**Resource Report 10 -- Alternatives**

**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.  Address the \"no action\"            | §         | Section 10.3  |
|     alternative.                         | 380       |               |
|                                          | .12(l)(1) |               |
| -   Discuss the costs and benefits       |           |               |
|     associated with the alternative.     |           |               |
+------------------------------------------+-----------+---------------+
| 2.  For large Projects, address the      | §         | Section       |
|     effect of energy conservation or     | 380       | 10.3.1 and    |
|     energy alternatives to the Project.  | .12(l)(1) | 10.3.2,       |
|                                          |           | respectively  |
+------------------------------------------+-----------+---------------+
| 3.  Identify system alternatives         | §         | Section 10.4  |
|     considered during the identification | 380       | and 10.5      |
|     of the Project and provide the       | .12(l)(1) |               |
|     rationale for rejecting each         |           |               |
|     alternative.                         |           |               |
|                                          |           |               |
| -   Discuss the costs and benefits       |           |               |
|     associated with each alternative     |           |               |
+------------------------------------------+-----------+---------------+
| 4.  Identify major and minor route       | §         | Section 10.6  |
|     alternatives considered to avoid     | 380       |               |
|     impact on sensitive environmental    | .12(l)(3) |               |
|     areas (e.g., wetlands, parks, or     |           |               |
|     residences) and provide sufficient   |           |               |
|     comparative data to justify the      |           |               |
|     selection of the proposed route.     |           |               |
|                                          |           |               |
| -   For onshore projects near to         |           |               |
|     offshore areas, be sure to address   |           |               |
|     alternatives using offshore          |           |               |
|     routings.                            |           |               |
+------------------------------------------+-----------+---------------+
| 5.  Identify alternative sites           | §         | Section 10.5  |
|     considered for the location of major | 380       |               |
|     new aboveground facilities and       | .12(l)(3) |               |
|     provide sufficient comparative data  |           |               |
|     to justify the selection of the      |           |               |
|     proposed site.                       |           |               |
+------------------------------------------+-----------+---------------+

**TABLE OF CONTENTS**

> **Page**

10\. Alternatives [1](#alternatives)

10.1 Introduction [1](#introduction)

10.1.1 Project Description [1](#project-description)

10.1.2 Energy Need [1](#energy-need)

10.2 Objective and Applicability [3](#objective-and-applicability)

10.3 No-Action Alternative [3](#no-action-alternative)

10.3.1 Energy Conservation [4](#energy-conservation)

10.3.2 Energy Alternatives [5](#energy-alternatives)

10.4 System Alternatives [6](#system-alternatives)

10.4.1 LNG Terminal Alternatives [6](#lng-terminal-alternatives)

10.4.2 Pipeline System Alternatives [12](#pipeline-system-alternatives)

10.5 Aboveground Alternatives [14](#aboveground-alternatives)

10.5.1 LNG Terminal Site Alternatives
[14](#lng-terminal-site-alternatives)

10.5.2 Terminal Design Alternatives [26](#terminal-design-alternatives)

10.6 Pipeline Alternatives [36](#pipeline-alternatives)

10.6.1 Delivery Alternatives [36](#delivery-alternatives)

10.6.2 Route Alternatives [37](#route-alternatives)

10.6.3 Major Route Alternatives [38](#major-route-alternatives)

10.6.4 Route Variations [41](#route-variations)

10.7 Summary [47](#summary)

10.8 References [48](#references)

**TABLES**

**FIGURES**

APPENDIX 10A Concentric Energy Advisors Demand and Supply analysis of
the Mid-Atlantic Natural Gas Markets 2005-2030

**APPENDIX 10B** Email Documenting Discussions with Maryland Agencies
Responsible for Managing Federally Funded Highways

**APPENDIX 10C** FERC Data Request Response Matrix

**LIST OF TABLES**

**Table No. Title**

Table 10.5.1-1 Minimum Channel Depth Parameters for Safe Transit of LNG
Vessels

Table 10.5.1-2 Comparison of Proposed LNG Terminal Location and Seven
Alternative Locations for the AES Sparrows Point Project

Table 10.5.2-1 Emissions Associated with Alternative Regasification
Methods

Table 10.5.2-2 Summary Comparison of Dredge Material Disposal Options

Table 10.6.2-1 Environmental Comparison of Alternatives to the Proposed
Primary Route

Table 10.6.4-1 Summary of Variations

LIST OF FIGURES

**Figure No. Title**

Figure 10.4.2-1 Existing Interstate Pipelines in the Mid-Atlantic region

Figure 10.5.1-1 Distribution of the Draft of LNG Carriers in the
Atlantic Basin with a Cargo Carrying Capacity Greater than 125,000 m^3^

