygen (-296oF) or several other cryogenic liquids that have 

been routinely produced and transported in the United States.

Vapor Dispersion

In the event of a loss of containment, LNG, ethane, propane, and NGL would vaporize on release 

from any storage or process facilities. Depending on the size of the release, cryogenic liquids, such as 

LNG and MRL, as well as NGL may form a liquid pool and vaporize. Additional vaporization would 

result from exposure to ambient heat sources, such as water or soil. When released from a containment 

vessel or transfer system, LNG will generally produce 620 to 630 standard cubic feet (ft3) of natural gas 

for each cubic foot of liquid. Ethane will produce approximately 370 ft3 of gas for each cubic foot of 

liquid. Propane will produce approximately 274 ft3 of gas for each cubic foot of liquid. The composition 

of NGL would vary throughout the heavy hydrocarbon removal process and may produce up to 275 ft3 of 

gas for each cubic foot of liquid. In the event of a loss of containment of stabilized condensate, the 

stabilized condensate would spill primarily as a liquid and form a pool, but would vaporize much more 

slowly than NGL.

If the loss of containment does not result in immediate ignition of the hydrocarbons, the vapor 

cloud would travel with the prevailing wind until it either encountered an ignition source or dispersed 

below its flammable limits. An LNG release would form a denser-than-air vapor cloud that would sink to 

the ground due to the cold temperature of the vapor. As the LNG vapor cloud disperses downwind and 

mixes with the warm surrounding air, the LNG vapor cloud may become buoyant. However, 

experimental observations and vapor dispersion modeling indicate the LNG vapor cloud would not 

typically be warm, or buoyant, enough to lift off from the ground before the LNG vapor cloud disperses 

below its lower flammability limit (LFL). A liquid ethane release would form a denser-than-air vapor 

cloud that would sink to the ground due to the cold temperature of the vapor. As the ethane vapor cloud 

disperses downwind and mixes with the warm surrounding air, the ethane vapor would become neutrally 

buoyant. A propane release would form a denser-than-air vapor cloud that would sink to the ground; 

however, propane would remain denser than the surrounding air, even after warming to ambient 

temperatures. The composition of NGL would vary throughout the heavy hydrocarbon removal process; 

therefore, a release in the NGL stream may form either a neutrally buoyant or a denser-than-air vapor 

cloud, even after warming to ambient temperatures.

Methane and heavier hydrocarbons are classified as simple asphyxiates and may pose extreme 

health hazards, including death, if inhaled in significant quantities within a limited time. Very cold 

methane and heavier hydrocarbons vapors may also cause freeze burns. However, the locations of 

concentrations where cold temperatures and oxygen-deprivation effects could occur are greatly limited 

due to the continuous mixing with the warmer air surrounding the spill site. For that reason, exposure 

injuries from contact with releases of methane and heavier hydrocarbons normally represent negligible 

risks to the public.
128

Vapor Cloud Ignition

Flammability of the vapor cloud is dependent on the concentration of the vapor when mixed with 

the surrounding air. In general, higher concentrations within the vapor cloud would exist near the spill, 

and lower concentrations would exist near the edge of the cloud as it disperses downwind. Mixtures 

occurring between the LFL and the upper flammability limit (UFL) can be ignited. Concentrations above 

the UFL or below the LFL would not ignite.

The LFL and UFL for methane are approximately 5%-vol and 15%-vol in air, respectively. 

Propane has a narrower flammability range, with a LFL of approximately 2%-vol and a UFL of 9.5%-vol 

in air. Ethane has a wider flammability range and a LFL of approximately 2.9% vol and a UFL of 13%-

vol in air. NGL has a LFL of approximately 2.8%- vol and a UFL of approximately 13%-vol. 

Condensate has a LFL of approximately 1.2%-vol and a UFL of approximately 7.8%-vol.

If the flammable portion of a vapor cloud encounters an ignition source, a flame would propagate 

through the flammable portions of the cloud. In most circumstances, the flame would be driven by the 

heat it generates. This process is known as a deflagration. An LNG vapor cloud deflagration in an 

uncongested and unconfined area travels at slower speeds and does not produce significant pressure 

waves. However, exposure to this LNG vapor cloud fire can cause severe burns and death, and can ignite 

combustible materials within the cloud. Overpressures of LNG, NGL, and refrigerant vapor clouds are 

discussed later in this section under “Overpressures.”

A deflagration may propagate back to the spill site if the vapor concentration along this path is 

sufficiently high to support the combustion process. When the flame reaches vapor concentrations above 

the UFL, the deflagration could transition to a fireball and result in a pool or jet fire back at the source. A 

fireball would occur near the source of the release and would be of a relatively short duration compared to 

an ensuing jet or pool fire.

The extent of the affected area and the severity of the impacts on objects either within an ignited 

cloud or in the vicinity of a pool fire would primarily be dependent on the quantity and duration of the 

initial release, the surrounding terrain, and the environmental conditions present during the dispersion of 

the cloud. Radiant heat and dispersion modeling are discussed in section 2.8.6.

Fires may also cause failures of nearby storage vessels, piping, and equipment. The failure of a 

pressurized vessel could cause fragments of material to fly through the air at high velocities, posing 

damage to surrounding structures and a hazard for operating staff, emergency personnel, or other 

individuals in proximity to the event. In addition, failure of a pressurized vessel when the liquid is at a 

temperature significantly above its normal boiling point could result in a boiling-liquid-expanding-vapor 

explosion (BLEVE). BLEVEs of flammable liquids can produce overpressures and a subsequent fireball 

when the superheated liquid rapidly changes from a liquid to a vapor upon the release from the vessel. 

The refrigerant make-up tanks and condensate storage tanks would be partially buried and mounded under 

a minimum of 2-feet of soil to mitigate radiant heat from nearby fires. This mitigation addresses a fire 

from one tank causing a failure to an adjacent tank(s) and would effectively result in a negligible risk of a 

BLEVE from the refrigerant and condensate storage area.

Overpressures

If the deflagration in a flammable vapor cloud accelerates to a sufficiently high rate of speed, 

pressure waves would be generated. As a deflagration accelerates to super-sonic speeds, larger pressure 

waves are produced, and a shock wave created. This shock wave, rather than the heat, would begin to 

drive the flame, resulting in a detonation. Deflagrations or detonations are often characterized more 
129

generally as explosions when the rapid movement of the flame and pressure waves associated with them 

cause additional damage. The amount of damage an explosion causes is dependent on the amount the 

pressure wave is above atmospheric pressure (i.e. an overpressure) and its duration (i.e., pulse). For 

example, a 1 psi overpressure is often cited as a safety limit in regulations and is associated with glass 

shattering and traveling with velocities high enough to lacerate skin. 

Flame speeds and overpressures are primarily dependent on the reactivity of the fuel, the ignition 

strength and location, the degree of congestion and confinement of the area occupied by the vapor cloud, 

and the flame travel distance.

The potential for unconfined LNG vapor cloud detonations was investigated by the USCG in the 

late 1970s at the Naval Weapons Center in China Lake, California. Using methane, the primary 

component of natural gas, several experiments were conducted to determine whether unconfined LNG 

vapor clouds would detonate. Unconfined methane vapor clouds ignited with low-energy ignition sources 

(13.5 joules), produced flame speeds ranging from 12 to 20 mph. These flame speeds are much lower 

than the flame speeds associated with a deflagration with damaging overpressures or a detonation.

To examine the potential for detonation of an unconfined natural gas cloud containing heavier 

hydrocarbons that are more reactive, such as ethane and propane, the USCG conducted further tests on 

ambient-temperature fuel mixtures of methane-ethane and methane- propane. The tests indicated that the 

addition of heavier hydrocarbons influenced the tendency of an unconfined natural gas vapor cloud to 

detonate. Natural gas with greater amounts of heavier hydrocarbons would be more sensitive to 

detonation.

Although it has been possible to produce damaging overpressures and detonations of unconfined 

LNG vapor clouds, the feed gas stream proposed for the Project would have lower ethane and propane 

concentrations than those that resulted in damaging overpressures and detonations. The substantial 

amount of initiating explosives needed to create the shock initiation during the limited range of vapor-air 

concentrations also renders the possibility of detonation of these vapors at an LNG plant as unrealistic. 

As discussed in the “Vapor Dispersion” and “Vapor Cloud Ignition” sections above, the primary hazards 

to the public from an LNG spill that disperses to an unconfined area, either on land or water, would be 

from dispersion of the flammable vapors or from radiant heat generated by a pool fire.

Ignition of a confined LNG vapor cloud could result in higher overpressures. In order to prevent 

such an occurrence, DCP would take measures to mitigate the vapor dispersion and ignition into confined 

areas, such as buildings. DCP plans to install hazard detection devices at all combustion and ventilation 

air intake equipment to enable isolation and deactivation of any combustion equipment whose continued 

operation could add to, or sustain, an emergency. We are including a recommendation that DCP file 

detailed information and locations of these hazard detection devices (see section 2.8.4). 

We received a comment that gas detection devices installed at the gas turbine air intakes are not 

sufficient to eliminate an ignition source from released flammable vapors. There are approximately 250 

gas detection devices currently installed at the LNG Terminal, and DCP proposes to install at least 180

additional gas detection devices throughout the Liquefaction Facilities. The preliminary hazard detection 

layouts for the proposed Liquefaction Facilities show gas detection devices strategically located in 

proximity to potential release sources. In addition, there would be numerous measures in place such as 

spill containment, instrumentation, alarms, safety instrumented systems, and ESD systems that would 

mitigate a hydrocarbon release before a flammable vapor cloud would reach an air intake. Furthermore, 

we are recommending that the gas detection devices would be calibrated to detect any hydrocarbon 

release (methane, propane, ethane, or condensate) to ensure any process release would be detected (see 

section 2.8.4).
130

In comparison with LNG vapor clouds, there is a higher potential for unconfined propane clouds 

to produce damaging overpressures, and an even higher potential for unconfined ethane vapor clouds to 

produce damaging overpressures. Unconfined ethane vapor clouds also have the potential to transition to 

a detonation much more readily than propane. This has been shown by multiple experiments conducted 

by the Explosion Research Cooperative to develop predictive blast wave models for low, medium, and 

high reactivity fuels and varying degrees of congestion and confinement (Pierorazio, 2005). The 

experiments used methane, propane, and ethylene, as the respective low, medium, and high reactivity 

fuels. In addition, the tests showed that if methane, propane, or ethylene is ignited within a confined

space, such as in a building, they all have the potential to produce damaging overpressures. The MRL 

and NGL process streams would contain a mixture of components such as the ones discussed above (i.e., 

ethane and propane). Therefore, a potential exists for these process streams to produce unconfined vapor 

clouds that could produce damaging overpressures in the event of a release.

Discussions of these hazards and potential mitigation are in section 2.8.6 for the liquefaction 

facilities.

Past LNG Facility Incidents

With the exception of the October 20, 1944, failure at an LNG facility in Cleveland, Ohio, the 

operating history of the U.S. LNG industry has been free of safety-related incidents resulting in adverse 

effects on the public or the environment. The 1944 incident in Cleveland led to a fire that killed 128 

people and injured 200 to 400 more people. The failure of the LNG storage tank was due to the use of 

materials inadequately suited for cryogenic temperatures. LNG migrating through streets and into 

underground sewers due to the lack of adequate spill impoundments at the site was also a contributing 

factor. Current regulatory requirements ensure that proper materials suited for cryogenic temperatures are 

used and that spill impoundments are designed and constructed properly to contain a spill at the site.

Another operational accident occurred in 1979 at the Cove Point LNG facility in Lusby, 

Maryland. A pump seal failure resulted in gas vapors entering an electrical conduit and settling in a 

confined space. When a worker switched off a circuit breaker, the gas ignited, causing heavy damage to 

the building and a worker fatality. With the participation of the FERC, lessons learned from the 1979 

Cove Point accident resulted in changing the national fire codes to ensure that the situation would not 

occur again.

On January 19, 2004, a blast occurred at Sonatrach’s Skikda, Algeria, LNG liquefaction facility, 

which killed 27 and injured 56 workers. No members of the public were injured. Findings of the

accident investigation suggested that a cold hydrocarbon leak occurred at Liquefaction Train 40 and was 

introduced to the high-pressure steam boiler by the combustion air fan. An explosion developed inside 

the boiler firebox, which subsequently triggered a larger explosion of the hydrocarbon vapors in the 

immediate vicinity. The resulting fire damaged the adjacent liquefaction process and liquid petroleum 

gas (LPG) separation equipment of Train 40, and spread to Trains 20 and 30. Although Trains 10, 20,

and 30 had been modernized in 1998 and 1999, Train 40 had been operating with its original equipment 

since start-up in 1981. As indicated in section 2.8.3 “Overpressures,” DCP would install hazard detection 

devices at all combustion and ventilation systems to enable isolation and deactivation of any combustion 

equipment whose continued operation could add to, or sustain, an emergency. We would review the final 

design to confirm the location and shutdown capabilities of these devices. 

On March 31, 2014, an explosion and fire occurred at Northwest Pipeline Corporation’s LNG 

peak-shaving facility in Plymouth, Washington. The facility was immediately shut down, and emergency 

procedures were activated, which included notifying local authorities and evacuating all plant personnel. 

No members of the public were injured. The accident investigation is still in progress. If measures to 
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address any causal factors which led to this incident are developed, they will be applied to all facilities 

under the Commission’s jurisdiction.

Throughout its operational life, the Cove Point facility has been subject to FERC’s reporting and 

inspection requirements for LNG facilities and must regularly report facility changes in operating 

conditions and any abnormal operating experiences.11 We received a comment requesting a list and 

description of incidents that have occurred at the facility, along with explanations of causes and 

subsequent changes made to address the causes. DCP reported the following incidents related to either 

the commissioning of equipment or activities by outside contractors performing maintenance activities. 

In 2003, a lap weld on the bottom of one of the LNG tanks failed due to excessive contraction during tank 

cool-down. The tank was isolated from the rest of the facility, warmed up, and repaired. DCP’s 

corrective actions included additional flow rate monitoring and communications procedures during tank 

cool-down activities. In 2007, contractors erected scaffolding near a heating coil and one of the wooden 

scaffolding boards ignited. In order to address this, DCP instituted additional oversight procedures for the 

activities of contractors when on site. In 2010, a contractor drowned while performing maintenance on 

the offshore pier piles. The contracting company subsequently updated its safety plan.

DCP has also reported minor natural gas leaks from piping and valve packing during normal 

operations. In these cases, staff monitoring, instrumentation, and detection devices identified the issue, 

allowing the equipment to be shut-down and isolated for repair or maintenance. None of these natural gas 

releases resulted in impacts on the public. DCP’s corrective actions included targeted piping connection 

inspections and increased monitoring.

The most significant event involving facility operations occurred in 1979. A pump seal failure 

resulted in gas vapors entering an electrical conduit and settling in a confined space. When a worker 

switched off a circuit breaker, the gas ignited, causing heavy damage to the building and a worker fatality. 

With the participation of the FERC, lessons learned from the 1979 Cove Point accident resulted in 

changing the national fire codes to ensure that flammable vapors do not migrate through the electrical 

system. 

2.8.4 Technical Review of the Preliminary Engineering Design

Operation of the proposed facility poses a potential hazard that could affect the public safety if 

strict design and operational measures to control potential accidents are not applied. The primary 

concerns are those events that could lead to an LNG spill of sufficient magnitude to create an off-site 

hazard as discussed in section 2.8.3. However, it is important to recognize the stringent requirements in 

place for the design, construction, operation, and maintenance of the facility, as well as the extensive 

safety systems proposed to detect and control potential hazards.

In general, we consider an acceptable design to include multiple protection systems or safeguards 

to reduce the risk of a potentially hazardous scenario from developing into an event that could impact the 

off-site public. These layers of protection should be independent of one another so that each could 

perform its function regardless of the action or failure of any other protection layer or initiating event. 

Such design features and safeguards typically include:

 

11

 LNG import operations at the Cove Point facility began in 1978, but ended in 1980 when major changes in the 

market for natural gas led to a suspension of LNG importation activity. Between 1980 and 1995 the facility 

remained in a standby mode with no LNG operations. In 1995, the facility installed liquefaction equipment and 

resumed operations by providing peaking and storage services. Import operations and maritime transit resumed 

in 2003. 
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 a facility design that prevents hazardous events through the use of suitable materials of 

construction; operating and design limits for process piping, process vessels, and storage

tanks; adequate design for wind, flood, seismic, and other environmental hazards;

 control systems, including monitoring systems and process alarms, remotely operated 

control and isolation valves, and operating procedures to ensure the facility stays within 

the established operating and design limits;

 safety-instrumented prevention systems, such as safety control valves and ESD systems, 

to prevent a release if operating and design limits are exceeded;

 equipment protection systems, such as pressure relief valves, proper equipment and 

building spacing, appropriate electrical area classification, spill containment, and 

structural fire protection, to prevent escalation to a more severe event;

 emergency response, including hazard detection and control equipment, firewater 

systems, on-site fire-fighting personnel and equipment, and coordination with local first 

responders to mitigate the consequences of a release and prevent it from escalating to a 

larger event; and

 site security measures for controlling access to the facility, including security inspections 

and patrols; response procedures to any breach of security and liaison with local law 

enforcement officials.

We find that the inclusion of such protection systems or safeguards in a facility design would 

minimize the potential for an initiating event to develop into an incident that could impact the safety of 

the off-site public. In addition, siting of the facility with regard to potential off- site consequences can be 

further used to minimize impacts to public safety. As discussed in section 2.8.5, DOT’s regulations in 49 

CFR 193, Subpart B require a siting analysis be performed by DCP.

As part of its application, DCP provided a FEED for the Project. In developing the FEED, DCP 

conducted a pre-Process Hazards Analysis (PHA) and a pre-Hazards and Operability Study (HAZOP) to 

identify potential risk scenarios. These studies provided a qualitative evaluation of a range of possible 

safety, health, and environmental effects which may result from the operation of the facility. Based on 

these major hazards, DCP included process and safety instrumentation, mitigation, and/or administrative 

controls to address the identified issues.

As part of our review of this Project, we analyzed the information filed by DCP to determine the 

extent that layers of protection or safeguards were included. Our review focused on the engineering 

design and safety concepts of the various protection layers, as well as the projected operational reliability 

of the proposed facilities. The design would use materials of construction suited to the pressure and 

temperature conditions of the process design. Piping would be designed, fabricated, assembled, erected, 

inspected, examined, and tested in accordance with American Society of Mechanical Engineers (ASME) 

B31.1 and ASME B31.3. Pressure vessels would be designed in accordance with ASME Section VIII and 

the storage tanks would be designed in accordance with API Standard 620, per 49 CFR 193 and the 

NFPA’s Standard 59A (NFPA 59A). Valves and other equipment would be designed to accepted good 

engineering practices.

As proposed in the NFPA 59A Preliminary Fire Protection Review filed on January 24, 2014, 

DCP would design facilities that contain LNG (such as the MCHE, expander, reboiler, nitrogen stripper, 

LNG pump structure, and pipe rack supporting LNG lines), as well as the condensate stabilizer column, to 
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withstand a sustained design wind speed of 150 mph (183.3 mph with a gust of 3-second duration). For 

equipment and piping not containing LNG, DCP proposes a design wind speed of 110 mph with a gust of 

3-second duration. DCP states storage, piping, compressors, condensers, and process vessels associated 

with the refrigerant systems would be designed to this 110-mph wind speed. As part of its role as a 

cooperating agency on this document, DOT provided comments stating that use of this wind speed for 

this equipment may not meet its regulatory requirements. Under 49 CFR § 193.2067, DOT requires the 

use of an assumed sustained wind velocity of not less than 150 mph for all equipment used for liquefying, 

transferring, storing, or vaporizing LNG. Alternative wind speeds may be approved by DOT provided 

they are justified by adequate wind data and an acceptable probabilistic methodology. As such, DCP 

either must design the facilities to accommodate wind forces based on a sustained wind velocity of 150 

mph or may request DOT approval for use of a lower wind speed under the regulatory means listed in § 

193.2067(b). As a result, we recommend that:

 Prior to the construction of the final design, DCP should file with the Secretary for 

review and written approval by the Director of OEP, certification that the final 

design has been modified to be consistent with the wind speed requirements of 49 

CFR § 193.2067 or that DOT has approved the use of a lower wind speed as allowed 

by § 193.2067(b). DCP should consult with DOT on any actions necessary to 

demonstrate compliance with Part 193. 

The site elevation ranges from 70 feet to 130 feet above mean sea level (NGVD29), with the 

majority of the existing and proposed facilities located at an elevation of more than 110 feet above mean 

sea level. The seismic and structural design of the liquefaction facilities are discussed in section 2.1.2.

DCP would install process control valves and instrumentation to safely operate and monitor the 

facility. Alarms would have visual and audible notification in the control room to warn operators that 

process conditions may be approaching design limits. Operators would have the capability to take action 

from the control room to mitigate an upset. DCP would expand the existing facility operation procedures 

to include the liquefaction facilities after completion of the final design; this timing is fully consistent 

with accepted industry practice. We are recommending that DCP provide updated operating and 

maintenance procedures for FERC review as they are developed, as listed in this section. In addition, we 

are recommending measures such as labeling of instrumentation and valves (i.e., car-sealed and/or locked 

valves) to address human error and improve facility safety. An alarm management program would also 

be in place to ensure effectiveness of the alarms.

Safety valves and instrumentation would be installed to monitor, alarm, shutdown, and isolate 

equipment and piping during process upsets or emergency conditions. Safety instrumented systems 

would comply with International Society for Automation Standard 84.01 and other generally accepted 

good engineering practices. As listed below, we are also including recommendations on the design, 

installation, and commissioning of instrumentation and emergency shutdown equipment to ensure 

appropriate cause and effect alarm or shutdown logic and enhanced representation of the emergency 

shutdown valves in the facility control system. This would ensure that the design includes sufficient 

safeguards to react to process upsets and hazardous conditions.

Safety relief valves and flares would be installed to protect the process equipment and piping. 

The safety relief valves would be designed to handle process upsets and thermal expansion within piping, 

per NFPA 59A and ASME Sections I, IV, VIII, and would be designed based on API recommended 

practices as well as other generally accepted good engineering practices. As listed below, we are 

including recommendations to ensure the pressure and vacuum relief valves would be sufficiently sized 

for major process equipment, vessels, and storage tanks.
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In the event of a release, drainage systems from the liquefaction facilities would direct a spill 

away from equipment in order to minimize flammable vapors from dispersing to confined, occupied, or 

public areas and to minimize heat from impacting adjacent equipment and public areas if ignition occurs. 

Our analysis of the impoundment systems is discussed in section 2.8.6.

DCP performed a preliminary fire protection review to ensure that adequate hazard detection, 

hazard control, and firewater coverage would be installed to detect and address any upset conditions. 

Structural fire protection, proposed to prevent failure of structural supports of equipment and pipe racks, 

would comply with NFPA 59A and other generally accepted good engineering practices. DCP would 

also install hazard detection systems to detect, alarm, and alert personnel in the area and control room to 

initiate an emergency shutdown and/or initiate appropriate procedures. These systems would meet NFPA 

72 as well as other generally accepted good engineering practices. Hazard control devices would be 

installed to extinguish or control incipient fires and releases, and would meet NFPA 59A and NFPA 10, 

11, 12, 13, and generally accepted good engineering practices. DCP would provide automatic firewater 

systems and monitors for use during an emergency to cool the surface of storage vessels, piping, and 

equipment exposed to heat from a fire. These systems would be designed to meet NFPA 59A, and NFPA 

15, 20, 22, and 24 requirements. We are recommending that DCP provide more information on the 

design, installation, and commissioning of hazard detection, hazard control, and firewater systems as DCP 

would further develop this information during the final design phase. We would review this information 

to confirm that the final design, installation, and capabilities of the hazard detection and control 

equipment would be consistent with the equipment proposed in the application.

DCP would also update its existing emergency procedures to include the Project, as required by 

49 CFR 193 and 33 CFR 127. The emergency procedures would provide for protection of personnel and 

the public as well as the prevention of property damage that may occur as a result of incidents at the 

facility. In order to minimize the risk of an intentional event, DCP would update its existing security 

fencing, gates, lighting, camera systems, and intrusion detection to deter, monitor, and detect intruders 

into the facility. In addition, as discussed in section 2.8.8, DCP must update the existing Facility Security 

Plan in accordance with the USCG’s regulations found in 33 CFR 105, Subpart D.

We conclude the use of these protection layers would minimize the potential for an initiating 

event to develop into an incident that could impact the safety of the off-site public. As a result of our

technical review of the information provided by DCP in its application, we did identify a number of 

concerns in letters issued on June 26 and September 3, 2013. DCP provided written responses on July 16, 

July 17, August 1, August 30, September 23, October 4, and December 27, 2013. Some of these 

responses indicated that DCP would correct or modify its design in order to address the identified issues. 

As a result, we recommend that:

 Prior to construction of the final design, DCP should file information/revisions with 

the Secretary, for review and written approval by the Director of OEP, pertaining 

to DCP’s response numbers 3, 19, 21, and 64 of its July 16, 2013 filing, which 

indicated features to be included or considered in the final design.

The FEED and specifications submitted for the proposed facilities to date are preliminary, but 

would serve as the basis for any detailed design to follow. If authorization is granted by the Commission, 

the next phase of the Project would include development of the final design, including final selection of 

equipment manufacturers, process conditions, and resolution of some safety-related issues. It is unlikely 

that the detailed design information to be developed would result in changes to the basis of design, 

operating conditions, major equipment selections, equipment design conditions, or safety system designs 

which were presented as part of DCP’s FEED.
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Prior to finalizing the design as “Issued for Construction,” a more detailed and thorough PHA and 

HAZOP as well as a Layers of Protection Analysis and Safety Integrity Level would be performed by 

DCP. These studies would further refine the required safety control levels and identify whether additional 

process and safety instrumentation, mitigation, and/or administrative controls would be needed. Once the 

design has been subjected to hazard design reviews, DCP’s design development team would track 

changes in the facility design, operations, documentation, and personnel. DCP would evaluate these 

changes to ensure that the safety, health, and environmental risks arising from these changes are 

addressed and controlled.

Information regarding the development of the final design, as detailed below, would need to be 

reviewed by FERC staff before equipment construction at the site would be authorized. To ensure the 

final design would be consistent with the safety and operability characteristics identified in the FEED, we 

recommend that the following measures should apply to the Dominion Cove Point Liquefaction 

Project. Information pertaining to these specific recommendations should be filed with the 

Secretary for review and written approval by the Director of OEP either: prior to initial site 

preparation; prior to construction of final design; prior to commissioning; prior to introduction of 

hazardous fluids; or prior to commencement of service, as indicated by each specific condition. 

Specific engineering, vulnerability, or detailed design information meeting the criteria specified in 

Order No. 683 (Docket No. RM06-24-000), including security information, should be submitted as 

critical energy infrastructure information pursuant to 18 CFR 388.112. See Critical Energy 

Infrastructure Information, Order No. 683, 71 Fed. Reg. 58,273 (October 3, 2006), FERC Stats. & 

Regs. ¶31,228 (2006). Information pertaining to items such as: offsite emergency response; 

procedures for public notification and evacuation; and construction and operating reporting 

requirements, will be subject to public disclosure. All information should be filed a minimum of 30 

days before approval to proceed is requested.

 Prior to initial site preparation, DCP should provide procedures for controlling 

access during construction.

 Prior to initial site preparation, DCP should file the quality assurance and quality 

control procedures for construction activities.

 Prior to initial site preparation, DCP should file a plot plan of the final design 

showing all major equipment, structures, buildings, and impoundment systems.

 Prior to initial site preparation, a technical review of facility design should be filed 

that: 

a. identifies all combustion/ventilation air intake equipment and the distances 

to any possible hydrocarbon release (LNG, flammable refrigerants, 

flammable liquids, and flammable gases); and

b. demonstrates that these areas are adequately covered by hazard detection 

devices and indicate how these devices would isolate or shutdown any 

combustion equipment whose continued operation could add to or sustain 

an emergency.

 The final design should include change logs that list and explain any changes made 

from the FEED provided in DCP’s application and filings. A list of all changes with 

an explanation for the design alteration should be provided and all changes should 

be clearly indicated on all diagrams and drawings.
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 The final design should provide up-to-date Process Flow Diagrams with heat and 

material balances and piping and instrumentation diagrams (P&IDs), which include 

the following information: 

a. equipment tag number, name, size, duty, capacity, and design conditions; 

b. equipment insulation type and thickness; 

c. valve high pressure side and internal and external vent locations;

d. piping with line number, piping class specification, size, and insulation type 

and thickness; 

e. piping specification breaks and insulation limits; 

f. all control and manual valves numbered; 

g. relief valves with set points; and

h. drawing revision number and date. 

 The final design should provide P&IDs, specifications, and procedures that clearly 

show and specify the tie-in details required to safely connect the Project to the 

existing facility.

 The final design should provide an up-to-date complete equipment list, process and 

mechanical data sheets, and specifications.

 The final design should provide complete drawings and a list of the hazard detection 

equipment. The drawings should clearly show the location and elevation of all 

detection equipment. The list should include the instrument tag number, type and 

location, alarm indication locations, and shutdown functions of the hazard detection 

equipment.

 The final design should provide complete plan drawings and a list of the fixed and 

wheeled dry-chemical, hand-held fire extinguishers, and other hazard control 

equipment. Drawings should clearly show the location by tag number of all fixed, 

wheeled, and hand-held extinguishers. The list should include the equipment tag 

number, type, capacity, equipment covered, discharge rate, and automatic and 

manual remote signals initiating discharge of the units.

 The final design should provide facility plans and drawings that show the location of 

the firewater and foam systems. Drawings should clearly show: firewater and foam 

piping; post indicator valves; and the location of, and area covered by, each 

monitor, hydrant, deluge system, foam system, water-mist system, and sprinkler. 

The drawings should also include P&IDs of the firewater and foam system.

 The final design should include an updated fire protection evaluation of the 

proposed facilities carried out in accordance with the requirements of NFPA 59A 

2001, chapter 9.1.2 as required by 49 CFR Part 193. A copy of the evaluation, a list 
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of recommendations and supporting justifications, and actions taken on the 

recommendations should be filed.

 The final design should specify that for hazardous fluids, piping and piping nipples 

2 inches or less are consistent with the existing facility’s piping specifications.

 The final design should include drawings and details of how process seals or 

isolations installed at the interface between a flammable fluid system and an 

electrical conduit or wiring system meet the requirements of NFPA 59A. 

 The final design should provide an air gap or vent installed downstream of process 

seals or isolations installed at the interface between a flammable fluid system and an 

electrical conduit or wiring system. Each air gap should vent to a safe location and 

be equipped with a leak detection device that: should continuously monitor for the 

presence of a flammable fluid; should alarm the hazardous condition; and should 

shutdown the appropriate systems.

 The final design should provide electrical area classification drawings.

