**Resource Report 1 -- General Project Description**

**AES Sparrows Point LNG Terminal**

**& Mid-Atlantic Express Pipeline**

+------------------------------------------+-----------+---------------+
| **SUMMARY OF REQUIRED FERC REPORT        |           |               |
| INFORMATION**                            |           |               |
+------------------------------------------+-----------+---------------+
| **TOPIC**                                | **FERC    | **Report      |
|                                          | Re        | Reference or  |
|                                          | ference** | Not           |
|                                          |           | Applicable**  |
+------------------------------------------+-----------+---------------+
| 1.  Provide a detailed description and   | §         | Sections 1.3, |
|     location map of the project          | 380       | 1.5, 1.6 and  |
|     facilities.                          | .12(c)(1) | 1.7, Figure   |
|                                          |           | 1.3-1 and     |
|     -   Include all pipeline and         |           | Appendix 1A   |
|         aboveground facilities.          |           |               |
|                                          |           |               |
|     -   Include support areas for        |           |               |
|         construction or operation.       |           |               |
|                                          |           |               |
|     -   Identify facilities to be        |           |               |
|         abandoned.                       |           |               |
+------------------------------------------+-----------+---------------+
| 2.  Describe any non-jurisdictional      | §         | Section 1.10  |
|     facilities that would be built in    | 380       |               |
|     association with the project.        | .12(c)(2) |               |
|                                          |           |               |
| -   Include auxiliary facilities.        | § 2.55(a) |               |
|                                          |           |               |
| -   Describe the relationship to the     | §380.12(  |               |
|     jurisdictional facilities.           | c)(2)(ii) |               |
|                                          |           |               |
| -   Include ownership, land              |           |               |
|     requirements, gas consumption,       |           |               |
|     megawatt size, construction status,  |           |               |
|     and an update of the latest status   |           |               |
|     of Federal, state, and local         |           |               |
|     permits/approvals.                   |           |               |
|                                          |           |               |
| -   Include the length and diameter of   |           |               |
|     any interconnecting pipeline.        |           |               |
|                                          |           |               |
| -   Apply the four-factor test to each   |           |               |
|     facility.                            |           |               |
+------------------------------------------+-----------+---------------+
| 3.  Provide current original U.S.        | §         | Figures and   |
|     Geological Survey (USGS)             | 380       | Appendix 1A   |
|     7.5-minute-series topographic maps   | .12(c)(3) |               |
|     with mileposts showing the project   |           |               |
|     facilities.                          |           |               |
|                                          |           |               |
| -   Maps of equivalent detail are        |           |               |
|     acceptable if legible (check with    |           |               |
|     staff)                               |           |               |
|                                          |           |               |
| -   Show locations of all linear project |           |               |
|     elements, and label them.            |           |               |
|                                          |           |               |
| -   Show locations of all significant    |           |               |
|     aboveground facilities, and label    |           |               |
|     them.                                |           |               |
+------------------------------------------+-----------+---------------+
| 4.  Provide aerial images or photographs | §         | Figure 1.3-3  |
|     or alignment sheets based on these   | 380       | and Appendix  |
|     sources with mileposts showing the   | .12(c)(3) | 1A            |
|     project facilities.                  |           |               |
+------------------------------------------+-----------+---------------+
| 5.  Provide plot/site plans of           | §         | Not           |
|     compressor stations showing the      | 380.1     | Applicable    |
|     location of the nearest noise        | 2(c)(3,4) |               |
|     sensitive areas (NSA) within 1 mile. |           |               |
|                                          |           |               |
| -   Scale no smaller than 1:3,600        |           |               |
|                                          |           |               |
| -   Show reference to topographic maps   |           |               |
|     and aerial alignments provided       |           |               |
|     above.                               |           |               |
+------------------------------------------+-----------+---------------+
| 6.  Describe construction and            | §         | Section 1.5   |
|     restoration methods.                 | 380       |               |
|                                          | .12(c)(6) |               |
| -   Include this information by milepost |           |               |
+------------------------------------------+-----------+---------------+
| 7.  Identify the permits required for    | §         | Section 1.8.1 |
|     construction across surface waters.  | 380       | and Table     |
|                                          | .12(c)(9) | 1.8-1         |
| -   Include the status of all permits.   |           |               |
|                                          |           |               |
| -   For construction in the Federal      |           |               |
|     offshore area be sure to include     |           |               |
|     consultation with the MMS File with  |           |               |
|     the MMS for rights-of-way grants at  |           |               |
|     the same time or before you file     |           |               |
|     with the FERC.                       |           |               |
+------------------------------------------+-----------+---------------+
| 8.  Provide the names and address of all | §         | Appendix 1B   |
|     affected landowners and certify that | 380.      |               |
|     all affected landowners will be      | 12(c)(10) |               |
|     notified as required in § 157.6(d).  |           |               |
|                                          | §         |               |
| -   Affected landowners                  | 157.6(d)  |               |
|                                          |           |               |
| -   Provide an electronic copy directly  |           |               |
|     to the environmental staff.          |           |               |
+------------------------------------------+-----------+---------------+

**Additional Information**

  --------------------------------------------------------- -------------
  Describe all authorizations required to complete the      Section 1.8.1
  proposed action and the status of applications            

  Provide Plot/site plans of all other aboveground          See Figure
  facilities that are not completely within the             1.3-2
  right-of-way.                                             

  Provide detailed typical construction right-of-way        Figure 1.3-4
  cross-section diagrams showing information such as widths and Appendix
  and relative locations of existing rights-of-way, new     2B
  permanent right-of-way, and temporary construction        
  right-of-way.                                             

  Summarize the total acreage of land affected by           Section 1.4
  construction and operation of the project.                and Table
                                                            1.4-1

  If Resource Report 5, Socioeconomics is not provided,     Section 1.5
  provide the start and end dates of construction, the      and Resource
  number of pipeline spreads that would be used, and the    Report 5
  workforce per spread.                                     

  Send two (2) additional copies of topographic maps and    Figure 1.3-1,
  aerial images/ photographs directly to the environmental  1.3-3 and
  staff of the Office of Energy Projects (OEP).             Appendix 1A
  --------------------------------------------------------- -------------

**TABLE OF CONTENTS**

**Page**

LIST OF TABLES [v](#__RefHeading___Toc155681481)

LIST OF FIGURES [v](#__RefHeading___Toc155681482)

1\. general project description [1](#general-project-description)

1.1 Introduction [1](#introduction)

1.2 Purpose and Need [1](#purpose-and-need)

1.2.1 Energy and Natural Gas Trends in the United States
[1](#energy-and-natural-gas-trends-in-the-united-states)

1.2.2 Natural Gas in the Mid-Atlantic Region
[2](#natural-gas-in-the-mid-atlantic-region)

1.3 Proposed Facilities Location and Description
[5](#proposed-facilities-location-and-description)

1.3.1 Project Description [5](#project-description)

1.3.2 Project Location [7](#project-location)

1.3.3 Proposed Facilities [10](#proposed-facilities)

1.3.4 Location Maps, Detailed Route Map, and Plot/Site Plans
[23](#location-maps-detailed-route-map-and-plotsite-plans)

1.4 Land Requirements [23](#land-requirements)

1.4.1 LNG Terminal and Pipeline Facilities
[23](#lng-terminal-and-pipeline-facilities)

1.4.2 Aboveground Facilities [25](#aboveground-facilities)

1.5 Construction Procedures [25](#construction-procedures)

1.5.1 Construction of LNG Terminal and Pipeline
[26](#construction-of-lng-terminal-and-pipeline)

1.5.2 Aboveground Facilities [45](#aboveground-facilities-1)

1.6 Operations and Maintenance [46](#operations-and-maintenance)

1.6.1 LNG Terminal Facilities [46](#lng-terminal-facilities-1)

1.6.2 Pipeline Facilities [49](#pipeline-facilities-2)

1.7 Future Plans and Abandonment [50](#future-plans-and-abandonment)

1.7.1 Expansion [50](#expansion)

1.7.2 Decommissioning and Abandonment
[51](#decommissioning-and-abandonment)

1.8 Regulatory Status [51](#regulatory-status)

1.8.1 Required Permits and Approvals
[51](#required-permits-and-approvals)

1.8.2 Agency, Tribe, and Public Communication
[52](#agency-tribe-and-public-communication)

1.9 Affected Landowners [52](#affected-landowners)

1.10 Non-jurisdictional Facilities
[52](#non-jurisdictional-facilities-1)

1.11 References [57](#references)

**TABLES**

**FIGURES**

**APPENDIX 1A** **Alignment Sheets & USGS Topographic Maps**

**APPENDIX 1B** **Affected Landowner List**

**APPENDIX 1C Dredging Management Plan**

**APPENDIX 1D Tables of LNG Ships Anticipated to Service Sparrows Point
and Dimensions of Other Area Commercial Shipping Traffic**

**APPENDIX 1E Resource Report 1 FERC Data Request Response Matrix**

[]{#__RefHeading___Toc155681481 .anchor}LIST OF TABLES

**Table No. Title**

1.3-1 Summary of Existing Rights-of-Way Paralleled by Pipeline

1.4-1 Aboveground Facilities Summary with Land Requirements

1.4-2 Pipeline Facilities Summary with Land Requirements

1.5-1 Construction Schedule

1.8-1 Summary of Major Permits, Consultations & Approvals

1.8-2 Summary of Agency Contacts & Correspondence

[]{#__RefHeading___Toc155681482 .anchor}LIST OF FIGURES

**Figure No. Title**

1.2-1 2005 U.S. Natural Gas Consumption by Census Region

1.2-2 Mid-Atlantic Region Natural Gas Consumption, 1995 -- 2030 (Tcf)

1.2-3 Mid-Atlantic Historic and Projected Natural Gas Consumption by
Segment

1.2-4 Mid-Atlantic Natural Gas Incremental Demand

1.3-1 Project Overview -- Sparrows Point LNG Terminal and Mid-Atlantic
Express Pipeline

1.3-2 (Sheet 1) Sparrows Point LNG Terminal - General Arrangement

1.3-2 (Sheet 2) Sparrows Point LNG Terminal Property and Associated
Dredge and Temporary Work Spaces

1.3-3 (Sheets 1-10) Proposed Route -- Mid-Atlantic Express Pipeline

1.3-4 Typical 30" Pipeline Construction Right-of-Way Detail

1.3-5 (Sheet 1) Typical Mainline Valve

1.3-5 (Sheet 2) Typical Meter Site

1.3-5 (Sheet 3) Proposed Pipeline Interconnection

**Appendix Figures**

1A Proposed Route - USGS Topographic Maps

1A Proposed Mid-Atlantic Express Pipeline (Drawing Nos. AES-PP-001
through AES PP-078)

1C-1 Proposed LNG Terminal Approach Channel Bathymetry

1C-2 Sparrows Point LNG Terminal -- Dredge Material Recycling Plan
Typical

1C-3 Dredged Material Recycling Facility Plan

  -------------------------------------------------------------------------
  **Term**        **Description**
  --------------- ---------------------------------------------------------
  \"              inches

  °F              degree Fahrenheit

  bbl             barrels

  bbl/h           barrels per hour

  AMSC            Area Maritime Security Committee

  ANSI            American National Standards Institute

  AOR             Area of Responsibility

  API             American Petroleum Institute

  ASME            American Society of Mechanical Engineers

  ATWS            Additional Temporary Workspace

  BIA             Bureau of Indian Affairs

  BIBI            Benthetic index of biotic integrity

  BMP             Best Management Practice

  BMS             Burner Management System

  BOG             boiloff gas

  Bscfd / bscfd   billion standard cubic feet per day

  Btu             British thermal unit

  Btu/(ft^2^hr)   British thermal unit per feet squared per hour

  C5 plus         pentane plus

  CCTV            closed circuit television

  CEQ             Council on Environmental Quality

  CFR             Code of Federal Regulations

  CO              carbon monoxide

  COE             U.S. Army Corps of Engineers

  COMAR           Code of Maryland Regulations

  COTP            Coast Guard Captains of the Port

  CROW            Construction right-of-way

  CWA             Clean Water Act

  cy              cubic yard

  CZMA            Coastal Zone Management Act of 1972

  DB&B            double block and bleed

  DCS             distributed control system

  DMRF            Dredge Material Recycling Facility

  Dth/day         Dekatherms per day

  EA              Environmental Assessment

  EIA             Energy Information Administration

  EIS             Environmental Impact Statement

  EPC             Engineering, Procurement and Construction

  ER              Environmental Report

  ERC             emergency release coupling

  ESA             Endangered Species Act of 1973

  ESD             emergency shutdown

  ESD-1           Pier Emergency Shutdown

  ESD-1-1         Activation of the unloading arm/vapor return arm ERCs on
                  Berth 1 and Berth 2

  ESD-2           Total Terminal Emergency Shutdown

  FAA             Federal Aviation Administration

  FBE             Fusion-Bonded Epoxy

  FEED            Front End Engineering Design

  FERC            Federal Energy Regulatory Commission

  FERC's Plan     FERC's Upland Erosion Control, Revegetation, and
                  Maintenance Plan

  FERC's          FERC's Wetland and Waterbody Construction and Mitigation
  Procedures      Procedures

  FM              Factory Mutual

  fps             feet per second

  ft              feet

  gpm             gallons per minute

  h               hour(s)

  H&MB            heat and material balance

  HAZID           Hazard Identification

  HAZOP           Hazard And Operability

  HDD             Horizontal Direction Drilling

  HDMS            Hazard Detection and Mitigation System

  HHV             higher heating value

  HID             High Intensity Discharge

  HIPPS           High Integrity Pipeline Protection System

  Hp / hp         horsepower

  HP              high pressure

  HTF             heat transfer fluid

  IESNA           Illuminating Engineering Society of North America

  in              inch

  inches H~2~O    inches of water

  inches Hg       inches of mercury

  inches Hg/h     inches of mercury per hour

  IP              intermediate pressure

  ISO             International Organization for Standardization

  Kts             knots

  kV              kilovolt

  kVA             kilovolt Ampere (one thousand Volt Amperes)

  LDC             Local Distribution Company

  LFL             lower flammability limit

  LHV             lower heating value

  LNG             Liquefied Natural Gas

  LNG Terminal    Sparrows Point LNG Import Terminal

  LOI             Letter of Intent

  LP              low pressure

  LTD             Level, Temperature, Density

  M&R             Metering and Regulator

  m^3^            cubic meters

  m^3^/hour       cubic meters per hour

  MAOP            Maximum Allowable Operating Pressure

  mbar            millibar

  mbar/hour       millibar per hour

  MCC             Motor Control Center

  mcf             million cubic feet

  MCMERG          Mid-Chesapeake Marine Emergency Response Group

  MCR             Main Control Room

  MDE             Maryland Department of the Environment

  MDNR            Maryland Department of Natural Resources

  Mg/l            Microgram per Liter

  MIS             Management Information System

  MLLW            mean low low water

  MLV             Mainline valve

  MMBtu/hr        million British thermal units per hour

  MMcf/day        million cubic feet per day

  MMscfd          million standard cubic feet per day

  MP              Milepost

  mph             miles per hour

  MW              megawatt

  N/A             not applicable

  NAS Pax River   Naval Air Station Patuxent River

  NAVD            North American Vertical Datum

  NDE / NDT       Nondestructive Examination / Nondestructive Testing

  NEC             National Electrical Code

  NEPA            National Environmental policy Act of 1969

  NFPA            National Fire Protection Association

  NGA / NGPA      Natural Gas Act / Natural Gas Policy Act

  NHPA            National Historic Preservation Act of 1969

  NMFS            National Marine Fisheries Service

  NOI             Notice of Intent

  No. ins         number of inches

  NOAA            National Oceanic and Atmospheric Administration

  NOx             nitrogen oxides

  NPDES           National Pollutant Discharge Elimination System

  NPL             National Priority List

  NPS             National Park Service

  NRCS            Natural Resources Conservation Service

  NRHP            National Register of Historic Places

  NSA             Noise Sensitive Area

  NWI             National Wetland Inventory

  NVIC            Navigation and vessel Inspection Circular

  O&M             Operations And Maintenance

  OBE             Operating Basis Earthquake

  OD              Outside Diameter

  OSHA            Occupational Safety and Health Administration

  P&ID            piping and instrumentation diagram

  PAH             Poly Aromatic Hydrocarbon

  PCB             Polychlorinated Biphyenyls

  PCMS            Plant Control and Monitoring System

  PCR             Platform Control Room

  PDEP            Pennsylvania Department of Environmental Protection

  PDM             Processed Dredged Material

  PIANC           Permanent International Association Navigation Congress

  PM              particulate matter

  POTW            Publicly-owned Treatment Works

  PPB / ppb       parts per billion

  PPM / ppm       parts per million

  PPT / ppt       Parts per trillion

  psf             pounds per square foot

  psig            pounds per square inch gauge

  PWSA            Preliminary water way suitability assessment

  PVC             Poly Vinyl Chloride

  QA              Quality Assurance

  QC              Quality Control

  RGS             Rigid Galvanized Steel (conduit)

  ROW             Right-of-Way

  RR              Resource Report

  RTD             resistance temperature detector

  RTU             remote terminal unit

  RUSLE           Revised Universal Soil Loss Equation

  SAV             Aquatic vegetation

  SCADA           Supervisory Control and Data Acquisition

  scfh            standard cubic foot (feet) per hour

  scfm            standard cubic foot (feet) per minute

  SCUBA           Self-contained Underwater Breathing Apparatus

  SHPO            State Historic Preservation Officer

  SIP             State Implementation Plan

  SIS             Safety Instrumented System

  SPCC            Spill Prevention, Control, and Countermeasure

  SSE             Safe Shutdown Earthquake

  SSURGO          Soil Survey Geographic

  STATSCO         State Soil Geographic

  SWPPP           Storm Water Pollution Prevention Plan

  Tcf             Trillion Cubic Feet

  TCP/IP          Transmission Control Protocol/Internet Protocol,

  THPO            Tribal Historic Preservation Office

  TMDL            Total Maximum Daily Load

  TOC             Total organic carbon

  Trap            Pig Launcher Receiver Facility

  UL              Underwriters Laboratories

  UPS             Uninterruptible Power Supply

  USCG            United States Coast Guard

  USDA            United States Department of Agriculture

  USDOE           United States Department of Energy

  USDOT           United States Department of Transportation

  USEPA / EPA     United States Environmental Protection Agency

  USFWS           U.S. Fish and Wildlife Service

  USGS            U.S. Geological Survey

  usg             United States gallons

  usgpm           United States gallons per minute

  V               voltage

  VOC             volatile organic compound

  WSA             Water way suitability assessment

  WWTP            Waste Water Treatment Plant

  §               Section
  -------------------------------------------------------------------------

# general project description

## Introduction 

AES Sparrows Point LNG, LLC (Sparrows Point LNG) proposes to construct,
own, and operate a new liquefied natural gas (LNG) import, storage, and
regasification terminal (LNG Terminal) at the Sparrows Point Industrial
Complex situated on the Sparrows Point peninsula east of the Port of
Baltimore in Maryland. LNG will be delivered to the LNG Terminal by LNG
marine vessels, offloaded from these vessels to shoreside storage tanks,
regasified to natural gas on the LNG Terminal site (Terminal Site), and
the regasified natural gas transported to consumers by pipeline. The LNG
Terminal will have a regasification capacity of 1.5 billion standard
cubic feet of natural gas per day (bscfd), with the potential to expand
to 2.25 bscfd. Regasified natural gas will be delivered to markets in
the Mid-Atlantic Region and northern portions of the South Atlantic
Region through an approximately 88-mile, 30-inch outside diameter
interstate natural gas pipeline (Pipeline) to be constructed and
operated by Mid-Atlantic Express, L.L.C. (Mid-Atlantic Express). The
Pipeline will extend from the LNG Terminal to points of interconnection
with existing interstate natural gas pipeline systems near Eagle,
Pennsylvania. Together the LNG Terminal and Pipeline projects are
referred to as the Sparrows Point Project or Project. Both Sparrows
Point LNG and Mid-Atlantic Express (hereinafter collectively referred to
as AES) are subsidiaries of The AES Corporation.

The Project footprint is located in the counties of Baltimore, Harford,
and Cecil in Maryland and the counties of Lancaster and Chester in
Pennsylvania. The Terminal Site, which is located entirely within
Baltimore County, is a parcel located within a former shipyard. The
route proposed for the Pipeline (Pipeline Route), which crosses all of
the listed counties, includes industrial, commercial, agricultural, and
residential lands. Together, the Terminal Site and the Pipeline Route
comprise the Project Area.