Figure 10.5.1-2 Alternative LNG Terminal Locations

Figure 10.5.1-3 Alternative LNG Terminal Location -- Proposed Sparrows
Point LNG Facility

Figure 10.5.1-4 Alternative LNG Terminal Location -- Calvert Cliffs
Alternative

Figure 10.5.1-5 Alternative LNG Terminal Location -- Cove Point
Alternative

Figure 10.5.1-6 Alternative LNG Terminal Location -- Greenbury Point
Alternative

Figure 10.5.1-7 Alternative LNG Terminal Location -- Fishing Point
Alternative

Figure 10.5.1-8 Alternative LNG Terminal Location -- Swan Creek
Alternative

Figure 10.5.1-9 Alternative LNG Terminal Location -- Kent Island
Alternative

Figure 10.5.1-10 Alternative LNG Terminal Location -- Mittal Steel
Alternative

Figure 10.5.2-1 Pier Design Alternatives

Figure 10.5.2-2 Preferred Option Regasification Method -- Steam Boilers

Figure 10.5.2-3 Option 1 (a&b) Regasification Method -- Submerged
Combustion Vaporizers

Figure 10.5.2-4 Option 2 (a&b) Regasification Method -- Gas Fired
Heaters

Figure 10.5.2-5 Option 3 Regasification Method -- Direct Seawater
Vaporization

Figure 10.6.2-1 Proposed Route Location Map

Figure 10.6.2-2 Major Route alternatives Location Map

Figure 10.6.3-1 Alternative Route 1 -- Dundalk West Alternative

Figure 10.6.3-2 Alternative Route 2 -- Western Corridor Alternative

Figure 10.6.3-3 Alternative Route 3 -- SR 136 Alternative

Figure 10.6.3-4 Alternative Route 4 -- U.S. I-95 Greenfield Alternative

Figure 10.6.4-1 Route Variation 1, 2 & 2a

Figure 10.6.4-2 Route Variation 3

Figure 10.6.4-3 Route Variation 4

Figure 10.6.4-4 Route Variation 5&6

Figure 10.6.4-5 Route Variation 7&8

Figure 10.6.4-6 Route Variation 8a

Figure 10.6.4-7 Route Variation 9&10

Figure 10.6.4-8 Route Variation 11&12

Figure 10.6.4-9 Route Variation 13

Figure 10.6.4-10 Route Variation 14

Figure 10.6.4-11 Route Variation 15&16

Figure 10.6.4-12 Route Variation 17&18

Figure 10.6.4-13 Route Variation 19&20

Figure 10.6.4-14 Route Variation 20a, 21&22

  -------------------------------------------------------------------------
  **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 marine traffic 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
  -------------------------------------------------------------------------

# Alternatives

## Introduction

### Project Description

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.

As described in Section 1.10 of Resource Report 1, *General Project
Description*, 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.

### Energy Need

AES is proposing the Project in an effort to introduce a new incremental
supply of natural gas into the Mid-Atlantic Region, which includes the
Baltimore and Maryland area markets and certain parts of the (northern)
portion of the South-Atlantic Region (through displacement rather than
direct supply), to help serve the growing demand for energy in those
markets in a safe, reliable and economic manner. [^1] The new
incremental supply will initially be sized at 1.5 bscfd with potential
expansion to 2.25 bscfd. The Project will provide U.S. gas customers
with access to natural gas production centers throughout the world
without the need to construct new long-haul pipelines or expand the
existing long-haul interstate pipeline systems that currently serve the
Mid-Atlantic Region. [^2] The Project will also introduce new natural
gas storage facilities into the Mid-Atlantic Region.

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.

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. 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 of Resource Report 1 -
*General Project Description*. 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. 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 1.2-4 of Resource Report 1
-- *General Project Description*, EIA projects that natural gas demand
from electric power generation will continue to show the most
significant growth for the period 2005 to 2030.

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.

## Objective and Applicability

The Project has undergone an analysis of need and routing that
considered both environmental and non-environmental factors. In
developing the Sparrows Point Project, AES has considered several
alternatives to the proposed LNG Terminal and Pipeline, including the no
action alternative, energy alternatives (including conservation), and
system alternatives (including LNG terminal alternatives and pipeline
system alternatives). LNG Terminal location alternatives, Pipeline Route
alternatives (as well as alternative location and design of aboveground
facilities associated with the Pipeline), and LNG Terminal design
alternatives (including alternative methods for dredged material
disposal associated with the LNG Terminal marine works), were also
evaluated. Each of these alternatives is discussed in further detail in
this Resource Report.