 The final design should provide spill containment system drawings with dimensions 

and slopes of curbing, trenches, and impoundments.

 The final design of the hazard detectors should account for the calibration gas when 

determining the LFL set points for methane, propane, ethane, and condensate.

 The final design should include a hazard and operability review of the completed 

design prior to issuing the P&IDs for construction. A copy of the review, a list of 

recommendations, and actions taken on the recommendations, should be filed.

 The final design should include the cause-and-effect matrices for the process 

instrumentation, fire and gas detection system, and ESD system. The cause-andeffect matrices should include alarms and shutdown functions, details of the voting 

and shutdown logic, and set points.

 The final design should include a drawing that shows the location of the ESD 

buttons. ESD buttons should be easily accessible, conspicuously labeled, and located 

in an area which would be accessible during an emergency.

 The final design should include a plan for clean-out, dry-out, purging, and tightness 

testing. This plan should address the requirements of the American Gas 

Association’s Purging Principles and Practice required by 49 CFR 193, and should 

provide justification if not using an inert or non-flammable gas for cleanout, dryout, purging, and tightness testing.

 The final design should include the sizing basis and capacity for the final design of 

pressure and vacuum relief valves for major process equipment, vessels, and storage 

tanks.

 The final design should provide the procedures for pressure/leak tests which 

address the requirements of ASME VIII and ASME B31.3, as required by 49 CFR 

193.
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 The final design should provide the specification, procedures, and schedule to 

modify the tunnel expansion joints.

 The final design should either set the pressure relief valves at the Mole Sieve Gas 

Dehydrators to the design pressure of the closed loop system or design the Mole 

Sieve Gas Dehydrators and the associated hot piping system for the regeneration 

design temperature and the feed gas design pressure of the pretreatment system. 

 The final design should include double isolation for each sulfur removal vessel. 

Manual isolation valves should be installed upstream of the inlet pneumatic valve 

and downstream of the outlet pneumatic valve with vent and purge connections 

between the manual and pneumatic valves.

 The final design should provide coarse mesh strainers in the bottom outlet piping of 

the adsorbers to prevent support material and molecular sieve migrating from Mole 

Sieve Gas Dehydrators to the piping system. 

 The final design should provide a redundant low temperature shutdown system for 

the Flash Gas Compressors. The set point should be set at no less than -50°F. 

 The final design of the Ethane Make-Up Drum and associated piping system should 

include stress analysis of the system at the equilibrium temperature of the Ethane at 

barometric pressure.

 The final design should provide all tests, investigations, and reports to ensure the 

existing firewater system’s compatibility and reliability. 

 The final design should equip the HRU Column with permanent drainage piping to 

the cold flare system, designed for cryogenic conditions. 

 The final design should provide drainage piping to the cold flare from the Nitrogen 

Stripper Reboiler bottom inlet piping and Nitrogen Stripper bottom outlet piping 

upstream of the shutoff valve. 

 The final design should equip the Stabilizer with permanent drainage piping to the 

flare system. 

 The final design of the refrigerant and stabilized condensate storage systems should 

provide dual full capacity relief valves that allow the isolation of individual pressure 

relief valves while providing full relief capacity during pressure relief valve 

maintenance or testing. 

 Prior to commissioning, DCP should file plans and detailed procedures for: testing 

the integrity of onsite mechanical installation; functional tests; introduction of 

hazardous fluids; operational tests; and placing the equipment into service.

 Prior to commissioning, DCP should provide a detailed schedule for commissioning 

through equipment startup. The schedule should include milestones for all 

procedures and tests to be completed: prior to introduction of hazardous fluids; and 

during commissioning and startup. DCP should file documentation certifying that 
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each of these milestones has been completed before authorization to commence the 

next phase of commissioning and startup will be issued.

 Prior to commissioning, DCP should tag all equipment, instrumentation and valves 

in the field, including drain valves, vent valves, main valves, and car-sealed or 

locked valves.

 Prior to commissioning, DCP should file a tabulated list and drawings of the 

proposed hand-held fire extinguishers. The list should include the equipment tag 

number, extinguishing agent type, capacity, number, and location. The drawings 

should show the extinguishing agent type, capacity, and tag number of all hand-held 

fire extinguishers.

 Prior to commissioning, DCP should file updates addressing the liquefaction 

facilities in the operation and maintenance procedures and manuals, as well as 

safety procedures.

 Prior to commissioning, DCP should maintain a detailed training log to demonstrate 

that operating staff has completed the required training.

 Prior to introduction of hazardous fluids, DCP should complete a firewater pump 

acceptance test and firewater monitor and hydrant coverage test. The actual 

coverage area from each monitor and hydrant should be shown on facility plot 

plan(s).

 Prior to introduction of hazardous fluids, DCP should complete all pertinent tests 

(Factory Acceptance Tests, Site Acceptance Tests, Site Integration Tests) associated 

with the Distributed Control System and the Safety Instrumented System that 

demonstrates full functionality and operability of the system.

 Prior to commencement of service, DCP should label piping with fluid service and 

direction of flow in the field in addition to the pipe labeling requirements of NFPA 

59A.

 Prior to commencement of service, progress on the construction of the proposed 

systems should be reported in monthly reports filed with the Secretary. Details 

should include a summary of activities, problems encountered, contractor 

non-conformance/deficiency logs, remedial actions taken, and current Project 

schedule. Problems of significant magnitude should be reported to the FERC within 

24 hours.

In addition, we recommend that the following measures should apply throughout the life of 

the facility:

 The facility should be subject to regular FERC staff technical reviews and site 

inspections on at least an annual basis or more frequently as circumstances indicate. 

Prior to each FERC staff technical review and site inspection, DCP should respond 

to a specific data request, including information relating to possible design and 

operating conditions that may have been imposed by other agencies or 

organizations. Up-to-date detailed P&IDs reflecting facility modifications and 

provision of other pertinent information not included in the semi-annual reports 
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described below, including facility events that have taken place since the previously 

submitted semi-annual report, should be submitted.

 Semi-annual operational reports should be filed with the Secretary to identify 

changes in facility design and operating conditions, abnormal operating experiences, 

activities (including ship arrivals, quantity and composition of imported and 

exported LNG, liquefied and vaporized quantities, boil-off/flash gas, etc.), plant 

modifications, including future plans and progress thereof. Abnormalities should 

include, but not be limited to: unloading/loading/shipping problems, potential 

hazardous conditions from off-site vessels, storage tank stratification or rollover, 

geysering, storage tank pressure excursions, cold spots on the storage tanks, storage 

tank vibrations and/or vibrations in associated cryogenic piping, storage tank 

settlement, significant equipment or instrumentation malfunctions or failures, nonscheduled maintenance or repair (and reasons therefore), relative movement of 

storage tank inner vessels, hazardous fluids releases, fires involving hazardous 

fluids and/or from other sources, negative pressure (vacuum) within a storage tank 

and higher than predicted boil-off rates. Adverse weather conditions and the effect 

on the facility also should be reported. Reports should be submitted within 45 days 

after each period ending June 30 and December 31. In addition to the above items, 

a section entitled “Significant Plant Modifications Proposed for the Next 12 Months 

(dates)” also should be included in the semi-annual operational reports. Such 

information would provide FERC staff with early notice of anticipated future 

construction/maintenance projects at the LNG facility.

 Significant non-scheduled events, including safety-related incidents (e.g., LNG, 

condensate, refrigerant, or natural gas releases, fires, explosions, mechanical 

failures, unusual over pressurization, and major injuries) and security-related 

incidents (e.g., attempts to enter site, suspicious activities) should be reported to 

FERC staff. In the event an abnormality is of significant magnitude to threaten 

public or employee safety, cause significant property damage, or interrupt service, 

notification should be made immediately, without unduly interfering with any 

necessary or appropriate emergency repair, alarm, or other emergency procedure. 

In all instances, notification should be made to FERC staff within 24 hours. This 

notification practice should be incorporated into the LNG facility’s emergency plan. 

Examples of reportable hazardous fluids related incidents include:

a. fire; 

b. explosion;

c. estimated property damage of $50,000 or more;

d. death or personal injury necessitating in-patient hospitalization;

e. release of hazardous fluids for 5 minutes or more;

f. unintended movement or abnormal loading by environmental causes, such 

as an earthquake, landslide, or flood, that impairs the serviceability, 

structural integrity, or reliability of an LNG facility that contains, controls, 

or processes hazardous fluids;
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g. any crack or other material defect that impairs the structural integrity or 

reliability of an LNG facility that contains, controls, or processes hazardous 

fluids; 

h. any malfunction or operating error that causes the pressure of a pipeline or 

LNG facility that contains or processes hazardous fluids to rise above its 

MAOP (or working pressure for LNG facilities) plus the build-up allowed 

for operation of pressure limiting or control devices; 

i. a leak in an LNG facility that contains or processes hazardous fluids that 

constitutes an emergency; 

j. inner tank leakage, ineffective insulation, or frost heave that impairs the 

structural integrity of an LNG storage tank;

k. any safety-related condition that could lead to an imminent hazard and 

cause (either directly or indirectly by remedial action of the operator), for 

purposes other than abandonment, a 20 percent reduction in operating 

pressure or shutdown of operation of a pipeline or an LNG facility that 

contains or processes hazardous fluids; 

l. safety-related incidents to hazardous fluids vessels occurring at or en route 

to and from the LNG facility; or

m. an event that is significant in the judgment of the operator and/or 

management even though it did not meet the above criteria or the guidelines 

set forth in an LNG facility’s incident management plan.

In the event of an incident, the Director of OEP has delegated authority to take whatever 

steps are necessary to ensure operational reliability and to protect human life, health, 

property, or the environment, including authority to direct the LNG facility to cease 

operations. Following the initial company notification, FERC staff would determine the 

need for a separate follow-up report or follow-up in the upcoming semi-annual operational 

report. All company follow-up reports should include investigation results and 

recommendations to minimize a reoccurrence of the incident.

In addition to the final design review, we would conduct inspections during construction and 

would review additional materials, including quality assurance and quality control plans, 

non-conformance reports, and commissioning plans, to ensure that the installed design is consistent with 

the safety and operability characteristics of the FEED. We would also conduct inspections during 

operation to ensure that the facility is operated and maintained in accordance with the filed design 

throughout the life of the facility. Based on our analysis and recommendations presented above, we 

conclude that the FEED presented by DCP would include acceptable layers of protection or safeguards 

which would reduce the risk of a potentially hazardous scenario from developing into an event that could 

impact the off-site public.

We received a comment regarding the control and monitoring systems and integrity management 

programs used at the existing facility, particularly for the LNG storage tanks. DCP has a maintenance 

plan in place to ensure storage tanks, piping, process equipment, vessels, instrumentation, and utilities are 

functioning properly. The facility has an inspection program that continually monitors and examines this 

equipment. The inspection and maintenance regime for the existing LNG storage tanks include cathodic 
142

protection and elevation surveys, thermal scanning of the outer tank, and examination and repair of the 

outer tank shell paint. 

We received a comment on whether the existing LNG Terminal could be safely operated during 

construction of the proposed Liquefaction Facilities. DCP would use temporary fencing or other 

restrictive measures to delineate the battery limits of the construction area from the operating portions of 

the plant. In addition, we are also recommending DCP to provide measures to control access during 

construction of the proposed Liquefaction Facilities (see section 2.8.4).

2.8.5 Siting Requirements

The principal hazards associated with the substances involved in the liquefaction of LNG result 

from cryogenic and flashing liquid releases; flammable vapor dispersion; vapor cloud ignition; pool fires; 

and overpressures. As discussed in section 2.8.4, our FEED review indicates that sufficient layers of 

protection would be incorporated into the facility design to mitigate the potential for an initiating event to 

develop into an incident that could impact the safety of the off-site public. Siting of the facility with 

regard to potential off-site consequences is also required by DOT’s regulations in 49 CFR 193, Subpart B 

to ensure that impact to the public would be minimized. The Commission’s regulations under 18 CFR 

380.12(o)(14) require DCP to identify how the proposed design complies with DOT’s siting 

requirements. As part of our review, we used DCP’s information, developed to comply with DOT’s 

regulations, to assess whether or not the facility would have a public safety impact. The Part 193 

requirements state that an operator or government agency must exercise control over the activities that 

can occur within an “exclusion zone,” defined as the area around an LNG facility that could be exposed to 

specified levels of thermal radiation or flammable vapor in the event of a release. Approved 

mathematical models must be used to calculate the dimensions of these exclusion zones. The 2001 

edition of NFPA 59A, an industry consensus safety standard for the siting, design, construction, 

operation, maintenance, and security of LNG facilities, is incorporated into Part 193 by reference, with 

regulatory preemption in the event of conflict. The following sections of Part 193 specifically address the 

siting requirements applicable to each LNG container and LNG transfer system:

 Part 193.2001, Scope of part, excludes any matter other than siting provisions pertaining 

to marine cargo transfer systems between the marine vessel and the last manifold or valve 

immediately before a storage tank;

 Part 193.2051, Scope, states that each LNG facility designed, replaced, relocated or 

significantly altered after March 31, 2000, must be provided with siting requirements in 

accordance with Subpart B and NFPA 59A (2001). In the event of a conflict with NFPA 

59A (2001), the regulatory requirements in Part 193 prevail;

 Part 193.2057, Thermal radiation protection, requires that each LNG container and LNG 

transfer system have thermal exclusion zones in accordance with Section 2.2.3.2 of 

NFPA 59A (2001); and

 Part 193.2059, Flammable vapor-gas dispersion protection, requires that each LNG 

container and LNG transfer system have a dispersion exclusion zone in accordance with 

Sections 2.2.3.3 and 2.2.3.4 of NFPA 59A (2001).

For the LNG facilities proposed for the Project, these Part 193 siting requirements would be 

applicable to the following equipment:
143

 seven 8,240-gallon per minute (gpm) LNG loading pumps (four new pumps and three 

existing pumps upgraded to 8,240 gpm) used for ship loading and associated piping and 

appurtenances; and two 6,543 gpm LNG product pumps used for LNG storage tank 

loading and associated piping and appurtenances – Parts 193.2057 and 2059 require 

thermal and flammable vapor exclusion zones. NFPA 59A (2001) does not address LNG 

transfer systems; however, Section 2.2.3.2 specifies the thermal exclusion zone and 

Sections 2.2.3.3 and 2.2.3.4 specify the flammable vapor exclusion zone based on the 

design spills for containers and process areas; and

 one liquefaction heat exchanger and associated piping and appurtenances, including an 

18-inch-diameter LNG rundown line – Parts 193.2057 and 2059 require thermal and 

flammable vapor exclusion zones. NFPA 59A (2001) Section 2.2.3.2 specifies the 

thermal exclusion zone and Sections 2.2.3.3 and 2.2.3.4 specify the flammable vapor 

exclusion zone based on the design spills for containers and process areas.

FERC EAs/EISs for past projects have identified inconsistencies and areas of potential conflict 

between the requirements in Part 193 and NFPA 59A (2001). Sections 193.2057 and 193.2059 require 

exclusion zones for each LNG container and LNG transfer system, and an LNG transfer system is defined 

in Section 193.2007 to include cargo transfer system and transfer piping (whether permanent or 

temporary). However, NFPA 59A (2001) requires exclusion zones only for “transfer areas,” which is 

defined as the part of the plant where the facility introduces or removes the liquids, such as truck loading 

or ship-unloading areas. The NFPA 59A (2001) definition does not include permanent plant piping, such 

as cargo transfer lines. Section 2.2.3.1 of NFPA 59A (2001) also states that transfer areas at the water 

edge of marine terminals are not subject to the siting requirements in that standard.

The DOT addressed some of these issues in a March 2010 letter of interpretation. In that letter, 

DOT stated that: (1) the requirements in the NFPA 59A (2001) for transfer areas for LNG apply to the 

marine cargo transfer system at a proposed waterfront LNG facility, except where preempted by the 

regulations in Part 193; (2) the regulations in Part 193 for LNG transfer systems conflict with NFPA 59A 

(2001) on whether an exclusion zone analysis is required for transfer piping or permanent plant piping; 

and (3) the regulations in Part 193 prevailed as a result of that conflict. The DOT determined that an 

exclusion zone analysis of the marine cargo transfer system is required.

In the FERC environmental assessments/impact statements for past projects, we have also noted 

that when the DOT incorporated NFPA 59A into its regulations, it removed the regulation that required 

impounding systems around transfer piping. As a result of that change, it is unclear whether Part 193 or 

the adopted sections of NFPA 59A (2001) require impoundments for LNG transfer systems. We note that 

Part 193 requires exclusion zones for LNG transfer systems, and that those zones were historically 

calculated based on impoundment systems. We also note that the omission of containment for transfer 

piping is not a sound engineering practice. For these reasons, we generally recommend containment for 

all LNG transfer piping within a plant’s property lines.

Federal regulations issued by the Occupational Safety and Health Administration (OSHA) under 

29 CFR 1910.119 (Process Safety Management of Highly Hazardous Chemicals; Explosives and Blasting 

Agents [PSM]), and the EPA under 40 CFR 68 (Risk Management Plans) cover hazardous substances, 

such as methane, propane, and ethane at many facilities in the U.S. However, OSHA and EPA 

regulations are not applicable to facilities regulated under 49 CFR 193. On October 30, 1992, shortly 

after the promulgation of the OSHA PSM regulations, OSHA issued a letter of interpretation that 

precluded the enforcement of PSM regulations over gas transmission and distribution facilities. In a 

subsequent letter on December 9, 1998, OSHA further clarified that this letter of interpretation applies to 

LNG distribution and transmission facilities.
144

In addition, EPA’s preamble to its final rule in Federal Register, Volume 63, Number 3, 639 645, 

clarified that exemption from the requirements in 40 CFR 68 for regulated substances in transportation, 

including storage incident to transportation, is not limited to pipelines. The preamble further clarified that 

the transportation exemption applies to LNG facilities subject to oversight or regulation under 49 CFR 

193, including facilities used to liquefy natural gas or used to transfer, store, or vaporize LNG in 

conjunction with pipeline transportation. Therefore, the above OSHA and EPA regulations are not 

applicable to facilities regulated under 49 CFR 193. As stated in Section 193.2051, LNG facilities must 

be provided with the siting requirements of NFPA 59A (2001 edition). The siting requirements for 

flammable liquids within an LNG facility are contained in NFPA 59A, Chapter 2:

 NFPA 59A, Section 2.1.1 requires consideration of clearances between flammable 

refrigerant storage tanks, flammable liquid storage tanks, structures and plant equipment, 

both with respect to plant property lines and each other. This section also requires that 

other factors applicable to the specific site that have a bearing on the safety of plant 

personnel and surrounding public be considered, including an evaluation of potential 

incidents and safety measures incorporated in the design or operation of the facility.

 NFPA 59A Section 2.2.2.2 requires impoundments serving flammable refrigerants or 

flammable liquids to contain a 10-minute spill of a single accidental leakage source or 

during a shorter time period based upon demonstrable surveillance and shutdown 

provisions acceptable to the DOT. In addition, NFPA Section 2.2.2.5 requires 

impoundments and drainage channels for flammable liquid containment to conform to 

NFPA 30, Flammable and Combustible Liquids Code.

 NFPA 59A Section 2.2.3.2 requires provisions to minimize the damaging effects of fire 

from reaching beyond a property line, and requires provisions to prevent a radiant heat 

flux level of 1,600 British thermal units per square foot-hour (Btu/ft2-hr) from reaching 

beyond a property line that can be built upon. The distance to this flux level is to be 

calculated with LNGFIRE or using models that have been validated by experimental test 

data appropriate for the hazard to be evaluated and that are acceptable to DOT.

 NFPA 59A Section 2.2.3.4 requires provisions to minimize the possibility of any 

flammable mixture of vapors from a design spill from reaching a property line that can be 

built upon and that would result in a distinct hazard. Determination of the distance that 

the flammable vapors extend is to be determined with DEGADIS or alternative models 

that take into account physical factors influencing LNG vapor dispersion. Alternative 

models must have been validated by experimental test data appropriate for the hazard to 

be evaluated and must be acceptable to DOT. Section 2.2.3.5 requires the design spill for 

impounding areas serving vaporization and process areas to be based on the flow from 

any single accidental leakage source.

For the following liquefaction facilities that are proposed for the Project, the FERC staff 

identified that the refrigerant siting requirements from Part 193 and NFPA 59A would be applicable to the 

following equipment:

 one liquefaction heat exchanger and associated piping and appurtenances;

 two partially buried and mounded ethane make-up bullets with a combined total capacity 

of 68,000 gallons and associated piping;
145

 four partially buried and mounded propane make-up bullets with a combined total 

capacity of 410,000 gallons and associated piping;

 two partially buried and mounded stabilized condensate storage tanks with a combined 

total capacity of 70,000 gallons and associated piping;

 one 133-gpm Propane Make-up Transfer Pump and associated piping and appurtenances;

 two 133-gpm Ethane Charge Pumps and associated piping and appurtenances;

 two 125-gpm condensate loading pumps and associated piping; and

 two 98-gpm NGL reinjection pumps and associated piping and appurtenances; and two 

108-gpm Stabilizer Reflux Pumps and associated piping and appurtenances.

2.8.6 Siting Analysis

Suitable sizing of impoundment systems and selection of design spills on which to base hazard 

analyses are critical for establishing an appropriate siting analysis. Although impoundment capacity and 

design spill scenarios for storage tank impoundments are well described by Part 193, a clear definition for 

other impoundments is not provided either directly by the regulations or by the adopted sections of NFPA 

59A (2001). Under NFPA 59A (2001) Section 2.2.2.2, the capacity of impounding areas for vaporization, 

process, or LNG transfer areas must equal the greatest volume that can be discharged from any single 

accidental leakage source during a 10-minute period or during a shorter time period based upon 

demonstrable surveillance and shutdown provisions acceptable to the DOT. However, no definition of 

single accidental leakage source is provided in the regulations.

We consider it prudent design practice to size impoundments based on the greatest flow capacity 

from any single pipe for 10 minutes, recognizing that different spill scenarios are used for the single 

accidental leakage sources for calculation of Part 193 exclusion zones. A similar approach is used with 

impoundments for process vessels, where the impoundments should be able to contain the contents of the 

largest process vessel served while recognizing that smaller design spills are used for Part 193 exclusion 

zone calculations.

Impoundment Sizing

Potential spills from the 36-inch-diameter ship loading header would be contained within the 

existing LNG Tank sub-impoundments located at LNG Storage Tanks 101-FF and 101-FG. As discussed 

in the FEIS for the Cove Point Expansion Project (Docket No. CP05-130), each LNG Tank subimpoundment is sized to contain a 1-hour release from the LNG storage tank and has a capacity of 

3,549,757 gallons. A 10-minute spill from the 36-inch-diameter LNG pump discharge header, with 6 

LNG pumps in operation, would result in a volume of 494,400 gallons. We determined that each existing 

LNG Tank sub-impoundment would sufficiently contain a 10-minute spill volume, including pump 

runout volume, from the LNG pump discharge header.

DCP proposes to install five impoundment basins including LNG Impoundment Basin #1, LNG 

Impoundment Basin #2, the Hydrocarbon Sump, the Amine Sump, and the Trucking Area Sump at the 

liquefaction process area. The LNG Impoundment Basin #1 would be 28.3-feet-wide, 33.25-feet-long, 

and 33-feet-deep, with a volume of 232,286 gallons. LNG Impoundment Basin #1 would be lined with 

perlite concrete and located adjacent to the liquefaction heat exchanger, within the 1-foot curbed 

liquefaction process area. Potential spills from the liquefaction heat exchanger and the propane condenser 

within the 1-foot curbed area would be sloped into the LNG collection trench system that ties into LNG 
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Impoundment Basin #1. The largest spill into LNG Impoundment Basin #1 would be a guillotine rupture

of the 42-inch-diameter propane condenser outlet piping, which would result in a 10-minute spill volume 

of 220,133 gallons. Without accounting for liquid volume reduction due to rapid evaporation, the 10-

minute propane spill volume would be contained within LNG Impoundment Basin #1. LNG 

Impoundment Basin #1 would also contain a 10-minute spill volume from the guillotine rupture of the 18-

inch-diameter LNG rundown line, which would be 79,980 gallons. This spill volume accounts for the 

LNG product pump runout condition and would be contained within LNG Impoundment Basin #1. 

The perlite concrete LNG Impoundment Basin #2 would be 33-feet-long, 36-feet-wide, and 16-

feet-deep, with a volume of 142,190 gallons. LNG Impoundment Basin #2 would be located 

approximately 500 feet north of the proposed liquefaction area and within the existing vaporization area. 

Any spills from the 18-inch-diameter LNG rundown line occurring north of the liquefaction process area 

would be sloped into an existing trench system that connects to LNG Impoundment Basin #2. A 10-

minute spill volume from the 18-inch LNG rundown line would be 79,980 gallons and would be 

contained within LNG Impoundment Basin #2. 

The proposed Hydrocarbon Sump would be 28-feet-long, 28-feet-wide, and 10-feet-deep, with a 

volume of 58,647 gallons. The Hydrocarbon Sump would be located adjacent to the Heavy Removal Unit 

and approximately 130 feet east of LNG Impoundment Basin #1. The largest process spill into the 

Hydrocarbon Sump would be from the 6-inch-diameter Heavies Removal Unit outlet piping, which would 

result in a 10-minute spill of 2,344 gallons. This spill would be contained within the 6-inch curb and 

sloped toward the Hydrocarbon Sump. 

The proposed Amine Sump would be 30-feet-long, 30-feet-wide, and 18-feet-deep, with a volume 

of 121,184 gallons to contain rainwater from a 1-year storm event. The Amine Sump would be located in 

the pre-treatment area, which would be between the refrigerant storage area and the liquefaction process 

area. Any spills from the refrigerant make-up piping in the pre-treatment area would be directed to the 

Amine Sump. Since all refrigerant make-up pumps would be at rated 133 gpm, a guillotine rupture from 

either the ethane or propane make-up line would result in a 10-minute spill volume of 1,330 gallons. 

Either spill volume would be contained within the Amine Sump. 

DCP proposes to install a 40,000-gallon Fresh Amine Tank within a 51.5-foot long by 32.6-foot 

wide by 7-foot-high diked area. The diked area would have a volumetric capacity of 87,913 gallons and 

would hold the entire contents of the Fresh Amine Tank. DCP also proposes to install a 26,438-gallon 

Contaminated Amine Tank within a 32.6-foot-long by 30.5-foot-wide by 8-foot-high diked area. This 

diked area would have a volumetric capacity of 59,503 gallons and would hold the entire contents of the 

Contaminated Amine Tank. DCP would also install a 25,000-gallon Aqueous Ammonia Tank within a 

50-foot long by 25-foot wide by 3.9-foot-high diked area. This diked area would have a volumetric 

capacity of 36,468 gallons and would hold the entire contents of the Aqueous Ammonia Tank.

DCP proposes to install three Propane Make-up Tanks, one Propane Make-up Transfer Tank, two 

Ethane Make-up Drums, and two Condensate Storage Tanks. These tanks would be partially buried and 

mounded under a minimum of 2-feet of soil. DCP proposes to install a Trucking Area Sump with 

dimensions of 5-feet-long by 5-feet-wide by 11-feet-deep, with a volume of 2,057 gallons, to contain any

potential liquid spills from the condensate truck loading hose. While DCP sized the Trucking Area Sump 

based on a guillotine rupture of the condensate loading hose, a hose rupture could also involve a release 

from the tanker truck’s inventory. As a result, we recommend that:

 Prior to initial site preparation, DCP should resize the Trucking Area Sump to 

adequately contain the maximum content of a condensate truck. DCP should file 

information on the resized Trucking Area Sump with the Secretary for review and 

written approval by the Director of OEP.
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Table 2.8.6-1 lists the spill volumes and their corresponding impoundment systems. 

TABLE 2.8.6-1

Impoundment Area Sizing

Source

Spill Size

(gallons) Impoundment System

Impoundment Size

(gallons)

Pump Withdrawal Header 494,400 Tank Sub-Impoundment 3,549,757

18-inch LNG Rundown Line (south) 79,980 LNG Impoundment Basin #1 232,286

18-inch LNG Rundown Line (north) 79,980 LNG Impoundment Basin #2 142,190

42-inch Propane Condenser Discharge (largest 

spill into Basin #1)

220,133 LNG Impoundment Basin #1 232,286

6-inch HRU Discharge Piping 2,344 Hydrocarbon Sump 58,647

Propane or Ethane Makeup Line 1,330 Amine Sump 121,184

Fresh Amine Tank 40,000 Fresh Amine Diked Area 87,913

Contaminated Amine Tank 26,438 Contaminated Amine Diked Area 59,503

Aqueous Ammonia Tank 25,000 Aqueous Ammonia Diked Area 36,468

Condensate Truck Hose 1,786 Trucking Area Sump 2,057

Design Spills

Design spills are used in the determination of the hazard calculations required by Part 193. Prior 

to the incorporation of NFPA 59A in 2000, the design spill in Part 193 assumed the full rupture of “a 

single transfer pipe which has the greatest overall flow capacity” for not less than 10 minutes (old Part 

193.2059(d)). With the adoption of NFPA 59A, the basis for the design spill for impounding areas 

serving only vaporization, process, or LNG transfer areas became the flow from any single accidental 

leakage source. Neither Part 193 nor NFPA 59A (2001) defines “single accidental leakage source.”

In a letter to the FERC staff, dated August 6, 2013, DOT requested that LNG facility applicants 

contact the OPS’ Engineering and Research Division regarding the Part 193 siting requirements.12 

Specifically, the letter stated that DOT required a technical review of the applicant’s design spill criteria 

for single accidental leakage sources on a case-by-case basis to determine compliance with Part 193.

In response, DCP provided DOT with its design spill criteria and identified leakage scenarios. 

This information included all of the proposed equipment, but did not include DCP’s existing facilities. 

DOT reviewed the data and methodology DCP used to determine the single accidental leakage sources for 

the design spills based on the flow from various leakage sources including piping, containers, and 

equipment containing LNG, refrigerants, and flammable fluids. DCP’s methodology considers the failure 

probability of over 400 piping segments and process vessels containing hazardous fluids for the purpose 

for selecting credible design spills using a list of nominal failures rates developed by FERC staff and 

presented by DOT on its webpage for “LNG Facility Siting” (http://primis.phmsa.dot.gov/lng/index.htm). 

This methodology also includes over 160 propane release scenarios. On February 27, 2014, DOT 

provided a letter to the FERC staff stating that DOT had no objection to DCP’s methodology for 

determining the single accidental leakage sources for candidate design spills to be used in establishing the 

Part 193 siting requirements for the proposed LNG liquefaction facilities.13 This letter was contingent on 

 

12 August 6, 2013 Letter from Kenneth Lee, Director of Engineering and Research Division, Office of Pipeline 

Safety to Terry Turpin, LNG Engineering and Compliance Branch, Office of Energy Projects. Filed in Docket 

Number CP13-113 on August 13, 2013. Accession Number 20140813-4011.