The AES Corporation is considering the possibility of building a
combined cycle cogeneration power plant (Power Plant) on the Terminal
Site. The Power Plant would be configured with one F-Class combustion
gas turbine, one steam turbine, and associated auxiliaries. The Power
Plant would operate only on natural gas and would produce approximately
300 megawatts (MW) of clean electric power within an area of high energy
demand. The Power Plant would be connected to the local utility electric
system by an overhead electric power transmission line.

## Purpose and Need

### Energy and Natural Gas Trends in the United States

Energy demand in the United States continues to grow at a relatively
constant pace. According to the U.S. Energy Information Administration
(EIA 2006), total energy consumption in the United States is projected
to increase by 27 percent by the year 2025 (1.2 percent annually), from
100 quadrillion British thermal units (Btu)/year in 2004 to 127
quadrillion Btu/year in 2025.

The EIA predicts that the projected growth in energy demand (from
present to 2025) will vary by fuel type. Demand for coal and petroleum
is expected to increase, with coal projected to increase steeply in the
years beyond 2020. Demand for natural gas is projected to continue with
strong growth through to 2020, after which it is expected to level off.

Most importantly, natural gas has increasingly become the fuel of choice
in the United States. According to the EIA, there are a number of
underlying conditions that characterize the U.S. gas market, including:

-   Increased gas demand driven by 200 gigawatts of installed gas-fired
    generation investment since 1999, with limited amounts of
    alternative fuel capability;

-   Declines in domestic gas production throughout the lower 48 states
    and in offshore areas that are under the control of the United
    States;

-   Increased gas imports from Canada nearing current maximum capacity;

-   Decreased gas supply deliverability in the current transportation
    infrastructure;

-   Declines in the demand destruction that began during the sustained
    high price environment; and,

-   Stabilization of gas demand due to the rebound in the U.S. economy
    beginning in 2003.

These conditions have led to supply constraints and a steadily
increasing gas price floor, well above pre-2000 historical levels of
below \$3.00/thousand cubic feet (mcf) gas. The North American natural
gas industry will face a critical period over the next 10 to 15 years
when increased supply availability will be essential. Inevitably,
failure to increase supply to domestic markets will lead to sustained
and higher prices unless new sources of natural gas supply, including
LNG, are developed and delivered to the market via import terminals and
associated pipeline facilities.

### Natural Gas in the Mid-Atlantic Region

The need for incremental sources of natural gas supply to meet growing
demand is particularly acute in the Mid-Atlantic and surrounding regions
of the United States due to distances from existing production areas and
limited pipeline capacity from those production areas. The Sparrows
Point Project will provide incremental gas supply directly into the
Mid-Atlantic Region, an area of acute need. The Mid-Atlantic Region
consists of New Jersey, Pennsylvania, Maryland, Delaware, the District
of Columbia, the southern parts of New York, and the northern parts of
Virginia. Baltimore is within the Mid-Atlantic Region and will receive
the benefits associated with the incremental source of natural gas
either through direct supply or displacement. The northern portions of
the South-Atlantic Region that will also benefit from the incremental
source of natural gas from the Project include the southern parts of
Virginia and the northern parts of North Carolina. The benefits in the
northern portions of the South-Atlantic Region will be realized
primarily through displacement rather than direct supply.

Natural gas demand for the Mid-Atlantic Region, the area that will be
most directly served by the Project, was approximately 2.4 trillion
cubic feet (Tcf) in 2005, representing approximately 11 percent of total
U.S. natural gas consumption as shown on Figure 1.2-1.

**Figure 1.2-1: 2005 U.S. Natural Gas Consumption by Census Region**[^1]

![](media/image1.wmf){width="4.622916666666667in"
height="3.7152777777777777in"}

Natural gas demand for the Mid-Atlantic Region has remained between 2.3
Tcf and 2.5 Tcf over the last 10 years (i.e., 1995 to 2005), as shown in
Figure 1.2-2 below. The EIA (EIA 2006) is projecting an approximate 1.3
percent compounded annual growth rate in natural gas demand for the
Mid-Atlantic Region from 2005 to 2020, which will result in an increase
from 2.4 Tcf in 2005 to 2.9 Tcf in 2020. For the period between 2020 and
2030, EIA has forecasted a modest decline in natural gas demand to 2.8
Tcf in 2030.

**Figure 1.2-2: Mid-Atlantic Region Natural Gas Consumption, 1995 --
2030 (Tcf)**[^2]

![](media/image2.wmf){width="4.86875in" height="3.063888888888889in"}

Natural gas demand from the electric power generation and commercial
segments has shown the most growth for the period 1995 to 2005. As shown
in Figure 1.2-3 below, EIA projects that natural gas demand from
electric power generation will continue to show the most significant
growth for the period 2005 to 2030.

> Figure 1.2-3: Mid-Atlantic Historic and Projected Natural Gas
> Consumption by
> Segment![](media/image3.wmf){width="5.990277777777778in"
> height="2.7847222222222223in"}

As shown in Figure 1.2-4 below and as discussed above, EIA is projecting
incremental demand growth in the Mid-Atlantic Region.

> Figure 1.2-4: Mid-Atlantic Natural Gas Incremental Demand
>
> ![](media/image4.wmf){width="5.248611111111111in"
> height="3.576388888888889in"}

Due to its location in the heart of an area of high (and increasing)
natural gas demand, the Project will result in a more reliable and
cost-effective supply of gas to its target markets than gas supplies
from the Gulf of Mexico or other domestic regions of production that
would require significant pipeline expansion to provide the equivalent
amount of natural gas to this market. Introduction of a new source of
supply will have the effect of reducing the "basis" in the market
intended to be served by the Project.[^3] The Project will serve a need
for additional natural gas by providing a new supply of LNG. While the
LNG supplier will dictate many of the terms of delivery, natural gas
will be supplied directly into the market area. AES expects the LNG
delivered to the LNG Terminal will be priced at various market index
price points, thus being priced competitively with alternative supplies
at these points.

## Proposed Facilities Location and Description

### Project Description

The principal components of the proposed LNG Terminal include marine
terminal facilities, three full-containment onshore LNG storage tanks, a
vaporization system, a vapor handling system, site utilities,
administrative and support buildings, instrumentation and control
systems, communications and security systems, and fire protection,
hazard detection and safety systems. The LNG Terminal facilities have
been sited and designed, and will be constructed and operated to meet or
exceed all applicable standards and requirements established by the U.S.
Department of Transportation (USDOT) (49 CFR Parts 192 and 193), the
Federal Energy Regulatory Commission (FERC) (18 CFR Parts 153 and 380)
and the U.S. Coast Guard (USCG) (33 CFR Parts 105, 127, 157 and 160), as
well as additional standards and regulations cited in Resource Reports 2
through 13. The inclusion of a Power Plant on the LNG Terminal Site is
also under consideration.

The Pipeline, which will carry the natural gas that has been
re-vaporized at the LNG Terminal, will extend from the LNG Terminal to
proposed interconnections with the existing Columbia Gas Transmission
Corporation (Columbia), Transcontinental Gas Pipe Line Corporation
(Transco) and Texas Eastern Transmission Corporation (TETCO) interstate
pipeline systems near Eagle, Pennsylvania. The interconnection point
near Eagle, Pennsylvania was chosen because of the relatively close
proximity of the above referenced three interstate pipelines with a
combined firm flowby capacity in excess of 7 Bcf per day. AES has
designed the interconnections to deliver up to one bscfd into both the
Transco and TETCO interstate pipeline systems, and up to 0.5 bscfd into
the Columbia pipeline system. The sizing of the Pipeline and
interconnections will allow the initial flow capacity of the Project,
1.5 bscfd, to be delivered to markets served by these interstate
pipelines. Actual flows through the individual interconnections will be
dependent upon final negotiations with customers. Although currently not
planned and not part of the Project description, interconnection with
local utility pipeline systems may occur in the future. In such event,
AES will submit appropriate documentation to appropriate agencies to
allow for such accommodation.

The likely customers of the proposed Project fall into three broad
categories:

-   Existing shippers with firm forward haul capacity on the three
    pipelines, including some of the country's largest electric
    generators and natural gas distributors, e.g., PECO (an Exelon
    Company), Philadelphia Gas Works, Consolidated Edison, Public
    Service Gas & Electric of New Jersey, New Jersey Natural and Key
    Span Energy Delivery.

-   Customers located south and west of the interconnection location
    that could be reached on a back haul basis on the three pipelines
    using existing capacity to deliver incremental volumes. This
    includes electric generation facilities and natural gas distributors
    located in the Mid-Atlantic Region including the consuming areas
    around Pittsburgh, Pennsylvania, Baltimore, Maryland, and
    Washington, D.C.  (Please see the Concentric Market Study submitted
    by AES for a complete list of potential backhaul customers for the
    three pipelines, which report is appended to Resource Report 10,
    *Alternatives.*).

-   Customers with underground storage capacity that could be reached on
    a forward or back haul basis. An example of this is the storage
    located in Liedy, Pennsylvania.

A subsidiary of The AES Corporation (AES Mid-Atlantic LNG Marketing,
LLC) was the successful bidder in the open season for the capacity on
the Pipeline as well as the holder of capacity in the LNG Terminal.
Prior to commencing operation of the Project, this subsidiary will seek
appropriate import authorization (blanket, long-term, or both) in
accordance with the United States Department of Energy regulations at 10
CFR Part 590, Administrative Procedures with Respect to the Import and
Export of Natural Gas (2006).

### Project Location

The LNG Terminal will be located on an approximately 80-acre parcel
within the existing Sparrows Point Industrial Complex located in
Baltimore County, Maryland. The 80-acre Terminal Site is comprised of
approximately 45 acres of upland area and the remainder is a near shore
riparian rights area. The Terminal Site previously was owned and
operated by Bethlehem Steel Corporation (BSC) as part of a steel
manufacturing and shipbuilding facility. BSC divided its operations and
split off the portion that dealt with shipbuilding. AES has an option to
lease the Terminal Site with the current owner of the Sparrows Point
Shipyard.

The Terminal Site is situated on a promontory that extends into the
Chesapeake Bay east of the Port of Baltimore as shown on Figure 1.3-3.
More specifically, the Terminal Site is located on the Marine Channel
adjacent to the Fort McHenry channel near the confluence of the Fort
McHenry Channel and the Brewerton Angle. The boundaries of the main
property where the LNG Terminal will be located, including both land
side and riparian rights area, the area that will be associated with
dredge material management, and the area of temporary equipment laydown,
storage and construction offices, are all shown on Figure 1.3-2 (Sheet
2).

The specific limits and dimensions of the 35-acre nearshore riparian
rights area are shown on Figure 1.3-2 (Sheet2) as bounds of the property
to be leased for the Terminal Site. First as a colony and then as a
state, Maryland incorporated the English common law of property,
including riparian rights. At common law, among other rights, a riparian
landowner was entitled to any natural accretion to his land, and to make
improvements upon submerged lands adjacent to his property in the form
of piers and/or deepened channels as necessary to preserve access to
navigation. These rights survive to the present day. Subject to the
rights of riparian owners, the State has been recognized since the days
of the common law to be the owner of submerged lands, which are deemed
to be held in trust for the benefit of all of its citizens. While these
riparian rights exist for submerged lands in Maryland, the Maryland
Department of the Environment (MDE) and United States Army Corps of
Engineers (COE) are vested with jurisdiction to authorize, via permits,
activities in submerged lands (such as installation of new structures
and dredging).

The specific limits and dimensions of the 35-acre riparian rights area
are shown on Figure 1.3-2 (Sheet 2) as bounds of the property to be
leased for the Terminal Site. First as a colony and then as a state,
Maryland incorporated the English common law of property, including
riparian rights. At common law, among other rights, a riparian landowner
was entitled to any natural accretion to his land, and to make
improvements upon submerged lands adjacent to his property, in the form
of piers and/or deepened channels, as necessary to preserve access to
navigation. These rights survive to the present day. Subject to the
rights of riparian owners, the State has been recognized since the days
of the common law to be the owner of submerged lands, which are deemed
to be held in trust for the benefit of all of its citizens. While these
riparian rights exist for submerged lands in Maryland, the Maryland
Department of Environment and US Army Corps of Engineers retain a
permitting mechanism for authorizing activities in submerged lands (such
as installation of new structures and dredging).

The proposed Pipeline Route generally parallels existing rights-of-way
(ROW) for highways, overhead electric transmission lines and other
pipelines. More specifically, the Pipeline Route:

-   Exits the former Sparrows Point Shipyard and steel mill property,
    north to northeast, for approximately 2 miles (MP 0.0 to 2.0);

-   Follows Route I-695 with the exception of minor divergences (to
    avoid interchanges) north and northwest for approximately 6 miles
    (MP 2.0 to 8.0);

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-   Turns north to northeast near the Back Creek crossing, and follows a
    Baltimore Gas and Electric Company (BG&E) overhead transmission
    corridor for approximately 24.5 miles (MP 8.0 to 32.5); and

-   Turns northeast at an intersection with the ROW for an existing
    Columbia pipeline and generally parallels the existing pipeline
    corridor for approximately 54 miles (MP 32.5 to 87.6) to its
    terminus near Eagle, Pennsylvania.

Preliminary collocation and/or route paralleling discussions have been
held with BG&E and Columbia, as well as with Maryland highway
authorities. AES is continuing discussions with the aforementioned
parties in an attempt to come to an agreement. AES will attempt to
conclude these discussions by the anticipated certificate date in
October 2007.

In accordance with conventional pipeline routing principles, collocation
with existing utility corridors to the maximum extent possible was the
primary routing strategy. Although not the only criterion used in route
selection, the preference towards the use of existing corridors is an
industry standard and consistent with the objectives of most regulatory
agencies, including the COE and the FERC. For this reason, AES
endeavored to select a route that would maximize the use of existing
utility and highway ROWs, thereby minimizing potential impacts to the
environment, individual landowners and other stakeholders, and ensuring
the technical and economic feasibility of constructing the Pipeline. A
summary of alignment segments that are parallel to existing ROWs is
presented in Table 1.3-1.

Utility ROWs include sides of public roadways and railways, electric
transmission line corridors, other pipeline (petroleum, natural gas,
etc.) corridors, or other setback areas. AES used maps and aerial
photographs to identify these utility ROWs during the initial planning
stages of the Project. During the course of in-field investigations and
surveys, AES discovered that there were some areas where the existing
ROW was not wide enough to locate the proposed Pipeline entirely within
the existing ROW corridors. In such cases, AES made reasonable attempts
to locate the Pipeline on the edge of the existing ROW, and intends to
pursue shared ROWs with the existing easement owners to that effect.
Such cooperative planning efforts will help to minimize newly created
ROW easements for portions that do not completely overlap. AES
discovered other situations during the course of its in-field
investigations where housing or other structures had been built close to
the existing utility ROW since the time the ROW was established. In
these latter cases, in an effort to meet the objectives of maximum
avoidance and impact minimization, AES explored route variations that
diverge from the existing ROWs. Where route variations are not
practical, AES intends to utilize special construction techniques to
assist in avoiding or mitigating impacts on residential neighborhoods.
The extent of the overlap, partial overlap, and routing away from the
existing ROWs as well as proposed mitigation efforts in residential
areas is more fully described in Resource Report 8, *Land Use,
Recreation and Aesthetics*.

In summary, several criteria were used to select the proposed Pipeline
Route and aboveground facility locations. Criteria included the
following:

-   Identifying existing ROWs, transportation features and utility
    crossings, and land uses (i.e., both existing and planned); avoiding
    and minimizing potential negative impacts (e.g. short-term
    disruptions due to construction activities); and enhancing positive
    impacts to local communities and landowners (e.g., increase in tax
    revenue as shown in Table 5.4-2, Resource Report 5, Socioeconomics);

-   Avoiding and minimizing potential impacts to environmental and
    cultural resources (e.g., architectural and archeological resources,
    waterbodies, fisheries, wetlands, threatened and endangered
    species/significant habitats), sensitive soils, and
    geologic/topographic hazards to the extent possible; and

-   Engineering, construction, and cost feasibility (i.e., including
    route length and topography and opportunities to use existing
    corridors).

Taking into consideration these criteria, four major route alternatives,
and twenty-two minor route variations have been identified and are
further discussed in Resource Report 10, *Alternatives*.[^4] While most
of the alternatives and variations involve routing on other utility
ROWs, greenfield construction was also considered. The four major route
alternatives that were identified include the following:

-   Alternative Route 1, also referred to as the Dundalk West
    Alternative, would deviate from the proposed Pipeline Route at North
    Road (approximately MP 0.8), and follow an existing roadway for
    approximately 1.2 miles before crossing Bear Creek (Figure
    10.4.1-1). Alternative Route 1 would then be routed along an
    electric utility corridor through a densely populated area of
    Dundalk heading north for approximately 4.8 miles. The route would
    then rejoin the proposed Pipeline Route at MP 8.0.

-   Alternative Route 2, also referred to as the Western Corridor
    Alternative, would deviate from the proposed Pipeline Route after
    the Back River crossing (MP 9.0) and head north for approximately
    21.0 miles along a northern-trending, two-tower BG&E transmission
    line corridor (Figure 10.4.1-2). Shortly after it crosses the
    Baltimore and Harford County line in Harford County, Maryland, this
    alternative route would turn to the northeast and closely parallel
    an existing pipeline corridor, rejoining the proposed Pipeline Route
    at MP 32.5.

-   Alternative Route 3, also referred to as the SR 136 Alternative,
    would deviate from the proposed Pipeline Route at the intersection
    with the overhead transmission corridor and I-95 at approximately MP
    19 (Figure 10.4.1-3). This alternative route would traverse
    northeast along I-95 for approximately 8.5 miles, and then turn
    north onto SR 136. For 13.6 miles, this alternative route would
    parallel, but not be adjacent to, SR 136 until rejoining the
    proposed Pipeline Route at approximately MP 40.0 at the existing
    Columbia pipeline ROW.

-   Alternative Route 4, also known as the US I-95 & Greenfield
    Alternative, would deviate from the proposed Pipeline Route at the
    intersection with the overhead transmission corridor and I-95 at
    approximately MP 19 (Figure 10.4.1-4). This alternative route would
    head north to northeast and follow I-95 for approximately 20.0
    miles. At this point, this alternative route would divert from I-95
    and traverse 13.8 miles in a northerly direction across new
    right-of-way. Shortly after this alternative route crosses U.S. 1 in
    Harford County, Maryland, it would reach Columbia pipeline,
    rejoining the proposed Pipeline Route at approximately MP 40.0.

A more complete description of the shorter segment route variations, and
evaluation/selection of preferred alternatives and variations appears in
Resource Report 10, *Alternatives*.

### Proposed Facilities

The LNG Terminal design regasification/sendout capacity will be 1.5
bscfd, at a maximum sendout pressure of 2,080 pounds per square inch
(psig). It is expected to operate continuously in a baseload mode of
operation, and will be designed to allow the potential addition of a
fourth tank and a potential expansion in vaporization and sendout
capacity of up to 2.25 bscfd. No increase in the capacity of the
Pipeline would be needed to accommodate the additional tank capacity
should such an expansion of the vaporization and sendout capacity be
undertaken in the future, because the expansions are anticipated to be
in local demands that would likely be served by the Project by
back-feeding existing pipeline infrastructure in the vicinity of the
Terminal Site. The Terminal design includes pre-investment in features
and equipment, including blanked off pipe connections, to facilitate
this future expansion. If and when the time comes to pursue this
expansion, AES will perform a more detailed study on the expansion case
to identify changes required to the existing Project facilities. The LNG
Terminal is designed in accordance with USDOT standards under 49 CFR
Part 193, and the National Fire Protection Association (NFPA) 59A,
Standard for the Protection, Storage, and Handling of Liquefied Natural
Gas (LNG), 2001 Edition, as further described in Resource Report 13,
*Engineering and Design Material* and Resource Report 11, *Safety and
Reliability*.

#### LNG Terminal Marine Facilities 

The LNG Terminal will make use of an existing pier located at the
northern end of the Terminal Site. The existing pier will be modified to
accommodate mooring of LNG ships. The modifications will consist of
repairing existing piles, resurfacing the deck, and building an
unloading platform and pipe trestle on top of the pier.

The pier will have two berths, one on the north side of the pier and the
other on the south side. Each berth will be designed to accommodate an
LNG ship with the capacities listed below. Although the pier will be
able to accommodate two LNG ships at one time, unloading will only be
permitted from one LNG ship at any given time. The southern berth, which
will be the primary receiving point for the LNG ships, is located
approximately 1.15 miles from the nearest residence. The north berth,
which will be used infrequently when weather or other delays result in
overlapping scheduling of two LNG ships, is located approximately 1.08
miles from the nearest residence.