This Resource Report is divided into six sections. Section 10.3
describes the no-action alternative. Because demand for energy in the
Mid-Atlantic Region is predicted to increase, analysis of the no-action
alternative necessarily involves a review of other means, including
conservation, to meet the growing energy demands. System alternatives
(i.e., alternatives to the proposed action that would make use of other
existing or proposed LNG or natural gas facilities to meet the
objectives of the Project) are evaluated in Section 10.4. Section 10.5
evaluates aboveground site alternatives. Section 10.6 discusses
alternatives to the proposed Pipeline, including different delivery
points or delivery methods for the LNG upon its receipt at the LNG
Terminal, and alternatives to the proposed Pipeline Route. Section 10.7
provides a summary of the alternatives analysis. Section 10.8 provides a
list of references used in the preparation of this Resource Report.

## No-Action Alternative

As noted above, total energy consumption in the United States is
projected to increase by 27 percent (1.2 percent annually) by the year
2025, from 100 quadrillion British thermal units (Btu)/year in 2004 to
127 quadrillion Btu/year in 2025. [^4] The North American natural gas
industry is facing a critical period when increased supply availability
will be essential to meeting a large portion of the expected increase in
total energy consumption. Natural gas demand will widen the gap between
that demand and available supplies unless new sources of natural gas
supply, including LNG, are developed and delivered to the market.
Delivery of natural gas via import terminals and associated pipeline
facilities is a safe and economical method to meet a significant portion
of the anticipated growth in natural gas demand.

The No-Action alternative involves consideration of the potential
benefits and adverse impacts if the proposed Project were not approved
and constructed. If the Project were not constructed, the potential
direct environmental impacts associated with construction and operation
of the Project would not occur. However, the primary purpose of the
Project (i.e., introduction of a new incremental supply of natural gas
into the Mid-Atlantic Region that can be sourced from numerous
world-wide production centers) would not be met. Accordingly, customers
in those markets would have fewer and potentially more expensive options
available for obtaining natural gas supplies in the near future. Options
available for bringing additional natural gas to the Mid-Atlantic Region
involve (i) construction of new LNG terminals (or construction of LNG
terminal expansions) and associated expansions of pipeline capacities
from outside the Mid-Atlantic Region[^5] or (ii) increased production
from sources outside the Mid-Atlantic Region and associated pipeline
expansions. [^6] Both of these options involve additional pipeline
tariffs associated with the delivery of gas to the Mid-Atlantic Region.
These tariffs are usually based on delivery areas throughout the
interstate pipeline system; the tariff increases by rate zone the
further away from the source where it is to be delivered. Assuming the
gas is shipped from world production centers to either a LNG terminal
outside the Mid-Atlantic Region or to the LNG Terminal proposed by AES
at the same delivered cost, with transportation charges included, the
delivered cost of gas from areas outside the Mid-Atlantic Region to
customers inside the Mid-Atlantic Region would be higher than if it were
to be delivered by the Project.[^7] This same reasoning applies to new
production sources (i.e., non-LNG) outside the Mid-Atlantic Region if
one assumes that the market sets the price for both LNG and non-LNG
sources of supply. Further, by introducing a new source of natural gas
into the Mid-Atlantic Region, competition will be enhanced. In general,
with all other factors being equal, increased supply competition has the
effect of stabilizing or decreasing prices.

The No-Action alternative would require that the unsatisfied demand for
energy supply in the Mid-Atlantic Region be met through energy
conservation if not by some other energy alternative (e.g., increased
pipeline transmission capacity from other areas of the United States or
elsewhere in North America) where natural gas supplies are more readily
available. As described in Sections 10.3.1 and 10.3.2, energy
conservation and the use of alternative energy strategies will not fully
satisfy the market needs of targeted consumers.

### Energy Conservation

AES evaluated the feasibility of using energy conservation measures as
an alternative to the proposed Project.