13 February 27, 2014 Letter “Re: Dominion Cove Point LNG, LP, Cove Point Liquefaction Project, CP13-113-000, 

Design Spill Determination” from Kenneth Lee to Lauren H. O'Donnell. Filed in Docket Number CP13-113-

000 on February 27, 2014. Accession Number 20140227-4004.
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DCP filing supplemental models in support of the DOT Design Spill Determination for FERC review 

(Accession Number 20140227-5111). The design spills produced by this method were identified in the 

documents reviewed by DOT and have been filed in the docket for this Project. DCP also filed 

supplemental Design Spill modeling information on March 7, March 14, and April 11, 2014. These 

filings contain information on the design spills described in the following sections.

DOT’s conclusions on the candidate design spills used in the siting calculations required by Part 

193 was based on preliminary design information which may be revised as the engineering design 

progresses. If DCP’s design or operation of the proposed facility differs from the details provided in the 

documents on which DOT based its review, then the facility may not comply with the siting requirements 

of Part 193. As a result, we recommend that:

 Prior to the construction of the final design, DCP should file with the Secretary for 

review and written approval by the Director of OEP, certification that the final 

design is consistent with the information provided to DOT as described in the design 

spill determination letter dated February 27, 2014 (Accession Number 20140227-

4004) and supplemental information filed by DCP on March 7, 2014 (Accession 

Numbers 20140307-5050 and 20140307-5051), March 14, 2014 (Accession Numbers 

20140314-5099 and 20140317-5100), and April 11, 2014 (Accession Numbers 

20140411-5252 and 20140411-5253). In the event that any modifications to the 

design alters the candidate design spills on which the Title 49 CFR 193 siting 

analysis was based, DCP should consult with DOT on any actions necessary to 

comply with Part 193.

As design spills vary depending on the hazard (vapor dispersion, overpressure, toxic or radiant 

heat), the specific design spills used for the DCP siting analysis are discussed under “Vapor Dispersion 

Analysis” and “Thermal Radiation Analysis” in this section.

We received comments requesting that a quantitative risk assessment (QRA) be performed for the 

proposed Project and that no dangerous condition should be allowed to extend off-property. The 

proposed Project must comply with DOT’s federal safety standards for siting of onshore LNG facilities 

under 49 CFR 193. These regulations require consequence calculations for a defined range of failures, 

rather than use of a QRA. Efforts are underway to develop a QRA method for LNG facility siting with 

the most notable method being described in Chapter 15 of the 2013 edition of NFPA 59A. Establishing 

specific assumptions/databases/models on which to base the risk methodology is critically important in 

ensuring that results are consistent and meaningful. As we have communicated to NFPA, differing failure 

rate data (often by several orders of magnitude), choice of consequence models, and hazard scenario 

selection that can be used under its QRA method can lead to inconsistent results for essentially identical 

facilities. The NFPA 59A Chapter 15 method has not yet addressed these issues.

Vapor Dispersion Analysis

As discussed in section 2.8.3, a large quantity of LNG spilled without ignition would form a 

flammable vapor cloud that would travel with the prevailing wind until it either dispersed below the 

flammable limit or encountered an ignition source. In order to address this hazard, 49 CFR § 193.2059 

requires each LNG container and LNG transfer system to have a dispersion exclusion zone in accordance 

with sections 2.2.3.3 and 2.2.3.4 of NFPA 59A (2001). Taken together, Part 193 and NFPA 59A (2001) 

require that flammable vapors either from an LNG tank impoundment or a single accidental leakage 

source do not extend beyond a facility property line that can be built upon. This is the Part 193 standard 

that we used in analyzing the siting of the proposed Project.
149

Title 49 CFR § 193.2059 requires that dispersion distances be calculated for a 2.5 percent average 

gas concentration (one-half the LFL of LNG vapor) under meteorological conditions which result in the 

longest downwind distances at least 90 percent of the time. Alternatively, maximum downwind distances 

may be estimated for stability Class F, a wind speed of 4.5 mph, 50 percent relative humidity, and the 

average regional temperature.

The regulations in Part 193 specifically approve the use of two models for performing these 

dispersion calculations, DEGADIS and FEM3A. In October 2011, two additional dispersion models were 

approved by DOT for use in vapor dispersion exclusion zone calculations: PHAST-UDM Version 6.6 and 

Version 6.7 (submitted by Det Norske Veritas) and FLACS Version 9.1 Release 2 (submitted by 

GexCon). PHAST 6.7 and FLACS 9.1, with their built-in source term models, were used to calculate 

dispersion distances.

Failure scenarios must be selected as the basis for the Part 193 dispersion analyses. Process 

conditions at the failure location would affect the resulting vapor dispersion distances. In determining the 

spill conditions for these leakage sources, process flow diagrams for the proposed design, used in 

conjunction with the heat and material balance information (i.e., flow, temperature, and pressure), can be 

used to estimate the flow rates and process conditions at the location of the spill. In general, higher flow 

rates would result in larger spills and longer dispersion distances; higher temperatures would result in 

higher rates of flashing; and higher pressures would result in higher rates of jetting and aerosol formation. 

Therefore, two scenarios may be considered for each design spill:

 the pressure in the line is assumed to be maintained by pumps and/or hydrostatic head to 

produce the highest rate of flashing and jetting (i.e. flashing and jetting scenario); and

 the pressure in the line is assumed to be depressurized by the breach and/or emergency 

shutdowns to produce the highest rate of liquid flow within a curbed, trenched, or 

impounded area (i.e. liquid scenario).

Alternatively, a single scenario for each design spill could be selected if adequately supported 

with an assessment of the depressurization calculations and/or an analysis of process instrumentation and 

shutdown logic acceptable to DOT.

In addition, the location and orientation of the leakage source must be considered. The closer a 

leakage source is to the property line, the higher the likelihood that the vapor cloud would extend off-site. 

As most flashing and jetting scenarios would not have appreciable liquid rainout and accumulation, the 

siting of impoundment systems would be driven by liquid scenarios, while siting of piping and other 

remaining portions of the plant would be driven by flashing and jetting scenarios.

DCP reviewed multiple releases for the liquid scenarios and for the flashing and jetting scenarios. 

DCP used the following conditions, corresponding to 49 CFR §193.2059, for the vapor dispersion 

calculations: ambient temperature of 57.4°F, relative humidity of 50 percent, atmospheric stability class 

of F, and a ground surface roughness of 0.03 m. In addition, a sensitivity analysis to the wind speed and 

direction was provided to demonstrate the longest predicted downwind dispersion distance in accordance 

with the PHAST and FLACS Final Decisions.

DCP accounted for the facility geometry, including the impoundment and trench geometry details 

as established by available plant layout drawings. Including the plant geometry accounts for any on-site 

wind channeling that could occur and allows for inclusion of mitigation measures, such as vapor barriers. 

The releases were initiated after sufficient time had passed in the model simulations to allow the wind 

profile to stabilize from effects due to the presence of buildings and other on-site obstructions.
150

Vapor Dispersion Analyses for LNG

In order to address the highest rate of LNG flow (i.e., liquid scenario) into the liquefaction 

process area, DCP specified the design spill as a guillotine rupture of the 18-inch rundown line. This 

liquid spill would result in a maximum runout flow rate for one LNG product pump of 7,998 gpm for a 

10-minute duration. DCP used FLACS to predict the extent of the 1⁄2-LFL dispersion distance from the 

liquid spill into the trench system. A sensitivity analysis was conducted at different wind speeds and 

directions. To mitigate the extent of the vapor dispersion, DCP proposes to install 20-foot-high vapor 

barriers at various locations in the plant as well as a 60-foot-high sound control barrier that would be 

located along the western and southern property lines of the plant. The locations of the vapor barriers and 

the 60-foot sound control barrier are shown in figure 2.8.6-1. The FLACS results indicate that the 

flammable vapor cloud would be contained within the 60-foot sound control barrier and would remain 

within DCP’s property. In order to ensure that the vapor barriers are maintained throughout the life of the 

facility, we recommend that:

 Prior to construction of the final design, DCP should file with the Secretary for 

review and written approval by the Director of OEP, the details of the vapor fences 

as well as procedures to maintain and inspect the vapor barriers provided to meet 

the siting provisions of 49 CFR § 193.2059. This information should be filed a 

minimum of 30 days before approval to proceed is requested.

DCP utilized PHAST Version 6.7 to conduct hole diameter and wind sensitivity studies in order 

to determine that the worst case jetting and flashing scenario would result from a 7-inch hole on the 18-

inch-diameter LNG rundown line. FLACS was used to model three different release locations along the 

LNG rundown line at different wind speeds and directions. The FLACS modeling results shows that the 

flammable vapor cloud would be contained within the 60-foot sound control barrier and would remain 

within DCP’s property. 

For LNG ship loading operations, DCP specified the design spill as a 1-inch hole on the 36-inchdiameter LNG ship loading header (i.e., jetting and flashing scenario) with six LNG pumps operating. A 

portion of the ship loading header and new piping associated with the LNG ship loading pumps would be 

located within the existing sub-impoundments located at LNG Storage Tanks 101-FF and 101-FG. The 

operating ranges for flows and pressures in existing marine transfer piping outside of the existing subimpoundments would not change and therefore were not evaluated. For the new equipment located 

within the existing sub-impoundments, PHAST was used to predict the extent of unmitigated and 

unobstructed dispersion distance to the 1⁄2-LFL vapor cloud from the 1-inch hole on the LNG ship loading 

header. DCP selected three wind speeds in the modeling to demonstrate the longest downwind dispersion 

distance. The PHAST dispersion distance of 724 feet would be centered at the existing subimpoundments and would remain within DCP’s property. As DCP’s calculations show the dispersion 

from flammable vapors would stay within DCP property, we conclude that the siting of the proposed 

Project would not have a significant impact on public safety. If the facility is constructed and operated, 

compliance with the requirements of 49 CFR 193 would be addressed as part of DOT’s inspection and 

enforcement program.
151

Figure 2.8.6-1

Vapor and Sound Barrier Locations
152

Vapor Dispersion Analyses for Other Hazardous Fluids

Even though DCP considered all possible releases from the MRL process system, the propane 

pre-cool system, and the heavy hydrocarbon removal system at the liquefaction process area, only the 

spills that produced the highest release rates and consequently the longest 1⁄2-LFL vapor clouds are 

discussed in this section. The highest rate of MRL release would be from a 2-inch-diameter hole on the 

MR piping from the MR/LP Propane Cooler to the MR Separator. PHAST was used to predict the 

releases MR vapor dispersion distance based on 3 different wind speeds. The PHAST results did not 

indicate any liquid rainout and calculated a 1⁄2-LFL distance of 750 feet that would remain within DCP’s 

property. 

Propane would be used in the liquefaction cycle to pre-cool the feed gas, and both propane and 

ethane would be used as components of the MR vapor. The worst case scenario for a propane release at 

the liquefaction process area would be a 14.7-inch hole on the Propane Compressor discharge piping. 

FLACS was used to model a horizontal release at different wind speeds and wind directions. FLACS 

calculated that the 1⁄2-LFL vapor dispersion distance for propane would extend about 775 feet and would 

be contained within DCP’s property. 

During the heavy hydrocarbon removal process, NGL and condensate would be extracted from 

the feed gas stream in the liquefaction area. For the NGL, the worst case scenario would be a 3-inch 

guillotine release from the NGL Reinjection Pump discharge piping. PHAST was used to model a 

horizontal release at different wind speeds and calculated a 1⁄2-LFL dispersion distance of 159 feet. For 

the condensate worst case, PHAST was used to model a 1.5-inch guillotine release from the Stabilizer 

outlet piping. PHAST calculated a 1⁄2-LFL distance of 162 feet. Each 1⁄2-LFL vapor cloud distance would 

remain within DCP’s property.

The refrigerant make-up tanks and condensate storage tanks would be partially buried and 

mounded under a minimum of 2-feet of soil. For process releases outside of the refrigerant make-up 

tanks, a guillotine rupture of the 4-inch-diameter ethane make-up line would result in the longest 

downwind 1⁄2-LFL distance. PHAST was used to calculate a 1⁄2-LFL dispersion distance from a horizontal 

release at varying wind speeds. PHAST results showed a dispersion distance of 135 feet, which would 

remain within DCP’s property. 

In the refrigerant and condensate trucking area, DCP considered releases from the ethane, 

propane, stabilized condensate truck hose connections for both refrigerant truck unloading and stabilized 

condensate truck loading operations. The largest release would be from a guillotine rupture of the 3-inchdiameter propane hose connection. The maximum spill duration was assumed to be the de-inventory time 

of the propane truck for 3.4 minutes. PHAST simulations showed that a release from the propane 

trucking hose in the horizontal direction would result in a 1⁄2-LFL dispersion distance of 930 feet. This 1⁄2-

LFL vapor cloud would remain within DCP’s property. 

The distances to the 1⁄2-LFL vapor cloud for all refrigerant and NGL release scenarios discussed 

above are provided in table 2.8.6-2 and would remain within the DCP’s property. As DCP’s calculations 

show the vapor dispersion would stay within DCP property, we conclude that the siting of the proposed 

Project would not have a significant impact on public safety. If the facility is constructed and operated, 

compliance with the requirements of 49 CFR 193 would be addressed as part of DOT’s inspection and 

enforcement program. 
153

TABLE 2.8.6-2

Vapor Dispersion Scenarios from Process Releases

Scenario Material Release Location

Approximate downwind distance

to 1⁄2-LFL (feet)

1 Mixed Refrigerant Liquefaction Process 750

2 Propane Liquefaction Process 775

3 Ethane Make-up Piping 135

4 NGL Process Piping 159

5 Condensate Process Piping 162

7 Propane Truck Unloading 930

Since the stabilized condensate would contain benzene, a toxic product, DCP used PHAST 

Version 6.7 to calculate the dispersion distances to toxic threshold exposure limits based on the Acute 

Exposure Guideline Level (AEGLs). Additionally, DCP calculated the AEGLs for H2S and ammonia. 

AEGLs are recommended for use by federal, state, and local agencies, as well as the private sector for 

emergency planning, prevention, and response activities related to the accidental release of hazardous 

substances. Other federal agencies, such as the DOE, use AEGLs as the primary measure of toxicity.

There are three AEGLs which are distinguished by varying degrees of severity of toxic effects 

with AEGL-1 (level 1) being the least severe to AEGL-3 being the most severe. AEGL-1 is the airborne 

concentration of a substance that the general population, including susceptible individuals, could 

experience notable discomfort, irritation, or certain asymptomatic nonsensory effects. However, these 

effects are not disabling and are transient and reversible upon cessation of the exposure. AEGL-2 is the 

airborne concentration of a substance above which it is predicted that the general population, including 

susceptible individuals, could experience irreversible or other serious, long-lasting adverse health effects 

or an impaired ability to escape. AEGL-3 is the airborne concentration of a substance above which it is 

predicted that the general population, including susceptible individuals, could experience life-threatening 

health effects or death. The EPA provides AEGLs for a list of chemicals at varying exposure times (10 

minutes, 30 minutes, 1 hour, 4 hours, and 8 hours). Table 2.8.6-3 shows the toxic concentrations of 

benzene, H2S, and Ammonia at the 10-minute exposure time AEGLs based on EPA’s published 

information (EPA 2012).

TABLE 2.8.6-3

Acute Exposure Guideline Levels (in ppm) at 10 minutes

Substance AEGL-1 AEGL-2 AEGL-3

Benzene 130 2,000 9,700

H2S 0.75 41 76

Ammonia 30 220 2,700

DCP’s toxicity analysis considers a 1.5-inch-diameter guillotine release from the Stabilizer outlet 

piping for benzene, a 0.707-inch gasket loss on the Acid Gas Blower Aftercooler discharge piping for 

H2S, and a 0.4-inch hole on the Aqueous Ammonia Storage Tank for aqueous ammonia. DCP used 

PHAST Version 6.7 to model each release. Similar to flammability concentrations, a safety factor of 2 

(i.e. 1⁄2 AEGL) was also applied to reflect uncertainties associated with the model. DCP submitted the 

benzene toxicity analysis to 65 ppm (i.e., 1⁄2 AEGL-1 at 10-minutes). The toxic dispersion distance was 

calculated to extend 314 feet from the release point. For the H2S in the acid gas stream, PHAST did not 

calculate any toxic hazards. The warm temperatures and low operating pressures allows the release to 

dissipate quickly. For the aqueous ammonia release, PHAST calculated the maximum distance to 15 ppm 
154

ammonia concentration (i.e., 1⁄2 AEGL-1 at 10 minutes) to 452 feet from a release point located at the 

Aqueous Ammonia Storage Tank. Each toxic dispersion distance for the AEGL-1, which are nondisabling and reversible, would remain within property under control of DCP. Dispersion distances 

associated with AEGL-2, and -3 would be shorter than these AEGL-1 distances. As a result, we conclude 

that the releases of the toxic components (i.e., stabilized condensate, H2S, and aqueous ammonia) would 

not present a significant impact to the public. If the facility is constructed and operated, compliance with 

the requirements of 49 CFR 193 would be addressed as part of DOT’s inspection and enforcement 

program.

Overpressure Considerations

As discussed in section 2.8.3, the propensity of a vapor cloud to detonate or produce damaging 

overpressures is influenced by the reactivity of the material, the level of confinement and congestion 

surrounding and within the vapor cloud, and the flame travel distance. It is possible that the prevailing 

wind direction may cause the vapor cloud to travel into a partially confined or congested area.

LNG Vapor Clouds

As adopted by Part 193, section 2.1.1 of NFPA 59A (2001) requires an evaluation of potential 

incidents and safety measures incorporated in the design or operation of the facility be considered. As 

discussed under “Overpressures” in section 2.8.3, unconfined LNG vapor clouds would not be expected 

to produce damaging overpressures. The presence of heavier hydrocarbons influences the propensity for 

a detonation or deflagration with damaging overpressures. Less processed product with greater amounts 

of heavier hydrocarbons is more sensitive to detonation. The Project would be designed to receive feed 

gas with methane concentrations as low as 91 percent. These compositions are not in the range shown to 

exhibit overpressures and flame speeds associated with high-order explosions and detonations.

The USCG studies referenced under “Overpressures” in section 2.8.3 indicated overpressures of 4 

bar and flame speeds of 35 meters per second (m/s) were produced from vapor clouds of 86 percent to 96 

percent methane in near stoichiometric proportions using exploding charges as the ignition source. The 4 

bar overpressure was the same overpressure produced during the calibration test involving exploding the 

charge ignition source alone, so it remains unclear that the overpressure was attributable to the vapor 

deflagration. However, unconfined methane vapor clouds ignited with low energy ignition sources have 

been shown to produce flame speeds ranging from 5.2 to 7.3 m/s, which is much less than the flame 

speeds associated with explosions or detonations.

Additional tests were conducted to study the influence of confinement and congestion on the 

propensity of a vapor cloud to detonate or produce damaging overpressures. The tests used obstacles to 

create a partially confined and turbulent scenario, but found that flame speeds developed for methane 

were not significantly higher than the unconfined case and were not in the range associated with 

detonations. Given the LNG compositions which would be handled onsite, potential ignition sources, and 

the expected vapor dispersion characteristics, damaging overpressures would not be expected to occur 

from ignition of an unconfined vapor cloud. However, ignition of a confined natural gas vapor cloud 

could result in higher overpressures. In order to prevent such an occurrence, DCP proposes to install 

flammable gas detectors in occupied building heating, ventilation, and air conditioning (HVAC) inlets to 

reduce the likelihood of flammable vapors dispersing into these buildings. We conclude that these 

measures provide sufficient protection and that the potential for overpressures from confined vapor clouds 

would be negligible.
155

Vapor Clouds from Other Hazardous Fluids

The refrigerants which would be used in the liquefaction process streams have a higher reactivity 

than LNG, and in some circumstances may produce damaging overpressures when ignited. In order to 

evaluate this hazard, DCP used the Baker-Strehlow-Tang Explosion model in PHAST Version 6.7 to 

perform an explosion overpressure analysis. With the assumption that the obstructed volume includes the 

entire vapor cloud, PHAST estimated the distances to the 1-psig threshold resulting from an ethane, 

propane, NGL, or MR releases at different wind speeds. The flammable vapor cloud was ignited at the 

greatest LFL cloud extent. Table 2.8.6-4 provides the worst-case results of the five explosion scenarios 

modeled by DCP. The PHAST results show that the maximum overpressure from the ignition of the 

ethane, propane, or NGL vapor clouds would remain on DCP property. However, PHAST results showed 

that the distance to 1-psig for the MR overpressure scenario would extend beyond DCP’s property 

boundary. Therefore, the MR overpressure scenario was identified for modeling using FLACS to account 

for the detailed geometry model of the Cove Point facility. Distances were determined with a safety 

factor of 2 (i.e., 1⁄2 psi), as a result of previous validation studies and peak-pressure averaging (Hansen, et 

al., 2010). Four congested regions were identified: Pretreatment, Propane Cooling, Liquefaction, and 

Main Air Coolers. The levels of confinement are input parameters in the overpressure modeling software. 

The overpressure threshold were calculated by placing an uniform, stoichiometric fuel/air mixture within 

each congested region and several vapor cloud explosion simulations were performed on FLACS. The 

results show that the distance to 1⁄2 psig overpressure from vapor cloud explosion would extend 

approximately 400 feet but would remain within DCP’s boundary. This overpressure would not reach the 

LNG storage tanks. FLACS also calculated an overpressure scenario from the 3-inch-diameter propane 

truck loading hose guillotine release. This release would disperse over the wooded area located west of 

the proposed facility. The FLACS geometry included the trees and geographic features of the Cove Point 

facility and modeled an ignition of the propane cloud in the wooded area. All of the overpressure 

scenarios calculated by DCP would remain within the DCP property. As a result, we conclude that the 

siting of the proposed Project would not have a significant impact on public safety. If the facility is 

constructed and operated, compliance with the requirements of 49 CFR 193 would be addressed as part of 

DOT’s inspection and enforcement program.

TABLE 2.8.6-4

Overpressure Distances from Refrigerant and Heavy Hydrocarbon Releases

Scenario Material and Leak Location Approximate overpressure distance

1 2-inch hole on MR piping to MR Separator 400 feet

2 2-inch hole on propane header to Propane Receiver 337 feet

3 1-inch hole on propane header to MR/HHP Propane Cooler 477 feet

4 3-inch guillotine on NGL reinjection pump discharge 263 feet

5 4-inch guillotine on Ethane Make-up Piping 247 feet

6 3-inch guillotine on Propane Truck Loading Hose 615 feet

Thermal Radiation Analysis

As discussed in section 2.8.3, if flammable vapors are ignited, the deflagration could propagate 

back to the spill source and result in a pool fire causing high levels of thermal radiation (i.e., heat from a 

fire). In order to address this, 49 CFR Section 193.2057 specifies hazard endpoints in terms of flux levels 

for spills into LNG storage tank containment and spills into impoundments for process or transfer areas. 

For any distance from a pool fire, a flux level which expresses how much thermal radiation would be 

received at that point can be calculated. Each LNG container and LNG transfer system is required to 

have a thermal exclusion zone in accordance with Section 2.2.3.2 of NFPA 59A (2001). Together, Part 

193 and NFPA 59A (2001) specify different hazard endpoints for spills into LNG storage tank 
156

containment and spills into impoundments for process or transfer areas. For spills from the process or 

transfer areas, the 1,600 Btu/ft2-hr flux level from the impoundments cannot extend beyond the facility’s 

property line that can be built upon. These are the Part 193 standards that we used in analyzing the siting 

of the proposed Project.

Part 193 requires the use of the LNGFIRE3 computer program model developed by the Gas 

Research Institute to determine the extent of the thermal radiation distances. Part 193 stipulates that the 

wind speed, ambient temperature, and relative humidity that produce the maximum exclusion distances 

must be used, except for conditions that occur less than 5 percent of the time based on recorded data for 

the area. DCP submitted a thermal radiation analysis that showed the following ambient conditions 

resulted in the maximum exclusion distances: wind speeds of 12.7 mph, ambient temperature of 28°F, 

and 35 percent relative humidity. We agree with DCP’s selection of atmospheric conditions.

For its analysis, DCP used LNGFIRE3 to predict the thermal radiation distances for fires from the 

Impoundment Basin #1, Impoundment Basin #2, Amine Sump, Hydrocarbon Sump, and Trucking Area 

Sump. As indicated in section “Impoundment Sizing,” we recommended DCP to resize the Trucking 

Area Sump accounting for the maximum content of a condensate truck. Therefore, FERC staff used a 

larger surface area of 134 square feet in LNGFIRE3 and calculated a distance of 80 feet to the 1,600-

Btu/ft2-hr heat flux from a resized Trucking Area Sump. This would remain on DCP property. The larger 

surface area is based on a conservative assumption that the Trucking Area Sump’s depth of 11 feet would 

remain the same. Although LNGFIRE3 is specifically designed to calculate thermal radiation flux levels 

for LNG pool fires, LNGFIRE3 could also be used to conservatively calculate the thermal radiation flux 

levels for flammable hydrocarbons such as ethane, propane, NGL, and condensate. Two of the 

parameters used by LNGFIRE3 to calculate the thermal radiation flux is the mass burning rate of the fuel 

and the surface emissive power (SEP) of the flame, which is an average value of the thermal radiation 

flux emitted by the fire. The mass burning rate and SEP of an ethane, propane, NGL, or condensate fire 

would be less than an equally sized LNG fire. Because the thermal radiation from a pool fire is dependent 

on the mass burning rate and SEP, the thermal radiation distances required for ethane, propane, NGL, and 

condensate fires would not extend as far as the exclusion zone distance previously calculated for an LNG 

fire in the same sump.

The resulting maximum thermal radiation distances are shown in table 2.8.6-5 and figure 2.8.6-2. 

The 1,600-Btu/ft2-hr heat flux from the proposed Impoundment Basins would remain within the facility 

property lines. As DCP’s calculations of Impoundment Basin #1, Impoundment Basin #2, Amine Sump, 

Hydrocarbon Sump and our calculation of the Trucking Area Sump show the radiant heat limits for Part 

193 would stay within DCP property, we conclude that the siting of the proposed Project would not have 

a significant impact on public safety. If the facility is constructed and operated, compliance with the 

requirements of 49 CFR 193 would be addressed as part of DOT’s inspection and enforcement program.

TABLE 2.8.6-5

Thermal Radiation Exclusion Zones for Impoundment Basins

Impoundment Basins

1,600 Btu/ft2

-hr Flux Distance

(feet from center of impoundment)

Impoundment Basin #1 184

Impoundment Basin #2 204

Amine Sump 180

Hydrocarbon Sump 173

Trucking Area Sump 39 a

____________________

a For a resized Trucking Area Sump, FERC staff calculated 80 feet. This distance is based on our assumed dimensions of 

the Trucking Area Sump. Thermal radiation analysis based on actual Trucking Area Sump dimensions would be 

performed prior to initial site preparation.
157

Figure 2.8.6-2

Impoundment 10,000, 3,000, and 1,600-Btu/ft2-hr Thermal Radiation Exclusion Zones
158

2.8.7 Emergency Response

Section 3A(e) of the NGA, added by Section 311 of the EPAct, stipulated that in any order 

authorizing an LNG terminal, the Commission shall require the LNG terminal operator to develop an 

emergency response plan (ERP) in consultation with the USCG and state and local agencies. The ERP 

has been in place since the Cove Point LNG Terminal began operation in 1978 and has been updated as 

new projects have changed the configuration of the LNG Terminal. The existing ERP would need to be 

updated to include the proposed liquefaction facilities and emergencies related to refrigerant handling. 

Therefore, we recommend that:

 Prior to initial site preparation, DCP should file its updated ERP to include the 

Liquefaction Facilities as well as instructions to handle on-site refrigerant and NGLrelated emergencies. DCP should file the updated ERP with the Secretary for 

review and written approval by the Director of OEP.

 Prior to initial site preparation, DCP should file an ERP that includes a CostSharing Plan identifying the mechanisms for funding all Project-specific security/

emergency management costs that would be imposed on state and local agencies. In 

addition to the funding of direct transit-related security/emergency management 

costs, this comprehensive plan should include funding mechanisms for the capital 

costs associated with any necessary security/emergency management equipment and 

personnel base. DCP should file the ERP, including the Cost-Sharing Plan, with the 

Secretary for review and written approval by the Director of OEP.

We received a comment on the evacuation route due to an LNG related incident. We did not 

identify any incident from the siting analysis that would change or impact the evacuation routes that have

been established for the existing facility. Furthermore, DCP’s existing emergency response plan indicates 

coordination with the Maryland State Police and Calvert County Sheriff’s Office for offsite emergency 

organization. The Maryland State Police and Calvert County Sheriff’s Office would provide the 

necessary law enforcement assistance, which includes evacuating individuals from designated public and 

private areas. Our recommendation above would address any new emergency situations associated with 

this Project.

2.8.8 Facility Security and LNG Vessel Safety

The security requirements for the Project are governed by 49 CFR 193, Subpart J - Security. This 

subpart includes requirements for conducting security inspections and patrols, liaison with local law 

enforcement officials, design and construction of protective enclosures, lighting, monitoring, alternative 

power sources, and warning signs. Requirements for maintaining safety of the liquefaction facility are in 

the USCG regulations in 33 CFR 127. Requirements for maintaining security of the terminal are in 33 

CFR 105. The Cove Point LNG Terminal has an existing Facility Security Plan, as required by 33 CFR 

105, which has been approved by the USCG. 

The DCP reactivated the offshore pier of the Cove Point LNG Terminal in 2003 and has been 

receiving LNG import shipments. Exporting operations would alter the direction of loaded LNG carrier 

transits, with ships arriving empty but departing with a full cargo. However, there would be no changes 

in the marine systems or the expected number of vessels for the export Project. The operations for LNG 

tankers would remain the same regardless of the direction of the shipment. The mooring, connection, and 

disconnection of the LNG tankers, as well as the shipping routes from/to the offshore pier, would remain 

the same. Currently, there are no U.S. flagged LNG vessels used in either import or export service.
159

In a letter to the USCG dated May 23, 2012, DCP detailed the proposed Project modifications and 

estimated the ship traffic would not exceed the previously approved 200 vessels per year in Docket CP05-

130, et al., and DCP would not accept LNG carriers larger than previously authorized in Docket CP09-60. 

In a letter dated July 2, 2012, the USCG stated that the existing WSA and LOR are adequate for the 

service associated with the proposed Project. However, the USCG specified that applicable amendments 

to the Operations Manual, Emergency Manual, and Facility Security Plan must be made that capture 

changes to the operations associated with the Project. As required by 33 CFR 105 and 127, DCP would 

amend these documents and submit them to the USCG prior to operation of the facility as an export 

terminal. Furthermore, the Memorandums of Understanding established between the USCG, Calvert 

County Sheriff’s Office, and the MDNR ensures enforcement of the safety/security zone while LNG 

vessels are in transit and moored at the facility.