The LNG berths will accommodate the dimensional characteristics of LNG
ships with storage capacities ranging from 786,200 barrel (bbl) (125,000
m³) up to 1,364,900 bbl (217,000 m³). This range of ship storage
capacities accounts for the vast majority of existing and planned LNG
ships in the world fleet (see Resource Report 10, *Alternatives*,
Section 10.5.1.1). The LNG ships will normally arrive at the pier loaded
and will leave in ballast condition as described in Section 2.4.9.2 of
Resource Report 2, *Water Use and Quality*. A table listing the
dimensions of the LNG ships expected to call at the LNG Terminal is
provided in Appendix 1D. Also included in that table is a listing of the
dimensions of other ships that currently call at the Port of Baltimore.
As can be seen from the information presented, the LNG ships expected at
the LNG Terminal do not differ greatly in size (and in some cases are
actually smaller) than the larger ships currently transiting the waters
offshore of the Terminal Site.

The main components of the marine facilities at the Terminal Site will
include the following:

-   An existing finger pier that will support an elevated pipeway and
    spill containment system, an elevated unloading platform, and
    gangways; the pier will also support the mooring of the LNG ships
    and provide a roadway to the loading platform area;

-   Dredged areas for ship access;

-   Aids to navigation;

-   A retractable security barrier; and

-   Mechanical systems.

The features of the marine facility at the Terminal Site are shown on
Figure 1.3-2 (Sheets 1 and 2). A description of the individual
components of the proposed marine facility is provided below.

##### LNG Pier

> Access between land and the unloading platform will be provided by an
> existing pile-supported finger pier. The pier structure consists of
> steel H-piles that support concrete pile caps. Spanning between the
> pile caps is a reinforced concrete deck.
>
> The existing pier will be rehabilitated to provide an adequate
> foundation for the new superstructure that will support the LNG
> pipeway and spill containment system, and also the unloading platform.
> A new fendering system and mooring fixtures will be installed on the
> pier to support the berthing and mooring activities of the LNG ships.

##### Turning Basin and Entrance Channel

> To facilitate access to the LNG Terminal by LNG ships, an approach
> channel and turning basin will be constructed by expanding existing
> channels by dredging (further discussed in the Dredge Management Plan
> in Section 1.5.1.2.A and Appendix 1C).
>
> The turning basin and approach channel will provide an access point
> for approaching LNG ships (from the existing Brewerton Channel to the
> southwest). LNG ships transiting to the proposed LNG Terminal will do
> so under active tractor tug escort. The speed of the incoming LNG ship
> will be gradually reduced during its transit of the Brewerton Channel
> until, by the time it reaches the entrance of the approach channel to
> the LNG Terminal, it will have been slowed sufficiently to operate
> safely in the waters adjacent to the LNG Terminal. The tugs will
> assist the ship to turn into the approach channel. The incoming vessel
> will transit the approach channel under active tractor tug control.
> The LNG ship will be brought to full stop in the approach channel, and
> with tug assistance it will be turned and berthed at either berth with
> the bow pointing out. The departure procedures for LNG ships will be
> similar to those for the incoming transiting LNG ships as described
> above, except that the outgoing vessels will not need to be rotated in
> the turning basin.
>
> The approach channel and turning basin preliminary layout has been
> formulated using the following considerations:

-   LNG tanker vessel design capacities and size listed in Appendix 1D.
    Those listed in Appendix 1D include future generations of vessel
    designs not currently in service that are expected to call at the
    LNG Terminal.

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-   Channel design guidance references ((Society of International Gas
    Tanker and Terminal Operators \[SIGTTO\] 1997) and Permanent
    International Association Navigation Congress \[PIANC\] (1997)) to
    calculate the minimum channel width. The width of the channel is
    dependent on the following factors: vessel speed, wind speed and
    direction, current speed and direction, wave height, period, and
    direction, navigational aid, type of seabed, channel depth, type of
    side slopes, and hazard level of cargo.

-   Factors and guidance reference information (SIGTTO) affecting
    channel depth design. The channel depth is dependent on the
    following factors: vessel design draft, vertical ship motion due to
    wave action, squat, keel clearance, and water density effects.

-   Real time and fast time computer simulations performed at the
    Maritime Institute of Technology and Graduate Studies (MITAGS) with
    participation by licensed members of the Maryland Pilots
    Association. Initial simulations were performed on July 5, 6 and 7;
    additional refinement simulations were performed on September 5 and
    6, 2006.

> Based on the above considerations, the approach channel preliminary
> layout dimensions include an approximately 45-foot depth and 440-foot
> width. The proposed turning basin, which is approximately
> semi-circular in shape, has a radius of approximately 820-foot (also
> with a nominal water depth of 45 feet), which will allow the turning
> of all fully loaded design LNG ships with three tugs providing
> assistance. The final geometry and layout of the approach channel and
> turning basin was refined further (and reduced) through the additional
> fast-time and real-time simulation studies that were performed on
> September 5 and 6, 2006. A report summarizing the studies and their
> results was prepared by MITAGS and can be found in Appendix 11D of
> RR-11, *Reliability and Safety*.
>
> To support the marine operations at the LNG Terminal, it is
> anticipated that the following navigational aids will be provided:

-   Buoys to mark the width of navigable channel will be placed
    approximately every 1,200 feet. The buoys will be equipped with
    lights according to International Association of Lighthouse
    Authorities (IALA) guidelines, and in accordance with local port
    authority requirements.

-   Navigation lights will be installed on land and on structures, such
    as the end of the pier.

-   A range light may also be installed if determined appropriate by the
    Maryland Pilots Association.

> Tug service for LNG ships calling at the LNG Terminal will be provided
> by existing tug contractors with pilot support from the Baltimore port
> area.

#### LNG Receiving 

##### LNG Unloading Platform and Pipeway

> The unloading platform will be elevated and located on the existing
> pier, approximately 620 feet from the shoreline. It will support the
> fully-articulated unloading and vapor arms that connect the LNG
> Terminal piping system to the vessel manifold. The unloading platform
> will consist of a pre-cast/cast-in-place concrete deck supported by a
> steel support structure constructed on top of the existing pier deck.
> The LNG piping will extend downward from the unloading arms into an
> elevated pipeway.
>
> The elevated pipeway will extend from the unloading platform to the
> shoreline. An elevated concrete spillway will be installed adjacent to
> and beneath the piping as part of the pipeway structure, and will be
> sloped to the shoreline to provide for transport and collection of any
> LNG leaks or spills. The piping and spillway will be supported by
> steel columns which will extend from the existing pier deck.
>
> The unloading system will be designed to unload the entire contents of
> one 868,000 bbl (138,000 cubic meter (m^3^)) capacity LNG ship within
> 12 to 17 hours, depending on the size of the vessel, with a second
> ship berthed but not simultaneously unloading its cargo. The design
> nominal unloading rate is 55,000 gallons per minute (gpm) (12,500
> cubic meters per hour (m^3^/hour)). Piping will be designed to allow
> circulation of LNG through the unloading system during periods when no
> ship is unloading. This system will maintain the unloading lines at
> cryogenic temperatures, thus avoiding thermal cycling of the unloading
> lines.

##### LNG Mechanical Systems

> Various mechanical systems will be provided to deliver LNG from the
> LNG ship to the onshore LNG storage tanks. The proposed mechanical
> systems will include the following:

-   Eight hydraulically actuated articulated unloading arms (three for
    LNG unloading and one for vapor return to the ship, per berth);

-   Two blowers for returning vapor from the LNG storage tanks to the
    ship;

-   Vapor desuperheater system;

-   LNG sampling system;

-   LNG flow and temperature monitoring instrumentation; and

-   Interconnecting piping systems.

##### Boiloff Gas Compressor

> The boiloff gas (BOG) compression system will consist of three
> reciprocating type BOG compressors, two of which will be used during
> active LNG ship unloading. During normal terminal operation, when no
> LNG ships are unloading, one BOG compressor will be needed to control
> the BOG pressure in the storage tanks. If the BOG compressor is
> inoperative due to an extended power failure or other emergency, the
> boiloff vapors will be directed to a heated vent stack. A detailed
> description of the BOG compression system is included in Section 13.5
> of Resource Report 13, *Engineering and Design Material*.

##### Safety and Firefighting Systems

> The LNG Terminal will be equipped with the following major safety
> systems:

-   A Hazard Detection and Mitigation System (HDMS), which will
    continuously monitor and alert the operators to hazardous conditions
    throughout the LNG Terminal from fire, combustible gas leaks and low
    temperature LNG spills. Monitoring capability will be provided via
    graphic display screens and/or mimic panel displays located in the
    Main Control Room and the Platform Control Room.

-   An independent Safety Instrumentation System (SIS), which will allow
    the safe, sequential shutdown and isolation of rotating equipment,
    vaporization equipment, pier operations and LNG storage facilities.

-   An Emergency Shutdown (ESD) system, which will include shutdown and
    control devices designed to put the LNG Terminal in a safe state in
    the event of major incidents. The ESD system can effect total
    shutdown of the LNG Terminal, shutdown of ship unloading, shutdown
    of the sendout system, and/or shutdown of individual pieces of
    equipment, depending on the type of incident.

-   A fire fighting system composed of fixed and portable fire water
    systems, fixed and portable dry chemical extinguishing systems, and
    a high expansion foam system. The LNG Terminal will contain two
    on-shore fire water pumps, each capable of providing the entire fire
    water demand (100 percent redundancy). One pump will be driven by an
    electric motor and the other pump will be driven by a diesel engine.
    This will ensure the fire water system is capable of providing the
    design basis flow and pressure in the event of an electrical power
    failure. Fire water from the local municipal water supply will be
    stored in an onsite fire water storage tank, sized to provide two
    hours of design basis fire water flow per code requirements. In
    addition, backup fire water from the Patapsco River will be provided
    from a set of diesel driven pumps installed at the water\'s edge.
    These backup pumps can provide full flow to the onshore fire water
    system, and can also provide tank deluge flow in the event of an LNG
    storage tank fire. The backup fire water pump intake structure will
    be configured with in-take screens designed to prevent ingress of
    debris, and to maintain inlet velocities below two feet per second
    (fps) to minimize the effect of flow on the local marine life.

-   The seawater will be drawn from the LNG Terminal berth area through
    the velocity cap fitted to a pipeline located within the sheet pile
    wall that will be used to construct the bulkhead, at a depth of
    approximately -15 feet mean lower low water (MLLW). Due to the
    dredging that is proposed for this area and the height of the
    structure, turbulence and intrusion of sand and debris are expected
    to be minimal. The seawater intake structure is described in more
    detail in Section 13.17.1.2 of Resource Report 13, *Engineering and
    Design Material*, and the potential impacts to marine life and
    mitigation measures to be implemented are described in Section
    2.4.9.2 of Resource Report 2, *Water Use and Quality*.

##### LNG Storage 

> Three full containment LNG storage tanks are proposed for construction
> at the LNG Terminal. The LNG tanks will be full containment tanks
> approximately 170 feet in height and 270 feet in diameter, as shown on
> Figure 1.3-2 (Sheet 2). Each tank will be designed to store up to
> 1,000,000 bbl (160,000 m^3^) of LNG, at a temperature of --260 ^o^F
> and a design internal pressure of 4.3 psig. Tank capacity is designed
> to facilitate offloading of the entire contents of a 1,000,000 bbl
> (160,000 m^3^) LNG ship, and receipt of LNG shipments at intervals of
> approximately every two to three days. The tanks are designed and will
> be constructed according to the requirements of the American Petroleum
> Institute (API) 620 Appendix Q, and NFPA 59A.
>
> Each LNG storage tank will consist of an inner and outer tank. Tanks
> will be H-pile supported as further described in Section 13.6.2 of
> Resource Report 13, *Engineering and Design* Material. The inner
> "liquid containing" tank will be the primary containment, and will be
> a cylindrical flat bottom structure constructed of low temperature,
> nine percent nickel steel. All welds of the tank will be inspected per
> code by radiography, ultrasonic test, vacuum box test, and/or liquid
> penetrant test to ensure integrity. To prevent the stratification of
> the tank's inventory, the tank design will allow for both top and
> bottom filling. Bottom filling will be done through a standpipe inside
> the tank, and top filling will be carried out through a separate tank
> feed line onto an internal deflector plate. The filling operation will
> use gravity to assist in mixing the unloaded LNG with the heel in the
> tank (i.e., heavy LNG will be unloaded on top of a lighter tank heel,
> and lighter LNG will be unloaded under a heavy heel).
>
> During ship unloading, the LNG tank pressure will be maintained at
> approximately 3.0 to 3.5 psig using multiple BOG compressors, as
> required, and vapor return blowers. During periods when no ship is
> unloading, the pressure in the tank will not increase as rapidly, and
> in that case, one BOG compressor will be adequate to handle the BOG
> volume.
>
> The inner LNG-containing tank will be surrounded by an outer concrete
> tank, including a carbon steel inner liner. The outer concrete tank
> will provide secondary liquid containment of at least 110 percent of
> the contents of the inner tank, and will have a flat bottom, dome
> roof, and cylindrical shell. The concrete roof provides full
> containment of the tank vapor. The outer tank will be designed to
> contain product vapors and protect the insulation systems from
> moisture and other conditions. The insulation system will consist of
> perlite, cellular glass and fiberglass insulation.
>
> Should the BOG compressors not be able to maintain tank pressures due
> to unusual circumstances, LNG storage tank overpressure protection
> will be provided by discharging BOG through a discretionary vent
> heater and vent stack. Prior to the tank pressure reaching its
> discretionary vent setpoint pressure, a pressure control valve will
> automatically relieve excess vapor from the BOG header connected in
> common with each tank to the heated vent stack. In addition, each tank
> is provided with atmospheric relief vents for ultimate overpressure
> protection. A pressure makeup system and vacuum breaker valves will
> also be installed to protect the tanks against vacuum conditions.
>
> Temperature and density measuring devices will be located in the LNG
> storage tanks to provide the plant operator with the means to detect
> LNG stratification. Automatic continuous level measurements will also
> be provided for the LNG storage tanks.

##### LNG Regasification and Sendout 

> The process systems associated with the LNG Terminal include the
> following:

-   Vapor handling system;

-   BOG recondenser;

-   LNG in-tank pumps;

-   LNG high-pressure sendout pumps;

-   LNG regasification system;

-   Natural gas metering station;

-   Heat transfer fluid system;

-   Utilities, including air compressors and nitrogen gas; and

-   Instrumentation and control.

> The process flow diagram for the process system and components is
> shown in Appendix U of Resource Report 13, *Engineering Design and
> Materials*. Piping, electrical distribution wiring and insulation of
> varying size and capacity will be installed throughout the LNG
> Terminal. Several of the components will be housed in separate
> buildings that will be connected via roadways and sidewalks.

##### Vapor Handling System

> The LNG vapor handling system will be designed to handle the vapor
> generated in the storage tanks coincident with a peak unloading rate
> of 55,000 gpm (12,500 m^3^/hour). During LNG ship unloading, heat
> input into the system will be from pumping, and heat transfer from the
> ambient surroundings. To suppress some of the vapor that would be
> generated due to the additional heat input, the storage tanks will be
> operated at a pressure slightly above that of the LNG ship. This
> allows part of the heat input of the system to manifest itself as a
> sensible heat increase in the LNG.
>
> Two 50 percent capacity blowers will be used to remove a portion of
> the vapor generated in the storage tanks during LNG ship unloading.
> The vapor from the discharge of the blowers will be returned to the
> LNG ship through a vapor return line and a vapor return arm. A
> desuperheater will be provided at each berth to provide cold vapor to
> the LNG ship (at approximately --180 ºF), if so required by the LNG
> ship.
>
> The remainder of the vapor generated in the storage tanks during LNG
> ship unloading will be handled by two (of three) 50 percent capacity
> BOG compressors. The vapor from the discharge of the compressors will
> be condensed in the BOG recondenser. During periods in which no LNG
> ship is unloading, only one of the compressors will be needed.

##### Boiloff Gas Recondenser

> At the recondenser, the BOG from the compressor discharge will be
> condensed by heat transfer with subcooled LNG from the low-pressure
> in-tank LNG pumps at approximately 50 psig. The condensed BOG will be
> mixed with the low-pressure pump discharge in the high pressure pump
> drum.

##### LNG In-Tank Pumps

> Low-pressure pumps will be installed in each LNG storage tank. Each
> in-tank pump will be located near the bottom of the storage tank, and
> will pump LNG up and out of the tank through a vertical column. The
> pumps will discharge into the low pressure LNG header that will be
> connected to the high pressure pump drum.

##### LNG High Pressure Pumps

> The in-tank pump discharge will flow into a suction drum for the high
> pressure pumps, where it will mix with condensed BOG flowing from the
> BOG recondenser. The LNG high pressure sendout pumps will increase the
> LNG's pressure to slightly above the sendout pressure before feeding
> it to the high pressure LNG vaporizers, which will provide gas to the
> sendout pipeline at 2,080 psig. The high pressure LNG pumps will be
> vertical, submerged, centrifugal, can-mounted pumps.

##### LNG Regasification 

> Discharge from the high pressure pumps will flow into the high
> pressure LNG vaporizers, which will warm the LNG to the design outlet
> temperature of 40^o^F. The LNG vaporizers will be vertical shell and
> tube heat exchangers, with LNG flowing on the tube side and heat
> transfer fluid flowing on the shell side.

##### Natural Gas Metering Station

> A metering station will be provided to meter the natural gas leaving
> the Terminal Site and entering the Pipeline. The LNG Terminal metering
> station will include gas analysis equipment to ensure quality control
> consistent with gas transmission line requirements.

##### Heat Transfer Fluid Heating System

> The LNG Terminal will use a glycol-water solution as its heat transfer
> fluid (HTF). Cold HTF leaving the shell side of the vaporizers will be
> pumped through the HTF heaters and returned to the vaporizers. The HTF
> heaters will be heated by a separate set of fired heaters burning
> natural gas. The HTF heating system is sized to provide sufficient
> heat to vaporize the baseload natural gas sendout rate, with one spare
> pump and one spare heater. The natural gas fuel for the system will be
> produced either from vaporized LNG from the LNG Terminal or from
> backfeed from the Pipeline (for startup). Detailed design information
> regarding the vaporization process is presented in Section 13.5.7 of
> Resource Report 13, *Engineering and Design Materials*.

##### Air Compressors

> The LNG Terminal will include a compressed plant air system designed
> to supply the service air and instrument air requirements of the LNG
> Terminal facilities. Dry instrument air will be provided for pneumatic
> operators and devices throughout the LNG Terminal. Compressed air
> service will be provided to appropriate areas of the Terminal Site via
> utility stations.
>
> Three 50 percent oil-free rotary screw-type package compressors will
> supply compressed air to the service air and instrument air system.
> The compressors will discharge to an air receiver for supply to the
> service and instrument air distribution systems. The plant air system
> will include dual tower desiccant-type dryers with heatless
> regeneration.

##### Instrumentation and Control

> The LNG Terminal control system will be a micro-processor based
> Distributed Control System (DCS). The DCS will control and supervise
> the LNG systems from the central control room. The primary control
> location will be the Main Control Room. The Main Control Room will
> contain the DCS operator station with consoles, printers, engineering
> workstation and other auxiliary equipment. The DCS will provide remote
> control functions to the plant operators either directly from the DCS
> control processors, or indirectly through hardwired connections or
> serial data links connected to the remotely located control packages.
>
> The DCS will be provided with color graphic displays of the plant
> equipment, with sufficient detail to allow proper control and
> monitoring of plant functions such as changing set points, placing a
> controller on manual or automatic, starting or stopping plant
> equipment, etc. The DCS will be interfaced with a control system for
> the auxiliary equipment, and electrical systems designed to achieve
> central control of the plant equipment. Required control, alarm and
> monitoring functions for miscellaneous equipment will be integrated
> into the DCS.
>
> As discussed above, a stand alone, independent HDMS will continuously
> monitor and alert the operator of potentially hazardous conditions
> throughout the LNG Terminal.

##### Utility Power Feeds

> The LNG Terminal will be supplied with power using two redundant 110
> kilovolt (kV) power feeds from the local utility. These utility feeds
> will be stepped down from 110 kV to 13.8 kV and lower for use at the
> LNG Terminal. Additionally, there will be a one hundred percent
> standby power generator set provided, capable of providing sufficient
> power to maintain LNG circulation via operation of one low pressure
> (LP) Pump and to provide for terminal lighting, all control systems,
> and the operation of all other necessary auxiliary systems. If the
> Power Plant that is presently under consideration is built, the
> primary source of power to the LNG Terminal will be from the Power
> Plant and the back up source will be from the two 110 kV utility
> feeds.