According to a Report of the National Petroleum Council, titled
Balancing *Natural Gas Policy --Fueling the Demands of a Growing
Economy* (dated September 25, 2003) while conservation measures are
aiding in reducing current demand for natural gas, the reductions
possible through conservation measures alone are not anticipated to meet
total current or future demand for natural gas. Conservation methods are
neither uniformly mandated nor followed. Current energy conservation
efforts, including the ENERGY STAR program that is a joint effort
between the U.S. Environmental Protection Agency (EPA) and the U.S.
Department of Energy (DOE) and identifies cost-effective,
energy-efficient products that are designed to save consumers money,
reduce energy consumption and help protect the environment (EPA 2006),
will aid in reducing the amount of natural gas used in the production of
a dollar's worth of economic output; however, conservation does not
negate the need for the Project. These findings are supported by a
report issued by the American Council for an Energy Efficient Economy
(ACEEE) in 2003, cited at p. 3-3 of the Final Environmental Impact
Statement on the Crown Landing LNG and Logan Lateral projects (FERC
Docket Nos. CP04-411-000 and CP04-416-000) (Crown Landing FEIS), that
analyzed projected energy demands in the Northeast, including New York,
New Jersey, Pennsylvania, Delaware and Maryland (ACEEE 2003). The ACEEE
concluded that energy efficiency and renewable energy measures could
result in a 0.9 percent reduction in natural gas consumption by 2008 in
the northeastern states, which would not meet the approximate 1.3
percent compounded annual growth rate in natural gas demand for the
Mid-Atlantic Region. The ACEEE recognized that energy efficiency and
renewable energy are not the only policy solutions required to address
the future natural gas needs of the United States, and that additional
sources of natural gas will be required either from domestic sources or
through the importation of LNG. Based on the projected increase in
demand for natural gas within the Mid-Atlantic Region through the year
2030, AES has determined that energy conservation measures alone,
coupled with the fact that these measures are not uniformly mandated,
would not provide a sufficient alternative to the Project.

### Energy Alternatives

AES evaluated the feasibility of using alternative sources of energy to
satisfy the need intended to be served by the Project, such as the use
of other fossil fuels, windpower generation, hydropower generation, and
nuclear power. The use of these energy alternatives, whether alone or in
combination, is not anticipated to provide a commercially viable and
environmentally preferable alternative to the Project.

Several alternatives for meeting energy needs are available in the
Mid-Atlantic Region; however, none is projected to be both as cost
efficient and environmentally benign as natural gas. Other fossil fuels,
specifically fuel oil and coal, are short-term viable alternatives to
meet the growing demand for energy in the region, the greatest part of
which is associated with electricity production. Compared to fuel oil or
coal, natural gas is a relatively clean and efficient fuel that can
reduce relative impacts on air quality (e.g., reduce emissions of
nitrogen oxides, sulfur dioxide, particulate matter and carbon dioxide)
to generate the same amount of electricity. According to the Crown
Landing LNG FEIS, because there is no pipeline infrastructure in place
to distribute these fuels to market in the Mid-Atlantic Region, use of
these alternative fossil fuels would require more truck, barge and train
trips to make up for the distribution of an equivalent amount of natural
gas, which would increase air emissions and traffic congestion. The
burning of coal would also require disposal of the resulting ash.
Moreover, the policy underlying the Maryland Healthy Air Act of 2006,
which mandates reductions from certain existing units at coal-fired
power plants of 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), encourages the use of natural gas for power production over
coal sources. Natural gas plants typically emit 43.7 percent less carbon
dioxide, 99.6 percent less sulfur dioxide, 79.8 percent less nitrogen
oxide, 99.7 percent less particulates and 100 percent less mercury than
coal plants. Natural gas plants also produce significantly fewer
emissions than oil plants (EIA, Natural Gas Issues and Trends 1998).

The contribution of renewable fuels to the U.S. electricity supply mix
remains relatively small in the EIA's Annual Energy Outlook for 2006.
Although conventional hydropower is projected to remain the largest
source of renewable generation through 2030, a lack of available
untapped large-scale sites, coupled with environmental concerns, limits
its growth; its share of total generation is projected to fall from 6.8
percent in 2004 to 5.1 percent in 2030 (EIA 2006). See also the ACEEE
Report.

While wind generation will become among the leaders in renewable energy
generation, the anticipated expansion over current capacity is only
projected to increase from a modest 0.4 percent of total energy
generation in 2004 to 1.1 percent in 2030 (EIA 2006). Energy from wind
power, while important to the overall energy mix, is not projected to
grow significantly and become a commercially viable alternative to the
Project. See also ACEEE Report.