2.8.9 Conclusions on Facility Reliability and Safety

The principal hazards associated with the substances involved in the liquefaction, storage, and 

vaporization of LNG result from cryogenic and flashing liquid releases; flammable vapor dispersion; 

vapor cloud ignition; pool fires; overpressures, and toxicity. As part of the NEPA review, Commission 

staff must assess whether the proposed facilities would be able to operate safely and securely to minimize 

potential public safety impacts. Based on our technical review of the preliminary engineering designs, as 

well as our suggested mitigation measures, we conclude that sufficient layers of safeguards would be 

included in the facility designs to mitigate the potential for an incident that could impact the safety of the 

off-site public. The FEED and specifications submitted for the proposed facilities to date are preliminary, 

but would serve as the basis for any detailed design to follow. If authorization is granted by the 

Commission, the next phase of the Project would include development of the final design. We do not 

expect that the detailed design information to be developed would result in changes to the basis of design, 

operating conditions, major equipment selections, equipment design conditions, or safety system designs 

which were presented as part of DCP’s FEED. However, we are recommending that the final design be 

provided for further staff review to ensure it would be consistent with the safety and operability 

characteristics identified in the FEED. In addition, we are recommending that the facility, during 

construction and operation, be subject to regular FERC staff technical reviews and site inspections on at 

least an annual basis.

Siting of the facility with regard to potential off-site consequences from these hazards is also 

required by DOT’s regulations in 49 CFR 193, Subpart B. As part of its application to FERC, DCP 

identified how its proposed design would comply with DOT’s Part 193 siting requirements. We used this 

information to assess whether or not a facility would have a public safety impact and DOT, as a 

cooperating agency, assisted in this evaluation. As provided, DCP’s siting analysis indicates that the 

siting of the proposed facility would not have a significant impact on public safety. If this facility is 

approved and becomes operational, the facility would also be subject to DOT’s inspection program under 

49 CFR 193. Final determination of whether a facility is in compliance with the requirements of Part 193 

would be made by DOT staff during those inspections.

2.9 CUMULATIVE IMPACTS

NEPA requires the lead federal agency to consider the potential cumulative impacts of proposals 

under their review. Cumulative impacts may result when the environmental effects associated with the 

proposed action are superimposed on or added to impacts associated with past, present, and reasonably 

foreseeable future projects. Cumulative impacts can result from individually minor, but collectively 

significant, actions taking place over a period of time. Generally, we believe that cumulative impacts

could result only from the construction of other projects in the same vicinity and impacting the same 

resource areas as the proposed facilities. In such a situation, although the impact associated with each 
160

project might be minor, the cumulative impact resulting from all projects being constructed in the same 

general area could be greater.

Our analysis includes other projects in the vicinity of the proposed Project that affect the same 

resources as the proposed Project in the same approximate time frame. Specifically, actions included in 

the cumulative impact analysis must:

 impact a resource potentially affected by the Project;

 cause this impact within all, or part, of the Project area; and

 cause this impact within all, or part, of the time span for the potential impact of the 

Project.

2.9.1 Projects and Activities Considered

Construction and operation of the Pleasant Valley Compressor Station, Suction/Discharge 

Pipelines, and M&R Facility would occur within DCP’s existing property and rights-of-way that are 

located in a relatively undeveloped area. As described in section 1.3.1, Nonjurisdictional Facilities, the 

existing electrical substation at the Pleasant Valley Compressor Station would also be expanded to 

support the additional compressor units proposed by DCP. The expansion would affect 0.9 acre within 

the fence line of the compressor station and would be constructed, owned, and operated by the Northern 

Virginia Electric Cooperative, which would obtain the necessary permits and approvals for the project. 

Based on the relatively small scale of the substation expansion and considering that the project would 

occur within the workspace of the Pleasant Valley Compressor Station modifications, we conclude that 

contemporaneous construction and operation of the Pleasant Valley Compressor Station and the 

expansion of the existing electrical substation would not result in any significant cumulative impacts.

No substantial developments have occurred recently in the vicinity of the Pleasant Valley 

facilities and no other known, projects are proposed in the area. Thus, the Pleasant Valley facilities would 

not result in construction-related cumulative impacts in the area. Operation of the modified compressor 

station could impact regional air quality and locally contribute to existing noise. However, only minor 

increases in air emissions and noise would occur because the additional compression would be achieved 

by electric-driven compressor units and DCP would implement measures, including installation of a 

sound barrier wall, to mitigate for noise. Thus, construction and operation of the proposed Pleasant 

Valley facilities (including the electrical substation expansion) would not result in any significant 

cumulative impacts, and they are not discussed further in this analysis.

The proposed modifications of the Loudoun M&R Facility would occur within DCP’s existing 

Loudoun Compressor Station site, and DCP would utilize developed and maintained space at the nearby 

Leesburg Compressor Station during construction. The primary recent development near the Loudoun 

M&R Facility is Greene Mill Preserve, a residential subdivision located approximately 1,500 feet 

northeast from the site. Development at the Greene Mill Preserve is ongoing, with additional homes 

being proposed and under construction. No other substantial development activities are known in the 

area. As described throughout section 2.0, construction of the Loudoun M&R Facility and temporary use 

of the Leesburg Compressor Station Contractor Staging Area would have only minor impacts on 

environmental resources associated with piping and measurement upgrades and material laydown and 

storage, respectively. As such, no increased operational impacts would occur. Thus, construction and 

operation of the proposed Loudoun M&R Facility would result in negligible, cumulative impacts on the 

environment and it is not discussed further in this analysis.
161

As described in section 1.1, the LNG Terminal has undergone four expansions or modifications 

since the original construction of the facility was completed in 1978. The most recent of these, the Pier 

Reinforcement Project, was completed and placed into service in 2011. Whereas the Liquefaction 

Facilities would result in incremental environmental impacts as described in section 2.0, we conclude that 

the proposed facilities and previous projects at the LNG Terminal would not have a cumulative impact on 

the environment largely because all of the on-shore components of the previous projects at the LNG 

Terminal occurred within the industrial Fenced Area where the proposed Liquefaction Facilities, if 

approved, would be constructed, and because the construction of the most recent previous project ended 

at least 3 years before construction of the proposed Project is scheduled to begin. Therefore, the previous 

expansions and modifications at the LNG Terminal or offshore pier are not considered further in this 

analysis. 

The proposed Liquefaction Facilities and Offsite Areas A and B would affect confined areas 

within Calvert County for an approximately 3-year construction timeframe. For this analysis, we 

considered Calvert County as the main region of influence in which impacts have the potential to be 

cumulative, extending our review as necessary to the watershed and air shed encompassing the Project 

area. In addition, we considered projects that could potentially be or are connected to the proposed 

Project in our analysis (i.e., the Keys Energy Center and the temporary warehouse, respectively). More 

distant projects are not addressed because these projects generally do not have regional effects, and 

therefore, do not contribute substantially to cumulative impacts in the proposed Project area. Table 2.9-1 

summarizes other ongoing or planned projects in proximity to the LNG Terminal that we considered in 

our cumulative impacts analysis. 

TABLE 2.9-1

Existing or Proposed Projects Evaluated for Potential Cumulative Impacts

Project Description Status

Location Relative to Cove 

Point Liquefaction Project

Projects Near the Liquefaction Facilities, Offsite Area A, and Offsite Area B

Calvert Cliffs Unit 3 Project Potential addition of a third 

unit at the Calvert Cliffs 

Nuclear Power Plant.

Initial permitting underway. 

The project does not have a 

required U.S. sponsor; 

therefore, construction is 

speculative and would likely 

occur after completion of the 

proposed Cove Point 

Liquefaction Project (Project).

Approximately 2.9 miles north 

of the Liquefaction Facilities.

Maryland Route 4 Upgrades Upgrades to the Thomas 

Jefferson Bridge and 

Maryland Route 4 to the south 

of the bridge, potentially 

resulting in a widening of the 

bridge from two lanes to four.

Planning phase scheduled to 

be completed in 2014. 

Maryland State Highway 

Administration conducted its 

environmental review and is 

drafting a Finding of No 

Significant Impact. 

Construction would likely 

occur after completion of the 

proposed Project.

West and south of Offsite 

Area B along Maryland Route 

4.

Hidden Treasure

Development

37-lot residential 

development.

Majority of lots have been sold 

with homes constructed; some 

unsold lots remain.

Within 0.25 mile south of the 

Fenced Area.

Keys Energy Center A nominal 735 megawatt

power generating facility; may

require construction of a new 

natural gas lateral pipeline 

from DCP’s existing Cove

Point Pipeline.

Initial planning phase; 

environmental review 

underway.

Approximately 30 miles 

northwest of the Liquefaction 

Facilities.
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TABLE 2.9-1 (cont’d)

Existing or Proposed Projects Evaluated for Potential Cumulative Impacts

Project Description Status

Location Relative to Cove 

Point Liquefaction Project

Nonjurisdictional Facilities Associated with the Cove Point Liquefaction Project

Road Improvements Addition of a signal at the 

intersection of Maryland Route 

2/4 and Maryland Route 497 

and construction of a 200-footlong right turn lane with a 150-

foot-long taper along 

eastbound Maryland Route 

497 at Cove Point Road.

Utility modifications, including

relocation of poles; guy wires 

and cables; and power and 

telecommunications wiring;

relocation of planned 

municipal improvements (e.g., 

road, water, sewer) along 

Cove Point Road. 

Modifications to traffic signals, 

signage, and road crossings 

may also be required. 

Construction underway.

Prior to construction of the 

Liquefaction Facilities.

Approximately 1.5 miles west 

of the LNG Terminal property, 

near Offsite Area A.

Cove Point Road, between 

Offsite Area B and the LNG 

Terminal. 

Calvert County sewer 

extension external to the LNG 

Terminal

Extension of the existing 

Calvert County septic sewer 

system approximately 2 miles

to the LNG Terminal entrance. 

Work would be contracted by 

DCP but constructed under 

guidance of the Calvert 

County Department of Public 

Works.

Approximately 1.7 acres 

affected.

Proposed completion in 2014. Extending approximately 2 

miles west of the LNG 

Terminal property.

Calvert County sewer service 

internal to the LNG Terminal

Construction of a new sewer 

system at the LNG Terminal to 

connect to the Calvert County 

sewer extension described 

above.

Proposed construction in 

2014. 

Within the Fenced Area and 

offshore pier tunnel and along 

the existing LNG Terminal 

access road.

Other Related Activities Associated with the Cove Point Liquefaction Project

Warehouse and storage yard Temporary use of an existing 

19,500 square-foot warehouse 

and 1-acre storage yard to 

store stock from an existing 

warehouse within the Fenced 

Area that would be removed 

as part of the Project.

Relocation of materials to the 

warehouse is underway.

Approximately 16 miles 

northwest of the Liquefaction 

Facilities in Prince Frederick, 

Maryland.

Temporary maintenance shop/

permanent warehouse, and 

new radio tower

Construction of an 

approximately 9,600 squarefoot building to be used as a 

maintenance shop during 

construction and as a 

warehouse during operation of 

the proposed Project. A new 

radio tower is to be erected 

next to the building.

Permit applications have been 

submitted. Proposed early 

2014.

Within the northeast corner of 

the Fenced Area.

Permanent maintenance shop Construction of a new 

maintenance shop to be used 

during operation of the 

proposed Project.

Permit applications have been 

submitted. Proposed early 

2014.

Within the Fenced Area, near 

the existing Administration 

Building.
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TABLE 2.9-1 (cont’d)

Existing or Proposed Projects Evaluated for Potential Cumulative Impacts

Project Description Status

Location Relative to Cove 

Point Liquefaction Project

New and relocated security 

fence

Temporary and permanent 

fencing to separate 

construction areas and secure 

areas within the Fenced Area.

Temporary fence installation is 

underway. Permanent gates/

access points would be 

activated after the USCG 

approves the facility security 

plan.

Within the Fenced Area.

Regarding the other related activities, the new buildings and radio tower would be constructed 

within the industrial Fenced Area at the LNG Terminal. The temporary and permanent security fencing 

would also be erected within the Fenced Area. Construction and restoration within these areas would be 

in accordance with our Plan and Procedures and DCP’s Project-specific E&SCPs, SMP, and other permit 

conditions as may be required, thereby minimizing impacts associated with construction and operation of 

the other related activities. In addition, the other related activities would be visually consistent with the 

existing industrial appearance within the Fenced Area, and would not contribute appreciably to noise in 

the surrounding area. We conclude that the other related activities within the Fenced Area would not 

result in significant cumulative impacts and, therefore, they are not discussed further in this analysis.

DCP’s temporary use of the existing warehouse in Prince Frederick, Maryland, would create 

additional traffic on area roads between the LNG Terminal and warehouse; however, we find that the 

existing road system could accommodate the added traffic. Based on the above and considering that 

DCP’s proposed use of the warehouse would be consistent with the purpose of the facility, we conclude 

that the temporary use of the warehouse would not result in significant cumulative impacts and, therefore, 

it is not discussed further in this analysis.

Construction and operation of the Calvert County sewer system within the LNG Terminal 

boundaries would largely take place within the workspace of the Liquefaction Facilities. The portions of 

the sewer system that would be constructed outside of the workspace for the Liquefaction Facilities would 

be installed within the existing developed LNG Terminal boundaries, including the offshore pier tunnel 

and existing access road entrance to the LNG Terminal site. Because the sewer system installation would 

occur within the workspace for the proposed Project and DCP’s existing industrial facilities, we conclude

that contemporaneous construction and operation of the proposed Liquefaction Facilities would not result 

in any significant cumulative impacts. 

We received comments suggesting our analysis include projects related to natural gas 

development and gathering (including Marcellus Shale development), natural gas transportation, and 

natural gas distribution in areas that are well beyond the proposed Project area, in some cases they would 

be hundreds of miles away. In addition, no such development is occurring in the State of Maryland. As 

discussed in section 1.2, the FERC’s authority under the NGA and NEPA review requirements relate only 

to natural gas facilities that are involved in interstate commerce. A more specific analysis of Marcellus 

Shale upstream facilities is outside the scope of this analysis because the exact location, scale, and timing 

of future facilities are unknown. In addition, the potential cumulative impacts of Marcellus Shale drilling 

activities are not sufficiently casually related to the Project to warrant the comprehensive consideration of 

those impacts in this EA. As such, these projects were not included in our cumulative analysis. 

The remaining projects listed in table 2.9-1, including the four projects in proximity to the LNG 

Terminal, as well as the nonjurisdictional road improvements and Calvert County sewer extension outside 
164

the LNG Terminal, have the potential to cumulatively affect resources during construction and operation 

of the proposed Project. These potential cumulative impacts are discussed below by affected resource. 

2.9.2 Geology and Soils

Construction of the Liquefaction Facilities and use of Offsite Areas A and B would have a direct

but temporary impact on near-surface geology and soils. Impacts on geology and soils could lead to poor 

revegetation potential and indirectly affect wildlife and aquatic resources as a result of poor vegetation 

cover and increased erosion and sedimentation. However, the soil stabilization and revegetation 

requirements in our Plan and Procedures and DCP’s E&SCPs would prevent or minimize any direct 

impacts. Because the direct effects would be highly localized and limited primarily to the period of 

construction, cumulative impacts on geology and soils would only occur if other projects are constructed 

at the same time and place as the proposed facilities. The construction schedules for the Calvert Cliffs 

Unit 3 Project and Maryland Route 4 upgrades have not yet been determined. Both projects are currently 

in the environmental review stage; however, construction is not expected to begin until after construction 

of the proposed Project. Road improvements are currently occurring near Offsite Area A and include 

vegetation clearing and grading to prepare for installation of the turn lane. These improvements would 

occur in compliance with erosion control measures required by the MSHA and Calvert County. The 

construction of the projects that require significant excavation or grading, such as the Maryland Route 4 

upgrades and road improvements, would also have temporary direct impacts on near-surface geology. 

However, the cumulative impacts on these resources would be minimized by the implementation of 

erosion control and restoration measures during the construction and restoration of the projects. 

Therefore, the additive impact of the Cove Point Liquefaction Project and associated nonjurisdictional 

and other related activities on most of these projects would be minimal because they would not occur 

within the same timeframe or the same local vicinity. 

2.9.3 Waterbodies and Wetlands

Construction of the proposed Project would affect three surface waterbodies and three wetlands. 

Operation of the Liquefaction Facilities would permanently fill one of the waterbodies (WUS1) and one 

of the wetlands (Wetland 1). The remaining waterbodies and wetlands affected by construction of the 

Project would be restored to preconstruction conditions following construction. 

Cumulative impacts on surface water resources and wetlands would be limited primarily to 

waterbodies and wetlands that are affected by other projects located within the same watershed as the 

proposed Project. Runoff from construction activities near waterbodies could also result in cumulative 

impacts, although this effect would be relatively minor and would be controlled by implementation of 

erosion and sediment control measures and by compliance with federal, state, and local requirements. 

Construction of the Maryland Route 4 upgrades could include in-water activities in the Patuxent 

River associated with the upgrades to the Thomas Jefferson Bridge; however, because construction of the 

Maryland Route 4 upgrades is not expected to occur until after construction of the proposed Project is 

complete and the bridge work would be required to comply with federal, state, and local requirements, no 

cumulative impacts on the Patuxent River would be expected.

If the proposed Project were constructed at the same time as the other proposed projects in the 

area, the geographic extent and duration of disturbances to waterbodies and wetlands by construction of 

the Project would be minimal, and further minimized by DCP’s implementation of our Plan and 

Procedures and its E&SCPs. While the proposed Project would result in the permanent loss of a portion 

of stream WUS1 and Wetland 1, the COE has determined that no mitigation would be required for these 
165

impacts. As such, we conclude that construction and operation of the proposed Project would not result 

in a significant cumulative impact on surface waters and wetlands.

2.9.4 Vegetation and Wildlife

When projects are constructed at the same time or close to the same time, they would have a 

cumulative impact on vegetation and wildlife occurring in the areas where the projects would be built. 

Clearing and grading and other activities associated with the Project, including the nonjurisdictional and 

other related activities, along with the projects described above, would result in the removal of vegetation; 

alteration of wildlife habitat; displacement of wildlife; and other potential secondary effects such as 

increased population stress, predation, and the establishment of invasive plant species. These effects 

would be greatest where the other projects are constructed within the same timeframe and in close 

proximity to the proposed Project facilities. 

As discussed in section 2.3.1, the greatest impact on vegetation would be the clearing of forested 

areas because of the length of time required for woody vegetation to revert to its preconstruction 

condition. Approximately 113 acres of upland forest and 2 acres of early successional woodland would 

be removed by construction of the Project. The amount of forest that would be removed at the LNG 

Terminal and Offsite Area A represents approximately 0.1 percent of the 81,000 acres of forest in Calvert 

County. Operation of the Project would result in the permanent loss of 11.5 acres of upland forest, 

including 11.2 acres within the Fenced Area at the LNG Terminal and 0.3 acre within the boundary of the 

Pleasant Valley Compressor Station. 

At Offsite Area A, DCP configured its workspace to preserve approximately 73 acres of forest, 

exceeding a minimum requirement of 61 acres that was required by Calvert County. In addition, DCP 

would mitigate the loss of forest land at the Liquefaction Facilities through the Calvert County fee-in-lieu 

program or the purchase of transferrable development rights, and by placing a 102-acre undeveloped 

parcel of land approximately 1 mile west of Offsite Area A into a preservation easement to offset forest 

and natural resource impacts associated with the Project. 

The impacts on vegetation and wildlife habitat associated with the projects listed in table 2.9-1 

would be minimal because many of the projects would primarily occur at locations that are already 

developed or along existing rights-of-way. The road improvements require the removal of vegetation 

immediately adjacent to Maryland Route 2/4 and Maryland Route 497. In addition, both the Liquefaction 

Facilities and Calvert Cliffs Nuclear Power Plant are adjacent to significant areas of undeveloped forested 

land placed in preservation trusts. Further, the proposed projects would be required to implement 

measures to reduce potential impacts on vegetation and wildlife, and DCP would implement the measures 

in our Plan and Procedures and its E&SCPs to reduce impacts associated with the proposed Project and 

promote revegetation following construction. As such, we conclude that the proposed Project would not 

contribute to a cumulative impact on vegetation or wildlife. 

2.9.5 Land Use, Recreation, and Visual Resources

The proposed Project and the other potential future projects in table 2.9-1 would result in both 

temporary and permanent changes to the current land uses. Much of the land that would be disturbed by 

construction at the Liquefaction Facilities, Calvert Cliffs Nuclear Power Plant, and the Maryland Route 4 

upgrades is currently developed or adjacent to previously developed land. As such, construction and 

operation of the projects would be consistent with existing uses of the site and views of the area. 

Residential development projects would convert additional acres of land from primarily undeveloped to 
166

developed. However, the change in land use would likewise be consistent with surrounding residential 

developments in the area.

The use of Offsite Areas A and B would be limited to the 3-year period of construction. Offsite 

Area A is currently undeveloped and would be restored and replanted as requested by the landowner. 

Offsite Area B would be allowed to revert to its previous use following construction and no permanent 

change to the land use would occur.

The proposed Project, if built during the same timeframe as other foreseeable future projects, 

could result in cumulative impacts on recreational or special interest areas if these projects would affect 

the same area or features (e.g., parkland, recreational river uses) at the same time. However, because the 

Liquefaction Facilities would primarily occur within an existing industrial facility and would not 

substantially affect the surrounding current land uses, most Project-related impacts would be limited to

the 3-year period of construction. Recreational users of the Solomons Island Boat Launch and Pier, 

which is adjacent to Offsite Area B, and users on the Patuxent River could experience short term 

cumulative impacts related to recreational activities on the water if construction of the Maryland Route 4 

upgrades and DCP’s use of Offsite Area B occur at the same time. However, construction of the 

Maryland Route 4 upgrades is not expected to occur until after construction of the proposed Project. In 

addition, DCP’s use of the temporary pier would include only 42 barge deliveries over the course of 18 

months, and DCP has committed to avoiding impacts on recreational users. During operations, the 

Maryland Route 4 upgrades would not result in impacts on recreational users of the Patuxent River or 

Solomons Island Boat Launch and Fishing Pier after construction (DOT and MSHA, 2010), and Offsite 

Area B would not be used beyond construction of the proposed Project. Therefore, we conclude that 

construction and operation of the proposed facilities would not result in a significant cumulative impact 

on recreational activities. 

The visual character of the existing landscape is defined by the historic and current land uses such 

as agriculture, recreation, conservation, and development. The visual qualities of the landscape are 

further developed by existing linear installations such as highways, railroads, pipelines, and electrical 

transmission and distribution lines. Within this context, DCP’s proposed Liquefaction Facilities, 

nonjurisdictional facilities, and other related activities, as well as the other foreseeable future projects 

described in table 2.9-1, could have a visual impact in the area. In addition, the removal of forest 

vegetation at Offsite Area A would result in a permanent visual impact. However, as previously 

discussed, the various proposed projects would be consistent with existing uses of the sites and views of 

the area. At Offsite Area A, DCP would maintain a 60-foot buffer of trees along the eastern boundary of 

the site to screen it from Maryland Route 2/4. Therefore, we conclude that the proposed Project would 

not contribute to a significant cumulative impact on visual resources. 

2.9.6 Socioeconomics

Present and reasonably foreseeable future projects and activities could cumulatively impact 

socioeconomic conditions in the Project area. Employment, housing, infrastructure, and public services 

could experience both beneficial and detrimental impacts. No environmental justice issues have been 

identified.

The proposed Project and the reasonably foreseeable future projects would generate temporary 

employment from construction jobs, as well as provide an influx of associated spending on local goods 

and services, including temporary housing. This influx would provide a temporary economic benefit to 

the individuals and communities in which they reside. In addition to the temporary influx of non-local 

construction workers and associated spending, there would be a cumulative economic benefit from the 
167

proposed Project and the other potential future projects. Annual tax revenues would be expected to 

increase from operation of the proposed Project. In addition, permanent employment would increase 

slightly as a result of operation of the projects. 

The influx of non-local construction workers would temporarily impact housing availability in the 

area. However, given the vacancy rates, and the number of rental housing units and hotel/motel rooms in 

the area, construction crews should not encounter difficulty in finding temporary housing. If construction 

occurs concurrently with other projects, temporary housing would still be available but may be slightly 

more difficult to find and/or more expensive to secure. However, construction of the two largest projects, 

the Calvert Cliffs Unit 3 Project and Maryland Route 4 upgrades, would likely occur after construction of 

the proposed Project. Regardless, these effects would be temporary, lasting only for the duration of 

construction, and there would be no long-term impacts on housing.

Construction of the Maryland Route 4 upgrades and other non-jurisdictional road improvements 

would have the potential to cumulatively affect traffic if DCP’s proposed transport of materials from 

Offsite Area B to the Liquefaction Facilities were to occur during the same time. However, the northern 

extent of the Maryland Route 4 upgrades may not extend to a point such that it would be affected by 

DCP’s transport of equipment. In addition, the construction scheduled for the Maryland Route 4 

upgrades has not yet been determined and is likely to begin after construction of the proposed Project. 

The non-jurisdictional road improvements of Maryland Route 2/4 and Maryland Route 497 would serve 

to lessen traffic impacts associated with DCP’s transport of workers and materials upon completion of the 

turn lane and traffic signal. DCP would coordinate with state and local officials to minimize the effect of 

other improvements along Cove Point Road. During construction of the proposed Project, DCP’s 

movement of large equipment and materials would be subject to local highway use permits, and any such 

permits would be expected to take into account the current traffic conditions on Maryland Route 4 in the 

event construction of the upgrade is underway. Therefore, we conclude that DCP’s transport of 

equipment would not be expected to have a cumulative effect on traffic when combined with other 

potential impacts associated with the Maryland Route 4 upgrades and other non-jurisdictional road 

improvements.

2.9.7 Cultural Resources

Past disturbances to cultural resources in the Project area have been related to construction and 

maintenance operations associated with existing roads, railroads, utility lines, electrical transmission 

lines, and other associated developments; accidental disturbances; intentional destruction or vandalism; 

and lack of awareness of historical value. The currently proposed projects in the area that require 

environmental review by a state or federal agency, including the Calvert Cliffs Unit 3 Project and the 

Maryland Route 4 upgrades, would include mitigation measures designed to avoid or minimize additional 

direct impacts on cultural resources. Where direct impacts on significant cultural resources are 

unavoidable, mitigation (e.g., data recovery) would occur before construction. Non-federal actions would 

comply with any mitigation measures required by the state. The Liquefaction Facilities, Calvert Cliffs 

Unit 3 Project, the Maryland Route 4 upgrades, and other non-jurisdictional road improvements would 

largely occur in areas that have been previously developed, which would likely reduce the potential for 

new impacts on cultural resources. DCP would avoid all potentially significant cultural resources 

identified by its surveys. Therefore, the proposed Project would not add to the effects of the other 

projects on cultural resources in the area. 
168

2.9.8 Air Quality and Noise

Air Quality

The cumulative impact area for air quality during construction of the Project is the area adjacent 

to and near the physical boundary of the construction area. The cumulative impact area for operation of 

the Project is the area covered by the cumulative NAAQS analysis discussed in section 2.7.1. 

Air emissions, including fugitive dust, generated during the construction of the Project and any 

future projects, could potentially result in cumulative impacts on air quality. Emissions from construction 

equipment would be primarily limited to daylight hours and would be minimized through mandated 

engine emission control equipment. Fugitive dust generated by construction activities would also be 

primarily limited to daylight hours and minimized through dust mitigation measures such as water 

suppression. The construction emissions would result in short-term, localized impacts. Cumulative 

impacts from the construction emissions would only occur if construction of the Liquefaction Facilities 

and other projects in the area overlap in schedule and location. Of the existing or proposed projects 

identified in table 2.9-1, only the Maryland Route 4 upgrades, Hidden Treasure Development, and 

nonjurisdictional facilities associated with the Cove Point Liquefaction Project are close enough to the 

Project to have construction-related air quality impacts on the same area. Construction of the Hidden 

Treasure Development and nonjurisdictional facilities associated with the Cove Point Liquefaction 

Project would be completed before the Project commences construction. Construction of the Maryland 

Route 4 upgrade would occur after the Project. In addition, those Project construction emissions (NOx

and VOC) that would potentially contribute to the ozone pollution in the region would be fully offset 

under General Conformity, thereby eliminating contribution to the regional ozone levels. As such, 

construction of the Project would not result in cumulatively significant air quality impacts in the area. 

As discussed in section 2.7.1, detailed modeling was performed to quantitatively evaluate the 

impacts from operation of the Liquefaction Facilities and associated marine vessels. The modeling also 

included other existing sources of air emissions in the Project area and background concentrations. The 

cumulative impacts of the FERC Modeling (modeled concentrations plus existing background 

concentration) demonstrated that the Project would not cause or significantly contribute to a violation of a 

NAAQS. The NAAQS are designed to be protective of human health and the environment. Projects that 

would potentially be constructed in the future, and are considered to be major sources of air emissions, 

would be required to conduct a similar modeling analysis. If operation of a new project would result in a 

significant impact on air quality, the MDE would enforce operational limitations or require emissions 

controls that ensure the facility’s compliance with the SIP and attainment with the NAAQS. In addition, 

DCP would be required to comply with extensive permit conditions during operation of the Liquefaction 

Facilities stationary emission sources, including implementation of LAER and BACT level emission 

controls and NOx and VOC emission offsets. Based on the FERC Modeling and the required emission 

controls, we conclude that there would be no significant cumulative impact on air quality as a result of the 

Project operation.

Noise

Noise impacts are particularly localized and attenuate quickly as the distance from the noise 

source increases. Therefore, cumulative noise impacts would only occur if construction of the 

Liquefaction Facilities and other projects in the area overlap in schedule and location. As discussed 

above, the projects that would occur in close proximity to the Project would not occur at the same time as 

the Project. Therefore, the construction of the Project would not result in significant cumulative noise 

impacts.
169

During operation of the Liquefaction Facilities, DCP’s use of acoustical buildings, piping noise 

control measures, and installation of the sound barrier would reduce noise impacts on the nearest NSAs to 

meet the applicable FERC and Maryland requirements. Because noise attenuates with increasing 

distances, no other projects have been identified in the immediate vicinity that would contribute to the 

operational noise impacts of the Project. Therefore, the Project’s operation would not result in a 

significant cumulative noise impact. 

2.9.9 Climate Change

Climate change is the change in climate over an extended period of time, whether due to natural 

variability, human activities, or a combination of both, and cannot be characterized by single annual 

events or individual weather anomalies. For example, a single large flood event or abnormally hot 

summer may not be an indication of climate change, but a series of floods or hot summers that 

statistically change the average precipitation or temperature over decades may indicate climate change.