#### Pipeline Facilities []{.mark}

The Pipeline consists of approximately 88-miles of 30-inch outside
diameter (OD) natural gas pipeline and associated facilities (e.g.,
mainline block valve sites, interconnect metering facilities, and a
Supervisory Control and Data Acquisition (SCADA) system required for
remote monitoring, control, and leak detection) which will extend from
the LNG Terminal in Sparrows Point, Maryland to the terminus near Eagle,
Pennsylvania. The terminus point was chosen based on the relatively
close proximity of three major interstate natural gas pipelines -
Columbia, Transco and TETCO. Allowance will also be made for
intermediate local interconnections with local utility systems or
others, should those entities determine that such interconnection is
beneficial.

The Pipeline is planned to have a capacity to enable delivery of up to
1.5 bscfd on a firm basis, and have a maximum allowable operating
pressure (MAOP) of 2,080 psig.

Pipeline facilities described in this Resource Report 1 are designed,
constructed, tested, operated, and maintained to conform with or exceed
the requirements of 49 CFR Part 192, *Transportation of Natural and
Other Gas by Pipeline: Minimum Safety Standards*, and other applicable
governmental regulations. A listing of applicable safety regulations and
design standards, including industry standards incorporated by
reference, is provided in Resource Report 11, *Safety and Reliability*.

The Pipeline will be installed within a 50-foot-wide permanent ROW.
During construction in non-agricultural lands, 25 feet of additional
temporary space will be required (in aggregate, a 75-foot construction
right-of-way, or CROW) to allow crews to safely construct all Pipeline
facilities. In areas where additional working width is necessary (e.g.,
to stockpile topsoil in agricultural lands), the CROW may be expanded up
to an additional 25 feet to accommodate the need (thus comprising a
100-foot CROW). Typical configurations for the Pipeline ROW and CROW are
shown on Figure 1.3-4 and in Appendix 2B (BMPs 2a through 2d). Project
Alignment Sheets appended to this Resource Report (Appendix 1A) show the
Pipeline alignment, permanent ROW, and the locations where the permanent
ROW overlaps with property lines of utility corridors that are owned in
fee. Similarly, in areas where the ROW must be restricted (e.g., near
residential areas) the CROW would be reduced as appropriate. The CROW
will be expanded or reduced as necessary (i.e., by length and/or width)
as shown on alignment sheets (see Appendix 1A) to accommodate crew needs
and site conditions. Additional temporary workspace (ATWS) will be used
where necessary to accommodate construction methods, materials, and/or
equipment (e.g., road and railroad crossings, equipment turn-arounds,
and waterbody crossings). Estimates of land affected by these elements
have been included in Tables 1.4-1 and 1.4-2 contained herein.
Approximate widths of overlap for the Pipeline temporary and permanent
ROWs along existing utility and road ROWs are provided on Table 1.3-1.

The Pipeline will be made of carbon steel pipe manufactured in
accordance with the API specifications for seamless and welded steel
line pipe for use in the natural gas pipeline industry (API 5L). The
planned standard pipe will be Class 3 pipe; however, pipe classification
will increase to Class 4 in selected areas based on class study and
regulatory requirements as described in Resource Report 11, *Reliability
and Safety* (Table 11.1.3-1). The pipe will be protected from internal
and external corrosion by a fusion-bonded epoxy (FBE) coating and an
impressed current cathodic protection (CP) system.

Where the Pipeline Route parallels existing pipeline(s), AES will seek
to maintain a minimum separation distance of 25 feet adjacent to and
abutting the existing pipeline ROW, unless constrained by other critical
features. In the event that such constraints arise, a lesser offset may
be agreed upon with the existing pipeline operator, and submitted for
any required regulatory approval.

Having safe and reliable entry to Pipeline facilities will require the
use of access roads. AES will use a combination of new and existing
temporary and permanent access roads for this purpose. Temporary access
roads will be utilized as Pipeline activities warrant (e.g., during
construction activities). To the extent possible, AES will use existing
access roads and maintain and/or improve them as needed. Permanent
access roads will be constructed (if not already available) to support
regular operational activities, e.g., regular inspections, ROW
maintenance, and facilities maintenance and operation. In both
instances, AES will seek and obtain the necessary property rights and
approvals from government agencies prior to the use or construction of
such roads. Public roads are available for use as access roads without
further approvals, subject to posted weight and clearance restrictions.
If a location is inaccessible via existing roadways, new roadways will
be constructed to provide access to the locations, after appropriate
environmental permits and approvals have been obtained. Safe and
accessible conditions, e.g., all of the required posted warnings,
roadways kept clear of construction related debris, traffic control
support in conjunction with local authorities, will be maintained at all
public roadway crossings and access points during project activities.
Specific access road locations are shown on the alignment sheets and
U.S. Geologic Survey (USGS) Topographic Maps (see Appendix 1A), and are
summarized in Resource Report 8, *Land Use, Recreation and Aesthetics*.

##### Aboveground Pipeline Facilities

> Aboveground facilities associated with the Pipeline include the
> mainline block valve sites and interconnect metering facilities.

-   **Mainline Block Valve Facilities.** Mainline Block Valve facilities
    (MLBVs) will be provided to stop the flow of gas and to isolate
    sections of the Pipeline during maintenance, repair, and if a leak
    is detected. Nine valves will be spaced to meet USDOT requirements,
    49 CFR Part 192, *Transportation of Natural and Other Gas by
    Pipeline: Minimum Federal Safety Standards* as follows (see Table
    1.4-1)*:*

-   Each point on the Pipeline in a Class 4 location will be within 2.5
    miles of a valve.

-   Each point on the Pipeline in a Class 3 location will be within 4
    miles of a valve.

-   Each point on the Pipeline in a Class 2 location will be within 7.5
    miles of a valve.

-   Each point on the Pipeline in a Class 1 location will be within 10
    miles of a valve.

-   The locations of the Pipeline MLBVs are shown on the Alignment
    Sheets (included in Appendix 1A) at the following mileposts:

-   MP 9.8

-   MP 19.8

-   MP 29.4

-   MP 39.4

-   MP 49.3

-   MP 59.1

-   MP 69.2

-   MP 78.4

-   MP 83.2

> All valves will be equipped with blowdown capabilities to allow
> natural gas to vent to the atmosphere in a controlled and safe manner
> if an overpressure event occurs. In the event of an emergency or
> routine maintenance activity, Pipeline segments would be isolated by
> closing the appropriate valves necessary to isolate the segment.
> Valves will be suitable for service at the design MAOP. See Figure
> 1.3-5 (Sheet 1), Typical Mainline Valve Site, which shows the
> potential typical layouts of proposed valve facilities. Valve sites
> will be graveled, accessible to work crews, and secured and fenced to
> provide security and safety and prevent uncontrolled entry. In
> addition, Pipeline operations will include remote control and
> monitoring capabilities for mainline block valves.

-   **Interconnect Facilities.** The Pipeline will be interconnected
    with three existing pipeline systems - Columbia, TETCO and Transco -
    by interconnects located near Eagle, Pennsylvania.[^5] AES has
    discussed interconnections with all three pipelines, and each has
    shared its technical requirements and tie-in locations.  All of the
    pipeline systems indicated that a tie-in north of the Susquehanna
    River would be the preferred interconnection location. Tie in north
    of the Susquehanna River will provide capacity further north on each
    of their systems and avoid the potential for future upgrades that
    would require additional crossings of the Susquehanna River.  The
    interconnect facilities are planned to include metering, flow
    control and/or pressure control functionality (as required), scraper
    receiver/launcher capability, system isolation, i.e., remotely
    controlled station isolation valves, SCADA, as well as security and
    safety equipment. Figure 1.3-7 (Sheets 2 and 3) show typical
    interconnect tie-in and metering and regulation layouts*.* Each
    location will be equipped for system isolation. The interconnection
    facilities will be fenced to provide security and safety, and to
    prevent uncontrolled entry. Security lighting during non-daylight
    hours will be provided to allow for secure and safe operations.
    Engineering controls, e.g., shielding and/or motion detectors, will
    be used to reduce stray lighting.

#### Non-Jurisdictional Facilities

AES is considering building a collocated 300 MW combined-cycle
cogeneration facility that may be used to provide both waste heat for
vaporization of the LNG and power to the LNG Terminal. A discussion of
this potential facility construction, its merits, and the potential
applicability of FERC regulations is included in Section 1.10.

### Location Maps, Detailed Route Map, and Plot/Site Plans

The proposed LNG Terminal, Power Plant and Pipeline (with alternative
and primary routes) locations are shown on aerial photograph-based
alignment sheets and on USGS 7.5-minute series topographic maps (see
Appendix 1A). Related temporary construction areas and aboveground
facilities (such as pipe storage yards, extra work/staging areas,
contractor yards, and access roads, Horizontal Directional Drilling
(HDD) set-up and pullback areas, etc.; mainline block valves and
cathodic protection locations) are provided on the Alignment Sheets
and/or the USGS topographic quadrangle maps (Resource Report 1
--Appendix 1A) and Resource Report 2, *Water Use and Quality --*
Appendix 2B, Best Management Practices (BMPs).

## Land Requirements

Land requirements for the Project are quantified into two categories:
construction (temporary) and operational (permanent). Temporary land
requirements are those areas disturbed by construction activities that
would be restored to pre-existing conditions or better upon completion.

Permanent land requirements are lands that the LNG Terminal or the
Pipeline will acquire in fee or by easement to locate permanent Project
facilities. Permanent lands include the Terminal Site footprint, the
Pipeline 50-foot-wide permanent ROW, permanent access roads, and lands
purchased or leased to locate aboveground facilities. Specific land
requirements are discussed in the following subsections.

### LNG Terminal and Pipeline Facilities

#### LNG Terminal Facilities

For the LNG Terminal facilities, temporary (construction) and permanent
(operational) land requirements will include the approximately 45 upland
acres at the parcel located on Sparrows Point, Maryland as well as an
additional 15 acres located just south of the property boundary and 20
acres to the north of the site, for construction use, as shown on Figure
1.3-2 (Sheet 2). The Power Plant would also be situated within the
45-acre upland site area described above. The 15 acres to the south of
the Terminal Site will be used during the construction period for the
Dredged Material Recycling Facility (DMRF). The 20 acres to the north of
the Terminal Site will be used during construction as a contractor yard
and/or to support the DMRF.

**Table 1.4-1 Aboveground Facilities Summary with Land Requirements**

+----------------+------------------+---------------+----------------+
| **Project      | **Impact Type**  | **Land        | **Land         |
| Component**    |                  | Disturbed     | Required for   |
|                |                  | During        | Operation**    |
|                |                  | C             |                |
|                |                  | onstruction** |                |
+================+==================+===============+================+
|                |                  | **(acres)**   | **(acres)**    |
+----------------+------------------+---------------+----------------+
| **Sparrows     | Construction     | 198.6\*\*     | 45\*           |
| Point LNG      | workspace and    |               |                |
| Terminal**     | permanent        |               |                |
|                | operating area   |               |                |
+----------------+------------------+---------------+----------------+
| **Interconnect | Construction     | Included      |                |
| and Mainline   | workspace and    | above in area |                |
| Block Valve at | permanent        | of LNG        |                |
| Terminal**     | operating area   | Terminal      |                |
+----------------+------------------+---------------+----------------+
| **Additional   | Construction     | 0.9           | 0.5            |
| Pipeline       | workspace and    |               |                |
| Mainline Block | permanent        |               |                |
| Valves**       | operating area   |               |                |
|                |                  |               |                |
| **(nine        |                  |               |                |
| locations)**   |                  |               |                |
+----------------+------------------+---------------+----------------+
| **Pipeline     | Construction     | 1.5           | 0.75           |
| Interconnects  | workspace and    |               |                |
| (3 locations)  | permanent        |               |                |
| -- Transco,    | operating area   |               |                |
| TETCO,         |                  |               |                |
| Columbia**     |                  |               |                |
+----------------+------------------+---------------+----------------+
| ** Totals**    |                  | **200.4**     | **46.25**      |
+----------------+------------------+---------------+----------------+

Notes:

> 1 -- Mainline Block Valves located to meet the requirements of 49 CFR
> § 192.179.
>
> 2 - \* The Terminal Site comprises approximately 45 acres of upland
> area required for operation and has 35 acres of near-shore riparian
> rights area.
>
> 3- \*\* The land disturbed during construction at the Terminal Site
> includes the 45 acres required for operation plus the following:

-   Approximately 35 acres onshore for temporary workspace for laydown
    and staging areas (20 acre area to the north and 15 acre to the
    south of the Terminal Site);

-   Approximately 118 acres of aquatic areas affected by dredging and
    shoreline seawall construction activities associated with the LNG
    Terminal (including portions of the designated 35-acre of riparian
    rights area).

Additionally, an offshore area (identified in the table above and shown
on Figure 1.3-2 (sheets 1 and 2) and on Appendix Figures 1C-1 and 1C-3),
comprising existing marine and approach channels and waterfront area
west of the former shipyard, will be temporarily affected by the
dredging operations required to expand the shipping channel and turning
basin. Although this area already has been impacted by historic dredging
and ongoing maintenance dredging, the expansion will affect some areas
not dredged in recent history.

#### Pipeline and Access Road Facilities

For the Pipeline facilities, temporary construction facilities will
consist of contractor offices and trailers, pipeyards and construction
equipment yards; additional workspace and staging areas; and temporary
access roads. Permanent Pipeline facilities will consist of the
Pipeline, the permanent ROW, and permanent access roads. The land
requirements for these facilities are listed in Table 1.4-2.

**Table 1.4-2 Pipeline Facilities Summary with Land Requirements**

  ---------------- -------------------------- ---------------- --------------
  **Project        **Impact Type**            **Land Disturbed **Land
  Component**                                 During           Required for
                                              Construction**   Operations**

                                              **(acres)**      **(acres)**

                                                                

  **Mid-Atlantic   Temporary construction and 1,031.3          544
  Express          permanently maintained                      
  Pipeline**       workspace                                   

                   Additional temporary       215.2            0
                   workspace areas                             

                   Temporary access roads     41.4             0

                   Permanent access roads     (Included above) 1.4

                   Pipeyards, contractor      315              0
                   yards, offices/trailers                     

  **Mainline Block Construction workspace and Included in      
  Valves**         permanent operating area   aboveground      
                                              facilities Table 
                                              1.4-1            

  **(9                                                         
  locations)**                                                 

  **Interconnect   Construction workspace and Included in      
  -- 3 locations:  permanent operating area   aboveground      
  Transco, TETCO,                             facilities Table 
  Columbia**                                  1.4-1            

  **Totals**                                  **1,602.9**      **545.4**
  ---------------- -------------------------- ---------------- --------------

NOTES:

> 1-The Mid-Atlantic Express Pipeline temporary and permanent ROW are
> shown on the Project Alignment Sheets (in Appendix 1A).
>
> 2- Temporary Access Roads and yards (including pipeyards, contractor
> yards and trailers/offices) are shown on the Project Alignment Sheets
> and/or the USGS Topographic Quadrangle Maps (in Appendix 1A).
>
> 3- Anticipated locations of the temporary and permanent access roads
> used for calculating land disturbance. summarized above. A subset of
> these temporary access roads will converted to permanent access roads
> .

During construction, the standard width of the CROW will be 75 feet.
This width may be expanded or reduced depending on site requirements.
Typical cross section descriptions are shown on Figures 2a -- 2d in
Appendix 2B, and specific ROW width is shown on the alignment sheets in
Appendix 1A).

Temporary construction land requirements for the Pipeline facilities are
approximately 1,031 acres, not including the currently anticipated
access road locations, yards and CROW described above in Table 1.4-2.
The total land disturbed during construction will be approximately
1,602.9 acres. Permanent operational land requirements for the Pipeline
facilities are estimated to be approximately 545.4 acres, including
permanent ROW and access roads (as known to date).

### Aboveground Facilities

Permanent land requirements for aboveground facilities associated with
the Pipeline (such as interconnection tie-ins and mainline block valves)
are limited to the footprint of the specific aboveground facility and
sufficient area to secure the area around those facilities with fencing
and provide needed access. Additional land at these locations may be
required on a temporary basis during construction. The reasons for the
greater requirement would include the need for sufficient access and
adequate space for material laydown, equipment, and worker safety. The
approximate land requirements needed for aboveground facilities are
summarized in Table 1.4-1.

## Construction Procedures

The Project will be constructed in accordance with applicable
governmental regulations, permits, and approvals. Construction methods
will be those that are consistent with industry-recognized practices,
company policies, and BMPs. These are summarized in the following
subsections. More detailed descriptions of construction methods will be
prepared in construction specifications and drawings prior to the
commencement of work. Construction will be performed in accordance with
the FERC's recommended construction plans and procedures, unless more
stringent regulatory requirements apply, or in accordance with requested
variances if and as approved by FERC Staff. AES reserves the right, if
necessary, to request variances to the FERC's Upland Erosion Control,
Revegetation and Maintenance Plan and the FERC's Wetland and Waterbody
Construction and Mitigation Procedures (FERC's Plan and Procedures).
Currently, variances are not viewed as necessary. However, if deemed
necessary, variance requests made by AES will be in writing, and will
include the existing condition, the existing FERC requirement, the
requested variance, and a description of how the variance is believed to
be equivalent to or better than the existing requirement. AES's
Environmental Construction Plan (ECP) is included as Appendix 2A to
Resource Report 2, *Water Use and Quality*, and adopts the FERC's Plan
and Procedures, including additions or changes based on applicable state
requirements.

Construction procedures will vary due to a variety of reasons (e.g.,
type of work, contractor performing the work, existing site conditions).
To enforce compliance with the environmental mitigation measures
identified in this Resource Report 1, as well as in Resource Reports 2
through 13, as applicable, or as may be required by the FERC, such
measures will be incorporated, either directly or by reference, into
applicable plans, procedures, drawings and specifications developed by
AES and its contracted entities. The requirements, which will be used
throughout the life of the Project unless otherwise changed in
accordance with appropriate regulations, include, but are not limited
to, the following:

-   Dredging Management Plan, Resource Report 1, Appendix 1C;

-   Environmental Construction Plan, Resource Report 2, *Water Use and
    Quality* Appendix 2A;

-   Best Management Practices, Resource Report 2, *Water Use and
    Quality*, Appendix 2B;

-   Spill Prevention Control and Countermeasures Plan, Resource Report
    2, *Water Use and Quality*, Appendix 2C;

-   Unanticipated Discovery Plan, Resource Report 4, *Cultural
    Resources*, Appendix 4C;

-   Project Blasting Plan, Resource Report 6, *Geological Resources*,
    Appendix 6A; and

-   Emergency Response Plan, Resource Report 11, *Reliability and
    Safety*.

Project Environmental Inspectors will monitor activities relative to
these requirements.

A summary of agricultural and residential areas crossed, along with
proposed construction methods and mitigation procedures is discussed in
Resource Report 7, *Soils* (including Table 7.4-2). Wetland and
waterbody crossings, along with proposed construction methods and
mitigation procedures are discussed in Resource Report 2, *Water Use and
Quality* (including Tables 2.4-1 and 2.5-1). Supporting information
regarding CROW workspace, topsoil segregation, and construction
techniques is available in the BMPs in Resource Report 2, *Water Use and
Quality,* Appendix 2A.

### Construction of LNG Terminal and Pipeline 

An overall Project schedule is shown on Table 1.5-1. Assuming receipt of
all required regulatory approvals and permits, Pipeline construction is
planned to commence in early 2009, and to be completed in 2010. AES
expects the Pipeline work to be completed during one construction season
with the use of multiple construction spreads. If restoration is not
completed by the 15^th^ of November, a winterization plan will be
implemented to stabilize and monitor disturbed areas through the winter
and subsequent spring thaw. All restoration activities are planned to be
completed by no later than the year following construction. The CROW
will be subject to follow-up inspections of all disturbed areas after
the first and second growing seasons to determine the success of
revegetation. As described in Appendix 2A to Resource Report 2, *Water
Use and Quality*, AES will monitor and record the success of wetland
revegetation annually for the first three years after construction, or
until wetland revegetation is successful. Monitoring of restoration in
agricultural lands affected by the Pipeline will continue until crop
yields have returned to pre-construction productivity.

The crossing of environmentally-sensitive resources (e.g., waterbodies
with fisheries) and agricultural lands (i.e., topsoil management) will
be in accordance with state timing restrictions where applicable. This
may require the use of pipeline tie-in crews to work out of sequence
with the scheduled construction activities of a main construction
spread.