The Intergovernmental Panel on Climate Change (IPCC) is the leading international, multigovernmental scientific body for the assessment of climate change. The U.S. is a member of the IPCC 

and participates in the IPCC working groups studying various aspects of climate change. The leading 

U.S. scientific body on climate change is the U.S. Global Change Research Program (USGCRP). 

Thirteen federal departments and agencies participate in the USGCRP, which began as a presidential 

initiative in 1989 and was mandated by Congress in the Global Change Research Act of 1990 (GCRA). 

The USGCRP coordinates and supports U.S. participation in the IPCC assessments.

The IPCC and USGCRP have recognized that:

 globally, GHGs have been accumulating in the atmosphere since the beginning of the 

industrial era (circa 1750);

 combustion of fossil fuels (coal, petroleum, and natural gas), combined with agriculture 

and clearing of forests, is primarily responsible for the accumulation of GHG;

 anthropogenic GHG emissions are the primary contributing factor to climate change; and

 impacts extend beyond atmospheric climate change alone, and include changes to water 

resources, transportation, agriculture, ecosystems, and human health.

The USGCRP issued the report, Global Climate Change Impacts in the United States, in June 

2009 summarizing the impacts climate change has already had on the U.S. and the projected future 

impacts due to continued climate change (USGCRP, 2009). The report describes the effects of global 

change on different regions of the U.S. (e.g., Southeast) and on various societal and environmental 

sectors, such as water resources, agriculture, energy use, and human health. Building on the findings 

presented in this report as well as other recent research, the USGCRP issued the report, The National 

Global Change Research Plan 2012-2021: A Strategic Plan for the U.S. Global Change Research 

Program, which outlines specific goals and objectives for the Program to generate and disseminate 

scientific knowledge that is readily available and directly useful to decision-makers and the general public 

(USGCRP, 2012). These efforts are intended to fulfill the Congressional mandate of the GCRA. 

Although climate change is a global concern, for this analysis, the focus is on the cumulative impacts of 

climate change in the Project area.

The USGCRP’s report notes the following observations of environmental impacts that may be 

attributed to climate change in the Northeast region:
170

 annual average temperatures have risen about 2 °F since 1970 with winter months rising 

twice this much;

 temperatures are projected to increase another 2.5 to 4 °F in winter months and 1.5 to 

3.3 °F in summer months during the next several decades; 

 substantial increases in the extent and frequency of storm surge, coastal flooding, erosion, 

property damage, and loss of wetlands;

 Heat waves, which are currently rare in the region, are projected to become much more 

commonplace in a warmer future, with major implications for human health;

 the number of days that fail to meet federal air quality standards is projected to increase 

with rising temperatures if there are no additional controls on ozone-causing pollutants; 

 large portions of the Northeast are likely to become unsuitable for growing popular 

varieties of apples, blueberries, and cranberries under a higher emissions scenario;

 the southern extent of the commercial lobster harvest appears to be limited by a 

temperature-sensitive bacterial shell disease, and these effects are expected to increase as 

near-shore water temperatures rise above the threshold for this disease;

 additional stress to the already-stressed regional cod fishery;

 increasing acidification resulting from the uptake of CO2 by ocean waters threatens 

corals, shellfish, and other living things that form their shells and skeletons from calcium 

carbonate;

 within the past century in the U.S., relative sea level changes ranged from falling several 

inches to rising about 2 feet and is expected to rise at least another 2 feet in Chesapeake 

Bay;

 coastal waters temperature rose about 2 °F in several regions and are likely to continue to 

warm as much as 4 to 8 °F this century; and 

 the warming of the Chesapeake Bay’s waters will make survival there difficult for 

northern species such as eelgrass and soft clams, while allowing southern species and 

invaders riding in ships’ ballast water to move in and change the mix of species that are 

caught and must be managed.

The GHG emissions associated with construction and operation of the Project were identified and 

quantified in section 2.7.1. Based on the total annual potential emissions for the constructed Liquefaction 

Facilities, Project operations would increase energy-related CO2 emissions in Maryland by approximately 

2.6 percent (based on 2010 emissions for Maryland [DOE, 2013]).

Operational GHG emissions from Project facilities would be minimized by application of EPAapproved BACT under the PSD permitting programs. DCP prepared a BACT analysis for the proposed 

compressor turbines, boilers, standby generator, fire pump engines, flares, thermal oxidizer, and fugitive 

emissions from the Liquefaction Facilities. This analysis was reviewed by the MDE with support from 

PPRP. This analysis will also be reviewed by EPA prior to final approval of the power plant project by 

the Maryland PSC. GHG emissions from the turbines at the Liquefaction Facilities would be minimized 
171

through use of natural gas and LNG process fuel gas as fuels and energy efficient design as BACT. The 

energy efficient design includes the use of HRSG on the turbines and a nitrogen stripper for off gas 

combustion as fuel. DCP estimated that without these measures, a similar facility would result in a 

typical combustion rate of 4,500 MMBtu/hr (compared to the 2,500 MMBtu/hr estimate for the 

Liquefaction Facilities for this Project). BACT for the boilers is the use of process fuel gas for fuel with 

natural gas only during start-up and efficient boiler design. The offgas stream from the acid gas process 

would consistent mainly of CO2 (94 percent). BACT was determined to be oxidation of the offgas using 

a thermal oxidizer supplemented with process fuel gas. The flares are used for controlling VOC and 

GHG emissions during specific events (such as ship cool- down, plant start‐ups and emergencies/upset 

conditions). Therefore, these units function as the GHG emission control to prevent methane from being 

emitted during these events, and additional controls are not practical. BACT for the flares include 

minimizing the duration of flare events. The fire pump engines and emergency generator operating hours 

would be limited making them a relatively small source of GHG emissions for the Project. BACT for 

fugitive emissions from equipment leaks is the implementation of a gas leak detection and repair program. 

This program would follow the procedures outlined in the 28 LAER leak detection and repair program 

from the Texas Commission of Environmental Quality (TCEQ), Control Efficiencies for TCEQ Leak 

Detection and Repair Programs. The use of process fuel gas (as noted above) would yield substantial 

GHG emission reductions for a facility of this size. The use of low carbon containing fuels (natural gas 

and process fuel gas) would also minimize GHG emissions.

In the BACT analysis, DCP evaluated the feasibility of a carbon capture and sequestration (CCS) 

for the Project and specific sources at the Liquefaction Facilities. CCS involves deploying a method to 

capture carbon from the exhaust stream and then finding a method for permanent storage (such as 

injecting the recovered CO2 underground through various means, including enhanced oil recovery, saline 

aquifers, and un-mineable coal seams). In the GHG BACT analysis, DCP stated that there is no 

commercially available carbon capture system of the scale that would be required to control the CO2

emissions from the Project. Additionally, there are significant adverse energy and environmental impacts 

due to the additional water and energy needs for CCS operation, with the associated generation of 

additional GHGs and other criteria pollutants from natural gas firing in combustion units. Based on these 

considerations and the significant costs for implementing CCS, it was not determined to be BACT.

The criteria pollutant BACT limits for the Liquefaction Facilities are summarized in section 2.7.1.

We received comments regarding the impacts climate change could have on the Project, 

particularly as a result of sea level rise and storm surge. Climate change in the northeast region could 

have two effects that may cause increased storm surges: temperature increase of the Chesapeake Bay 

waters, which would increase storm intensity; and a rising sea level. The final grade elevation of the 

Liquefaction Facilities Project site would range between 70 and 130 feet above mean sea level. 

Therefore, even with increased sea levels due to climate change and increased storm surge, the Project 

facilities would not be vulnerable to even a 100-year climate change-enhanced storm surge because of its 

significant elevation above sea level.

Currently, there is no standard methodology to determine how the Project’s incremental 

contribution to GHGs would result in physical effects on the environment, either locally or globally. 

However, estimated emissions associated with the Project would incrementally increase the atmospheric 

concentrations of GHGs, in combination with GHG emissions from other sources identified in the 

cumulative impacts analysis. Because we cannot determine the Project’s incremental physical impacts 

due to climate change on the environment, we cannot determine whether or not the Project’s contribution 

to cumulative impacts on climate change would be significant. 
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2.9.10 Safety

Impacts on reliability and public safety would be mitigated through the use of the DOT Minimum 

Federal Safety Standards in 49 CFR 192 and 49 CFR 193, which are intended to protect the public and to 

prevent natural gas facility accidents and failures. No cumulative impacts on reliability and public safety 

would be anticipated to occur. 

For the proposed Liquefaction Facilities, we considered the cumulative impact area for marine 

vessel traffic to include the Chesapeake Bay from Cape Henry, Virginia where LNG vessels would enter 

the Bay from the Atlantic Ocean. The cumulative impact area for the Liquefaction Facilities is the area 

adjacent to and in the vicinity of the existing LNG Terminal site. The cumulative impact area for 

emergency services includes the area in the general vicinity of the proposed Liquefaction Facilities.

DCP would mitigate impacts on public safety through the implementation of applicable federal, 

state, and local rules and regulations for the proposed Project as described in section 2.8. Those rules and 

regulations would ensure that the applicable design and engineering standards are implemented to protect 

the public and avoid or minimize the potential for accidents and failures. 

The USCG Sector Baltimore concurred that operation of the proposed Liquefaction Facilities 

would not result in an increase in the size and/or frequency of LNG marine traffic beyond that envisioned 

in the current WSA for the LNG Terminal, and that the WSA and LOR are adequate for the service 

associated with the Project. Because DCP has not requested an increase in the number of LNG carriers 

calling on the LNG Terminal, the Liquefaction Facilities would not add to the current risk assessment of 

public safety on the Chesapeake Bay or of an intentional attack on an LNG carrier at berth or in transit to 

the offshore pier. 

Emergency response time is a key aspect of public health and safety. Key emergency services are 

currently provided by the existing Cove Point LNG Terminal in Calvert County. In accordance with our 

regulations, DCP would prepare a comprehensive plan that identifies the cost sharing mechanisms for 

funding emergency response costs. Therefore, we conclude that the proposed Project would not result in 

a significant cumulative impact on public safety. 

2.9.11 Conclusion

The adverse cumulative impacts that could occur in conjunction with the Project would be 

temporary and minor. Temporary cumulative benefits could occur through temporary jobs and wages, 

and the purchases of local goods and materials. Overall, we have determined that the Project, in 

association with other projects in the area, would not result in significant cumulative impacts. 
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3.0 ALTERNATIVES

In accordance with NEPA and FERC policy, we14 evaluated a range of alternatives to the Project 

including the No Action Alternative, energy conservation and alternative sources of energy, system 

alternatives, design alternatives of the Liquefaction Facilities, alternative sources of water for construction 

and operation of the Liquefaction Facilities, and alternative offsite locations to support construction of the 

Liquefaction Facilities. The criteria used to evaluate potential alternatives included whether they:

 Offer a significant environmental advantage over the proposed Project;

 Are technically and/or economically feasible and practical;

 Are permittable within the same general timeframe of the proposed Project; and

 Meet DCP’s stated purpose to liquefy for export domestically produced natural gas. 

DCP participated in our pre-filing process during the preliminary design stage for the Project (see 

section 1.6). This process emphasized identification of potential stakeholder issues, as well as 

identification and evaluation of alternatives that could avoid or minimize impacts. We analyzed Project 

alternatives based on published information, comments, and suggestions from regulatory agencies;

analysis prepared for similar projects; public comments; and data and analysis provided on the public 

record by DCP. The results of the alternatives analyses are provided in the following sections.

3.1 NO ACTION ALTERNATIVE

Under the No Action Alternative, the objectives of the Project would not be met and DCP would 

not provide proposed natural gas capacity for export. In addition, environmental impacts identified in this 

EA would not occur. If the Project is not built, DCP’s export customers would likely seek alternatives to 

meet the contracted service, which could include the construction and operation of other facilities and/or 

the use of alternative forms of energy, resulting in environmental impacts commensurate with the 

facilities and energy source. Also, the beneficial impacts of the Project, including increased employment, 

increased tax revenues, stimulation of the local economy, improved national trade balance, and providing 

a market for U.S. natural gas reserves, would not be realized.

It is speculative and beyond the scope of this analysis to predict what action might be taken by 

policy makers or end users in response to the No Action Alternative. It is possible that without the 

proposed Project, energy needs may be met by alternate energy sources (see discussion below). 

3.2 ALTERNATIVE ENERGY

We believe it is important to consider alternative energy sources as part of the alternative 

selection process. As noted above, implementing the No Action Alternative could force potential natural 

gas customers to seek other forms of energy. Traditional energy alternatives to natural gas include coal, 

oil, hydroelectric, and nuclear power. Renewable energy resources such as solar, ocean energy, biomass, 

wind, landfill gas, and municipal solid waste represent new, advanced energy alternatives. Conceivably, 

each of these energy alternatives could support the generation of new electric power, which is a major 

consumer of natural gas along with residential heating, commercial, and industrial uses. 

The International Energy Agency (IEA) (2012b) reported that coal exports are increasing, and in 

the United States several new coal export projects were recently proposed, suggesting that in many 

international markets coal will remain competitive with natural gas in spite of coal’s greater air emissions. 

EPA (2013) stated that compared to the average air emissions from coal-fired generation, natural gas 

 

14 “We,” “us,” and “our” refer to the environmental staff of the Commission’s Office of Energy Projects.
174

produces half as much CO2, less than a third as much NOx, and 1 percent as much sulfur oxides at power 

plants. Similarly, fuel oil is commonly used for power generation in many countries and will continue to 

compete with natural gas as a fuel source in spite of greater emissions. As a result, if the No Action 

Alternative is selected, it could result in a greater use of other fossil fuels and a potentially substantial 

increase of environmental impacts as compared to the use of natural gas. However, many countries are 

cognizant of the greater environmental impact of coal and fuel oil and prefer to use natural gas as a fuel 

source.

There has been a recent renewed interest in electric power generation by nuclear energy. 

However, because of the increasing demand in electricity consumption worldwide, the U.S. Energy 

Information Administration (2012) estimates that the proportion of electricity generated by nuclear power 

will decrease from 19 percent to 15 percent. In addition, regulatory hurdles, public concern over nuclear 

power and nuclear waste disposal, construction costs, and plant construction lead times make it unlikely 

that nuclear generating capacity could be available to serve all the markets targeted by the Project on a 

similar timeline. Further, plans for nuclear power generation have been scaled back as countries 

reconsidered policies after the accident at the Fukushima Daiichi nuclear power plant near Fukushima, 

Japan, but capacity is still projected to rise, led by China, Korea, India, and Russia (IEA, 2012a).

Renewable energy may become an increasingly significant factor in meeting future energy 

demands worldwide. As reported by IEA (2012a and 2012b), renewables are projected to become the 

world’s second-largest source of power generation by 2015, and are expected to close in on coal as the 

primary source by 2035. However, this rapid increase hinges critically on continued subsidies. In 2011, 

these subsidies (including for biofuels) amounted to $88 billion, but to reach the projection noted above, 

the subsidies would need to increase to $4.8 trillion by 2035 (IEA, 2012a). 

Hydropower is currently the largest source of renewable electric power generation worldwide, 

and IEA expects this trend to continue through 2030. However, as with nuclear power generation, there 

are high costs associated with developing substantial hydropower projects and long time periods between 

project conception and the production of electric power. 

Other promising renewable energy resources include solar, ocean energy, and biomass. However, 

the cost of these types of renewable energy projects is currently high per energy output unit in comparison 

to natural gas-fired power generation. Photovoltaic production in support of solar energy is increasing, 

and the cost of photovoltaic systems is decreasing, with photovoltaic cells potentially able to greatly 

supplement electrical generation resources. 

Ocean energy is a largely unexplored renewable resource. Technologies to capture ocean energy 

are in their infancy, and environmental and engineering considerations are being studied to better 

understand the implications of placement of power generating facilities in the ocean. 

Entrepreneurs and scientists are exploring the emerging use of algae for biofuels and other 

renewable energy applications, and are working to accelerate the development of applications to use algal 

biomass. IEA (2012b) projected electric power generation from biomass technology to increase four-fold 

through 2035, but that time frame is well beyond the planned startup and the currently requested 

authorization lifetime of the proposed Project. 

Further generation of electrical power by wind would require construction of new wind turbines 

and additional electric transmission lines. Although this is likely to occur in many parts of the world, it is 

also likely that such development will be slow-paced in most countries due to the high cost of 

construction. In addition, wind power cannot be used for constant and reliable energy production because 
175

of the variability in winds, and other power generation facilities are commonly in place as backup 

facilities.

Electric generation from municipal waste and landfill methane are growing trends in developed 

countries. Again, the cost of these facilities, including operating costs, is beyond the means of many 

countries. 

With regard to these renewable sources of energy, natural gas is often considered a “bridge fuel;” 

a fuel that bridges the time between the dominant use of fossil fuels today and the greater use of 

renewable energy sources in the future. Natural gas is cleaner burning than other fossil fuels and can also 

reliably serve as a backup fuel to renewable energy facilities, which often provide power intermittently. 

There is currently considerable momentum behind advancing renewable energy technologies and 

moving toward more diversified energy sources. These advanced technologies, either individually or in 

combination, will likely be important in addressing future energy demands. Presumably new energy 

technologies will continue to offset an increasing amount of fossil fuels to meet growing energy demands, 

and that situation is not expected to change in the next decade. 

Although it is speculative and beyond the scope of this analysis to predict what action might be 

taken by policymakers or end users in response to the No Action Alternative, it is possible that without 

the proposed Project, the energy needs may be met by alternative energy sources, likely resulting in 

impacts on the environment. Alternative energy forms such as coal and oil are available and could be 

used to meet increased demands for energy; however, natural gas is a much cleaner-burning fuel. These 

other fossil fuels emit greater amounts of particulate matter, SO2, CO, CO2, hydrocarbons, and noncriteria pollutants. The use of nuclear energy as replacement of other fuel sources also carries undesirable 

consequences, such as negative public perception of the safety of electric generation through nuclear 

plants and the disposal of waste products created. Renewable energies, such as solar, hydroelectric, and 

wind are not always reliable or available in sufficient quantities to support most market requirements and 

would not necessarily be an appropriate substitute for natural gas in all applications. Therefore, we have 

dismissed this alternative as a reasonable alternative to meet the Project objectives.

3.3 SYSTEM ALTERNATIVES

System alternatives would make use of other existing, modified, or proposed systems to meet the 

stated objectives of the Project. A system alternative would make it unnecessary to construct all or part of 

the Project, although some modifications or additions to the alternative system may be required. Such 

modifications or additions would result in environmental impacts; however, the impacts could be less 

than, similar to, or greater than that associated with the Project. 

3.3.1 Other LNG Terminal Alternatives

There are 11 existing LNG terminals in the lower 48 states of the United States, including 6 on 

the Gulf Coast and 5 on the East Coast. Of the five facilities on the East Coast, two are currently seeking 

authorization to export LNG (DCP’s LNG Terminal at Cove Point, Maryland; and El Paso Corporation’s 

Southern LNG Terminal at Elba Island, Georgia). All six of the existing facilities on the Gulf Coast have 

received or are seeking LNG export authorization.

Six other LNG terminals have been approved in the United States, including five on the Gulf 

Coast and one on the East Coast. Five of these six facilities have been approved for LNG import, none of 

which are under construction. The remaining facility, Cheniere/Sabine Pass LNG in Sabine, Louisiana, 
176

has been approved for LNG export and is under review to add additional LNG processing and export 

capability.

Sixteen other LNG terminals have been proposed in the lower 48 states of the United States, 

including 13 facilities for LNG export and 3 facilities for LNG import. Of the 13 proposed LNG export 

facilities, 9 are located on the Gulf Coast, 2 are located in the northwestern United States, and 2 are 

located on the East Coast (DCP’s LNG Terminal at Cove Point, Maryland; and El Paso Corporation’s 

Southern LNG Terminal at Elba Island, Georgia). Similar to the Project, most of the proposed export 

facilities would be constructed at existing LNG import facilities.

Existing, approved, and proposed LNG terminals located other than on the East Coast of the 

United States are not considered as viable system alternatives to the Project. DCP states that the existing 

interconnects with the Cove Point Pipeline would allow feed gas for the Project to be sourced from a wide 

variety of regions in the United States, depending on market forces and circumstances at any given time, 

but presumes that the Project customers selected DCP’s facility as their location for export due to its 

proximity to natural gas supplies in the northeastern United States. Due to added transportation costs, it is 

not reasonable to consider that the Project customers would transport natural gas sourced in the 

northeastern U.S. to facilities on the Gulf Coast or West Coast of the United States for overseas export. 

In addition, the use of other approved and proposed facilities to meet the Project objectives would be 

unlikely to offer an environmental advantage over the Project as the facilities would require construction 

and operation of similar, if not greater, pipeline, LNG production, storage, and marine facilities when 

compared to the proposed Project.

For similar reasons as discussed above, we also did not consider further modification of the 

existing Southern LNG Terminal in coastal Georgia as a viable system alternative to the proposed Project. 

The FERC is currently evaluating El Paso Corporation’s proposal to modify the facility to export LNG

under Docket No. CP14-103-000, and DOE is currently evaluating an application submitted by Southern 

LNG Company, L.L.C. to export LNG to non-FTA nations. Further, the capacity of the existing Southern 

LNG Terminal is fully contracted with subsidiaries of BG Group and Shell and, therefore, would require 

the construction of new facilities to meet DCP’s commitments for the proposed Project.

Regarding the three other, existing LNG terminals on the East Coast, the Distrigas of 

Massachusetts, LLC facility is an LNG import facility on the banks of the Mystic River in Everett, 

Massachusetts, and the Excelerate Energy Northeast Gateway and Neptune LNG Deepwater Port are 

LNG import facilities located approximately 10 miles offshore from Boston and Gloucester, 

Massachusetts, respectively. Modification of these facilities to liquefy and export natural gas would 

require the construction of new facilities, including large floating liquefaction and storage units (FLSUs) 

in the case of the offshore import terminals. As a result, the modification of these facilities to export 

natural gas as LNG would be unlikely to provide a significant, comparative environmental advantage, or 

meet the timeframe of the proposed Project and, thus, are not preferred or viable alternatives to DCP’s 

proposal.

3.3.2 Other Pipeline Alternatives

The existing LNG Terminal is connected to three interstate natural gas transmission systems via 

the Cove Point Pipeline, which would allow the Project customers to transport their supplies of natural 

gas to the proposed Liquefaction Facilities without construction of a new transmission pipeline. 

The nearest interstate pipeline to the Liquefaction Facilities that is not operated by DCP is the 

mainline system of Transcontinental Gas Pipe Line Company. Expansion of this system to the 

Liquefaction Facilities would require at least 90 miles of new, large diameter pipeline and at least one 
177

new compressor station to meet the feed gas requirements of the Project. Such an expansion would result 

in substantially greater environmental impact on landowners and most resources (e.g. vegetation, soil, 

water, and air quality) than the use of the existing Cove Point Pipeline and, thus, is not environmentally 

preferable to DCP’s proposal. Similarly, no alternative to the proposed Pleasant Valley Suction/

Discharge Pipelines was considered because the pipelines would be the shortest length possible between 

the Pleasant Valley Compressor Station and M&R Facility and would be constructed and operated within 

DCP’s existing, maintained right-of-way.

3.3.3 Compression Alternatives

During development of the proposed Project, DCP considered various modifications to its system 

as alternatives to the proposed additional compression at the Pleasant Valley Compressor Station.

Due to relatively low pressure in the pipelines that the Project customers would use to deliver 

natural gas into the Cove Point Pipeline, a higher operating pressure on the Cove Point Pipeline would be 

necessary to meet DCP’s existing contractual obligations and deliver the incremental capacity of the 

Project to the Liquefaction Facilities. In some cases, pipeline looping can be used instead of additional 

compression to increase the overall capacity of a system. However, looping would not resolve the 

pressure differentials between pipelines and, therefore, looping is not a viable alternative to additional 

compression.

Some of the additional compression needed for the Project could potentially be installed at a new 

compressor station located between the Loudoun Compressor Station and the Pleasant Valley Compressor 

Station. However, a new compressor station would not eliminate the need for some additional 

compression at the Pleasant Valley Compressor Station, and construction and operation of a new 

greenfield compressor station would result in overall greater environmental impacts than DCP’s proposed 

expansion of the Pleasant Valley Compressor Station. Therefore, we determined that construction and 

operation of a new compressor station is not an environmentally preferable system alternative to DCP’s 

proposal.

DCP originally considered splitting the compression requirements of the Project between the 

Pleasant Valley Compressor Station and the Loudoun Compressor Station. The Loudoun Compressor 

Station is located in proximity to substantially more homes than the Pleasant Valley Compressor Station 

and, during the scoping process, nearby homeowners raised concerns regarding potential impacts of 

additional compression at the Loudoun Compressor Station. In addition, the existing compressor units at 

the Loudoun Compression Station are fueled by natural gas, whereas the existing units at the Pleasant 

Valley Compressor Station are electric driven, resulting in substantially lower air emissions. DCP also 

proposes to install electric driven compressors at the Pleasant Valley Compressor Station, which would 

only require expansion of the existing Northern Virginia Electric Cooperation substation on the site. In 

contrast, an approximately 3.25-mile-long electric transmission line and new electric substation would be 

required for DCP to operate electric driven compressor units at the Loudoun Compressor Station. Finally, 

DCP determined that adding compression at the Pleasant Valley Compressor Station would satisfy the 

potential customer receipt scenarios to supply gas into the system and the Liquefaction Facilities. Based 

on the above discussion, we agree with DCP’s Project change and conclude that splitting the Project’s 

additional compression requirements between the Pleasant Valley Compressor Station and Loudoun 

Compressor Station is not environmentally preferable to DCP’s proposed expansion of the Pleasant 

Valley Compressor Station only.
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3.4 LIQUEFACTION FACILITIES DESIGN ALTERNATIVES

DCP considered proprietary designs for the Liquefaction Facilities from two separate engineering 

contractors during preliminary Project development. Both of these alternative designs were vetted and 

reviewed by our LNG engineering staff during the pre-filing phase for this Project. In addition to 

improved operating efficiencies, DCP selected the proposed design in its application because it offered 

the following environmental advantages over the alternative design: 

 Use of waste heat from two gas turbines to produce steam utilized to produce electrical 

power via two steam turbine generators;

 reduced fuel consumption and resulting emissions with steam power generation instead 

of gas turbines for power generation;

 reduced impact on the existing facilities and, therefore, existing customers;

 reduced construction workspace and duration of construction; 

 no offshore structural work; and

 less land disturbance at Offsite Area A.

Both the proposed and alternative designs for the Liquefaction Facilities would be constructed 

and operated within the Fenced Area of the LNG Terminal. However, based on the above environmental 

factors and our evaluation of the alternative design during pre-filing, we conclude that the alternative 

design is not environmentally preferable to DCP’s proposed design.

We received comments about the feasibility of using electric driven compressors instead of the 

natural gas driven turbines to reduce potential air quality impacts. There currently is not sufficient 

electric transmission capacity in the vicinity of the Liquefaction Facilities to provide the approximately 

240 MW that would be necessary. Providing the electric transmission capacity to the Liquefaction 

Facilities would require new rights-of-way, permits, and modifications to the existing conservation 

easements that surround the LNG Terminal. Onsite generation is not feasible because there would not be 

sufficient space on the site to build both a stand-alone generation facility and the Liquefaction Facilities. 

In addition, the waste gas generated by the process would be used as the primary fuel for the turbines and 

auxiliary boilers. Because the waste gas is, at times, a lower Btu gas with elevated nitrogen levels that 

could not be used as pipeline gas, the onsite combustion of the waste gas for fuel provides a use for the 

waste gas energy and eliminates energy requirements to compress it to enter the transmission pipeline. 

Therefore, we conclude that the use of electric driven compressors at the Liquefaction Facilities is not 

environmental preferable to DCP’s proposed design.

3.5 ALTERNATIVE WATER SOURCES FOR THE LIQUEFACTION FACILITIES

DCP proposes to utilize groundwater obtained from existing wells at the LNG Terminal for 

construction and subsequent operation of the Liquefaction Facilities. We received comments about 

potential impacts from groundwater withdrawals associated with the Project. In addition, as part of the 

MDNR water appropriations permitting process, DCP evaluated the alternative use of water from the 

Chesapeake Bay, using surface waters on DCP’s property, or obtaining water from the existing Calvert 

County public water supply system.
179

DCP does not have an existing water intake system in the Chesapeake Bay and, according to 

DCP, environmental covenants on the land surrounding the Fenced Area of the LNG Terminal (see 

section 1.2.1) preclude installation of a water line from the Chesapeake Bay to the Fenced Area. In 

addition, brackish water from the Chesapeake Bay would require costly treatment, which would generate 

large volumes of wastewater that would need to be properly managed. DCP also stated that pumping 

water from either Lake Levy or Osborne Pond, which are located on the 1,017-acre LNG Terminal 

property, is not a viable alternative due to the environmental covenants noted above.

The Calvert County public water supply system was considered as a potential source of water for 

the Project. However, DCP’s consultations with Calvert County determined that the current system has 

insufficient capacity to meet the Project’s water requirements as described in section 2.2.

As discussed in section 2.2.1, the Lower Patapsco Aquifer from which the groundwater would be 

withdrawn for the Project has substantial capacity in the area, and pump test data and modeling indicate 

that DCP’s proposed withdrawal, as revised by the MDE, would not significantly impact the aquifer or 

other groundwater users. Therefore, based on the above discussion, we conclude that there are no other 

viable, environmentally preferable sources of water for construction and operation of the Liquefaction 

Facilities.

3.6 OFFSITE AREA ALTERNATIVES

During Project planning and based on consultation with us and MDNR, DCP identified and 

evaluated alternative locations for Offsite Areas A and B as discussed below. DCP would utilize Offsite 

Areas A and B to support construction of the Liquefaction Facilities, after which the properties would be 

restored in accordance with our Plan and Procedures, DCP’s site-specific E&SCPs, environmental permit 

conditions, and landowner agreements. DCP would not own or operate the properties after construction is 

complete. 

3.6.1 Offsite Area A Alternatives

As indicated in sections 1.2.3 and 1.7.3, Offsite Area A consists of 179.4 acres of largely wooded, 

undeveloped land approximately 1.5 miles west of the LNG Terminal. DCP designed the proposed 

workspace of Offsite Area A to minimize the amount of land needed, and incorporated 100-foot-wide 

buffers around wetlands, waterbodies, and other sensitive resources, as well as to provide visual screening 

from Maryland Route 2/4. As a result, approximately 95 acres of the property would be cleared, which 

DCP states is the area needed to support construction of the Liquefaction Facilities. 