Assuming receipt of all required regulatory approvals and permits, the
LNG Terminal construction is planned to commence in 2008, and is
expected to be completed in the first quarter of 2011. Separate
construction crews are anticipated for the construction of the LNG
tanks, marine facilities, LNG process facilities and offshore dredging
activities; therefore, many of these construction activities will be
undertaken simultaneously.

#### LNG Terminal Onshore Facilities 

Construction of the tanks will include the following:

-   Site preparation;

-   Tank construction; and

-   Inspection and corrosion protection.

##### Tank Construction Overview

The initial site work will concentrate on the site improvement and
foundations for the storage tanks. The tanks will be supported on
concrete H-piles and topped with a pile cap.

After the tank pilings and H-pile cap base slab are complete,
construction will begin on the steel-lined, pre-stressed reinforced
concrete outer tank wall and the outer tank roof. After the steel outer
tank roof has been raised into position, the roof will be covered with
reinforced concrete. Insulation will be installed for the tank bottom
and then the nine percent nickel inner tank construction will begin.
Once the inner tank has been completed, a perlite insulation system will
be installed into the annular space between the inner and outer tank. A
suspended deck with insulation will sit above the inner tank to retain
the cold in the inner tank. Piping on the outside of the tank and the
tank roof will be installed during inner tank construction. The inner
tank will be hydrostatically tested after completion. Hydrostatic
testing procedures are described below. The outer tank will be
pneumatically tested per an approved procedure.

The "bulk" materials, including piping, insulation, electrical and
instrumentation, will be received on-site in order to meet the work
schedule. Subassembly (spooling) of pipe will begin as the pipe and
fittings are received. Mechanical, electrical and instrumentation work
will be concurrent with or closely follow pipe erection. Following the
completion of pipe testing, pipe painting (as needed) and insulation
will be conducted concurrent with electrical and instrument
installation.

As the process, mechanical, electrical and instrumentation work is
completed, pre‑commissioning activities will begin. Instruments will be
calibrated before loop checks of the electrical and instrumentation
circuits are completed. When the pre‑commissioning activities are
completed, the tanks and systems piping will be cleaned, hydrostatically
tested (as described below), dried and then purged with nitrogen. When
the Project is ready for the first shipment of LNG, the tank will be
purged of nitrogen gas and then cooled down using either LNG or
nitrogen. Use of LNG for cooldown will require a loaded LNG ship to be
furnished for approximately five days for the cooldown and subsequent
filling of the tank.

Equipment required for construction of the LNG Terminal will include
cranes ranging in size from 30-ton to 200-ton capacity, multiple
portable welding units, scaffolding, equipment trailers and
nondestructive test equipment. It is estimated that a maximum labor
force of approximately 325 on-site personnel will be required for each
tank and LNG system construction. Site improvements, construction of the
tanks and associated processing and delivery systems will take
approximately 32 - 34 months to reach commercial operations.

##### Hydrotest Procedure

The LNG tanks and piping at the Terminal Site will be hydrostatically
and pneumatically tested in compliance with the applicable codes that
govern the pipe and/or tank design. Water from the Patapsco River will
be used for the hydrostatic testing. Permits for water extraction and
release will be obtained as needed in each location tested, and
municipal sources will be used if no sources are available nearby. Each
LNG tank hydrotest is expected to require approximately 28 million
gallons (102,000 m^3^) of water. Hydrotest water will be filtered and
discharged in accordance with applicable permits. Following the
hydrotest, a potable water spray rinse (of approximately 100,000 gallons
(380 m^3^) per tank) will be conducted if seawater or brackish water is
used for the hydrotest. Potential withdrawal sources of hydrotest water
will be located during detailed design and engineering. Additional
details regarding the hydrotest procedure are provided in Resource
Report 2, *Water Use and Quality*.

##### Tank Painting and Corrosion Protection

The concrete outer tanks do not require a coating for corrosion
protection. Other exterior surfaces of the tanks will be provided with
corrosion protection by painting or galvanizing of all carbon steel
structures. The LNG storage tank structural steel will be painted with
the exception of the galvanized items.

##### Demolition, Site Filling & Ground Improvements

Demolition of selected structures existing at the Terminal Site will be
needed to prepare the site for construction. The shipyard formerly
consisted of ten slips used for ship construction and/repair. Slip
Numbers 1 through 5 are already demolished, and the area they occupied
is at a common grade. Portions of the remaining slips (Nos. 6 through
10) are used for hauling out and dismantling barges. Behind these slips
to the east, the site contains two large buildings, a metal sided
structure (known as the "Panel Building"), and a masonry structure (the
"Fabrication Building").

For development of the LNG Terminal, the remaining slip structures will
be demolished and the associated area leveled to the site's common
grade. The Panel Building will also be demolished. A new shoreward
bulkhead line will be established to straighten out the waterfront --
the approximate alignment of the new sheet pile bulkhead is shown in
Figure 1.3-2 (Sheet 2). Existing finger piers and low-level relieving
platforms that lie offshore of the new bulkhead alignment will be
removed as required.

Once the new bulkhead is established, additional fill may be added to
the Terminal Site to bring it to a consistent grade. Fill to bring the
site to grade will be obtained from the processed dredge material (PDM),
pending determination of engineering and environmental properties and
matching of the schedule between the dredge operations to initial
construction of the LNG Terminal. As described in Section 2.4.3 of
Resource Report 2, Water Use and Quality, AES has performed
environmental analysis of the proposed dredge area sediment as part of
the Terminal Site geotechnical investigations. The analysis performed to
date has indicated that the nature of contaminants that are present are
consistent with material dredged from other areas comprising the Port of
Baltimore (see Resource Report 2, Water Use and Quality). Elutriate
testing of sediment samples (also summarized in Resource Report 2, Water
Use and Quality) indicated no exceedance of water quality toxicity
criteria in the water elutriate, indicating that the dredge material,
untreated, is not expected to contravene water quality criteria. In
addition, the treatment methods used for dredge material recycling
utilize admixtures to both chemically and physically stabilize the
dredged sediment. Specific agents that are admixed (such as Portland
cement, pozzolanic materials, etc.) will be tailored to match sediment
makeup (grain size, moisture, etc.) and chemical quality so that the
recycled material produced meets physical properties for intended
application (like flowable fill or sub-base aggregate-type material),
and will not leach contaminants once it has been processed. AES will
perform additional sampling and characterization of the sediment in the
proposed dredge area, in accordance with COE dredge permit application
requirements (if required), to further characterize the levels of
contamination (if present). If required by permit conditions, this
additional sediment sampling and analysis will be performed during the
first quarter of 2008.

If required, AES will conduct the appropriate treatment of the sediment
at the DMRF discussed in Section 1.5.1.2.A below. AES will ensure that
PDM meets applicable environmental standards prior to use and placement
as fill material.

If the dredge material is found to be unsuitable for use based on
chemical or engineering properties, engineered soil fill for the
Terminal Site construction will be imported from a local commercial
source. Material will be obtained from a commercial source that can
provide documentation that the soil meets the engineering requirements
and does not contain environmental contaminants in quantities above
acceptable limits.

##### Buildings

The structures associated with the on-shore portion of the LNG Terminal
will include the existing Fabrication Building, which will be
refurbished to house the control room, administrative functions and
utilities; the compressor building; various other structures (fire pump
house, security building, etc.); and the potential future Power Plant.
Refurbishment of the Fabrication Building will include
repair/replacement of portions of the roof, removal of hazards, and
repair of interior foundations. Other site buildings will require new
construction, and will be constructed in accordance with code
requirements commensurate with their function. Where permitted,
buildings will be constructed on concrete slabs.

##### Foundations and Process Equipment 

The techniques used to construct the foundations for the associated
structures (those structures other than the LNG storage tanks) will
depend on the soil bearing capacity of the selected site. Options for
the foundations include the use of H-pile supports or spread footings.
Foundations will be constructed of reinforced concrete and designed
according to standard engineering practices. Foundations for all process
equipment and large machinery will be completed before the units arrive
on-site.

This scheduling reduces the need for temporary storage, extra movement
and lifting, all of which can damage the equipment. After the machinery
is set on its foundation, it will be leveled and shimmed before securing
the anchor bolts, with grouting being installed when required by the
equipment manufacturer. Final alignment of rotating equipment will be
performed after the final attachment of the pipe. After final alignment,
pre‑commissioning will begin with lubricant filling and initial
electrical energizing for motor "directional rotation" checks. The
systems will then be placed in service to support the balance of plant
start up activities.

##### Piping

Typically, pipe is pre‑fabricated in segments (spools), which allows
complicated pipe segments to be completed more easily and within weather
protected structures. AES expects to have some pipe spools fabricated by
a vendor off-site, and will also produce some pipe spools on-site.
Piping will be fabricated and installed according to ASME B31.3
standards. Installation will conform to the final design plans and
specifications. Welders will be qualified according to ASME Section IX.
For LNG and other cryogenic and flammable pipe services, the use of
flanges or other potential leak sources will be minimized in the design.

Shortly after any process equipment is set and secured to its
foundation, pipe attachment will begin. If the pipe is pre‑fabricated,
the final closure welds will not be completed until the equipment is
set, to prevent pipe connection misalignment.

Long lengths of pipe that are installed on a pipe rack and/or structural
supports often are installed "in position". The pipe is laid on the pipe
rack, after which temporary support rolls are installed so that the pipe
lengths can be "rolled" during jointing or welding. When the jointing
work on the long pipe rack lengths is completed the temporary support
rolls are removed. Hydrostatic or pneumatic testing of the pipe is
conducted as soon as valves and/or flanges are attached. All the
cryogenic piping will be pneumatically tested.

The pipe and mechanical installation work is expected to be performed at
many locations within the LNG Terminal at the same time. Scheduling of
the pipe work in an area is often determined by the deliveries of the
major process equipment. Pipe and plumbing work inside the buildings
will be included as part of the building construction, or will be
scheduled for installation concurrent with the building interior work.

##### Systems Painting and Corrosion Protection

Piping will be delivered to either the job site or subcontractor for
blasting and priming prior to erection on-site. Purchased items that
will be installed within a building will use manufacturer\'s standard
coating systems. The equipment to be located outside will have a coating
system that is compatible with the Project coating system and operating
environment.

##### Storm water Management System

Storm water will be pumped out of site impoundments and pass through an
oil-water separator prior to flowing into the existing water treatment
system. Other storm water collecting on the site will gravity flow to
the existing system. Discharges will be monitored and tested. Resource
Report 13, Engineering and Design Material, describes the storm water
system in detail in Section 13.7.6, and schematics are provided in
Appendices U.5 and U.6 of Resource Report 13, Engineering and Design
Material.

##### Roads, Curbs and Sidewalks

Road work is typically the last item to be completed. This work will be
scheduled after the heavy equipment (cranes, heavy haul trucks, etc.)
have completed their work, so as to avoid and minimize damage to the
roadways by heavy equipment. Most roadways will be paved.

#### LNG Terminal Offshore Construction 

Dredge equipment and support vessels (tugs and fuel tenders) will be
mobilized to the Terminal Site along with aboveground storage tanks for
fuel oil storage during the initial stages of site preparation. The fuel
storage tanks will arrive in a ready for placement condition and will be
installed and secured according to manufacturer's recommendation.

##### Dredging

Construction of the LNG Terminal will include widening and deepening the
existing approach channel and turning basin offshore of the Terminal
Site to accommodate the LNG ships expected at the LNG Terminal, which
will be larger than the ships that have utilized the existing shipyard,
floating dry dock and graving yard/coal channel (south of the proposed
Terminal Site) to date.

The Brewerton Channel, the existing approach channel, and certain areas
offshore of the proposed Terminal Site, have been dredged in the past
and currently are the subject of dredging permits issued by the COE and
a Water Quality Certification from the State of Maryland, allowing the
performance of dredging using hydraulic or mechanical techniques.
Dredging of the approach channel and areas offshore of the proposed
Terminal Site is allowed under these existing permits for maintenance
and waterfront operations, to a depth of -39 feet MLLW. In addition, on
May 6, 2005, the COE issued a permit to BWI-Sparrows Point LLC
(CENAB-OP-RMN \[BWI-Sparrows Point LLC/Dredging\] 04-64865-1),
approving:

-   mechanical or hydraulic dredging of a channel, turning basin, and
    berthing areas to -39 feet MLLW;

-   placement of approximately 600,000 cubic yards (CY) of dredge
    material at the Hart-Miller Island disposal site; and

-   Installation of sheet piling and construction of fendering systems.

The permit also approved a subsequent phase, consisting of the deposit
of approximately 2.6 million CY of dredge material at disposal sites yet
to be determined.

As described above, actual volume to be dredged and material handling
requirements may be less than discussed by this Resource Report 1
depending on bathymetric configuration of this area at the time of LNG
Terminal construction. The approach envisioned here has been developed
to anticipate dredge operations based on current bathymetry (i.e.,
bathymetry as of Spring 2006). AES has also allowed for methods that may
be needed if dredge volumes are greater than projected, and/or if the
environmental quality of dredge material in sections of the dredge area
is degraded relative to currently permitted dredge materials. AES will
follow procedures for dredge performance consistent with recent past
dredge approvals for this location, as updated based on data collected
for this project. AES has analyzed the existing sediment conditions in
the proposed dredge area as described in Section 2.4.3 of Resource
Report 2, *Water Use and Quality*. Additionally, AES has evaluated past
dredge practices, existing dredge technology, anticipated impacts and
proposed mitigation strategies, as described in Section 2.4.8 of
Resource Report 2, *Water Use and Quality*.

The approach channel expansions will be performed primarily by use of
mechanical clamshell dredge, or an environmental bucket technology if
required, with some limited areas near shore excavated by backhoe
dredge. Conventional mechanical dredge techniques will be used, or if
chemical analyses obtained for dredge planning indicate sediment quality
is more significantly degraded than is allowed by current dredge
permits, environmental dredge bucket removal or equivalent would be
used, as discussed in Section 2.4.8 of Resource Report 2, *Water Use and
Quality*. The limits of the existing approach channel and turning basin,
and proposed expansion area, are shown on Appendix Figures 1C-1 and
1C-3. A summary of the dredging proposed, and establishment of the
recycling facility appear below; additional detail appears in Appendix
1C.

> ***Dredged Material Recycling Facility***
>
> As part of the construction phase, AES will construct the DMRF
> adjacent to the existing waterway at the Terminal Site. This phase
> will precede actual dredging operations. The purpose of the DMRF is to
> process material excavated from the water bottom into one or more
> useful products that will be temporarily stored in a new location near
> the DMRF until transferred to the ultimate end users of the new
> product(s). Operation of the DMRF will not require onshore or
> unconfined placement of any dredge materials.
>
> The 10,000 CY per day DMRF will occupy approximately five acres of the
> 15 acres of upland property located immediately to the south of the
> Terminal Site (see Figures 1C-2 and 1C-3 in Appendix 1C). The DMRF
> will consist of two systems processing in parallel, each of which will
> include hoppers, conveyors, pugmills for mixing additives, and
> stacking equipment. Emissions from each pugmill and additive delivery
> system will be equipped with and controlled by separate baghouse
> dust-collection devices.
>
> Existing site roadways will be used to transport the PDM from the
> pugmill processing system to the temporary PDM storage area. The
> temporary PDM storage area will consist of an approximately 10-acre
> area (within the 15-acre upland area) covered by bituminous paving, or
> lined with a 10-mil high density polyethylene (HDPE) liner covered by
> 6- to 12-inches of existing site soil or imported soil. A scale house
> and truck scale will be located adjacent to the temporary PDM storage
> area for weighing of the outbound shipments of the PDM product upon
> sale. Existing site roadways will be used for outbound shipments of
> the PDM product.
>
> The DMRF and temporary PDM stockpile area will be graded as necessary
> and paved with bituminous concrete, and equipped with stormwater
> management controls tied to existing facilities.
>
> After civil work is completed, the DMRF will be erected at the
> Terminal Site. All components of the processing systems will be
> fabricated off-site and delivered via truck to the construction site.
>
> Operation of the DMRF will occur during the LNG Terminal construction
> phase, and processing will commence simultaneously with the
> commencement of dredging operations.
>
> An additional area, approximately 20 acres in size, is available for
> use as a contractor yard for LNG Terminal construction or to support
> the DMRF facility, as needed for PDM or equipment storage. If utilized
> to support the DMRF operations, the site will be prepared consistent
> with the description above (e.g., paved, stormwater controls, etc).
> This 20-acre area is located north of the Terminal Site as shown
> (labeled Temporary Equipment Laydown and Storage Yard) on Figure 1.3-2
> (Sheet 2).
>
> ***Dredging Operations***

Dredging associated with the LNG Terminal is anticipated to begin in the
berthing area, and progress in reaches towards the outer channel to
allow for earlier commencement of pier/dock construction operations. The
anticipated limits of the area to be dredged are shown on Figures 1.3-2
(Sheet 1) and 1C-3. Assuming the anticipated dredged channel and turning
basin depth of 45 feet, it is estimated that approximately 3.5 to
4.0-million CY of dredged material will be generated for recycling.
Maintenance dredging under current permits may decrease this amount
somewhat, depending on the amount of dredging performed prior to LNG
Terminal construction in areas of overlap.

Dredging will be conducted utilizing a mechanical (clamshell) dredge, or
if conditions warrant, with an environmental bucket or suitable
alternative if required by permit condition, as further discussed in
Section 2.4.8 of Resource Report 2, *Water Use and Quality*. A
directional Global Positioning System (GPS) will be used to locate the
channel limits and to identify shoaled areas. Sediment will be removed
to the design depth of 45 feet below MLLW. Computer-controlled recording
software will track the progress of the dredging and will ensure
complete coverage of the area to be dredged.

Dredging production is expected to be up to 10,000 CY per day, and
operations are expected to last approximately 24 months. It is
anticipated that ten to fourteen 1,500 to 3,500-CY work scows will be
used. All scows and containers will be of solid hull construction, and
will be completely sealed and watertight in order to avoid any release
of dredge material.

> The initial step in processing dredged materials is the reduction of
> the water content of the dredged sediments. The proposed dewatering
> process would involve dewatering of loaded barges at the dredging site
> or the DMRF. Loaded scows would be allowed to settle so that the
> free-liquid portion would be visibly free of suspended sediments prior
> to pumping the decant water to the cargo area of a dedicated
> dewatering barge. After settling, the decant water will be discharged
> within the area of dredging after testing for suspended solids or as
> required by permits. Alternately, after the initial barge settling
> period, portable pumps will be utilized to pump the water to land
> based tanks (i.e. frac tanks) for additional settling. All decant
> water from dewatered dredged material at the DMRF will pass through a
> settling tank system and filter prior to discharge back to the harbor.
> Chemical and physical analysis will be conducted on the decant water
> in accordance with an MDE Water Management Program Individual Permit
> for Industrial Water Discharge that will be issued for the DMRF.
> Threshold values for discharge will be set forth in that permit.
> Following this secondary settling, the water will be filtered and
> discharged under applicable permit conditions. If chemical analysis
> indicates the presence of contaminants in the water, at concentrations
> in excess of allowable regulatory limits, options for onsite treatment
> prior to discharge or offsite treatment and disposal will be
> evaluated. If feasible, the water will be treated to meet applicable
> Federal, State and/or local standards prior to discharge.
> Alternatively, offsite disposal options may be utilized and include
> the local Publicly-Owned Treatment Works (POTW) or a
> privately-operated treatment, storage, disposal (TSD) facility. AES
> has identified three offsite facilities that may potentially be able
> to accept the contaminated water, if required. These potential sites
> include Clean Harbors Baltimore, MD; Veolia Environmental Services
> (VES) York, Pennsylvania; and Waste Management Industrial Services,
> Crofton, MD.
>
> After raking, the raw dredged material will be stevedored from the
> work barges directly into a pugmill processing system utilizing
> hydraulic excavator(s) equipped with hydraulic closed clamshell
> bucket(s). At no time will the raw dredged material be stored on the
> Terminal Site or elsewhere. The screened raw dredged material will be
> fed to a twin-shaft pugmill blending system and mixed with reagent
> admixtures. After mixing, the PDM will empty from the pugmill onto a
> radial stacking conveyor. The "radial stacker" can be positioned to
> load directly into trucks, or to stockpile the material for
> re-handling to trucks, railcars, or back to hopper scows.
>
> Following processing, the PDM will be transported via on-site trucks
> to the designated staging area within the permitted temporary storage
> site. The PDM will be placed using hydraulic excavators, bulldozers
> and vibratory compactors into large stockpiles for temporary storage
> in inventory until the material is sold for beneficial use.
>
> The PDM will be trans-loaded by wheel loaders or hydraulic excavators
> into road trucks for off-site shipment to ultimate destination sites.
> While dredging production and dredged material processing will be at a
> rate of 10,000 CY per day, transportation offsite of PDM will be at a
> rate of 5,000 CY per day. The schedule to remove PDM is twice as long
> as the schedule for dredging and processing. AES anticipates
> approximately 220 truck trips a day hauling PDM off-site (assuming 276
> hauling days per year). This equates to approximately 5,500 tons of
> PDM shipped off-site daily. Alternatively, PDM may be transported by
> rail car (capacity per rail car is approximately 98 to 108 tons), or a
> combination of trucking and rail car to its destination; each rail car
> would transport the same volume as four to five trucks.
>
> Potential uses for the PDM include:

-   Abandoned mine land and quarry reclamation;

-   Brownfields redevelopment;

-   Landfill capping and closure;

-   Alternate grading materials;

-   Low permeability cap layer in lieu of geo-membrane systems;

-   Manufactured top soil;

-   General structural and non-structural fill for commercial /
    industrial development; and

-   Bulk construction fill, including site grading material and highway
    embankments.