Alternative Offsite Areas Considered but Eliminated from Further Analysis

During Project design and in response to agency comments, we evaluated 10 parcels in the LNG 

Terminal region as potential alternatives to proposed Offsite Area A. These parcels, referred to as 

Alternative Offsite Areas C through L, are depicted on figure 3.6.1-1. We eliminated the following seven 

parcels from more detailed analysis for the indicated reasons and they are not discussed further:

Alternative Offsite Area C

Alternative Offsite Area C encompasses 40 acres, of which only 18.2 acres would be available for 

use after incorporating buffers around sensitive resources. Thus, Alternative Offsite Area C is of 

insufficient size on its own to support construction of the Liquefaction Facilities. 
Virginia

Maryland

0 0.5 1

Miles

Date: (8/23/2013) Source: Z:\Clients\A_D\Dominion\Cove_Point\ArcGIS\2013\07\Application\Dominion_Cove_Point_Figure_3.6.1-1.mxd

4 Figure 3.6.1-1

Cove Point Liquefaction Project

Offsite Area Alternatives

Proposed Offsite Area

Offsite Area A Alternative

#* Offsite Area B Alternative

180
181

Alternative Offsite Area D

Alternative Offsite Area D encompasses 82 acres, of which only 59.4 acres would be available 

for use after incorporating buffers around sensitive resources. Thus, Alternative Offsite Area D is of 

insufficient size on its own to support construction of the Liquefaction Facilities. In addition, the site is 

encumbered by a Declaration of Covenants, Easements, Charges, and Liens which prohibits the types of 

activities that would be conducted at the site. 

Alternative Offsite Area H

Alternative Offsite Area H encompasses 282 acres and, thus, could likely meet DCP’s minimum 

workspace requirements. A portion of the site is open, farmed land which could reduce the amount of 

tree clearing for the Project. However, approximately 5 residences would be directly adjacent to the 

workspace and access to the site would be via a county road through a residential area. A trip between 

Alternative Offsite Area H and the LNG Terminal would be approximately 3.0 miles longer than a trip 

between proposed Offsite Area A and the LNG Terminal, and homeowners along the access road would 

experience Project-related traffic for the 3-year period of construction. 

Alternative Offsite Area I

Alternative Offsite Area I encompasses 347 acres and, thus, could likely meet DCP’s minimum 

workspace requirements. The majority of the site is open, farmed land which would reduce the amount of 

tree clearing for the Project. However, the site is crossed by several roads which would require residents 

and other traffic to cross through the workspace. The site also borders Hellen Creek, Mears Creek, and 

the Patuxent River, which would raise increased water quality concerns. In addition, site access would be 

via a county road through residential areas. A trip between Alternative Offsite Area I and the LNG 

Terminal would be approximately 3.3 miles longer than a trip between proposed Offsite Area A and the 

LNG Terminal, and homeowners along the access road would experience Project-related traffic for the 3-

year period of construction. 

Alternative Offsite Area J

Alternative Offsite Area J encompasses 34 acres of largely open land that would require little or 

no tree clearing, but is of insufficient size to support construction of the Liquefaction Facilities on its 

own. The site also abuts Calvert Cliffs State Park and a cemetery, and homeowners along the existing 

access road would experience Project-related traffic for the 3-year period of construction.

Alternative Offsite Area K

Alternative Offsite Area K is a 138-acre parcel occupied by the Calvert County Golf Course. The 

site is partly adjacent to the LNG Terminal and would thus reduce traffic impacts in the area and 

potentially reduce the amount of tree clearing for the Project. However, the site is not available for 

acquisition.

Alternative Offsite Area L

Alternative Offsite Area L encompasses 197 acres of largely open farm land and, thus, would 

meet DCP’s minimum workspace requirements and reduce the amount of tree clearing for the Project. 

However, the site is more than 25 miles away and across the Patuxent River from the LNG Terminal, and 

more than 30 miles from Offsite Area B. In addition, DCP inquired and found that the property is not for 

sale or available for lease.
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Alternative Offsite Areas C, D, and E

In response to agency comments, we considered a combination of Alternative Offsite Areas C, D,

and E (discussed below) as an alternative to DCP’s proposed use of Offsite Area A. Use of these 

combined areas would meet DCP’s minimum workspace requirements and would reduce the required 

amount of forest clearing by approximately 7 acres after incorporating 100-foot-wide buffers around 

sensitive resources. However, the use of three separate parcels would create logistical inefficiencies and 

result in increased traffic between Offsite Area B and the parcels, between each parcel and the LNG 

Terminal, and between the individual parcels themselves. Residences along the various access roads 

would experience this increased traffic for the 3-year period of construction. In addition, as discussed 

below, Alternative Offsite Area E contains a number of sensitive resources; DCP has acquired the 

property and intends to place it into a conservation easement to offset some of the environmental impacts 

associated with the Project. Therefore, on balance, we conclude that a combination of Alternative Offsite 

Areas C, D, and E is not environmentally preferable or practical when compared to DCP’s proposed use 

of Offsite Area A.

Alternative Offsite Areas Considered for Further Analysis

The three remaining sites considered as alternatives to proposed Offsite Area A are discussed in 

greater detail in the following sections. A comparison of environmental factors of Offsite Area A and the 

alternatives is provided in table 3.6.1-1.

TABLE 3.6.1-1

Comparison of Offsite Area A Alternatives

Factor

Offsite Areas

A E

a F G

Size (acres) 179 102 167 315

Usable Size (acres)b 97.0 28.6 87.4 91.7

Wetlands (acres) 8.7 24.4 10.6 15.9

Streams (linear feet) 4,675 7,604 6,858 13,314

Wetland/Stream Crossings (no.) 1 3 3 2

Existing Land Use Forest/

Undeveloped

Forest/

Undeveloped

Forest/

Undeveloped

Forest/

Undeveloped

Forested Land (acres) 171.5 88.0 156.9 307.0

Forest Clearing Required (acres) 95.0 28.6 87.4 90.0

Rare, Threatened, Endangered Species (no./

impacts)

1 (no impacts) 1 (no impacts) 1 (no impacts) 0

Access to Adequate Roads (Y/N) Y N N N

Distance to LNG Terminal via Road (miles) 1.5 4.3 3.7 4.5

____________________

a DCP has acquired Offsite Area E and intends to place the parcel into a preservation easement to offset forest and natural 

resources impacts associated with the Project.

b The Usable Size is the area that remains after incorporating 100-foot-wide protective buffers around sensitive resources 

including wetlands, waterbodies, and rare or protected species.

Alternative Offsite Area E

As indicated in table 3.6.1-1, Alternative Offsite Area E encompasses 102 acres and is 

approximately 2.5 miles west of the LNG Terminal. DCP conducted natural resource inventories of the 

site, including wetland delineations, forest stand delineations, and rare, threatened, and endangered plant 

surveys. Based on these surveys, the site was found to include 88 acres of forest, 24.4 acres of wetlands, 

and 7,604 feet of stream channel, including over 3,000 feet of Hellen Creek (Alternative Offsite Area E is 

situated 1,200 feet upstream of the Hellen Creek Hemlock Preserve, a preserve of the Cove Point Natural 
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Heritage Trust). In addition, the parcel contains documented occurrences of state listed plant species and 

is identified by Calvert County as potential FIDS habitat. 

Although the overall size of Alternative Offsite Area E would meet DCP’s minimum workspace 

requirements, only 28.6 acres would be available for use after incorporating 100-foot-wide buffers around 

sensitive resources. Thus, Alternative Offsite Area E is of insufficient size, on its own, to support 

construction of the Liquefaction Facilities. DCP also noted that the orientation of streams on the property 

would require at least three wetland and waterbody crossings of a similar scope to the one crossing 

required at Offsite Area A. In addition, use of the site would require road improvements to provide 

access to Maryland Route 2/4, and a trip between Alternative Offsite Area E and the LNG Terminal 

would be approximately 2.8 miles longer than a trip between proposed Offsite Area A and the LNG 

Terminal. Residences located along the access road would experience Project-related traffic for the 3-

year period of construction. 

Based on the above discussion, we conclude that Alternative Offsite Area E is not 

environmentally preferable to proposed Offsite Area A. As discussed in section 2.3.1, DCP has 

purchased Alternative Offsite Area E because of its sensitive resources and intends to donate the parcel to 

a conservation group for placement into a preservation easement to offset forest and natural resource 

impacts associated with the Project. 

Alternative Offsite Area F

Alternative Offsite Area F encompasses 167 acres and is approximately 3.5 miles southwest of 

the LNG Terminal. Natural resource inventories identified 156.9 acres of forest, 10.6 acres of wetlands, 

and 6,858 feet of stream channel on the site. Approximately 87.4 acres of useable space would remain 

after incorporating 100-foot-wide buffers around sensitive resources, which is slightly less than the 

workspace requirements identified by DCP. DCP also noted that streams on the property separate the 

parcel into four distinct areas which would require three wetland and waterbody crossings of a similar 

scope to the one crossing required at Offsite Area A. Access to the site would require local road 

improvements, and a trip between Alternative Offsite Area F and the LNG Terminal would be 

approximately 2.2 miles longer than a trip between proposed Offsite Area A and the LNG Terminal. The 

majority of the additional road traffic would occur on Maryland Route 2/4 for the 3-year period of 

construction. 

In conclusion, Alternative Offsite Area F could not meet DCP’s workspace requirements due to 

the 100-foot-wide buffers that would be required around sensitive resources and without clearing a similar 

amount of forest. Use of the alternative would also result in increased impacts on wetlands, waterbodies, 

and traffic. Therefore, we conclude that Alternative Offsite Area F is not environmentally preferable to 

proposed Offsite Area A. 

Alternative Offsite Area G

Alternative Offsite Area G encompasses 315 acres and is north and adjacent to Offsite Area A 

and approximately 1.5 miles northwest of the LNG Terminal. Natural resource inventories identified 307 

acres of forest, 15.9 acres of wetlands, and 13,314 feet of stream channel on the site. A large portion of 

the property is also subject to a Maryland Environmental Trust conservation easement which is intended 

to preserve and limit development of natural areas. Approximately 91.7 acres of the site would be 

available for use after excluding the conservation easement area and providing for a 100-foot-wide buffer 

around sensitive resources. Thus, the site would meet DCP’s stated workspace requirements. Use of the 

site would require the removal of approximately 90 acres of trees, or approximately 5 fewer acres of tree 

removal compared to Offsite Area A. However, streams on the property would require a minimum of two 

wetland and waterbody crossings of a similar scope to the one crossing required at Offsite Area A. 
184

Regarding construction traffic, the environmental easement would prevent direct access onto Maryland 

Route 2/4, requiring DCP to utilize a local road and impacting residences along the road for the 3-year 

period of construction at the Liquefaction Facilities. A trip between Alternative Offsite Area G and the 

LNG Terminal would also be approximately 3.0 miles longer than a trip between Offsite Area A and the 

LNG Terminal. 

In summary, compared to Offsite Area A, Alternative Offsite Area G would require clearing 

approximately 5 fewer acres of trees but would increase impacts on wetlands, waterbodies, traffic, and 

local residents, and is subject to a Maryland Environmental Trust conservation easement. Therefore, we 

conclude that Alternative Offsite Area G is not environmentally preferable to proposed Offsite Area A. 

3.6.2 Offsite Area B Alternatives

As discussed in section 1.2.3 and 1.7.3, Offsite Area B would be used to receive marine deliveries 

of large and heavy equipment to be installed at the Liquefaction Facilities. DCP estimates that 42

shipments would be received via barge at Offsite Area B, requiring approximately 150 truck loads to the 

LNG Terminal and/or Offsite Area A.

We considered four alternative locations for receiving marine shipments, including construction 

of a barge offloading pier at the LNG Terminal; use of the existing barge area at Calvert Cliffs Nuclear 

Plant; use of the existing Calvert Marina in Solomon’s Island; and utilizing the existing facilities at the 

Port of Baltimore. The alternative locations are depicted on figure 3.6.1-1.

LNG Terminal Alternative

A barge offloading pier at the LNG Terminal would avoid the use of an offsite location and 

eliminate the need to utilize public roads for overland transport of large equipment and materials. 

However, a Maryland Natural Heritage Area, Cove Point Marsh, occupies the majority of the beach front 

and coastal area of the LNG Terminal property and the shoreline is potential habitat for the federally 

listed northeastern beach tiger beetle. In addition, the southern extent of the Calvert Shore Oyster 

Sanctuary is offshore from the LNG Terminal between the shoreline and the offshore pier. Further, the 

LNG Terminal property between the Fenced Area and the Chesapeake Bay is subject to environmental 

conservation easements that restrict development in these areas. Lastly, DCP determined that 

construction of a barge offloading pier at the LNG Terminal would likely require dredging, which would 

result in greater impacts on the nearshore and marine environment than the proposed use of Offsite Area 

B. For these reasons we conclude that construction and use of a barge offloading pier and associated 

facilities at the LNG Terminal is not a viable or environmentally preferable alternative to Offsite Area B.

Calvert Cliffs Nuclear Plant Alternative

The Calvert Cliffs Nuclear Plant operates an existing barge offloading facility approximately 3 

miles north of the LNG Terminal on the Chesapeake Bay. We have determined that use of this facility 

would not be feasible due to potential security constraints and conflict with operations of the nuclear 

plant, upgrades to the pier to support the heavy loads proposed for offloading, and upgrades to the 

existing offloading road.

Calvert Marina Alternative

We evaluated the use of the existing Calvert Marina, approximately 0.5 mile from proposed 

Offsite Area B. The Calvert Marina is an active marina, and use of the facility to support the Project 

would require the removal of boat slips and relocation of boats for up to a 3-year period, therefore 

potentially affecting recreation and operations of the marina and boat owners. Use of the facility would 

also likely require widening of the existing access road that is located in the state designated critical 
185

buffer area of the Chesapeake Bay, as well as major road upgrades to access Maryland Route 2/4. In 

contrast, the proposed use of Offsite Area B would not impact marina activities or require upgrades to 

public roads. For these reasons we conclude that use of the Calvert Marina is not preferable to the use of 

Offsite Area B.

Port of Baltimore Alternative

In response to agency comments, we considered the use of existing facilities at the Port of 

Baltimore near the head of the Chesapeake Bay. This alternative location would require each Project 

barge to travel approximately 125 miles further on the Chesapeake Bay than if delivering to Offsite Area 

B, resulting in increased fuel use, air emissions, and marine impacts. Use of the Port of Baltimore would 

also require each heavy load to traverse an additional minimum of 75 miles of road to reach the LNG 

Terminal, resulting in increased logistical and safety concerns. Due to the size of the anticipated loads, 

substantial road upgrades, bridge reinforcements, and overhead utility relocations could also be required. 

Although the Port of Baltimore location would avoid the use of Offsite Area B, we determined that most 

impacts at Offsite Area B would be temporary and minor and, therefore, conclude that the Port of 

Baltimore is not environmentally preferable to DCP’s proposed use of Offsite Area B.
186

4.0 CONCLUSIONS AND RECOMMENDATIONS

Based upon the analysis in this EA, we15 have determined that if DCP constructs and operates the 

proposed facilities in accordance with its application, supplements, and our mitigation measures below, 

approval of this Project would not constitute a major federal action significantly affecting the quality of 

the human environment.

We recommend that the Commission Order contain a finding of no significant impact and include 

the measures listed below as conditions in any authorization the Commission may issue to DCP.

1. DCP shall follow the construction procedures and mitigation measures described in its application

and supplements (including responses to staff data requests) and as identified in the EA, unless 

modified by the Order. DCP must:

a. request any modification to these procedures, measures, or conditions in a filing with the 

Secretary;

b. justify each modification relative to site-specific conditions;

c. explain how that modification provides an equal or greater level of environmental 

protection than the original measure; and

d. receive approval in writing from the Director of the OEP before using that 

modification.

2. Director of OEP has delegated authority to take all steps necessary to ensure the protection of life, 

health, property and the environment during construction and operation of the Project. This 

authority shall include:

a. stop-work authority and authority to cease operation; and

b. the design and implementation of any additional measures deemed necessary to assure 

continued compliance with the intent of the conditions of the Order.

3. Prior to any construction, DCP shall file an affirmative statement with the Secretary, certified 

by a senior company official, that all company personnel, EIs, and contractor personnel will be 

informed of the EI’s authority and have been or will be trained on the implementation of the 

environmental mitigation measures appropriate to their jobs before becoming involved with 

construction and restoration activities. 

4. The authorized facility locations shall be as shown in the EA, as supplemented by filed drawings 

and plans. As soon as they are available, and before the start of construction, DCP shall file 

with the Secretary any revised detailed drawings or plans at a scale not smaller than 1:6,000 with 

station positions for all facilities approved by the Order. All requests for modifications of 

environmental conditions of the Order or site-specific clearances must be written and must 

reference locations designated on these drawings or plans.

5. DCP shall file with the Secretary detailed drawings or plans and aerial photographs at a scale not 

smaller than 1:6,000 identifying all route realignments or facility relocations, and staging areas, 

 

15 “We,” “us,” and “our” refer to the environmental staff of the Commission’s Office of Energy Projects.
187

pipe storage yards, new access roads, and other areas that would be used or disturbed and have 

not been previously identified in filings with the Secretary. Approval for each of these areas must 

be explicitly requested in writing. For each area, the request must include a description of the 

existing land use/cover type, documentation of landowner approval, whether any cultural 

resources or federally listed threatened or endangered species would be affected, and whether any 

other environmentally sensitive areas are within or abutting the area. All areas shall be clearly 

identified on the maps/sheets/aerial photographs. Each area must be approved in writing by the 

Director of OEP before construction in or near that area.

This requirement does not apply to extra workspace allowed by our Plan and/or minor field 

realignments per landowner needs and requirements that do not affect other landowners or 

sensitive environmental areas such as wetlands.

Examples of alterations requiring approval include all facility location changes resulting from:

a. implementation of cultural resources mitigation measures;

b. implementation of endangered, threatened, or special concern species mitigation 

measures;

c. recommendations by state regulatory authorities; and

d. agreements with individual landowners that affect other landowners or could affect 

sensitive environmental areas.

6. Within 60 days of the acceptance of the authorization and before construction begins, DCP 

shall file an Implementation Plan for the review and written approval by the Director of OEP. 

DCP must file revisions to the plan as schedules change. The plan shall identify:

a. how DCP will implement the construction procedures and mitigation measures described 

in its application and supplements (including responses to staff data requests), identified 

in the EA, and required by the Order;

b. how DCP will incorporate these requirements into the contract bid documents, 

construction contracts (especially penalty clauses and specifications), and construction 

drawings so that the mitigation required at each site is clear to onsite construction and 

inspection personnel;

c. the number of EIs assigned for the facility sites, and how the company will ensure that 

sufficient personnel are available to implement the environmental mitigation;

d. company personnel, including EIs and contractors, who will receive copies of the 

appropriate materials;

e. the location and dates of the environmental compliance training and instructions DCP 

will give to all personnel involved with construction and restoration (initial and refresher 

training as the Project progresses and personnel change), with the opportunity for OEP 

staff to participate in the training session(s); 

f. the company personnel (if known) and specific portion of DCP’s organization having 

responsibility for compliance;
188

g. the procedures (including use of contract penalties) DCP will follow if noncompliance 

occurs; and

h. for each discrete facility, a Gantt or PERT chart (or similar project scheduling diagram), 

and dates for:

i. the completion of all required surveys and reports;

ii. the environmental compliance training of onsite personnel;

iii. the start of construction; and

iv. the start and completion of restoration.

7. DCP shall employ at least two EIs for the Project, one for the Liquefaction Facilities and one for 

the facilities in Virginia. The EIs shall be:

a. responsible for monitoring and ensuring compliance with all mitigation measures 

required by the Order and other grants, permits, certificates, or other authorizing 

documents;

b. responsible for evaluating the construction contractor's implementation of the 

environmental mitigation measures required in the contract (see condition 6 above) and 

any other authorizing document;

c. empowered to order correction of acts that violate the environmental conditions of the 

Order, and any other authorizing document;

d. a full-time position, separate from all other activity inspectors;

e. responsible for documenting compliance with the environmental conditions of the Order, 

as well as any environmental conditions/permit requirements imposed by other federal, 

state, or local agencies; and

f. responsible for maintaining status reports.

8. Beginning with the filing of its Implementation Plan, DCP shall file updated status reports on a 

monthly basis for the Project until all construction and restoration activities are complete. On 

request, these status reports will also be provided to other federal and state agencies with 

permitting responsibilities. Status reports shall include:

a. an update on DCP’s efforts to obtain the necessary federal authorizations;

b. the construction status of the Project sites, work planned for the following reporting 

period, and any schedule changes for stream crossings or work in other environmentallysensitive areas;

c. a listing of all problems encountered and each instance of noncompliance observed by 

each EI(s) during the reporting period (both for the conditions imposed by the 

Commission and any environmental conditions/permit requirements imposed by other 

federal, state, or local agencies);

d. a description of the corrective actions implemented in response to all instances of 

noncompliance, and their cost;
189

e. the effectiveness of all corrective actions implemented;

f. a description of any landowner/resident complaints which may relate to compliance with 

the requirements of the Order, and the measures taken to satisfy their concerns; and

g. copies of any correspondence received by DCP from other federal, state, or local 

permitting agencies concerning instances of noncompliance, and DCP’s response.

9. DCP shall develop and implement an environmental complaint resolution procedure. The 

procedure shall provide landowners with clear and simple directions for identifying and resolving 

their environmental mitigation problems/concerns during construction of the Project and 

restoration of the Project facility sites. Prior to construction, DCP shall mail the complaint 

procedures to each landowner whose property would be adjacent to the Project or within 0.5 mile 

of the Project facilities.

a. In its letter to landowners, DCP shall:

i. provide a local contact that the landowners should call first with their concerns; 

the letter should indicate how soon a landowner should expect a response;

ii. instruct the landowners that if they are not satisfied with the response, they 

should call DCP’s Hotline; the letter should indicate how soon to expect a 

response; and

iii. instruct the landowners that if they are still not satisfied with the response from 

DCP’s Hotline, they should contact the Commission’s Dispute Resolution 

Division Helpline at 877-337-2237 or at ferc.adr@ferc.gov.

b. In addition, DCP shall include in its monthly status report a copy of a table that contains 

the following information for each problem/concern:

i. the identity of the caller and date of the call;

ii. the location of the affected property;

iii. a description of the problem/concern; and

iv. an explanation of how and when the problem was resolved, will be resolved, or 

why it has not been resolved.

10. Prior to receiving written authorization from the Director of OEP to commence 

construction of any Project facilities, DCP shall file with the Secretary documentation that it 

has received all applicable authorizations required under federal law (or evidence of waiver 

thereof).

11. DCP must receive written authorization from the Director of OEP prior to introducing 

hazardous fluids into the Project facilities. Instrumentation and controls, hazard detection, 

hazard control, and security components/systems necessary for the safe introduction of such 

fluids shall be installed and functional.
190

12. DCP must receive written authorization from the Director of OEP before placing into service the

Project facilities. Such authorization will only be granted following a determination that the 

facilities have been constructed in accordance with FERC approval and applicable standards, can 

be expected to operate safely as designed, and the rehabilitation and restoration of the right-ofway and other areas affected by the Project are proceeding satisfactorily.

13. Within 30 days of placing the authorized facilities in service, DCP shall file an affirmative 

statement with the Secretary, certified by a senior company official:

a. that the facilities have been constructed in compliance with all applicable conditions, and 

that continuing activities will be consistent with all applicable conditions; or

b. identifying which of the authorization conditions DCP has complied with or will comply 

with. This statement shall also identify any areas affected by the Project where 

compliance measures were not properly implemented, if not previously identified in filed 

status reports, and the reason for noncompliance.

14. DCP shall file the following information, stamped and sealed by the professional engineer-ofrecord, with the Secretary for review and written approval by the Director of OEP:

a. structure and foundation design drawings and calculations of the Liquefaction Facilities;

b. foundations and pile design drawings and calculations for all vibratory equipment,

including gas turbines, HRSGs, steam generators, and compressors supported on piles;

and

c. quality control procedures to be used for design and construction. 

In addition, DCP shall file, in its Implementation Plan, the schedule for producing this 

information.

15. Prior to starting any work on the Pleasant Valley Compressor Station, DCP shall file the 

results of the geotechnical investigation, foundation recommendations, Project design, and 

construction details with the Secretary for review and written approval by the Director of OEP.

16. DCP shall file the final Oyster Bar Mitigation Plan, approved by the MDNR, and artificial reef 

development plan before implementation of the plans.

17. Prior to the use of Offsite Area A, DCP shall file the final Forest Preservation Plan for Offsite 

Area A, approved by the MDNR.

18. Within 7 days prior to the start of tree clearing between the dates of April 1 and August 31, 

DCP shall conduct a survey to identify whether any nesting BCC birds are present in the Fenced 

Area and Offsite Area A. If nesting BCC birds are identified, DCP shall avoid tree clearing and 

other Project activities within 50 feet of active nests until young have fledged the nest and 

vacated the Project area, or it is determined by a qualified biologist that the nest has been 

abandoned. 

19. Prior to construction, DCP shall file documentation of concurrence from MDE that the 

Liquefaction Facilities are consistent with the Maryland Coastal Zone Management Program.
191

20. Prior to construction, DCP shall file the final landscaping plan, approved by the MDNR, for the 

LNG Terminal sound barrier.

21. Prior to construction, DCP shall file the final lighting distribution plan for the Liquefaction 

Facilities, approved by the MDNR, with the Secretary for review and written approval by the 

Director of OEP.

22. Prior to construction, DCP shall install protective fencing around the buffer area for site 

18CV505 at Offsite Area A.

23. Prior to construction, DCP shall file the following information for the issuance of a final General 

Conformity Determination:

a. an updated estimation of Project emissions for each calendar year of construction and initial 

start-up based on the current Project schedule at that time;

b. a record of NOx offsets obtained and demonstrate that this amount is equal to the amount 

required under the General Conformity regulation; and

c. letters from MDE and VDEQ concurring that the offset requirements for the Project have 

been met.

24. Prior to construction, DCP shall file a revised Fugitive Dust Control Plan with the Secretary for 

review and written approval by the Director of OEP. The plan shall specify the precautions that 

DCP would take to minimize fugitive dust emissions from construction activities and identify 

additional mitigation measures to control fugitive dust emissions of Total Suspended Particulates, 

PM10, and PM2.5, including:

a. identifying how DCP would implement these measures (e.g., identification of speed 

limits, usage of speed limit signage, use of gravel at construction entrances to reduce trackout);

b. clarifying that the EI has the authority to determine if/when water or a palliative needs to 

be used for dust control; and

c. clarifying that the EI has the authority to stop work if the contractor does not comply with 

dust control measures.

25. Prior to commissioning of the Liquefaction Facilities, DCP shall file with the Secretary the 

specific noise mitigation measures that would be used on the ground flares and a noise analysis 

demonstrating that the noise from all of the equipment operated during commissioning (including 

ground flares) would not exceed an Ldn of 55 dBA at the nearby NSAs.

26. DCP shall file a full load noise survey at the Liquefaction Facilities with the Secretary no later 

than 60 days after placing the Liquefaction Facilities in service. If a full load condition noise 

survey is not possible, DCP shall provide an interim survey at the maximum possible operation 

within 60 days of placing the Liquefaction Facilities in service and file the full load operational 

survey within 6 months. If the noise attributable to the operation of all of the equipment at the 

LNG Terminal, under interim or full load conditions, exceeds an Ldn of 55 dBA at any nearby 

NSAs, DCP shall file a report on what changes are needed and shall install the additional noise 

controls to meet the level within 1 year of the in-service date. DCP shall confirm compliance 
192

with the above requirement by filing a second noise survey with the Secretary no later than 60 

days after it installs the additional noise controls.

27. DCP should file noise surveys with the Secretary no later than 60 days after placing the 

modified Pleasant Valley Compressor Station in service. If a full load condition noise survey is 

not possible, DCP should provide an interim survey at the maximum possible horsepower load 

and provide the full load survey within 6 months. If the noise attributable to the operation of all 

of the equipment at the compressor station, under interim or full horsepower load conditions, 

exceeds an Ldn of 55 dBA at any nearby NSAs, DCP should file a report on what changes are 

needed and should install the additional noise controls to meet the level within 1 year of the inservice date. DCP should confirm compliance with the above requirement by filing a second 

noise survey with the Secretary no later than 60 days after it installs the additional noise 

controls.

The following measures shall apply to the proposed Liquefaction Facilities at Dominion Cove Point’s 

LNG Terminal. Information pertaining to these specific recommendations shall be filed with the 

Secretary for review and written approval by the Director of OEP either: prior to initial site 

preparation; prior to construction of final design; prior to commissioning; prior to introduction of 

hazardous fluids; or prior to commencement of service, as indicated by each specific condition. 

Specific engineering, vulnerability, or detailed design information meeting the criteria specified in Order 

No. 683 (Docket No. RM06-24-000), including security information, should be submitted as critical 

energy infrastructure information pursuant to 18 CFR 388.112. See Critical Energy Infrastructure 

Information, Order No. 683, 71 Fed. Reg. 58,273 (October 3, 2006), FERC Stats. & Regs. ¶31,228 

(2006). Information pertaining to items such as: offsite emergency response; procedures for public 

notification and evacuation; and construction and operating reporting requirements, will be subject to 

public disclosure. All information shall be filed a minimum of 30 days before approval to proceed is 

requested.

28. Prior to initial site preparation, DCP shall provide procedures for controlling access during 

construction.

29. Prior to initial site preparation, DCP shall file the quality assurance and quality control 

procedures for construction activities.

30. Prior to initial site preparation, DCP shall file a plot plan of the final design showing all major 

equipment, structures, buildings, and impoundment systems.

31. Prior to initial site preparation, a technical review of facility design shall be filed that: 

a. identifies all combustion/ventilation air intake equipment and the distances to any 

possible hydrocarbon release (LNG, flammable refrigerants, flammable liquids, and 

flammable gases); and 

b. demonstrates that these areas are adequately covered by hazard detection devices and 

indicate how these devices would isolate or shutdown any combustion equipment whose 

continued operation could add to or sustain an emergency.

32. Prior to initial site preparation, DCP shall resize the Trucking Area Sump to adequately 

contain the maximum content of a condensate truck.
193

33. Prior to initial site preparation, DCP shall file its updated ERP to include the Liquefaction 

Facilities as well as instructions to handle on-site refrigerant and NGL-related emergencies. 

34. Prior to initial site preparation, DCP shall file an ERP that includes a Cost-Sharing Plan 

identifying the mechanisms for funding all Project-specific security/emergency management 

costs that would be imposed on state and local agencies. In addition to the funding of direct 

transit-related security/emergency management costs, this comprehensive plan shall include 

funding mechanisms for the capital costs associated with any necessary security/emergency 

management equipment and personnel base. 

35. DCP shall certify that the final design has been modified to be consistent with the wind speed 

requirements of 49 CFR § 193.2067 or that DOT has approved the use of a lower wind speed as 

allowed by § 193.2067(b). DCP shall consult with DOT on any actions necessary to demonstrate 

compliance with Part 193.

36. The final design, DCP shall include information/revisions pertaining to DCP’s response numbers 

3, 19, 21, and 64 of its July 16, 2013 filing, which indicated features to be included or considered 

in the final design.

37. The final design shall include change logs that list and explain any changes made from the FEED 

provided in DCP’s application and filings. A list of all changes with an explanation for the 

design alteration shall be provided and all changes shall be clearly indicated on all diagrams and 

drawings.

38. The final design shall provide up-to-date Process Flow Diagrams with heat and material balances

and P&IDs, which include the following information: 

a. equipment tag number, name, size, duty, capacity, and design conditions; 

b. equipment insulation type and thickness; 

c. valve high pressure side and internal and external vent locations;

d. piping with line number, piping class specification, size, and insulation type and 

thickness; 

e. piping specification breaks and insulation limits; 

f. all control and manual valves numbered; 

g. relief valves with set points; and

h. drawing revision number and date. 

39. The final design shall provide P&IDs, specifications, and procedure that clearly show and 

specify the tie-in details required to safely connect the Project to the existing facility.

40. The final design shall provide an up-to-date complete equipment list, process and mechanical 

data sheets, and specifications.

41. The final design shall provide complete drawings and a list of the hazard detection equipment. 

The drawings shall clearly show the location and elevation of all detection equipment. The list 
194

shall include the instrument tag number, type and location, alarm indication locations, and 

shutdown functions of the hazard detection equipment.

42. The final design shall provide complete plan drawings and a list of the fixed and wheeled drychemical, hand-held fire extinguishers, and other hazard control equipment. Drawings shall 

clearly show the location by tag number of all fixed, wheeled, and hand-held extinguishers. The 

list shall include the equipment tag number, type, capacity, equipment covered, discharge rate, 

and automatic and manual remote signals initiating discharge of the units.

43. The final design shall provide facility plans and drawings that show the location of the firewater 

and foam systems. Drawings shall clearly show: firewater and foam piping; post indicator 

valves; and the location of, and area covered by, each monitor, hydrant, deluge system, foam 

system, water-mist system, and sprinkler. The drawings shall also include P&IDs of the firewater 

and foam system.

44. The final design shall include an updated fire protection evaluation of the proposed facilities 

carried out in accordance with the requirements of NFPA 59A 2001, chapter 9.1.2 as required by 

49 CFR Part 193. A copy of the evaluation, a list of recommendations and supporting 

justifications, and actions taken on the recommendations shall be filed.

45. The final design shall specify that for hazardous fluids, piping and piping nipples 2 inches or less 

are consistent with the existing facility’s piping specifications.

46. The final design shall include drawings and details of how process seals or isolations installed at 

the interface between a flammable fluid system and an electrical conduit or wiring system meet 

the requirements of NFPA 59A. 

47. The final design shall provide an air gap or vent installed downstream of process seals or 

isolations installed at the interface between a flammable fluid system and an electrical conduit or 

wiring system. Each air gap shall vent to a safe location and be equipped with a leak detection 

device that: shall continuously monitor for the presence of a flammable fluid; shall alarm the 

hazardous condition; and shall shutdown the appropriate systems.

48. The final design shall provide electrical area classification drawings.

49. The final design shall provide spill containment system drawings with dimensions and slopes of 

curbing, trenches, and impoundments.

50. The final design of the hazard detectors shall account for the calibration gas when determining 

the LFL set points for methane, propane, ethane, and condensate.

51. The final design shall include a hazard and operability review of the completed design prior to 

issuing the P&IDs for construction. A copy of the review, a list of recommendations, and actions 

taken on the recommendations, shall be filed.

52. The final design shall include the cause-and-effect matrices for the process instrumentation, fire 

and gas detection system, and ESD system. The cause-and-effect matrices shall include alarms 

and shutdown functions, details of the voting and shutdown logic, and set points.
195

53. The final design shall include a drawing that shows the location of the ESD buttons. ESD 

buttons shall be easily accessible, conspicuously labeled, and located in an area which would be 

accessible during an emergency.

54. The final design shall include a plan for clean-out, dry-out, purging, and tightness testing. This 

plan shall address the requirements of the American Gas Association’s Purging Principles and 

Practice required by 49 CFR 193, and shall provide justification if not using an inert or nonflammable gas for cleanout, dry-out, purging, and tightness testing.

55. The final design shall include the sizing basis and capacity for the final design of pressure and 

vacuum relief valves for major process equipment, vessels, and storage tanks.

56. The final design shall provide the procedures for pressure/leak tests which address the 

requirements of ASME VIII and ASME B31.3, as required by 49 CFR 193.

57. The final design shall provide the specifications, procedures, and schedule to modify the tunnel 

expansion joints.

58. The final design shall either set the pressure relief valves at the Mole Sieve Gas Dehydrators to 

the design pressure of the closed loop system or design the Mole Sieve Gas Dehydrators and the 

associated hot piping system for the regeneration design temperature and the feed gas design 

pressure of the pretreatment system. 

59. The final design shall include double isolation for each sulfur removal vessel. Manual isolation 

valves shall be installed upstream of the inlet pneumatic valve and downstream of the outlet 

pneumatic valve with vent and purge connections between the manual and pneumatic valves.

60. The final design shall provide coarse mesh strainers in the bottom outlet piping of the adsorbers 

to prevent support material and molecular sieve migrating from Mole Sieve Gas Dehydrators to 

the piping system. 

61. The final design shall provide a redundant low temperature shutdown system for the Flash Gas 

Compressors. The set point shall be set at no less than -50°F. 

62. The final design of the Ethane Make-Up Drum and associated piping system shall include stress 

analysis of the system at the equilibrium temperature of the Ethane at barometric pressure.

63. The final design shall provide all tests, investigations, and reports to ensure the existing firewater 

system’s compatibility and reliability. 

64. The final design shall equip the HRU Column with permanent drainage piping to the cold flare, 

designed for cryogenic conditions. 

65. The final design shall provide drainage piping to the cold flare from the Nitrogen Stripper 

Reboiler bottom inlet piping and Nitrogen Stripper bottom outlet piping upstream of the shutoff 

valve. 

66. The final design shall equip the Stabilizer with permanent drainage piping to the flare system. 
196

67. The final design of the refrigerant and stabilized condensate storage system shall provide dual 

full capacity relief valves that allow the isolation of individual pressure relief valves while 

providing full relief capacity during pressure relief valve maintenance or testing. 

68. DCP shall certify that the final design is consistent with the information provided to DOT as 

described in the design spill determination letter dated February 27, 2014 (Accession Number 

20140227-4004) and supplemental information filed by DCP on March 7, 2014 (Accession 

Numbers 20140307-5050 and 20140307-5051), March 14, 2014 (Accession Numbers 20140314-

5099 and 20140317-5100), and April 11, 2014 (Accession Numbers 20140411-5252 and 

20140411-5253). In the event that any modifications to the design alters the candidate design 

spills on which the Title 49 CFR 193 siting analysis was based, DCP shall consult with DOT on 

any actions necessary to comply with Part 193.

69. The final design shall include the details of the vapor fences as well as procedures to maintain 

and inspect the vapor barriers provided to meet the siting provisions of 49 CFR § 193.2059.

70. Prior to commissioning, DCP shall file plans and detailed procedures for: testing the integrity of 

onsite mechanical installation; functional tests; introduction of hazardous fluids; operational tests; 

and placing the equipment into service.

71. Prior to commissioning, DCP shall provide a detailed schedule for commissioning through 

equipment startup. The schedule shall include milestones for all procedures and tests to be 

completed: prior to introduction of hazardous fluids; and during commissioning and startup. DCP 

shall file documentation certifying that each of these milestones has been completed before 

authorization to commence the next phase of commissioning and startup will be issued.

72. Prior to commissioning, DCP shall tag all equipment, instrumentation and valves in the field, 

including drain valves, vent valves, main valves, and car-sealed or locked valves.

73. Prior to commissioning, DCP shall file a tabulated list and drawings of the proposed hand-held 

fire extinguishers. The list shall include the equipment tag number, extinguishing agent type, 

capacity, number, and location. The drawings shall show the extinguishing agent type, capacity, 

and tag number of all hand-held fire extinguishers.

74. Prior to commissioning, DCP shall file updates addressing the liquefaction facilities in the 

operation and maintenance procedures and manuals, as well as safety procedures.

75. Prior to commissioning, DCP shall maintain a detailed training log to demonstrate that operating 

staff has completed the required training.

76. Prior to introduction of hazardous fluids, DCP shall complete a firewater pump acceptance test 

and firewater monitor and hydrant coverage test. The actual coverage area from each monitor 

and hydrant shall be shown on facility plot plan(s).

77. Prior to introduction of hazardous fluids, DCP shall complete all pertinent tests (Factory 

Acceptance Tests, Site Acceptance Tests, Site Integration Tests) associated with the Distributed 

Control System and the Safety Instrumented System that demonstrates full functionality and 

operability of the system.

78. Prior to commencement of service, DCP shall label piping with fluid service and direction of 

flow in the field in addition to the pipe labeling requirements of NFPA 59A
197

79. Prior to commencement of service, progress on the construction of the proposed systems shall 

be reported in monthly reports filed with the Secretary. Details shall include a summary of 

activities, problems encountered, contractor non-conformance/deficiency logs, remedial actions 

taken, and current Project schedule. Problems of significant magnitude shall be reported to the 

FERC within 24 hours.

The following measures shall apply throughout the life of the facility:

80. The facility shall be subject to regular FERC staff technical reviews and site inspections on at 

least an annual basis or more frequently as circumstances indicate. Prior to each FERC staff 

technical review and site inspection, DCP shall respond to a specific data request, including 

information relating to possible design and operating conditions that may have been imposed by 

other agencies or organizations. Up-to-date detailed P&IDs reflecting facility modifications and 

provision of other pertinent information not included in the semi-annual reports described below, 

including facility events that have taken place since the previously submitted semi-annual report, 

shall be submitted.

81. Semi-annual operational reports shall be filed with the Secretary to identify changes in facility 

design and operating conditions, abnormal operating experiences, activities (including ship 

arrivals, quantity and composition of imported and exported LNG, liquefied and vaporized 

quantities, boil-off/flash gas, etc.), plant modifications, including future plans and progress 

thereof. Abnormalities shall include, but not be limited to: unloading/loading/shipping problems, 

potential hazardous conditions from off-site vessels, storage tank stratification or rollover, 

geysering, storage tank pressure excursions, cold spots on the storage tanks, storage tank 

vibrations and/or vibrations in associated cryogenic piping, storage tank settlement, significant 

equipment or instrumentation malfunctions or failures, non-scheduled maintenance or repair (and 

reasons therefore), relative movement of storage tank inner vessels, hazardous fluids releases, 

fires involving hazardous fluids and/or from other sources, negative pressure (vacuum) within a 

storage tank and higher than predicted boil-off rates. Adverse weather conditions and the effect 

on the facility also shall be reported. Reports shall be submitted within 45 days after each 

period ending June 30 and December 31. In addition to the above items, a section entitled 

“Significant Plant Modifications Proposed for the Next 12 Months (dates)” also shall be included 

in the semi-annual operational reports. Such information would provide FERC staff with early 

notice of anticipated future construction/maintenance projects at the LNG facility.

82. Significant non-scheduled events, including safety-related incidents (e.g., LNG, condensate, 

refrigerant, or natural gas releases, fires, explosions, mechanical failures, unusual over 

pressurization, and major injuries) and security-related incidents (e.g., attempts to enter site, 

suspicious activities) shall be reported to FERC staff. In the event an abnormality is of 

significant magnitude to threaten public or employee safety, cause significant property damage, 

or interrupt service, notification shall be made immediately, without unduly interfering with any 

necessary or appropriate emergency repair, alarm, or other emergency procedure. In all 

instances, notification shall be made to FERC staff within 24 hours. This notification practice 

shall be incorporated into the LNG facility’s emergency plan. Examples of reportable hazardous 

fluids related incidents include:

a. fire; 

b. explosion;

c. estimated property damage of $50,000 or more;
198

d. death or personal injury necessitating in-patient hospitalization;

e. release of hazardous fluids for 5 minutes or more;

f. unintended movement or abnormal loading by environmental causes, such as an 

earthquake, landslide, or flood, that impairs the serviceability, structural integrity, or 

reliability of an LNG facility that contains, controls, or processes hazardous fluids;

g. any crack or other material defect that impairs the structural integrity or reliability of an 

LNG facility that contains, controls, or processes hazardous fluids; 

h. any malfunction or operating error that causes the pressure of a pipeline or LNG facility 

that contains or processes hazardous fluids to rise above its MAOP (or working pressure 

for LNG facilities) plus the build-up allowed for operation of pressure limiting or control 

devices; 

i. a leak in an LNG facility that contains or processes hazardous fluids that constitutes an 

emergency; 

j. inner tank leakage, ineffective insulation, or frost heave that impairs the structural 

integrity of an LNG storage tank;

k. any safety-related condition that could lead to an imminent hazard and cause (either 

directly or indirectly by remedial action of the operator), for purposes other than 

abandonment, a 20 percent reduction in operating pressure or shutdown of operation of a 

pipeline or an LNG facility that contains or processes hazardous fluids; 

l. safety-related incidents to hazardous fluids vessels occurring at or en route to and from 

the LNG facility; or

m. an event that is significant in the judgment of the operator and/or management even 

though it did not meet the above criteria or the guidelines set forth in an LNG facility’s 

incident management plan.

In the event of an incident, the Director of OEP has delegated authority to take whatever steps are 

necessary to ensure operational reliability and to protect human life, health, property, or the 

environment, including authority to direct the LNG facility to cease operations. Following the 

initial company notification, FERC staff would determine the need for a separate follow-up report 

or follow-up in the upcoming semi-annual operational report. All company follow-up reports 

shall include investigation results and recommendations to minimize a reoccurrence of the 

incident.
199

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205

6.0 LIST OF PREPARERS

Federal Energy Regulatory Commission

Wachholder, Joanne – Environmental Project Manager; Water Resources, Fisheries, and 

Wetlands; Vegetation and Wildlife; Socioeconomics; Cumulative Impacts

M.S., Crop and Soil Sciences/Environmental Toxicology, Michigan State University

B.S., Environmental Biology, University of Wisconsin, Stevens Point

Hudzik, Thomas – Deputy Project Manager; Soils; Land Use, Recreation, and Visual Resources

B.S., Environmental Science and Policy, University of Pittsburgh

Suter, Magdalene – Deputy Project Manager; Air Quality and Noise

B.S., Environmental Systems Engineering, Pennsylvania State University

Barakat, Kandilarya – Air Quality and Noise

M.E. Environmental Engineering/Project Management, University of Maryland, College Park

B.S. Chemical Engineering, University of Maryland, College Park

Boros, Laurie – Cultural Resources

B.A., Anthropology/Archaeology, Queens College, C.U.N.Y.

Glaze, James – Geology; Soils

B.S., Geology, California Lutheran University

Nguyen, Thach – Reliability and Safety

B.S., Mechanical Engineering, University of Texas at Austin

Patel, Ghanshyam – Reliability and Safety

B.S., Chemical Engineering, Pennsylvania State University

Merjent, Inc.

Braun, Bill – Project Manager; Proposed Action; Geology and Soils; Cumulative Impacts; 

Alternatives

M.S. coursework completed, Geology, South Dakota School of Mines and Technology

B.S., Earth Sciences, St. Cloud State University

Rice, Zeke – Deputy Project Manager; Socioeconomics; Land Use, Recreation, and Visual 

Resources

B.A., Anthropology/Archaeology and Sociology, Hamline University

Krause, Kari – Cultural Resources

M.S., Archaeological Resource Management, Ball State University

B.A., Anthropology/History, Ripon College

Mackenthun, Jeff – Water Resources, Fisheries, and Wetlands; Vegetation and Wildlife

B.S., Environmental Studies, Bemidji State University

Mordorski, Paul – Air Quality and Noise

B.C.E., Chemical Engineering, University of Minnesota
APPENDIX A

SOIL CHARACTERISTICS AFFECTED BY THE PROJECT
A-1

APPENDIX A

Soil Characteristics Affected by the Project

Facility/Soils Series/Description

Disturbed (acres) a Composed on Site a

Prime 

Farmland

Soil Limitations

Const. Oper

On-site 

Acres

On-site 

Percent

Water 

Erosion 

Hazard

Compaction 

Potential

Depth to Rock 

(inches)

Revegetation 

Potential WEG K-factor

Liquefaction Facilities

Aquasco and Beltsville; BeB

Beltsville-Aquasco complex (silt 

loam and sandy clay loam), 2 to 5 

percent slopes

0.3 <0.1 <0.1 <0.1 Yes Slight Low 20-40 Low 5 0.4

Downer and Dodon; DoG

Downer-Dodon complex (loamy 

sand, and sandy loam), 25 to 80 

percent slopes

9.0 7.8 8.5 22.7 No High Moderate 80+ Moderate 2 0.2

Keyport; KwB

Keyport silt loam, 2 to 5 percent 

slopes

0.1 <0.1 0.1 0.3 No Slight Low 80+ High 5 0.5

Matapeake and Beltsville; MeB

Matapeake-Beltsville complex (silt 

and sandy loam), 2 to 5 percent 

slopes

0.3 0 0.3 0.8 Yes Slight Low 80+ High 5 0.4

Urban; Ub

Urban land

24.8 18.5 25.4 67.7 No Not rated No rated - Not rated Not 

rated

Not rated

Woodstown; WdB

Woodstown sandy loam, 2 to 5 

percent slopes

2.1 2.1 2.1 5.6 Yes Slight Low 80+ High 3 0.2

Woodstown; WdC

Woodstown sandy loam, 5 to 10 

percent slopes

1.1 1.1 1.1 2.9 No Slight Low 80+ High 3 0.2

Subtotal 37.7 29.5 37.5 100.0

Offsite Area A

Aquasco and Beltsville; BeB

Beltsville-Aquasco complex (silt 

loam and sandy clay loam), 2 to 5 

percent slopes

13.3 0 13.7 7.6 Yes Slight Low 20-40 Low 5 0.4

Downer and Dodon; DoG

Downer-Dodon complex (loamy 

sand, and sandy loam), 25 to 80 

percent slopes

46.3 0 105.9 59.0 No High Moderate 80+ Moderate 2 0.2

Fort Mott-Cedartown; FcE

Fort Mott-Cedartown complex 

(sand, loamy sand, and sandy 

loam), 15 to 25 percent slopes

0 0 6.4 3.6 No High Moderate 80+ High 2 0.1
A-2

APPENDIX A

Soil Characteristics Affected by the Project

Facility/Soils Series/Description

Disturbed (acres) a Composed on Site a

Prime 

Farmland

Soil Limitations

Const. Oper

On-site 

Acres

On-site 

Percent

Water 

Erosion 

Hazard

Compaction 

Potential

Depth to Rock 

(inches)

Revegetation 

Potential WEG K-factor

Galstown-Woodstown; GwC

Galstown-Woodstown complex 

(sandy loam and loamy sand), 5 

to 10 percent slopes

3.4 0 4.9 2.7 No Slight Low 80+ High 2-3 0.1

Galstown-Woodstown; GwD

Galstown-Woodstown complex 

(sand and loamy), 10 to 15 

percent slopes

2.2 0 2.2 1.2 No Slight Low 80+ High 2-3 0.1

Ingleside-Evesboro; IeC

Ingleside-Evesboro complex 

(loamy sand and sandy loam), 5 

to 10 percent slopes

1.9 0 6.2 3.5 Yes Slight Low 80+ High 3-1 0.2

Ingleside-Galestown; IgB

Ingleside-Galestown complex 

(loamy sand, sandy loam, and silt 

loam), 5 to 10 percent slopes

2.2 0 2.2 1.2 No Slight Low 80+ High 2 0.2

Ingleside-Woodstown; IwC

Ingleside- Woodstown complex 

(loamy sand and sandy loam), 5 

to 10 percent slopes

19.7 0 25.4 14.2 No Slight Low 80+ High 2-3 0.2

Matapeake and Beltsville; MeA

Matapeake-Beltsville complex (silt 

loam and sandy loam), 0 to 2 

percent slopes

1.5 0 1.9 1.1 Yes Slight Low 80+ High 5 0.4

Matapeake and Beltsville; MeB

Matapeake-Beltsville complex (silt 

and sandy loam), 2 to 5 percent 

slopes

4.5 0 7.9 4.4 Yes Slight Low 80+ High 5 0.4

Woodstown; WdC

Woodstown sandy loam, 5 to 10 

percent slopes

0.1 0 0.6 0.3 No Slight Low 80+ High 3 0.2

Zekiah and Issue; ZBA

Zekiah and Issue soils (silt loam, 

loam, and fine sandy loam), 0 to 2 

percent slopes

0 0 2.1 1.2 No Slight High 80+ Low 5 0.4

Subtotal 94.9 0 179.4 100.0
A-3

APPENDIX A

Soil Characteristics Affected by the Project

Facility/Soils Series/Description

Disturbed (acres) a Composed on Site a

Prime 

Farmland

Soil Limitations

Const. Oper

On-site 

Acres

On-site 

Percent

Water 

Erosion 

Hazard

Compaction 

Potential

Depth to Rock 

(inches)

Revegetation 

Potential WEG K-factor

Offsite Area B

Annemessex; AsA

Annemessex silt loam, 0 to 2 

percent slopes

2.9 0 3.9 35.1 No Slight Low 80+ Moderate 5 0.4

Ingleside and Woodstown; IwB

Ingleside-Woodstown complex 

(loamy sand and sandy loam), 2 

to 5 percent slopes

0.5 0 2.8 25.2 Yes Slight Low 80+ High 5 0.2

Piccowaxen; PcB

Piccowaxen Loam, 2 to 5 percent 

slopes

1.4 0 3.0 27.0 No Slight Low 80+ Moderate 5 0.2

Water; W

Water

0 0 0.1 0.9 No - - - - - -

Woodstown and Piccowaxen; 

WpD

Woodstown-Piccowaxen complex 

(sandy loam, fine sandy loam, 

loam, and loamy sand), 5 to 15 

percent slopes

1.0 0 1.3 11.7 No Slight Low 80+ High 5 0.2

Subtotal 5.8 0 11.1 99.9

Pleasant Valley Compressor 

Station

Albano; 1A

Albano silt loam, 0 to 2 percent 

slopes

2.4 <0.1 6.8 25.0 No Slight Low 40-60 Low 4 0.4

Ashburn; 2B

Ashburn silt loam, 0 to 7 percent 

slopes

11.6 2.1 12.9 47.4 No Slight Low 20-40 High 5 0.4

Penn; 85B

Penn silt loam, 2 to 7 percent 

slopes

<0.1 0 1.6 5.9 Yes Slight Low 20-40 to 

paralithic 

bedrock; 40-

60 to lithic 

bedrock

High 5 0.3

Penn; 85C

Penn silt loam, 7 to 15 percent

slopes

1.0 0.1 1.4 5.1 No Slight Low 20-40 to 

paralithic 

bedrock; 40-

60 to lithic 

bedrock

High 5 0.3
A-4

APPENDIX A

Soil Characteristics Affected by the Project

Facility/Soils Series/Description

Disturbed (acres) a Composed on Site a

Prime 

Farmland

Soil Limitations

Const. Oper

On-site 

Acres

On-site 

Percent

Water 

Erosion 

Hazard

Compaction 

Potential

Depth to Rock 

(inches)

Revegetation 

Potential WEG K-factor

Sycoline-Kelly; 94B

Sycoline-Kelly complex, 2 to 7 

percent slopes

1.0 0 4.5 16.5 Yes Slight High 20-40 Low 5 0.4

Subtotal 16.0 2.2 27.2 99.9

Pleasant Valley 

Suction/Discharge Pipelines

Albano; 1A

Albano silt loam, 0 to 2 percent 

slopes

0.7 0 0.7 38.3 No Slight Low 40-60 Low 4 0.4

Catlett; 11C

Catlett gravelly silt loam, 7 to 15 

percent slopes

1.0 0 1.0 53.7 No Slight High 10-20 to 

paralithic 

bedrock; 20-

40 to lithic 

bedrock

High 5 0.2

Chantilly-Sycoline-Kelly; 27B

Chantilly-Sycoline-Kelly loam, 0 

to 15 percent slopes

0.1 0 0.1 6.5 No Slight Low 40-60 to lithic 

bedrock

High 5 0.3

Sycoline-Kelly; 94B

Sycoline-Kelly complex, 2 to 7 

percent slopes

<0.1 0 <0.1 1.5 Yes Slight High 20-40 Low 5 0.4

Subtotal 1.8 0 1.8 100.0

Loudoun M&R Facility

Panorama; 71B

Panorama silt loam, 2 to 7 

percent slopes

<0.1 <0.1 <0.1 20.3 Yes Slight Low 40-60 High 3 0.4

Penn; 73C

Penn silt loam, 7 to 15 percent 

slopes

<0.1 <0.1 <0.1 79.7 No Slight Low 20-40 to 

paralithic 

bedrock; 40-

60 to lithic 

bedrock

High 5 0.3

Subtotal 0.1 0.1 0.1 100

Leesburg Compressor Station

Albano; 79A

Albano silt loam, 0 to 2 percent 

slopes

0.2 0 0.2 3.3 No Slight Low 40-60 Low 4 0.4
A-5

APPENDIX A

Soil Characteristics Affected by the Project

Facility/Soils Series/Description

Disturbed (acres) a Composed on Site a

Prime 

Farmland

Soil Limitations

Const. Oper

On-site 

Acres

On-site 

Percent

Water 

Erosion 

Hazard

Compaction 

Potential

Depth to Rock 

(inches)

Revegetation 

Potential WEG K-factor

Manassas; 14B

Manassas silt loam, 0 to 7 

percent slopes

0.2 0 0.2 3.3 Yes Slight Low 80+ High 4 0.4

Leedsville; 70B

Leedsville cobbly silt loam, 2 to 7 

percent slopes

2.0 0 2.0 32.8 No Slight Low 80+ High 8 0.3

Leedsville; 70C

Leedsville cobbly silt loam, 7 to 

15 percent slopes

3.7 0 3.7 60.7 No Slight Low 80+ High 8 0.3

Subtotal 6.1 0 6.1 100.1

Project Total 162.4 31.8 263.2

____________________

a

Impervious surfaces and buildings not included from the composition and impacts totals.

WEG = Wind Erodibility Group.

Sources: NRCS, 2012; USDA, 2011.

Note: The totals shown in this table may not equal the sum of addends due to rounding.
APPENDIX B

GENERAL CONFORMITY ANALYSIS
Appendix B

Draft General Conformity Determination for the 

Cove Point Liquefaction Project

May 2014

Dominion Cove Point LNG, LP

Docket No. CP13-113-000
B-i

TABLE OF CONTENTS

Cove Point Liquefaction Project

General Conformity Determination

Page

1.0 INTRODUCTION......................................................................................................................B-1

2.0 GENERAL CONFORMITY – REGULATORY BACKGROUND......................................B-1

2.1 General Conformity Requirements.................................................................................B-2

2.2 General Conformity Process...........................................................................................B-2

3.0 GENERAL CONFORMITY APPLICABILITY....................................................................B-3

3.1 Emission Sources............................................................................................................B-4

4.0 GENERAL CONFORMITY.....................................................................................................B-6

4.1 General Conformity Determination – Maryland.............................................................B-7

4.1.1 Consistency with Relevant Maryland SIP Requirements..................................B-7

4.1.2 Maryland SIP Budgets and Project Emission Offsets........................................B-8

4.1.3 Finding of Conformity – Maryland.................................................................. B-10

4.2 General Conformity Determination – Virginia............................................................. B-10

4.2.1 Consistency with all Relevant Virginia SIP Requirements ............................. B-10

4.2.2 Virginia SIP Budgets and Project Emission Offsets........................................ B-11

4.2.3 Finding of Conformity – Virginia.................................................................... B-13

LIST OF TABLES

Table 3-1 General Conformity Thresholds...................................................................................B-3

Table 3.1-1 Construction and Non-Permitted Project Emissions Summary....................................B-5

Table 4.1.1-1 Control Measures in the Maryland SIP ........................................................................B-7

Table 4.2.1-1 Control Measures in the Virginia SIP ........................................................................B-10
B-1

1.0 INTRODUCTION

Dominion Cove Point LNG, LP (DCP) owns and operates a liquefied natural gas (LNG) import terminal, 

the Cove Point LNG Terminal (LNG Terminal), in Lusby, Calvert County, Maryland. DCP filed an 

application in April 2013 with the Federal Energy Regulatory Commission (FERC or Commission) to 

construct, modify, and operate facilities to liquefy and export LNG. The Project would involve 

installation of one LNG train with two natural gas fired turbines and expansion of existing DCP facilities 

to provide gas liquefaction and LNG export services to customers that would provide their own gas 

supply. Using facilities proposed as part of the Cove Point Liquefaction Project (Project), combined with 

existing facilities, DCP would provide a bi-directional service of receiving and regasification of imported 

LNG from LNG vessels (import service), and liquefaction of natural gas for loading onto LNG ships for 

export at the LNG Terminal (export service). DCP is requesting authorization to construct and operate 

liquefaction facilities with LNG production capacity of up to 5.75 million metric tons per annum 

(MTPA). DCP would construct the liquefaction facilities on 49 acres within the 131-acre fenced area of 

the LNG Terminal site. DCP would also use 96.9 acres of Offsite Area A as a temporary construction 

laydown/parking area, including temporary buildings and office trailers, and 5.9 acres of Offsite Area B 

as a temporary barge offloading area including a temporary pier (both areas within Calvert County, 

Maryland).

Natural gas would be delivered to the LNG Terminal via the existing Cove Point Pipeline. No 

modifications are needed to the underground pipeline. However, additional compression on the Cove 

Point Pipeline is required to deliver the inlet gas to the LNG Terminal. To accommodate the gas 

associated with the Project moving through the Cove Point Pipeline system, DCP proposes to install four 

new electric-driven compressor units and install and/or replace suction and discharge piping at the 

existing Pleasant Valley Compressor Station in Fairfax County, Virginia. DCP would also modify the 

Loudoun Meter and Regulating Station and use the Leesburg Compressor Station for construction 

laydown, parking, and staging all within Loudoun County, Virginia. 

With the exception of some construction and operational marine vessel emissions, the entire 

proposed Project would occur in Calvert County, Maryland and Fairfax and Loudoun Counties, Virginia. 

All of these counties are within the Washington DC-MD-VA Ozone Nonattainment Area. Fairfax and 

Loudoun Counties are also designated nonattainment for the annual particulate matter less than 2.5 

microns (PM2.5) standard. 

2.0 GENERAL CONFORMITY – REGULATORY BACKGROUND

The U.S. Environmental Protection Agency (EPA) promulgated the General Conformity Rule on 

November 30, 1993 to implement the conformity provision of Title I, section 176(c)(1) of the federal 

Clean Air Act (CAA). Section 176(c)(1) states that any department, agency, or instrumentality of the 

Federal Government shall not engage in, support in any way or provide financial assistance for, license or 

permit, or approve, any activity which does not conform to an approved CAA implementation plan. The 

General Conformity Rule is codified in Title 40 Code of Federal Regulations (CFR) Part 93, Subpart B, 

“Determining Conformity of General Federal Actions to State or Federal Implementation Plans.”