> While AES has not identified the specific applications for the re-used
> dredged material at this time, all of the uses listed above have been
> demonstrated as both technically and commercially viable in other
> similarly-affected port/harbor sediments and settings, and regulatory
> jurisdictions. Final determination of the application(s) will be made
> prior to initiation of the dredging activities and will depend on
> market needs and conditions at that time. Because the Project proposed
> by AES is a private, non-governmental, venture, all costs associated
> with the dredging and delivery of the recycled product(s) will be
> carried by AES.
>
> Further details and specifications regarding dredging, equipment,
> schedule, spoils handling and processing is provided in Appendix 1C -
> Dredging Management Plan.
>
> Other potential options for management of dredged material include
> off-site disposal, open ocean disposal at approved off-shore
> locations, and upland fill sites, as described in Section 10.5.2 of
> Resource Report 10, *Alternatives*. All of these potential options
> also depend on the chemical makeup of the dredged material, receipt of
> approvals from applicable agencies and, in some cases, approval by the
> receiving facility(s). These other alternatives are not currently
> considered to be as viable as the recycling alternative, and they are
> not as consistent with the Port of Baltimore's long term goals for
> management of dredged material as the recycling option.

##### LNG Berths

> The construction process for the LNG ship berths will include the
> rehabilitation of an existing pier, installation of an elevated
> unloading platform, and the installation of an elevated pipeway and
> associated spillway.
>
> Pier rehabilitation will include the concrete encasement, and/or
> splicing of the existing piles, repairs to the concrete cap, and
> repairs/resurfacing of the existing concrete deck. The repairs to the
> piles and caps will take place from floating construction barges. The
> floating construction barges provide the ability to be repositioned as
> required in the working area in order to provide uninhibited access to
> the items being repaired, ensuring that proper construction techniques
> can be utilized.
>
> Pre-cast concrete elements for the unloading platform, pipeway and
> associated spillway will be set into place via crane, which will be
> located either on floating construction barges or the existing pier,
> pending space availability. The floating construction barges will be
> anchored into place with spud piles. These construction barges provide
> the ability to be repositioned as required in the working area in
> order to provide uninhibited access to the item under construction,
> ensuring that proper construction techniques can be utilized.
>
> The cast-in-place concrete elements to support the deck
> rehabilitation, unloading platform, pipeway and associated spillway
> will be constructed from floating construction barges or landside, as
> space allows. As noted for the precast elements and pier repairs,
> floating construction barges will provide the ability to be
> repositioned as required in the working area in order to provide
> uninhibited access to the item under construction, ensuring that
> proper construction techniques can be utilized.
>
> Once the rehabilitation of the pier deck has been completed, the
> elevated steel structure will be built to support the unloading
> platform, pipeway and spillway. This construction will take place from
> the land side; however, the final setting of the unloading arms will
> take place from a construction work barge.

##### Bulkhead-Sheet Pile Installation

> A king pile steel sheet pile bulkhead will be installed along the
> western limits of the upland facility. The steel sheets will be driven
> with either a vibratory or impact pile driving hammer. Where
> accessible, the piles will be driven from land based rig. In locations
> where access is from the waterside only, the piles will be driven by a
> rig based on a floating construction barge. The barge can be anchored
> into location with spud piles to provide a stable working area.
> Templates will be used to ensure that the sheet piles are driven in
> the proper location, and that plumbness is maintained within
> acceptable limits.

#### Pipeline Facilities 

AES anticipates that the construction of Pipeline facilities within one
construction season will require multiple construction spreads. Each
spread will utilize standard overland pipe lay construction techniques
for similarly-sized pipe diameters. Construction will take place within
approved workspace limits. Each spread will generally follow a set of
sequential construction phases, outlined below, and proceed along the
CROW in a continuous operation. Typical construction techniques for
specific elements (such as waterbody or road crossings) are provided in
BMP Figures located in Appendix 2B. Information regarding the
construction controls and restoration techniques are included in the
Sparrows Point Project ECP, which is based on the FERC Upland Erosion
Control, Revegetation and Maintenance Plan and FERC Wetland and
Waterbody Construction and Mitigation Procedures. The Project ECP is
located in Resource Report 2, *Water Use and Quality*, Appendix 2A.

An annual average of 200 workers is anticipated to be employed for
direct Pipeline construction. Crews associated with a spread will vary
depending on the selected contractor and execution plan prepared, but
elements normally include the following:

##### Surveys & Marking ROW 

> Surveys will be completed to identify the Pipeline centerline,
> exterior CROW limits, and areas where ATWS is needed. Once surveyed,
> locations along the CROW will be marked (e.g., flagged, staked). In
> addition to centerline and limit surveys, other resources will be
> identified along the route. These will include environmental and
> archaeological resources; geologic and topographic features;
> land-types and uses; other utility crossings (e.g., pipelines, power
> lines, railroads, and other wires/cables); agricultural land and
> drainages; and access roads. Information surveyed to date has been
> incorporated in the Alignment Sheets (Appendix 1A), and where
> properties do not become accessible during project development, the
> surveys will be completed as soon as access is available, and that
> information will be provided to the FERC. Surveys for design and
> construction purposes will be performed separately as needed.
>
> Prior to construction the centerline and corridor limits of the CROW
> will be marked (e.g., flagged, staked) to support the construction and
> environmental inspection activities. The CROW marking will include
> ATWS areas, access roads, and environmentally- or culturally-sensitive
> features (e.g., wetlands, waterbody crossings, archaeological
> avoidance areas, etc).

##### Clearing and Grading

> The Pipeline CROW will be cleared of vegetation. A combination of
> heavy equipment and sawyers will be used to remove large trees, heavy
> brush, and small trees, but ground cover (i.e., including bushes) may
> remain until grading is required. Grading creates a safe working
> platform to construct project facilities. Marketable timber cleared
> from the CROW will be managed in accordance with the landowners'
> agreements, and other timber may be given back to the landowner (e.g.,
> for fire wood), used as timber riprap in wetland crossings, or
> properly disposed of as construction debris (e.g., burned, chipped or
> hauled to an approved disposal site). Displaced soils normally will be
> stockpiled along the CROW to minimize the need and potential impact of
> additional haul vehicles. However, in locations where the CROW is
> restricted, these soils may be stockpiled at a different location. In
> areas where topsoil segregation is required, topsoil will be
> segregated and stockpiled in such a manner that it is conserved and
> can be returned to the CROW.
>
> To manage stormwater surface flow, regular breaks (gaps) in windrowed
> spoil piles and diversion structures will be used to manage cross
> drainage needs. Gaps in windrowed spoil (and topsoil piles) will allow
> surface water to migrate across the CROW in such a way as to minimize
> up-gradient flooding and downstream sedimentation. Gaps will be
> located at regular intervals and/or where appropriate due to site
> conditions (e.g., depressions in terrain where water will likely
> concentrate).

##### Trenching 

> Trenching will be accomplished with backhoes and/or mechanical
> trenching machines. Under typical conditions, the average trench depth
> will be no less than 60 inches, to accommodate the 30-inch diameter
> pipeline and 36-inches of cover. In agricultural areas and at certain
> crossings (e.g., roads, waterbodies), the trench depth will be greater
> in order to achieve the greater depth of cover requirements. The
> trench width will vary based on site conditions (e.g., soil types,
> bedrock, and presence of groundwater). In areas where shallow bedrock
> and/or large boulders are present, specialized construction techniques
> to remove the rock may be necessary (e.g., blasting, rock hammer).
> Blasting is discussed in the Specialized Construction Methods and
> Crossings section below.
>
> Similar to grading activities, considerations for cross drainage will
> be made while trenching and where stormwater runoff flows are a
> concern. Flume pipe (e.g., appropriately sized steel, polyvinyl
> chloride \[PVC\], or iron piping) or diversion berms/ditches may be
> used where needed to direct stormwater across the trench and away from
> the CROW. Inlet and outlet structures may also be necessary to prevent
> erosion and scouring. Additionally, on sloping terrain, a combination
> of trench plugs may be used to prevent water from scouring the bottom
> of the trench line. Trench plugs are made of earthen material and can
> be characterized as soft or hard. Soft plugs will be excavated and the
> spoil re-compacted in the trench. Hard plugs will not be excavated.

##### Pipeline Laying 

##### 1. Pipe Stringing and Bending {#pipe-stringing-and-bending .unnumbered}

> Sections of line pipe (joints) will be strung along the CROW and
> adjacent to the trench, set on wooden supports (skids), and arranged
> so they are safely accessible to construction personnel. Joints vary
> in length and can be individual (i.e., a single length of pipe) or
> double-jointed (i.e., two lengths of pipe pre-welded offsite). Pipe
> joint lengths from the mill can vary from 40 to 80 feet, and can be
> cut as needed in the field. Depending on CROW requirements and
> restrictions, some pipe bends may be pre-manufactured at the pipe mill
> (factory bends). For all other bends (field bends), a mechanical
> pipe-bending machine will bend joints to the desired angle at
> locations where there are unique changes in the natural ground
> contours.

##### 2. Pipe Assembly and Field Welding {#pipe-assembly-and-field-welding .unnumbered}

> After the stringing and bending are complete, pipe sections will be
> aligned and welded together. All welding will be performed in
> accordance with the Project's Welding Procedure Specification (to be
> developed during design of the Project), by qualified welders who have
> passed specified qualifying tests. Welders and welding procedures will
> be qualified according to applicable American National Standards
> Institute (ANSI), American Society of Mechanical Engineers (ASME), and
> API standards.

##### 3. Nondestructive Examination, Inspection, and Weld Repair {#nondestructive-examination-inspection-and-weld-repair .unnumbered}

> All welds will be inspected (100 percent), both visually and by
> nondestructive examination (NDE). Visual inspection will be carried
> out on all welds to check for imperfection(s) that can be seen with
> the naked eye. Weld imperfections will be rejected and repaired upon
> identification (i.e. before NDE). Welds will then be inspected using
> the NDE process (i.e., x-ray examination) for imperfections that are
> not visible with the naked eye. The NDE acceptance criteria will be in
> accordance with API 1104. The USDOT regulations (49 CFR §§ 192.241,
> 243) includes the minimum NDE inspection requirements of 100 percent
> in Class 3 and 4 areas and at major crossings, which includes all of
> the Pipeline.
>
> Detailed records of all welds, including successful welds, welds that
> are repaired, and those that are cut-out, will be maintained for each
> weld as it is completed. The records will include identification
> serial number; the location of the weld; the date it was produced,
> qualified procedure reference number; welders' names, and reference
> numbers. These records will be maintained in the permanent files
> associated with the Project.

##### 4. Pipe Coating, Inspection and Repair {#pipe-coating-inspection-and-repair .unnumbered}

> Line pipe will be coated to protect it from the environment and
> accelerated degradation. Line pipe is normally mill-coated or
> yard-coated prior to stringing. However, line pipe also requires a
> coating at the field welded joints where bare metal has been exposed.
> Prior to lowering the pipeline segment into the trench, the pipeline
> coating will be visually and electronically inspected to locate and
> repair coating faults or voids.

##### Backfilling 

##### Once the welds and coating have passed inspection, and just prior to lowering-in, the trench will be checked for sharp edges that could damage the pipe, and/or its coating during installation, i.e., "crumbing" the line. Next, sand bags with clean fill will be placed along the trench bottom to support the pipe allowing the padding material to sufficiently surround the pipe. In areas where the backfill has the potential to damage the coating, the pipe will be wrapped in rock shielding material to provide additional protection.  {#once-the-welds-and-coating-have-passed-inspection-and-just-prior-to-lowering-in-the-trench-will-be-checked-for-sharp-edges-that-could-damage-the-pipe-andor-its-coating-during-installation-i.e.-crumbing-the-line.-next-sand-bags-with-clean-fill-will-be-placed-along-the-trench-bottom-to-support-the-pipe-allowing-the-padding-material-to-sufficiently-surround-the-pipe.-in-areas-where-the-backfill-has-the-potential-to-damage-the-coating-the-pipe-will-be-wrapped-in-rock-shielding-material-to-provide-additional-protection. .unnumbered}

##### The welded pipe section to be lowered-in is typically placed into the trench with pipe slings and side-boom tractors. Once the pipe is lowered, trench breakers will be installed on sloping terrain and/or at sensitive environmental crossings, to prevent the subsurface conveyance of water which could create void space and subsidence or drain environmental features. Clean fill (e.g., soil, sand) will be used where needed as padding material to provide protection to the pipe and coating. The material used for padding will be selected in accordance with permit conditions and project engineering specifications, and under no circumstances will topsoil be used as padding or backfill material. The trench will then be rough backfilled using backfilling equipment (e.g., bulldozers, track hoes) to protect the pipe until final restoration can be completed. No foreign materials (e.g., construction debris) will be permitted to be used as backfill material. If allowed by permit conditions and landowner agreements, excess rock and woody debris (e.g., stumps, brush) may be buried onsite within the CROW, or windrowed along the edge of the CROW. Otherwise, these materials will be properly disposed of off-site as construction debris. {#the-welded-pipe-section-to-be-lowered-in-is-typically-placed-into-the-trench-with-pipe-slings-and-side-boom-tractors.-once-the-pipe-is-lowered-trench-breakers-will-be-installed-on-sloping-terrain-andor-at-sensitive-environmental-crossings-to-prevent-the-subsurface-conveyance-of-water-which-could-create-void-space-and-subsidence-or-drain-environmental-features.-clean-fill-e.g.-soil-sand-will-be-used-where-needed-as-padding-material-to-provide-protection-to-the-pipe-and-coating.-the-material-used-for-padding-will-be-selected-in-accordance-with-permit-conditions-and-project-engineering-specifications-and-under-no-circumstances-will-topsoil-be-used-as-padding-or-backfill-material.-the-trench-will-then-be-rough-backfilled-using-backfilling-equipment-e.g.-bulldozers-track-hoes-to-protect-the-pipe-until-final-restoration-can-be-completed.-no-foreign-materials-e.g.-construction-debris-will-be-permitted-to-be-used-as-backfill-material.-if-allowed-by-permit-conditions-and-landowner-agreements-excess-rock-and-woody-debris-e.g.-stumps-brush-may-be-buried-onsite-within-the-crow-or-windrowed-along-the-edge-of-the-crow.-otherwise-these-materials-will-be-properly-disposed-of-off-site-as-construction-debris. .unnumbered}

##### Testing 

> Prior to commissioning, the Pipeline will be pressure hydrotested in
> accordance with engineering specifications and regulatory approvals.
> Proposed sources of test water are discussed in Section 2.4.5 of
> Resource Report 2, *Water Use and Quality*. The Pipeline will then be
> tested in sections to a pressure in excess of the MAOP for a specified
> period of time. Test sections will be determined by pipe wall
> thickness and elevation changes. Once the test of a section is
> successfully completed, water will be re-used to the extent possible.
> The test water will be discharged in accordance with regulatory and
> permitted requirements. Details regarding the testing, segments and
> water withdrawal/discharges are summarized in Resource Report 2,
> *Water Use and Quality*, Appendix 2F, the Mid-Atlantic Express (MAE)
> Pipeline Hydrotesting and Pre-Commissioning Plan.

##### Restoration and Cleanup 

> Cleanup of Pipeline activities will include removing construction
> debris (i.e., including un-used and surplus materials), temporary
> construction structures, and equipment. Restoration will consist of
> returning the CROW and areas disturbed by construction activities to
> pre-existing contours and hydraulic regimes. Normally, final
> restoration occurs within 10 to 20 days of rough backfilling.
> Permanent erosion and sediment controls will be installed (e.g.,
> waterbars on sloping terrain), and the CROW will be re-seeded and/or
> mulched per permit requirements and landowner agreements. Pipeline
> markers will then be installed. Soil adjuncts and fertilizers may be
> added where necessary. Temporary erosion controls will be removed when
> the area has been stabilized in accordance with applicable permit
> requirements. The revegetation will be monitored for at least two
> growing seasons following final restoration.

##### Special Construction Techniques, Crews or Work Areas

> In addition to the standard construction practices listed above, the
> following special construction methods and crossings are likely to
> occur throughout the construction phase.

##### 1. Tie-In Crews {#tie-in-crews .unnumbered}

> Tie-in crews are normally self-sufficient crews that work in tandem
> with the construction spread. They have equipment, welders, and labor
> to perform a specialized task (e.g., waterbody/wetland crossing, road
> crossing). Tie-in crews are also used in areas that will normally
> slow-down the main spread, or in locations that have been skipped for
> temporary lack of access.

##### 2. Additional Temporary Workspace {#additional-temporary-workspace .unnumbered}

> ATWS will be needed at locations requiring additional excavation; soil
> placement requirements; or staging of additional equipment and/or
> materials. Examples include:

-   Road and railroad crossings,

-   Wetland and waterbody crossings,

-   Areas with steep slopes (greater than 25 percent) and side hills,

-   Areas requiring topsoil segregation (e.g., agricultural lands),

-   Equipment turnarounds and spread move-arounds,

-   Hydrotest fill and spill locations and test locations,

-   Pipeline crossovers,

-   HDD entry and exit points (i.e., including false CROWs), and

-   Equipment and material staging areas.

> The size and configuration of an ATWS is dependent upon its purpose as
> well as the existing site conditions (e.g., available and/or
> accessible space, nearby resources) at each proposed work location.
> Proposed ATWS locations, including dimensions and purpose, are shown
> on the alignment sheets in Appendix 1A, and are listed in Resource
> Report 8, *Land Use, Recreation, and Aesthetics*. ATWS locations are
> shown on the Project Alignment Sheets (Appendix 1A) and are included
> in the total acreage area to be affected by construction, as shown in
> Table 1.4-1.

##### 3. Temporary Construction Facilities {#temporary-construction-facilities .unnumbered}

> Temporary construction facilities will include contractor offices;
> pipeyards and laydown areas; warehouses and equipment and material
> staging areas; and fabrication areas. The number, size, and location
> of these facilities will depend on the location of the Pipeline Route,
> route accessibility, local infrastructure, and the general
> construction implementation plan. Upon completion of construction
> activities, areas used for temporary construction facilities will be
> restored to pre-existing conditions or better. Temporary construction
> facility locations are shown on the USGS Topographic Maps (Appendix
> 1A) and are included in the total acreage area to be affected by
> construction, as shown in Table 1.4-1

##### 4. Access Roads {#access-roads .unnumbered}

> Access roads will be necessary during construction activities to
> provide temporary access to the CROW in addition to public road
> access. To the extent possible, existing access roads will be used for
> this purpose. In some instances, improvements will be necessary (e.g.,
> widening and reinforcing). Once temporary access roads are no longer
> necessary, they will be returned to their as-found condition or
> better, subject to the requirements of applicable permits and
> landowner agreements. Access roads will be designed and constructed in
> accordance with local and state standards and codes (e.g., with
> respect to specifications, materials, adequate drainage). Access road
> locations are shown on the Project Alignment Sheets (Appendix 1A) and
> are included in the total acreage area to be affected by construction,
> as shown in Table 1.4-1

##### 5. Road and Railroad Crossings {#road-and-railroad-crossings .unnumbered}

> The proposed Pipeline Route crosses major roadways and railroads along
> which, in some instances, traffic cannot be interrupted. These will be
> crossed by using trenchless construction techniques. These techniques
> include boring (see Appendix 2B, BMP 14) and/or HDD (see Resource
> Report 2, *Water Use and Quality*, Site Specific Crossing Plans in
> Appendix 2B-2 for details on HDD) crossings. AES anticipates using
> bores for road and railroad crossings except where, following
> consultation with the appropriate authority (e.g., town, county, local
> railroad), an open-cut crossing (see Resource Report 2, *Water Use and
> Quality*, Appendix 2B, Figure 14) is determined to be feasible. Minor
> roadways and drives will be crossed by open trenching. Once completed,
> roadways will be restored in accordance with engineering
> specifications, to pre-construction conditions or better. Furthermore,
> when construction activities occur within public roadways, provisions
> will be made for appropriate signage and, when necessary, temporary
> detours or other traffic control measures to allow safe traffic flow
> during construction.

##### 6. Wetland and Waterbody Crossings {#wetland-and-waterbody-crossings .unnumbered}

> The proposed route for the Pipeline has been selected to avoid or
> minimize where practicable impacts to wetland and waterbody areas
> located in the vicinity of the Project Area, as described in Resource
> Report 2, *Water Use and Quality*, and Resource Report 3, *Fish,
> Wildlife, and Vegetation*. Construction in these areas will be
> performed in accordance with the FERC's Wetland and Waterbody crossing
> procedures and applicable permit conditions, unless more stringent
> regulatory requirements apply or in accordance with variances
> requested in this application. Further discussion of wetland and
> waterbody areas and resources in the vicinity of the Project Area is
> included in Resource Report 2, *Water Use and Quality*, and Resource
> Report 3, *Fish, Wildlife and Vegetation*. A copy of the FERC's
> Wetland and Waterbody crossing procedures (along with any requested
> modifications) is attached to Resource Report 2. BMPs for water body
> crossings (BMP 17, 18, 18a, and 19), wetland crossings (BMP 23 and 24)
> and site specific waterbody crossings are provided in Appendix 2B of
> Resource Report 2, *Water Use and Quality.*

##### 7. Dewatering {#dewatering .unnumbered}

> Dewatering activities may be necessary to remove excess water from the
> trench line during periods of excessive precipitation or high water
> table. Dewatering activities will be performed in accordance with
> AES's BMPs or the Project ECMP (based on FERC's Plan and Procedures).
> Under no circumstances will heavily silt-laden waters be directly
> discharged into wetlands or waterbodies (see BMP 20 for typical filter
> bag usage). To the extent possible, discharges will occur in
> well-vegetated uplands areas on stable, non-erosive surfaces. If
> dewatering locations are selected that are not within or immediately
> adjacent to the CROW, they will be sited to avoid and minimize
> off-CROW impacts. If dewatering locations must occur within sensitive
> areas (e.g., designated wetland areas), prior approval will be sought
> and (if approved) multiple sediment controls will be used consistent
> with the ECP to prevent adverse impacts. A copy of the Project ECP is
> attached to Resource Report 2, *Water Use and Quality*, Appendix 2A.

##### 8. Agricultural Crossings {#agricultural-crossings .unnumbered}

> In selecting the Pipeline Route, AES considered avoidance, to the
> extent feasible, of sensitive soils that are of high agricultural
> value. Inquiries have been initiated with landowners and agricultural
> agents to determine the locations and configuration of drain tiles and
> other important features (diversion ditches, etc.) to avoid or
> accommodate during construction. AES will continue to work actively
> with landowners to identify site conditions (i.e., to include drain
> tiles and header systems) crossed by Pipeline facilities, so that
> impacts and disruptions can be avoided and minimized to the extent
> feasible. Topsoil will be segregated and restored consistent with the
> ECP and BMPs (BMP 3) in Resource Report 2 Appendices 2A and 2B, and
> guidance provided by the Pennsylvania and Maryland State Departments
> of Agriculture, as appropriate. Additionally, AES will, during
> construction, locate drain tiles in fields which are affected, and
> repair any that are damaged by construction to as-found condition or
> better, in accordance with the Project ECP. Resource Reports 7,
> *Soils*, and 8*,* *Land Use, Recreation and Aesthetics*, include more
> detailed descriptions and locations of agricultural crossing
> procedures (Table 7.4-2).

##### 9. Residential Crossings {#residential-crossings .unnumbered}

> The Pipeline Route has been selected to avoid residential areas to the
> extent possible. Where unavoidable, construction in residential areas
> (i.e., where construction activities and/or the edge of the CROW are
> located within 50 feet or less of an active residence) will be
> accomplished by employing additional restrictive measures including
> restricting the CROW width. AES will coordinate with residence owners
> and/or tenants prior to construction activities. Additional safety
> precautions will include: erecting barricades (e.g., standard orange
> barricade fencing), welding off site, controlling fugitive dust, and
> reducing the duration of the open trench. The occurrences where the
> CROW is within 50 feet of a residence is provided on Table 8.4.3-1 in
> Resource Report 8, *Land Use, Recreation and Aesthetics*, along with
> proposed mitigation steps to be taken in these areas.

##### 10. Stovepipe Construction {#stovepipe-construction .unnumbered}

> Stovepipe construction is typically used where the pipeline is
> installed close to an existing structure or when an open trench will
> adversely impact a residential, commercial, or industrial area.
> Stovepiping involves installing the pipeline one joint at a time (or
> double-jointed) whereby the welding, radiography, and coating
> activities are all performed in the open trench. At the end of each
> day, the newly-installed pipe is backfilled or the open trench is
> covered. The length of excavation performed each day will not exceed
> the amount of pipe installed. Further discussion of construction
> techniques for constrained workspace areas, such as Stovepipe
> Construction, is provided in Section 8.4 and 8.5 of Resource Report 8,
> *Land Use, Recreation and Aesthetics.*

##### 11. Blasting {#blasting .unnumbered}

> It may be necessary to perform blasting in areas with shallow bedrock.
> Before a decision is made to blast, AES will investigate other rock
> excavation techniques including rock saws, hydraulic hoe hammers and
> ripper teeth. Where blasting is the necessary method to remove shallow
> bedrock, the work will be performed by licensed contractors utilizing
> appropriate safety precautions. Blasting Procedures will include:
> notification requirements, controls to prevent and/or minimize
> fly-rock, and procedures to minimize environmental impacts. Resource
> Report 6, *Geological Resources*, contains additional information on
> blasting procedures and a summary of anticipated areas of shallow
> bedrock. Specific details regarding blasting procedures will be known
> after the construction contractor(s) have been selected and have had
> an opportunity to review blasting locations and propose method(s)
> based on site-specific evaluation. Areas with the potential for
> shallow bedrock and where potential blasting construction techniques
> may be utilized is provided on Table 6.3-1 in Resource Report 6,
> *Geological Resources.*

##### 12. Trenchless Techniques {#trenchless-techniques .unnumbered}

> Trenchless construction techniques include boring, pipe-jacking, and
> HDD, which are further described in Resource Report 2, *Water Use and
> Quality* (locations of planned HDD crossed waterbodies are provided on
> Table 2.4-1). Trenchless methods allow the installation of the
> pipeline with minimal impacts or disturbance to surficial features.
> Boring techniques are regularly used when crossing transportation
> features that cannot be disrupted (e.g., roadways, railroads). HDDs
> may be used when re-routing alternatives are limited and other
> trenching and trenchless techniques are not feasible. AES anticipates
> using bores for road and railroad crossings, unless an open-cut
> crossing is allowed by the roadway authority.
>
> Specific crossings (Back River at MP 9 and Susquehanna River at MP 44)
> are planned as HDD crossings; however, specific geotechnical
> investigations and engineering reviews are planned to assess
> feasibility of such HDD crossings. In addition, the National Marine
> Fisheries Service has requested evaluation of HDD crossing at limited
> additional locations (e.g., Gunpowder Falls, Deer Creek, and the
> Octoraro River). The geotechnical investigations of Back River and the
> Susquehanna will be completed prior to completion of detailed design
> and construction. A summary of the investigation results will be
> provided to FERC when available.

### Aboveground Facilities

The aboveground facilities proposed for the Pipeline include a pressure
reduction facility (including metering and regulation equipment) located
at the LNG Terminal, nine mainline block valve facilities for the
Pipeline, and three interconnection tie-in locations with the Columbia,
Transco, and TETCO systems. In addition, one or more interconnects with
local utility systems or others are possible. The construction of
aboveground facilities is discussed below.

#### Clearing and Grading

Proposed aboveground facility locations will be cleared and graded to
the extent necessary to install the facility and provide a level
platform and sufficient space to execute the work safely. Onsite
material will be used as structural backfill where permitted by
engineering specifications. If necessary, clean imported structural
backfill material will be used if a sufficient amount of onsite material
does not exist. Areas temporarily disturbed by construction activities
will be restored to pre-existing conditions or better. Some site
modifications (e.g. re-contouring) may be required to provide sufficient
drainage and site access. Construction activities at the aboveground
facilities will be completed in accordance with measures specified in
the Project ECP.

#### Foundations and Structures

Foundations will be designed primarily of reinforced concrete with an
appropriate strength rating to support planned loads based upon current
geotechnical reports for each site. Concrete pours will be randomly
sampled to verify compliance with minimum strength requirements. Valve
locations will have prepared gravel/rock surfacing.

#### Equipment Installation

Equipment will normally be delivered by truck, then offloaded and
positioned, leveled, grouted, and secured with anchor bolts as
necessary. Equipment installation will include the inspection of all
major mechanical and electrical equipment (i.e., both visual and
radiographic), and painting and finishing.

#### Clean-up and Restoration

Clean-up and restoration activities will be performed as discussed in
Section 1.5.1.3.G above. Some site modifications (e.g., re-contouring)
may be required to provide sufficient drainage and site access.

## Operations and Maintenance

The LNG Terminal and the Pipeline will be operated and maintained by
appropriately-trained and licensed AES employees and contracted
entities, in accordance with applicable statutes and regulations,
regulatory permit conditions and authorizations, engineering design
specifications, recommended manufacturer maintenance practices, and
Project operating policies and procedures. The LNG Terminal design
considers all required and reasonably-foreseeable aspects that may
affect security and safety of operation, including preventative and
responsive actions to events that may affect vessel approach to and
berthing at the LNG Terminal, and routine operations of the LNG
Terminal. These elements are contained in Resource Reports 11, *Safety
and Reliability*, and 13, *Engineering and Design Material*, and the
Waterway Suitability Assessment (WSA), which is prepared in coordination
with the USCG. The WSA addresses the current commercial and recreational
waterway traffic and the impact of the LNG vessels. Note that the WSA
contains some sensitive security information that can only be released
to those persons authorized by the USCG. A summary of the non-sensitive
information is presented in Resource Report 11, *Reliability and
Safety*, Section 11.4.5.

The remaining aspects of routine operation and maintenance activities
are summarized in the following subsections.

### LNG Terminal Facilities 

#### Terminal Commissioning

Formal commissioning of the LNG Terminal will begin after completion of
all testing, flushing and checkout of piping, equipment and
instrumentation and control equipment. The commissioning will be
performed in accordance with detailed engineering and operating
procedures, with steps including dryout and purge of all process
systems, cooldown, and initial inventorying of one of the LNG storage
tanks. Dryout will be performed by flowing dry air throughout the
process system piping and components until discharged air achieves a
procedurally controlled low dew point. Following dryout, the piping and
components will be purged with nitrogen until the oxygen content of the
discharged gas reaches a procedurally controlled low percentage. Once
the pipe is purged of oxygen, system cool-down will commence, using
either liquid nitrogen or LNG. The LNG Terminal piping system is
designed to allow for cross connections needed during initial startup,
and to simplify future maintenance activities which require opening up
process systems to atmosphere. Natural gas generated as LNG evaporates
during cool-down may be sent to the heated vent stack, or as an option
the gas may be pressurized to sendout pressure using temporarily
installed pipeline compressors.

#### Terminal Electrical Supply and Distribution System

The LNG Terminal will include an electrical power distribution system,
including transformers, switchgear, multiple voltage distribution, and
emergency and uninterruptible power supply systems. Power will be
supplied from the local utility interconnections located in the site
vicinity, or from the Power Plant that may be collocated at the Terminal
Site. Emergency power will be supplied by an emergency diesel generator
sized to permit operation of all safety and control systems, and to
maintain circulation cooling.

#### Routine and Non-Routine Operations

AES will develop procedures to properly operate all LNG Terminal
facilities in accordance with governmental regulations, permit
requirements and authorizations, manufacturer recommendations, and AES's
own corporate procedures. These procedures will address operations,
maintenance and safety requirements for LNG Terminal activities,
including routine activities (operations and maintenance) and
non-routine activities (startup of equipment, cool-down of idle
equipment prior to restart, troubleshooting, emergency response, etc.).
The procedures will be provided in manuals and LNG Terminal personnel
will be trained in their use, as well as to respond to abnormal
occurrences and emergencies.

#### Hazard Detection and Mitigation Systems 

The Hazard Detection and Mitigation System (HDMS) will detect fire and
explosion hazard conditions, provide notification of the hazardous
conditions, and initiate mitigating actions/systems to avoid and
minimize the hazard consequences.  System design will focus on the
hazards that have severe consequences to the public, facility personnel,
and to plant equipment.  The system will consist of detectors, a fire
panel to process data from the detectors, audible and visual
notification devices, and system releasing devices.  Communications with
other systems and additional panels will be provided for redundancy,
improved response, and activation of other systems, such as the
Emergency Shutdown (ESD) system.

The HDMS design includes a Proprietary Protective Signaling System that
meets the requirements of NFPA 72, with the Main Fire Panel located in
the Main Control Room, which will be attended 24-hours per day.  The
hazards to be detected by the system include those associated with:

-   LNG due to leaks, ruptures, and other spills.

-   Natural gas vapors within flammability limits from LNG spills or
    leaks, ruptures, or other releases from gaseous systems.

-   Ordinary combustibles.

-   Combustible liquids such as lubricating oils, flammable
    refrigerants, and others.

-   Electrical hazards (e.g., cable insulation, motors).

-   The types of detectors will include:

-   Low temperature sensors to detect LNG spills.

-   Combustible gas detectors to detect accumulation of natural gas
    vapors that may result in flammable/explosive conditions.

-   Fire detectors consisting of smoke, high temperature, rate of rise
    thermal, and UV/IR flame detectors to detect appropriate fire
    conditions.

All hazard signals will alarm both in the control room and locally. 
Local signals will be both audible and visible (strobe lights), and have
distinctive alarms and colors for fire and flammable gas (leak) hazards.
Where appropriate a hazard trip may initiate automatic shutdown of
equipment and systems and/or may activate the ESD system. Detector
activation is processed by the fire panel that provides for notification
of the HDMS or the ESD system. The HDMS includes logic that will
initiate the LNG Terminal's ESD.  Alarms will be transmitted to the LNG
Terminal's DCS. 

The ESD system will initiate closure of valves, shutdown of fuel gas,
and/or shutdown of process drivers under emergency situations.  The ESD
system also includes ESD manual push buttons located in several areas in
the terminal.  The manual push buttons allow the ESD system to be
activated based on the decision of on-site plant personnel.  The
location of the pushbuttons in the Terminal Site will determine the
shutdown level, and the system logic will close the associated emergency
shutdown valves in predetermined locations at the Terminal Site (such as
ship unloading lines and circulation lines, pump discharge lines, inlets
to each vaporizer, and the plant sendout gas line). In response to the
fire and gas alarms, the operators will manually initiate appropriate
fire fighting and/or shutdown actions via hard-wired switches provided
on the main control room and the platform control room control consoles.

The hazard mitigation systems will include fire protection systems and
spill containment provisions built into the LNG Terminal design.

The fire protection systems will consist of a fire water distribution
system including hydrants, hose reels and monitors, plus sprinklers and
deluge systems. In addition, the LNG Terminal will be equipped with
portable and fixed dry chemical firefighting equipment, and a high
expansion foam system.

LNG spill containment features will include providing sloped ground so
that spills will be directed to an impoundment sump, which will be
equipped with hazard detection equipment and fire protection systems
such as high expansion foam.

#### Emergency Response Plan

An Emergency Response Plan will be developed for the LNG Terminal that
will consist of a number of individual plans, including the Facility
Contingency Plan, Spill Prevention Control and Countermeasures Plan,
Facility Response Plan and the Port Security Plan. The Emergency
Response Plan will be implemented at any time there is an event
resulting in an operating malfunction, structural collapse, personnel
error, forces of nature, emergency conditions adjacent to the facility,
and/or during a fire emergency.

The Emergency Response Plan will include details of:

-   Actions to be taken by individuals who have designated
    responsibilities in responding to emergency situations and terrorist
    or other external threats posed to the facility, which will also
    include communications with federal, state and local regulatory
    agencies and authorities.

-   Protocols for communicating an emergency situation to external
    organizations that will provide resources to assist in an emergency
    situation.

-   Protocols for safeguarding plant personnel and equipment.

-   Protocols for safeguarding the local community and the environment.

-   Protocols for ordering evacuation of personnel.

The Emergency Response Plan, which is required pursuant to Section
3A(e)(1) of the NGA, will be developed in cooperation with federal,
state and local safety agencies, and will include details of training
requirements as well as training exercises that must be performed
periodically to confirm the functionality of the plan and to confirm
individual roles and responsibilities.

### Pipeline Facilities

#### Pipeline Commissioning

AES personnel and required vendor representatives will be present during
the initial system commissioning. Personnel will also be present at the
appropriate surface facilities when the system is pressurized and the
line is filled with natural gas. These activities will be conducted in
accordance with an engineering commissioning procedure that will include
general operations surveillance, line fill, equipment checks and
troubleshooting, starting and stopping equipment, equipment maintenance,
permit compliance testing (e.g., emissions), and inventory accounting.
Details regarding hydrotesting and pre-commissioning are included in
Appendix 2F, Mid-Atlantic Express Pipeline Hydrotesting and
Pre-Commissioning Plan.

#### Routine and Non-Routine Operations

AES will develop and/or modify existing procedures to properly operate
the Pipeline facilities in accordance with governmental regulations,
permit requirements and authorizations, manufacturer recommendations,
and operating procedures for the Pipeline. These standardized and
systematic procedures will enhance performance, reliability, and safety
of the Pipeline, and will address routine Pipeline operations, e.g.,
system checks, cleaning, and maintenance, and non-routine activities,
e.g., trouble-shooting, system analysis, and emergency response. AES
will participate in the local One-Call system for utility stake out, and
will perform outreach training and coordination activities with local
emergency response entities regarding operations and response. Pipeline
operations are discussed further in Resource Report 11, *Reliability
and* *Safety*.

#### Aerial Reconnaissance and Ground Patrols 

Periodic aerial reconnaissance and ground patrols will be conducted to
visually inspect the Pipeline Route from above or on the ground for
activities such as vegetative encroachment, evidence of unauthorized
activity, damaged or exposed Pipeline facilities, areas of environmental
concern (e.g., subsidence, erosion), and other concerns that could
affect public safety and operation of the Project. Routine aerial
patrols of the Pipeline ROW will be conducted in accordance with AES's
operating procedures.

#### Permanent ROW Maintenance

Vegetation along the permanent ROW will be maintained to prevent woody
growth from encroaching onto the permanent easement (e.g., brush
cutting, tree trimming). The maintenance is necessary to assure Pipeline
integrity and ROW accessibility. Annually, certain sections of the ROW
will be inspected on the ground (e.g., after identification during
fly-overs or foot patrols). These inspections may involve the use of
light equipment and hand tools. Mowing and hand cutting will be the
primary method for maintenance within the ROW. Tree and brush trimming
will be performed in accordance with regulatory requirements and
landowner agreements, and documented in maintenance records. In fenced
and stoned aboveground facility locations where mowing and hand cutting
is impractical or undesirable, non-restricted use herbicides may be
used. These activities will be controlled by applicable governmental
laws and regulations, permit conditions/authorizations, and landowner
agreements. Pipeline ROW maintenance is discussed further in the Project
ECP, in Appendix 2A of Resource Report 2, *Water Use and Quality*.

#### Pipeline Integrity Management

AES will design, construct, operate and maintain its facilities in
accordance with USDOT regulations. Several protective controls will be
included in the Pipeline system to inhibit system degradation and better
assure its safe and reliable operation. These controls are discussed in
Resource Report 11, *Reliability and* *Safety*.

#### Personnel Training

AES personnel and subcontracted entities will be qualified and properly
trained for the tasks for which they are assigned. The USDOT requires
that pipeline companies develop and maintain a written qualifications
program for individuals performing certain safety-related tasks, known
as the Operator Qualification Program. The Operator Qualification
Program will document formal training and on-the-job experience. The
intent is to ensure a qualified workforce and reduce the possibility of
incidents caused by human error.