The General Conformity Rule applies to all federal actions occurring in non-attainment or 

maintenance areas. However, the General Conformity Rule excludes programs and projects that require 

funds or approval from the U.S. Department of Transportation, the Federal Highway Administration, the 

Federal Transit Administration, or the Metropolitan Planning Organization. In lieu of a conformity 

analysis, these latter types of programs and projects must comply with the Transportation Conformity 

Rule promulgated by EPA on November 24, 1993.
B-2

2.1 General Conformity Requirements

Conformity under Title I, section 176(c)(1) of the CAA, means to conform to an implementation 

plan’s purpose of eliminating or reducing the severity and number of violations of the National Ambient 

Air Quality Standards (NAAQS) and achieving expeditious attainment of such standards. A proposed

action or activity cannot:

 Cause or contribute to new violations of any NAAQS in any area;

 Increase the frequency or severity of any existing violation of any NAAQS in the area; or

 Delay timely attainment of any NAAQS, interim emission reductions, or other milestones 

in the area.

The General Conformity Rule allows for a conformity determination to be performed in 

coordination with and as part of the National Environmental Policy Act (NEPA) process, although this is 

not required. The General Conformity Rule applies to air pollutant emissions (direct and indirect) 

associated with “federal actions” as defined in 40 CFR 93.152 and ensures that the emissions do not 

contribute to air quality degradation or prevent the achievement of state and federal air quality goals. 

General Conformity, if applicable to the action, basically refers to the process to evaluate the action to 

determine and demonstrate that it satisfies the requirements of the approved state implementation plan

(SIP). The purpose of the General Conformity Rule is to encourage federal agencies to consult with state 

and local air quality districts so that these regulatory entities are aware of the expected impacts of the 

federal action and ensure the action meets their SIP.

2.2 General Conformity Process

The General Conformity process for a proposed action involves two distinct steps: applicability 

analysis and conformity determination. The applicability analysis is an assessment of whether a proposed 

action is subject to the General Conformity Rule. If the General Conformity Rule is applicable for the 

proposed action, then a General Conformity Determination may be required. A General Conformity 

Determination is an assessment of whether the proposed action conforms to the applicable SIP.

An applicability analysis is required for any “federal action”, as defined in 40 CFR 93.152, that is 

in a nonattainment or maintenance area and the emissions associated with the project may have the 

potential to exceed the rates listed specified in 40 CFR 93.153(b)(1) and (2). If emissions exceed these 

rates, then a General Conformity Determination is required. A “federal Action” is defined in 40 CFR 

93.152 as “any activity engaged in by a department, agency, or instrumentality of the federal government, 

or any activity that a department, agency or instrumentality of the federal government supports in any 

way, provides financial assistance for, licenses, permits, or approves, other than activities related to 

transportation plans, programs and projects developed, funded, or approved under Title 23 U.S.C. or the 

Federal transit Act (49 U.S.C. 1601 et seq.). Where the “federal action” is a permit, license, or other 

approval for some aspect of a non-federal undertaking, the relevant activity is the part, portion, or phase 

of the non-federal undertaking that requires the federal permit, license or approval.”

The General Conformity process does not include a review of new sources or existing source 

modifications that are subject to state or federal New Source Review permitting. Under the General 

Conformity Rule, these sources are presumed to comply with the SIP by completing the applicable air 

permitting process with the jurisdictional agency.
B-3

If a General Conformity Determination is required for the proposed action, then an evaluation 

must be performed to determine if the action conforms to the SIP. Where an action would exceed the 

applicability threshold in multiple states, or where the air quality control region (AQCR) encompasses 

multiple states, a General Conformity Determination is prepared and conformance documented for each 

state where the thresholds are exceeded. This may be performed in one document or separately for each 

state or AQCR.

The FERC is the lead agency responsible for authorizing applications to construct and operate 

onshore LNG export and interstate natural gas facilities. The Project is considered a “federal action” and 

the FERC is the lead agency responsible for making the General Conformity Determination. As required 

under General Conformity, an applicability analysis was performed for the Project to determine if the 

total direct and indirect emissions for criteria pollutants in non-attainment or maintenance areas exceeded 

the rates specified in 40 CFR 58.853(b)(1) and (2) and the results are presented in Section 3.0 below. The 

Project would exceed applicability thresholds and a General Conformity Determination is presented in 

Section 4.0, below.

3.0 GENERAL CONFORMITY APPLICABILITY

The General Conformity Rule applies only to actions in a nonattainment or maintenance area and 

the applicability thresholds apply for those portions of the project within that nonattainment area. The 

General Conformity applicability thresholds are based on the attainment classification for each pollutant. 

Table 3-1 provides a summary of the attainment status and applicability thresholds for the Project area 

(LNG terminal, Offsite Areas A and B, and pipeline facilities).

TABLE 3-1

General Conformity Thresholds

Pollutant

Calvert County, MD Fairfax and Loudoun Counties, VA

Status

Threshold 

(tons/year) Status

Threshold 

(tons/year)

Particulate matter less than 10 microns Attainment NA Attainment NA

Particulate matter less than 2.5 microns (PM2.5) Attainment NA Nonattainment 

(Annual only) a

100 PM2.5

100 NOx

100 SO2

SO2 Attainment NA Attainment NA

Nitrogen dioxide Attainment NA Attainment NA

Ozone Nonattainment b 100 NOx

50 VOC

Nonattainment b 100 NOx

50 VOC

Carbon monoxide Attainment NA Attainment NA

Lead Attainment NA Attainment NA

____________________

a NOx and SO2 are considered precursor pollutants to the formation of PM2.5 and have thresholds as well.

b NOx and VOC are considered precursor pollutants to the formation of ozone and have thresholds as well. The 

Washington, DC-MD-VA Ozone Nonattainment Area is also located within an ozone transport region, resulting in more 

stringent VOC thresholds.

All three Counties are within the Washington, DC-MD-VA Ozone Nonattainment Area.

Loudoun and Fairfax Counties are Washington, DC-MD-VA PM2.5 Nonattainment Area.

NA = not applicable

The marine vessel emissions were included for LNG carriers, and related support vessels, 

traveling through the Chesapeake Bay to and from the LNG terminal within Calvert and Saint Mary’s
B-4

Counties, Maryland. Calvert County is the only county currently designated non-attainment. Therefore, 

the marine vessel emissions that are included in this analysis for the Washington, DC-MD-VA Ozone 

Nonattainment Area are conservative. LNG carriers and support vessels would also pass through waters 

adjacent to counties in the Norfolk-Virginia Beach-New Port News (Hampton Roads) 8-hour ozone 

maintenance area, specifically Virginia Beach City, Poquoson City, and York Counties. These counties 

are part of a different air quality control region and need to be assessed separately from the Washington, 

DC-MD-VA Ozone Nonattainment Area. Based on experience with other National Environmental Policy 

Act (NEPA) analyses and General Conformity Applicability analyses, the LNG carrier and support vessel 

transit emissions in the Virginia maintenance counties are not expected to exceed the general conformity 

applicability thresholds.

1

 Therefore, these emissions are not included in the detailed general conformity 

applicability analysis. 

3.1 Emission Sources

Project emissions sources that are subject to the General Conformity Applicability Analysis 

include the following:

Construction Emissions

 Barges – Emissions from the transport of equipment and materials to the Project.

 Construction equipment – Emissions from air compressors, backhoes, cranes, and 

other construction equipment.

 On-road vehicles – Emissions from commuter buses, passenger vehicles, and diesel 

and gasoline trucks.

 Off-road construction vehicle traffic – Emissions from commuter buses, dump trucks, 

light/medium duty trucks, and water/fuel trucks.

 Marine construction vessels – Emissions from offshore construction equipment (e.g., 

survey boats, barges, cranes, and tugboats).

 Earthmoving activities – Emissions resulting from bulldozing, grading, and land 

disturbance.

 Construction storage piles – Particulate matter emissions from active storage piles that 

would be used during construction.

Non-Permitted Operational Emissions

 New Employees Commuting – Vehicle emissions from an increase in the number of 

DCP employees commuting to the facility.

 

1 Based on the Sparrows Point LNG Terminal and Pipeline Project (Docket Nos. CP07-62-000 and CP07-

63-000), the marine vessel emissions from 180 LNG carriers passing through these same counties were estimated at 

39.4 tons per year (TPY) NOx and 1.1 TPY VOC. The proposed Project would involve less than half as many 

carriers. The applicability thresholds are 100 TPY NOx and 50 TPY VOC.
B-5

 Waste Haulers – Truck emissions from the increase in waste hauling trucks needed for 

the site.

 Marine Vessels – Emissions from the LNG export activities, including LNG carriers 

and supporting marine vessels, such as tugboats and security vessels. The estimated 

emissions are based on 85 LNG export carriers per year, one security boat per LNG 

export carrier, and three tugs per LNG export carrier.

The emissions from these sources were calculated using the expected equipment counts and 

equipment utilizations along with emission factors from various EPA guidance documents and modeling 

software.

2

These Project emissions are summarized in table 3.1-1 and compared to the general conformity 

applicability thresholds.

TABLE 3.1-1

Construction and Non-Permitted Operating Project Emissions Summary

Ozone Nonattainment Area a PM2.5 Nonattainment Area b

Year

Emissions (tons/year) Emissions (tons/year)

NOx VOC NOx SO2 PM2.5

2014 171.13 15.38 0.00 0.00 0.00

2015 326.94 35.00 0.00 0.00 0.00

2016 230.91 32.80 20.61 0.79 5.82

2017 – Construction 123.14 16.43 0.82 0.03 0.66

2017 – Operation (non-permitted) – LNG Terminal 77.23 2.29 0.00 0.00 0.00

2017 (Total) 200.37 18.72 0.82 0.03 0.66

2018 & Beyond (Operational – LNG Terminal) 77.23 2.29 0.00 0.00 0.00

Conformity Applicability Threshold 100 50 100 100 100

____________________

a Emissions are summarized for activities that would occur in Calvert County, MD and Loudoun and Fairfax 

Counties, VA (Ozone Nonattainment Area).

b Emissions are provided only for the activities that would occur in Loudoun and Fairfax Counties (PM2.5

Nonattainment Area).

Project construction would occur in 2014 – 2017. Construction would be completed in 2017 and operation would begin. 

Only the LNG Terminal would have any notable non-permitted operational emissions (marine vessels, employee commuter 

vehicle traffic, and waste haul truck traffic).

NOx = nitrogen oxides

SO2 = sulfur dioxide

VOC = volatile organic compounds

PM2.5 = particulate matter less than 2.5 microns

The emissions in table 3.1-1 include all nitrogen oxides (NOx) and VOC that would occur in the 

Washington DC-MD-VA Ozone Nonattainment Area (Calvert County, Maryland; Loudoun and Fairfax 

Counties, Virginia). Also included in table 3.1-1 are the NOx, sulfur dioxide (SO2) and PM2.5 emissions 

for those activities that would occur in the Washington, DC-VA-MD PM2.5 Nonattainment Area

(Loudoun and Fairfax Counties, Virginia). As shown in table 3.1-1, the estimated direct and indirect NOx

emissions could exceed the applicability thresholds for 2014 through 2017. It is also conservatively 

 

2 Detailed information on calculation methodology for each emission source is available on the FERC website, http://www.ferc.gov, using the 

"elibrary" link and the project docket number CP13-113.
B-6

assumed that in 2017, an entire year of marine vessel emissions (due to LNG operations) would occur in 

addition to the construction emissions. 

Because the emissions from the Project would exceed the applicability threshold for NOx, a 

general conformity determination must be completed to assess the Project’s NOx emissions conformance 

to the approved SIP(s) for years 2014 through 2017. These emissions are referred to within this 

determination as the “General Conformity Project emissions.” 

Multi-year projects of this scale often encounter schedule modifications. It is possible that 

construction emissions from one year would shift to another. As discussed below, DCP would offset its 

maximum year projected emissions for all years. This would account for any schedule adjustment that 

may result in greater emissions than originally projected in earlier years. The General Conformity Rule 

also provides for a reassessment if the final General Conformity Determination becomes outdated or if 

emissions are significantly greater than originally anticipated.

4.0 GENERAL CONFORMITY

A SIP is completed by each jurisdictional agency tasked with implementing the CAA. For SIP 

matters relating specifically to the Washington DC-MD-VA Nonattainment Area, the District of 

Columbia, Maryland, and Virginia have formed the Metropolitan Washington Air Quality Committee 

(MWAQC) to generate the SIP measures for the area that are then incorporated into each state’s/

territory’s SIP. The measures in the SIPs are implemented by the Maryland Department of the 

Environment (MDE) in Maryland and the Virginia Department of Environmental Quality (VDEQ) in 

Virginia; including those measures in the Washington DC Area. Therefore, the Project emission 

summarized above must comply with the Washington DC Area SIP submittals as well as other NOx SIP 

submittals for Maryland or Virginia that may apply. 

The potentially applicable requirements were determined through a review of the following SIP 

documents:

 Plan to Improve Air Quality in the Washington, DC-MD-VA Region, SIP for 8-Hour 

Ozone Standard, May 23, 2007, MWAQC.

 Maryland State Implementation Plan for CAA Section 110(a)(2) for Nitrogen Dioxide 

and Section 128 for all National Ambient Air Quality Standards, December 21, 2012, 

MDE.

 Baltimore Nonattainment Area 8-hour Ozone State Implementation Plan and Base 

Year Inventory, June 15, 2007, MDE.

 Washington DC-MD-VA 1997 PM2.5 Maintenance Plan and Redesignation Request, 

May 22, 2013, MWAQC.

The list above includes two Washington DC Area SIP documents and two State of Maryland SIP 

documents. The VDEQ does not maintain SIP document postings. A search of the EPA Region III SIP Index3

did not show any other approved SIP documents that may apply to the construction emissions from the 

Loudoun and Pleasant Valley facilities. Barges would originate from Fairless Hills, Pennsylvania;

Baltimore, Maryland; and Corpus Christi, Texas. As such, barge emissions would primarily occur in 

 

3 http://yosemite.epa.gov/r3/r3sips.nsf/SIPIndex!OpenForm&Start=1&Count=1000&Expand=5.1&Seq=4
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other air quality control regions, but the barge emissions were quantified and determined to be well below 

the general conformity threshold for these other AQCRs. Therefore, they were not analyzed any further 

in this General Conformity Determination.

4.1 General Conformity Determination – Maryland

With the exception of barges delivering equipment for the Liquefaction Facilities, all of the 

emissions from the Liquefaction Facilities construction are expected to occur in Maryland. The criteria 

for determining conformity are provided in 40 CFR 93.158. An action would be determined to conform 

for a specific pollutant if it meets the requirements of 40 CFR 93.158(c) and any of the applicable 

requirements in 40 CFR 93.158(a)(1) through (5). Section 40 CFR 93.158(c) requires the total of direct 

and indirect emissions from the action be in compliance with all relevant requirements and milestones 

contained in the applicable SIP. Section 40 CFR 93.158(a)(1) through (5) provide a number of pollutantand state-specific options for demonstrating conformity. The demonstration of compliance with the 

Maryland SIP requirements, in accordance with 40 CFR 93.158(c), is provided in Section 4.1.1 of this 

document, and an analysis of the options the Project would use to demonstrate conformity under 40 CFR 

93.158(a) is documented in Section 4.1.2.

4.1.1 Consistency with Relevant Maryland SIP Requirements

The NOx emission control measures and regulations included in the Maryland SIP that may 

potentially apply to the Liquefaction Facilities and related activities are listed in table 4.1.1-1.

TABLE 4.1.1-1

Control Measures in the Maryland SIP

Emission Control Measures Type

Potential Applicability to the Liquefaction Facilities

and Related Activities

Seasonal Open Burning Restrictions Local Open Burning During Construction

EPA Non-road Diesel Engines Rule Federal Diesel powered construction equipment greater than 50 

horsepower

Emissions Standards for Large Spark Ignition Engines Federal Industrial spark-ignition engines rated over 19 kilowatts

Reformulated Gasoline for Off-Road Applications State Gasoline construction equipment

Enhanced Inspections/Maintenance Federal Delivery and commuter vehicles

Federal Tier 1 and 2 Vehicle Standards Federal Delivery and commuter vehicles

National Low Emission Vehicle Standards Federal Delivery and commuter vehicles

Heavy Duty Diesel Engine Rule Federal Construction and Heavy Duty On-Road Vehicles

California Low Emission Vehicle State Delivery and commuter vehicles

Several of the regulations identified in table 4.1.1-1 would indirectly affect the emissions from 

the proposed Project through implementation of new standards for manufacturers (such as reformulated 

fuel and engines). Construction equipment and delivery/commuter vehicles would be powered by engines 

that are subject to these programs. Implementation and compliance with these programs would be 

required by the manufacturers and refiners; not DCP. Therefore, it is assumed that the Project would be 

in compliance with these regulations. There is also a requirement in the MWAQC 8-hour ozone SIP to 

restrict open burning at the local level. DCP has committed not to conduct open burning during 

construction. Therefore, the Project meets the requirements of 40 CFR 93.158(c) for complying with all 

relevant requirements and milestones contained in the applicable SIP.
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4.1.2 Maryland SIP Budgets and Project Emission Offsets

In addition to complying with the control measures and regulations relied upon in the applicable 

SIP, 40 CFR 93.158(a) of the General Conformity Rule requires that the project comply with one of the 

following:

 40 CFR 93.158(a)(1) – For any criteria pollutant or precursor, the total of direct and 

indirect emissions from the action are specifically identified and accounted for in the 

applicable SIP’s attainment or maintenance demonstration or reasonable further 

progress milestone or in a facility-wide emission budget included in a SIP in accordance 

with 40 CFR 93.161.; 

Annual emissions from LNG import vessels were included in the 2002 and 2009 SIP 

baseline emission inventories. These are operational emissions from sources not subject 

to stationary source permitting. However, the Maryland SIP budgets do not specifically 

include the General Conformity Project emissions (i.e., emissions from construction,

LNG export vessels, and associated LNG export support vessels). Therefore, this 

conformity option is not applicable.

 40 CFR 93.158(a)(2) - For precursors of ozone, nitrogen dioxide, or Particulate Matter, 

the total of direct and indirect emissions from the action are fully offset within the same 

nonattainment or maintenance area (or nearby area of equal or higher classification 

provided the emissions from that area contribute to the violations, or have contributed to 

violations in the past, in the area with the Federal action) through a revision to the 

applicable SIP or similar enforceable measure that effects emissions reductions so that 

there is no net increase in emissions of that pollutant.

Similar to this conformity option, the Maryland Nonattainment New Source Review 

(NNSR) program (COMAR 26.11.17) requires that new major stationary sources or 

major modifications completely offset the proposed Project NOx emissions. These 

offsets may be obtained through the purchase of emission reduction credits (ERC) from 

the MDE ERC program. The ERCs are credits generated by local air emissions sources 

that have made an enforceable, permanent, and quantifiable emission reduction. DCP has 

already stated in supplemental information filed with the Commission, that DCP has 

purchased sufficient NOx ERCs to meet the General Conformity regulation. These ERCs 

are from sources within the Washington DC-MD-VA Air Quality Control Region

including Essroc Cement Corporation. 

Because this is the method of conformance selected, DCP must demonstrate that it has 

purchased these offsets and that MDE finds their use acceptable under General 

Conformity. Therefore, the Environmental Assessment for this Project includes a 

recommendation that prior to any construction, DCP is required to provide 

documentation demonstrating that it has purchased sufficient offsets under General 

Conformity and DCP is required to provide a letter from MDE indicating the ERCs are 

acceptable.

 40 CFR 93.158(a)(3) - For any directly-emitted criteria pollutant, the total of direct and 

indirect emissions from the action meets the requirements:

 (i) Specified in paragraph (b) of this section based on areawide air quality modeling 

analysis and local air quality modeling analysis; or
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 (ii) Meet the requirements of paragraph (a)(5) of this section and, for local air 

quality modeling analysis the requirement of paragraph (b) of this section.

The NOx General Conformity Project emissions would be emitted as ozone or particulate 

matter precursor pollutants. Therefore, this conformity option is not applicable.

 40 CFR 93.158(a)(4) - For carbon monoxide or directly emitted particulate matter:

 (i) Where the State agency primarily responsible for the applicable SIP determines 

that an areawide air quality modeling analysis is not needed, the total of direct and 

indirect emissions from the action meet the requirements specified in paragraph (b) 

of this section, based on local air quality modeling analysis; or

 (ii)Where the State agency primarily responsible for the applicable SIP determines 

that an areawide air quality modeling analysis is appropriate and that a local air 

quality modeling analysis is not needed, the total of direct and indirect emissions 

from the action meet the requirements specified in paragraph (b) of this section, 

based on areawide modeling, or meet the requirements of paragraph (a)(5) of this 

section.

This conformity option is not applicable because the only General Conformity Project 

emissions are NOx, as ozone and particulate matter precursor emissions.

 40 CFR 93.158(a)(5) - For ozone or nitrogen dioxide, and for purposes of paragraphs 

(a)(3)(ii) and (a)(4)(ii) of this section, each portion of the action or the action as a whole 

meets any of the following requirements:

 (i) Where EPA has approved a revision to the applicable implementation plan after 

the area was designated as nonattainment and the State or Tribe makes a 

determination as provided in paragraph (a)(5)(i)(A) of this section or where the State 

or Tribe makes a commitment as provided in paragraph (a)(5)(i)(B) of this section;

 (ii) The action (or portion thereof), as determined by the MPO, is specifically 

included in a current transportation plan and transportation improvement program 

which have been found to conform to the applicable SIP under 40 CFR part 51, 

subpart T, or 40 CFR part 93, subpart A;

 (iii) The action (or portion thereof) fully offsets its emissions within the same 

nonattainment or maintenance area (or nearby area of equal or higher classification 

provided the emissions from that area contribute to the violations, or have 

contributed to violation in the past, in the area with the Federal action) through a 

revision to the applicable SIP or an equally enforceable measure that effects 

emissions reductions equal to or greater than the total of direct and indirect 

emissions from the action so that there is no net increase in emissions of that 

pollutant;

 (iv) Where EPA has not approved a revision to the relevant SIP since the area was 

designated or reclassified, the total of direct and indirect emissions from the action 

for the future years (described in §93.159(d)) do not increase emissions with respect 

to the baseline emissions:
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 (v) Where the action involves regional water and/or wastewater projects, such 

projects are sized to meet only the needs of population projections that are in the 

applicable SIP.

Sections 93.158(a)(5)(i), (ii), (iv), and (v) are not applicable to the Project. Section 

93.158(a)5(iii) is identical to Section 93.158(a)(2). Therefore, this conformity option is 

not applicable. 

4.1.3 Finding of Conformity – Maryland

DCP has entered into contractual agreements and purchased all offsets required for construction 

of the Project. In addition, we included a recommendation for any order Granting Authority and issuing 

Certificate (Order) approving this Project that prior to the Commission granting any construction, DCP 

must provide a record of NOx offsets obtained and demonstrate that this amount is equal to the amount 

required under the final General Conformity Determination. DCP must also obtain and submit a letter 

from MDE concurring that the offset requirement has been met. This recommendation ensures that no 

emissions would occur from the Project before offsets are obtained and that once offsets are obtained, any 

emissions from the Project would be completely offset and cause a net reduction in emissions within the 

nonattainment area. In addition, DCP has provided information to demonstrate that sufficient offsets are 

available to it to completely offset NOx emissions from the Project, and FERC staff have determined that 

offsetting is a viable approach to demonstration conformance.

We have determined that the Project will achieve conformity in Maryland through compliance 

with 40 CFR 93.158(a)(2) and 40 CFR 93.158(c).

4.2 General Conformity Determination – Virginia

Emissions from construction in Loudoun and Fairfax Counties, Virginia would occur in 2016 and 

2017. The NOx emissions from these activities would be subject to the general conformity determination 

requirements, as codified in 40 CFR 93.185(a) and (c) and discussed in Section 4.0 above.

4.2.1 Consistency with all Relevant Virginia SIP Requirements

The emission control measures and regulations that have been included in the Virginia SIP that 

may potentially apply to the Project are summarized in table 4.2.1-1.

TABLE 4.2.1-1

Control Measures in the Virginia SIP

Emission Control Measures Type

Potential Applicability to the Liquefaction Facilities

and Related Activities

Seasonal Open Burning Restrictions Local Open Burning During Construction

EPA Non-road Diesel Engines Rule Federal Diesel powered construction equipment greater than 50 

horsepower

Emissions Standards for Large Spark Ignition Engines Federal Industrial spark-ignition engines rated over 19 kilowatts

Reformulated Gasoline for Off-Road Applications State Gasoline construction equipment

Enhanced Inspections/Maintenance Federal Delivery and commuter vehicles

Federal Tier 1 and 2 Vehicle Standards Federal Delivery and commuter vehicles

National Low Emission Vehicle Standards Federal Delivery and commuter vehicles

Heavy Duty Diesel Engine Rule Federal Construction and Heavy Duty On-Road Vehicles
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Several of the regulations identified in table 4.2.1-1 would indirectly affect the emissions from 

the proposed Project through implementation of new standards for manufacturers (such as reformulated 

fuel and engines). Construction equipment and delivery/commuter vehicles would be powered by engines 

that are subject to these programs. Implementation and compliance with these programs would be 

required by the manufacturers and refiners; not DCP. Therefore, it is assumed that the Project would be 

in compliance with these regulations. There is also a requirement in the MWAQC 8-hour ozone SIP to 

restrict open burning at the local level. DCP has committed not to conduct open burning during 

construction. Therefore, the Project meets the requirements of 40 CFR 93.158(c) for complying with all 

relevant requirements and milestones contained in the applicable SIP.

4.2.2 Virginia SIP Budgets and Project Emission Offsets

In addition to complying with the control measures and regulations relied upon in the applicable 

SIP, 40 CFR 93.158(a) of the General Conformity Rule requires that the project comply with one of the 

following:

 40 CFR 93.158(a)(1) ) – For any criteria pollutant or precursor, the total of direct and 

indirect emissions from the action are specifically identified and accounted for in the 

applicable SIP’s attainment or maintenance demonstration or reasonable further 

progress milestone or in a facility-wide emission budget included in a SIP in accordance 

with 40 CFR 93.161.

The Virginia SIP budgets do not specifically include the emissions from the subject 

Project emissions.

 40 CFR 93.158(a)(2) - For precursors of ozone, nitrogen dioxide, or Particulate Matter, 

the total of direct and indirect emissions from the action are fully offset within the same 

nonattainment or maintenance area (or nearby area of equal or higher classification 

provided the emissions from that area contribute to the violations, or have contributed to 

violations in the past, in the area with the Federal action) through a revision to the 

applicable SIP or similar enforceable measure that effects emissions reductions so that 

there is no net increase in emissions of that pollutant.

As noted above in section 4.1.2, the ERCs that DCP plans to purchase would be sufficient 

to completely offset the General Conformity Project emissions (including the NOx

emission related to the construction of the Loudoun and Pleasant Valley facilities),

thereby meeting 40 CFR 93.158 (a)(2) of the general conformity regulations.

 40 CFR 93.158(a)(3) - For any directly-emitted criteria pollutant, the total of direct and 

indirect emissions from the action meets the requirements:

 (i) Specified in paragraph (b) of this section based on areawide air quality modeling 

analysis and local air quality modeling analysis; or

 (ii) Meet the requirement sof paragraph (a)(5) of this section and, for local air 

quality modeling analysis the requirement of paragraph (b) of this section.

The NOx General Conformity Project emissions would be emitted as ozone or particulate 

matter precursor pollutants. Therefore, this conformity option is not applicable.

 40 CFR 93.158(a)(4) - For carbon monoxide or directly emitted particulate matter:
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 (i) Where the State agency primarily responsible for the applicable SIP determines 

that an areawide air quality modeling analysis is not needed, the total of direct and 

indirect emissions from the action meet the requirements specified in paragraph (b) 

of this section, based on local air quality modeling analysis; or

 (ii)Where the State agency primarily responsible for the applicable SIP determines 

that an areawide air quality modeling analysis is appropriate and that a local air 

quality modeling analysis is not needed, the total of direct and indirect emissions 

from the action meet the requirements specified in paragraph (b) of this section, 

based on areawide modeling, or meet the requirements of paragraph (a)(5) of this 

section.

This conformity option is not applicable because the only General Conformity Project 

emissions are NOx, as ozone and particulate matter precursor emissions.

 40 CFR 93.158(a)(5) - For ozone or nitrogen dioxide, and for purposes of paragraphs 

(a)(3)(ii) and (a)(4)(ii) of this section, each portion of the action or the action as a whole 

meets any of the following requirements:

 (i) Where EPA has approved a revision to the applicable implementation plan after 

the area was designated as nonattainment and the State or Tribe makes a 

determination as provided in paragraph (a)(5)(i)(A) of this section or where the State 

or Tribe makes a commitment as provided in paragraph (a)(5)(i)(B) of this section;

 (ii) The action (or portion thereof), as determined by the MPO, is specifically 

included in a current transportation plan and transportation improvement program 

which have been found to conform to the applicable SIP under 40 CFR part 51, 

subpart T, or 40 CFR part 93, subpart A;

 (iii) The action (or portion thereof) fully offsets its emissions within the same 

nonattainment or maintenance area (or nearby area of equal or higher classification 

provided the emissions from that area contribute to the violations, or have 

contributed to violation in the past, in the area with the Federal action) through a 

revision to the applicable SIP or an equally enforceable measure that effects 

emissions reductions equal to or greater than the total of direct and indirect 

emissions from the action so that there is no net increase in emissions of that 

pollutant;

 (iv) Where EPA has not approved a revision to the relevant SIP since the area was 

designated or reclassified, the total of direct and indirect emissions from the action 

for the future years (described in §93.159(d)) do not increase emissions with respect 

to the baseline emissions:

 (v) Where the action involves regional water and/or wastewater projects, such 

projects are sized to meet only the needs of population projections that are in the 

applicable SIP.

Sections 93.158(a)(5)(i), (ii), (iv), and (v) are not applicable to the Project. Section 

93.158(a)5(iii) is identical to Section 93.158(a)(2). Therefore, this conformity option is 

not applicable. 
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4.2.3 Finding of Conformity – Virginia

As noted in Section 4.1.3, the General Conformity Project emissions will be completely offset at 

a ratio of at least 1 to 1, thereby meeting the requirement of 40 CFR 93.158(a)(2). In addition, the 

General Conformity Project emissions would be consistent with the applicable SIP requirements, thereby 

meeting the requirements of 40 CFR 93.128(c). Therefore, we have determined that the Project will 

conform to the Virginia SIP and meet the requirements of the General Conformity Rule. However, DCP

must also obtain and submit a letter from VDEQ concurring that the offset requirement has been met.