## Future Plans and Abandonment

At this time, there are no foreseeable future plans to expand the
Project beyond the description and scope discussed herein. However,
certain design aspects have been engineered to allow for Project
expansion if market conditions change such that an expansion is
justified. Additionally, at some time in the future, Project facilities
could be decommissioned and abandoned, but the circumstances and timing
are not known and cannot be predicted with any reasonable accuracy. To
the extent possible, these are discussed in the following subsections.

###  {#section .unnumbered}

### Expansion

Additional interconnections to the Pipeline may occur based upon market
demands and the availability of additional resources or purchasers of
natural gas. Market forces will determine the timing and need for these
possible interconnections.

The Pipeline and LNG Terminal designs have been engineered to allow for
project expansion if future market conditions warrant. For example, the
LNG Terminal equipment and site design layout could support a fourth
tank installation, and could easily support an upgrade in system
vaporization and sendout capacity to up to 2.25 bscfd. However, there
are presently no specific plans for any such expansion.

If market conditions change such that expansion is justified, AES would
seek the appropriate authorization(s) from the FERC and appropriate
regulatory agencies.

### Decommissioning and Abandonment

The design life of the Project is 25 years. Continued operation beyond
25 years may be viable, depending upon market viability and facility
conditions. Future conditions that affect any
abandonment/decommissioning decision are largely based on factors which
will not be known until a future date, and therefore details of Project
closure are speculative.

Abandonment of the Project would be executed in a manner consistent with
governmental laws and regulations at that time. This process would
involve interaction with the appropriate regulatory agencies and
affected landowners. Mid-Atlantic Express and Sparrows Point LNG would
develop a detailed decommissioning and abandonment plan when that
information is better understood. This plan will be based upon
establishing an "end use" objective, which may include:

-   Alternate use;

-   Abandonment in place;

-   Demolition and removal (i.e., the removal of all buildings,
    equipment, and installed features); or

-   A combination thereof.

For the safety of personnel and the environment, abandonment activities
would be implemented after operations have ceased and associated piping
and equipment have been properly decommissioned.

## Regulatory Status

### Required Permits and Approvals

The construction and operation of Project facilities will involve the
acquisition of various regulatory permits and approvals in addition to
the FERC authorization and certificate of public convenience and
necessity under Sections 3 and 7 of the Natural Gas Act (NGA),
respectively. The general schedule for obtaining permits (relative to
remaining Project development activities) appears in Table 1.5-1. Table
1.8-1 summarizes the permits and approvals that AES anticipates will be
required for the Project. A Preliminary Waterway Suitability Assessment
(PWSA) was developed and submitted to the USCG on March 3, 2006,
followed by the final submittal to the USCG on October 25, 2006. AES is
meeting and coordinating on an ongoing basis with the USCG and other
stakeholders involved in vessel routing and handling. AES expects final
recommendations from the USCG on the WSA in January 2007.. With regard
to the Power Plant, AES has continued to review the project with the
Maryland Power Plant Resource Program (PPRP) in developing a permit
application for the potential Power Plant. AES is evaluating the timing
of application development in conjunction with design scheduling that
would apply to this future potential option.

### Agency, Tribe, and Public Communication

In developing the Project, AES has had in-person discussions, telephone
conferences, and written consultation with various Federal, state and
local regulatory agencies, and Native American groups, as summarized in
Table 1.8-2. This coordination is expected to continue throughout the
development and execution of the Project.

## Affected Landowners

AES has performed extensive outreach to landowners during development of
the Project. This has included issuance of over 2,200 letters to
landowners and stakeholders and contacts for survey permission. Under 18
CFR §157.6(d), AES is required to send letters to residents within
one-half mile of the proposed Terminal Site. However, there are no
residences within one mile of the Terminal Site, but AES has exceeded
this FERC requirement by mailing letters to landowners within one mile
of the Terminal Site have been notified by letter), and letters have
been sent to landowners on and abutting the proposed primary and
alternative Pipeline Route segments. AES will continue to perform such
outreach and will notify affected landowners whose property is crossed
or otherwise affected by the Project facilities. The landowners and
street addresses of the affected properties are included in Appendix 1B.
The complete property owner mailing list was previously provided to the
FERC on April 14, 2006, in accordance with 18 CFR §157.6(d).

As noted above, AES has attempted to locate its proposed Pipeline in a
manner that will avoid or greatly minimize potential impacts on adjacent
landowners. Use of existing utility corridors is intended to avoid
impacts to private landowners. Where existing utility corridors cannot
be used completely or at all, and encroachment on private lands is
necessary, AES will implement construction and restoration techniques in
a manner intended to eliminate any long-term affects. For example, in
agricultural areas AES will use some or all of the following techniques:
installation of erosion control barriers, separation of soils, removal
of excess rock for at least the top 12 inches of soil, repair of
irrigation systems or drain tiles. Decompaction of work areas,
restoration of fences and removal of temporary erosion barriers,
addition of fertilizers or soil modifiers, and final grading to
pre-construction contours. The entire time spent in construction and
restoration work at any single area will be limited to about two weeks
depending on existing conditions. Once these activities are completed,
AES does not expect there will be any ongoing impact to those
landowners. More detailed descriptions of potential impacts to
landowners are provided in Resource Report 5, *Socioeconomics*, Resource
Report 8, *Land Use, Recreation and Aesthetics* and Resource Report 2,
*Water Use and Quality*.

Both the affected landowners and the surrounding communities at all
levels of government will benefit from the taxes and jobs associated
with the Project construction. A description of these benefits is
provided in Resource Report 5, *Socioeconomics*.

## Non-jurisdictional Facilities

Non-jurisdictional facilities are those facilities related to the
Project that will be constructed, owned, and operated by others and are
not subject to FERC jurisdiction.

As noted above, AES is considering the potential collocation of a 300 MW
natural gas fired combined cycle Power Plant at the Terminal Site. If
constructed, it would result in synergies with the LNG Terminal, such as
fuel supply to the combined cycle plant, transfer of cold from the LNG
Terminal heat transfer system to the combined cycle process for cooling,
and transfer of waste heat from the Power Plant into the LNG heat
transfer system for vaporization of the LNG. The Power Plant would
require a gas supply from the LNG Terminal and transmission lines
leaving the site to tie into the local utility system. The Power Plant
would provide the primary power source to the LNG Terminal, and the back
up supply would come from the 110 kV utility system. The Power Plant
would make additional power supplies available to a congested area of
the Mid-Atlantic Region at competitive market prices, would create
additional union construction and permanent jobs, would provide
additional tax revenues for the local area, would be a cogeneration
plant whose waste heat will be used to re-vaporize the LNG at the LNG
Terminal, and would be consistent with the emissions reduction policy
underlying the Maryland Healthy Air Act of 2006, which mandates
significant reductions in certain air pollutant emissions from certain
coal-fired units at existing power plants in Maryland.

The natural gas fired Power Plant is proposed to be a state-of-the-art
combined cycle cogeneration facility, using an advanced F-Class gas
turbine, and be capable of producing enough power to provide electricity
to about 300,000 homes. It would obtain its fuel from the LNG Terminal.
The Power Plant would operate by burning the re-vaporized natural gas in
a combustion turbine. The combustion turbine would cause a generator to
spin, thus creating electricity. Hot exhaust gasses from the combustion
turbine would be directed to a heat recovery generator where steam will
be produced. The steam would then be piped to a steam turbine and will
cause another generator to spin, thus creating additional electricity.
The use of two distinct generation modes (gas and steam) makes the
facility a "combined cycle" power plant. By using the heat energy in the
hot exhaust gasses to generate more electricity, a combined cycle
facility may be made to be as much as 40 percent more efficient than a
stand-alone combustion turbine.

The Power Plant would also be a cogeneration plant in that the natural
gas fuel will be used to generate two distinct useful products. The
first product, as described above, is electricity. The second useful
product is heat that will be used to vaporize the LNG at the adjacent
LNG Terminal. The Power Plant would be sized such that all of the heat
available for use from the steam side of the Power Plant can be used to
vaporize the LNG. The heat/cold exchange that would take place between
the Power Plant and the LNG Terminal would allow for the elimination of
any need for cooling water when both facilities are operating, and there
would be sufficient cold and fuel gas available from the LNG to fully
provide for the needs of the Power Plant.

A summary of the important advantages offered by a Power Plant include
the following:

-   **A CLEAN SOURCE OF POWER:** The Power Plant would use "purified"
    natural gas from the LNG Terminal as its only fuel source. Natural
    gas, which is recognized as the cleanest fuel source for large-scale
    energy production, typically contains small amounts of impurities
    that are emitted into the air when the fuel is burned. Those
    impurities are taken out during the liquefaction process prior to
    delivery of the fuel, so the Power Plant will be low in emissions.

-   **LIMITED WATER REQUIRED:** For the majority of the time the Power
    Plant would not require an outside source of cooling water while
    operating in conjunction with the proposed LNG Terminal. All cooling
    needs would be supplied via a heat/cold exchange system with the LNG
    Terminal. If there is ever a time when the LNG Terminal is not
    operating or there is insufficient cold from the LNG being vaporized
    and power is required to be generated under contractual obligations,
    it would be possible to operate the Power Plant using water obtained
    from the municipal water system.

-   **POWER WHERE IT IS NEEDED:** The Power Plant would be located close
    to heavy industries and other consumers of large amounts of energy.
    The ability to supply these nearby industries and other consumers
    with their electricity needs would eliminate power line congestion
    issues and transmission costs.

-   **HIGH EFFICIENCY:** The inherent design of the Power Plant -- the
    combined cycle aspect and the cogeneration aspect --would make this
    one of the most efficient power plants in the world, and certainly
    the most efficient power plant in the Mid-Atlantic Region.

-   **FUEL SOURCE:** The Power Plant would be fueled by natural gas that
    is obtained directly from a safe, reliable source. This would avoid
    pipeline transportation-related costs that are paid by other natural
    gas power plant operators.

-   **ECONOMIC BENEFITS:** The additional investment in the Power Plant
    would create more union construction jobs, more jobs (both permanent
    and indirect) during the operations phase, and more tax revenues for
    the local area, with little or no strain on existing infrastructure
    and services.

-   **BASELOAD POWER:** The high efficiency associated with the Power
    Plant design would help to ensure that the Power Plant produces
    power at a low cost and therefore will be operating nearly
    continuously as a baseloaded plant. Only the most reliable and
    cost-effective power plants operate to provide the base of power for
    the regional electric supply system.

The Power Plant concept also is consistent with the emissions reduction
policy underlying the Maryland Healthy Air Act of 2006, which mandates
reductions in carbon dioxide (10 percent cut by 2018), sulfur dioxide
(83 percent cut by 2010 and 90 percent by 2015), nitrogen oxides (67
percent cut by 2010 and 80 percent by 2015), and mercury (90 percent cut
by 2010) from certain coal-fired units at existing power plants in
Maryland. Natural gas plants typically emit 43.7 percent less carbon
dioxide, 99.6 percent less sulfur dioxide, 79.8 percent less nitrogen
oxide, and 99.7 percent less particulates than coal plants. As more
electric power is needed in congested areas of growing demand,
clean-burning options such as the Power Plant are environmentally
preferred over options with higher air emissions. Accordingly, whether
the potential Power Plant displaces existing power generating sources or
meets a portion of the increasing demand in the area, net air emissions
would be less than would be experienced were a generating option with
higher air emissions to fulfill that same demand.

In order to determine whether non-jurisdictional components or
facilities associated with a proposed project require environmental
review by FERC, a four factor test is applied using the criteria
specified in 18 C.F.R. § 380.12(c)(2)(ii). In short, these criteria are
intended to determine whether there is sufficient federal control and
responsibility over the subject component or facility as a whole to
warrant environmental analysis. The factors to be considered include:

-   Whether the regulated activity comprises \"merely a link\" in a
    corridor-type project, e.g., a transportation or utility
    transmission project;

-   Whether there are aspects of the non-jurisdictional facility in the
    immediate vicinity of the regulated activity that affect the
    location and configuration of the regulated activity;

-   The extent to which the entire project would be within FERC's
    jurisdiction; and

-   The extent of cumulative federal control and responsibility.

With regard to the first factor, the potential Power Plant is clearly
linked to the proposed LNG Terminal, a jurisdictional natural gas import
project. The proposed Power Plant would serve as a direct power source
for the LNG Terminal as well as consumers of electricity in the service
area that the Power Plant would support. The Power Plant would also
provide heat needed in the revaporization process. Although the two
facilities are not "merely a link" with each other, these direct power
and heat connections between the potential Power Plant and the LNG
Terminal suggests somewhat that the FERC should examine the
environmental aspects of this non-jurisdictional facility.

With regard to the second factor, the proposed Power Plant would receive
natural gas as a fuel source from the jurisdictional LNG Terminal, and
waste heat from the Power Plant would function to warm the LNG for
regasification for send out in the Pipeline. However, other mechanisms
of warming are available, i.e. the Power Plant is not a unique method to
warming the LNG, and neither siting nor configuration of the LNG
Terminal is dependant upon collocation of the Power Plant. Thus, the
second factor does not support FERC's environmental review of the
non-jurisdictional Power Plant.

With regard to the second factor, the proposed Power Plant would receive
natural gas as a fuel source from the jurisdictional LNG Terminal, and
waste heat from the Power Plant would function to warm the LNG for
re-gasification for send out in the Pipeline. However, other mechanisms
of warming are available, i.e. the Power Plant is not a unique method to
warming the LNG, and neither siting nor configuration of the LNG
Terminal is dependant upon co-location of the Power Plant. Thus, the
second factor does not support FERC's environmental review of the
non-jurisdictional Power Plant.

The third factor weighs the extent to which the entire Project would be
within FERC's jurisdiction. FERC has exclusive approval authority over
the LNG Terminal, and primary authority over approval of the associated
Pipeline. Several other federal and state agencies, however, also
exercise approval authority over related aspects of the Project
(dredging, wetlands and waterbody crossings, etc.), under FERC's lead in
the National Environmental Policy Act (NEPA) process. The Power Plant,
apart from its collocation at the LNG Terminal, would be
non-jurisdictional and would be under the approval authority of the
Maryland Public Service Commission (MD PSC). Because FERC has no
authority over the non-jurisdictional facility, this factor also weighs
against extending the scope of the environmental review.

The last factor weighs the extent of cumulative federal control and
responsibility over the non-jurisdictional facility. Federal control is
determined by the amount of federal financing, assistance, direction,
regulation, or approval inherent in a project. The non-jurisdictional
facility is a private construction project. The federal government has
no financial involvement, and no federal lands are involved.
Construction of the Power Plant will generate a new source of air
emissions; however, these are regulated by the State of Maryland. The
location of the Power Plant within the proposed Terminal Site is not
expected to impact wetlands, water bodies, other natural resources,
federal or state lands. Based on the available information, federal
agencies are expected to have limited involvement in the approval of the
non-jurisdictional facility Power Plant. Therefore, cumulative federal
control is minimal, and this factor does not warrant extending FERC's
environmental review.

Applying the four factor test to the potential addition of a power
generating facility as part of the Project indicates that only one
factor somewhat favors examining the non-jurisdictional facility.
Therefore, insufficient justification exists to warrant extension of
FERC's environmental review to include the non-jurisdictional facility.
However, because construction of one or more power generating facilities
is reasonably foreseeable somewhere in the region (with locations near
load centers being preferred over locations far from the load centers),
and AES is committed to providing an evaluation of all potential impacts
of the Project, the potential combined impacts of siting the Power Plant
as a co-generation facility within the Terminal Site is included in the
analysis of cumulative impacts. Relevant elements of the Power Plant
construction, operation and potential impacts are provided in each
Resource Report, as appropriate.

AES will make a final decision on the construction of the Power Plant
prior to the time detailed design of the LNG Terminal begins. Detailed
design of the LNG Terminal will not commence before FERC gives final
approval of the Project.. Any decision or commitment to move forward
with the Power Plant will be based on series of considerations related
to existing or proposed power generation or transmission infrastructure,
business considerations and market conditions. Factors weighing on the
decision may include:

-   Infrastructure related items - existing transmission system
    constraints, potentially-required system upgrades, planned (or yet
    to be developed) additional power generation facilities, or other
    unplanned modifications to existing power generation or transmission
    facilities.

-   Business considerations -- projected electric utility market rates,
    wheeling charges, potential customers, and changes in natural gas or
    other fuel sources for power generation facilities.

With the exception of Project facilities that will qualify, for purposes
of future modifications, relocation or abandonment, as "auxiliary
facilities" under Section 2.55(a) of the FERC's regulations, and the
Power Plant discussed here, there are no other known non-jurisdictional
facilities associated with this Project.

## References

1.  American Petroleum Institute (API), Design and Construction of
    Large, Welded, Low-Pressure Storage Tanks (API 620 - Appendix Q).

2.  American Society of Mechanical Engineers, Process Piping (B31.3) and
    Welding (Section IX) reference codes.

3.  Code of Federal Regulations (CFR), 18 CFR Part 157 Applications for
    Certificates of Public Convenience and Necessity and Orders for
    Permitting and Approving Abandonment Under Section 7 of the Natural
    Gas Act and Part 380 Regulations implementing the National
    Environmental Policy Act.

4.  Federal Energy Regulatory Commission, Guidance Manual for
    Environmental Report Preparation, August 2002.
    http://www.ferc.gov/industries/gas/enviro/erpman.pdf

5.  Federal Energy Regulatory Commission, Upland Erosion Control,
    Revegetation, and Maintenance Plan, January 2003.
    http://www.ferc.gov/industries/gas/enviro/uplndctl.pdf

6.  Federal Energy Regulatory Commission, Wetland and Waterbody
    Construction and Mitigation Procedures, January 2003.
    http://www.ferc.gov/industries/gas/enviro/wetland.pdf

7.  National Fire Protection Association (NFPA) 59A, Standard for the
    Protection, Storage, and Handling of Liquefied Natural Gas (LNG),
    2001 Edition.

8.  National Fire Protection Association, NFPA Code 72 -- National Fire
    Alarm Code.

9.  Permanent International Association Navigation Congress, PIANC
    Approach Channels, 1997.

10. Society of International Gas Tanker and Terminal Operations, Site
    Selection and Design for LNG Ports and Jetties, 1997.

11. U.S. Department of Energy, National Electric Transmission Congestion
    Study,
    2006.http://www.oe.energy.gov/DocumentsandMedia/Congestion_Study_2006-10.3.pdf

12. USDOT standards, 49 CFR Part 193 Liquefied Natural Gas Facilities:
    Federal Safety Standards.
    http://www.access.gpo.gov/nara/cfr/waisidx_04/49cfr193_04.html

13. USDOT Standards, 49 CFR Part 192, Transportation of Natural and
    Other Gas by Pipeline: Minimum Safety Standards.
    http://www.access.gpo.gov/nara/cfr/waisidx_04/49cfr192_04.html

14. U.S. Energy Information Administration, The Annual Energy Outlook
    2006, February 2006.
    http://www.eia.doe.gov/oiaf/aeo/assumption/pdf/0554(2006).pdf

APPENDIX 1A

Alignment Sheets & USGS Topographic Maps

APPENDIX 1B

Affected Landowner List

APPENDIX 1C

Dredging Management Plan

APPENDIX 1D

Tables of LNG Ships Anticipated to Service Sparrows Point and Dimensions
of Other Area Commercial Shipping Traffic

APPENDIX 1E

FERC Data Request Response Matrix

[^1]: U.S. Energy Information Administration, [The Annual Energy Outlook
    2006]{.underline}, February 2006, Supplemental Tables 1-20.

[^2]: Energy Information Administration, Natural Gas Annual for 2004,
    2000, 1996; Information Administration, "The Annual Energy Outlook
    2006", February 2006, Supplemental Table 2.

[^3]: "Basis" refers to the differential between index prices for
    delivered gas in a given market and the index for prices in a supply
    region such as the Henry Hub prices of natural gas.

[^4]: Route alternatives are segments of the Pipeline alignment that
    deviate from the preferred route filed, and that cover extended
    distances (miles) for purposes of providing different route segment
    options relative population, ROW and resource evaluation. Route
    variations are short-distance segments where localized options are
    considered in order to optimize a portion of the Pipeline Route to
    avoid human or environmental impacts. Examples of such variations
    include re-routing around congested housing areas that have
    developed adjacent to the existing ROW being followed, re-routing
    around areas where a sensitive resource or other feature(s) exists,
    or re-routing where varying from a utility corridor parallel path
    helps to minimize impact, improve constructability, or both.

[^5]: Each pipeline system has provided interconnection application
    forms and information to AES. These interconnection application
    forms were filed with FERC in October and November 2006.