Energy from nuclear power is not a commercially viable substitute able
to replace or significantly offset the demand for natural gas over the
next 20 years (EIA 2005). The EIA reports that even with modest
increases in nuclear generation from improvements in plant performance
and expansion of existing facilities, the share of generation from
nuclear plants is projected to decline from 20 percent in 2004 to 15
percent in 2030, as total generation grows at a faster rate than nuclear
generation. Furthermore, nuclear power energy involves its own distinct
and significant environmental issues such as the disposal of radioactive
materials (spent fuel), alterations to hydrological/biological systems
and visual impacts. [^8]

## System Alternatives

AES evaluated potential system alternatives to the proposed action to
determine whether existing LNG projects or LNG projects that have
recently been approved by the Commission (both expansions and new
construction) would meet the stated objectives of the proposed Project.
Next, AES evaluated potential system alternatives to the Proposed Action
to determine whether existing or new natural gas pipeline systems would
meet the stated objectives of the proposed Project. Based on the
conclusions set forth below, none of these system alternatives would
meet the stated objectives of the proposed Project.

The basis for evaluation of system alternatives derives from information
supplied by the EIA and other sources referenced below. The EIA has
indicated that the overall United States natural gas demand, as well as
the natural gas market in the Mid-Atlantic Region, currently is supplied
with natural gas from three main sources including gas produced in the
United States, imports from Canada, and LNG imports. The Mid-Atlantic
Region receives gas produced in the United States and Canada through the
existing interstate pipeline network. Production areas in the United
States that serve the Mid-Atlantic Region are found primarily in the
Gulf Coast (onshore and offshore) and, to a much smaller degree, in the
Northeast. Supplies from these production areas, and from Canada, are
expected to decline in the immediate future. For example, by 2010,
domestic supplies available to the Mid-Atlantic Region are expected to
decline by four percent, while gas available from Canada is expected to
decline by 19 percent. Combining forecasted declines in supply basin
deliveries with expected increases in demand, the total natural gas
needs in the Mid-Atlantic Region are expected to increase by
approximately 1.98 bscfd by 2010, 3.03 bscfd by 2015, and 8.55 bscfd by
2030. The report prepared by Concentric Energy Advisors (CEA), included
in Appendix 10A, provides further information regarding these forecasted
declines.

### LNG Terminal Alternatives

In order to bridge the gap between declines of existing supplies and
increases in demand, LNG imports are predicted to increase
significantly. Specifically, the LNG component of the national supply
mix is predicted to increase from 0.6 Tcf of the total United States
demand in 2005 (approximately three percent of the total 20 Tcf demand),
to 4.4 Tcf of the total United States demand in 2030 (approximately 16
percent of the total demand for natural gas in the United States) (EIA
2006). Currently, the Mid-Atlantic Region receives vaporized LNG from
the existing Dominion Cove Point LNG terminal in Calvert County,
Maryland (all of the LNG imported at Cove Point is consumed in the
Mid-Atlantic Region) and significantly lesser amounts from the existing
LNG import terminals located in Lake Charles, Louisiana and Elba Island,
Georgia.

Recognizing the need to increase the supply of LNG within the country,
the Commission and the United States Coast Guard (USCG) recently
approved applications to expand or construct 17 LNG import facilities,
which, if all are brought on line, would increase United States
LNG-import vaporization capacity initially by up to 16.0 bscfd. In
addition to these approved projects (both new and expansion), there are
numerous projects that have been proposed in various locations. These
new and proposed facilities are summarized below. Because the majority
of the projects are not in the Mid-Atlantic Region and are constrained
by capacity-limited interstate pipeline systems into the region, none of
the newly approved terminals, including approved terminal expansions,
nor any of the proposed terminals, is capable of meeting the stated
Project objective of introducing a new 1.5 bscfd (expandable to 2.25
bscfd) source of natural gas into the Mid-Atlantic Region.[^9]

10.4.1.1  New LNG Terminals

Recently, the Commission and the USCG have authorized the construction
and operation of 13 new LNG import terminals and related facilities as
described below:

**Port Pelican Offshore Deepwater Port Project** -- (USCG Docket No.
14134) Chevron Texaco is authorized to construct the Port Pelican
Offshore Deepwater Port in the Gulf of Mexico offshore of Louisiana. The
terminal would have the capability to store up to 330,000 cubic meters
(m3) of natural gas and have a send-out capability of an average of 1.6
bscfd. While USCG and Department of Transportation (USDOT) approvals
were issued in November 2003, the project has been placed on hold
indefinitely.

**Gulf Landing Offshore Deepwater Port Project** -- (USCG Docket No.
16860) Chevron Texaco is authorized to construct the Gulf Landing
Offshore Deepwater Port in the Gulf of Mexico offshore of Louisiana. The
terminal would have the capability to store up to 200,000 m3 of natural
gas and have a send-out capability of an average of 1.0 bscfd. The USCG
and USDOT approvals were issued in February 2005.

**Creole Trail LNG & Creole Trail Pipeline** -- (Docket Nos.
CP05-360-000; CP05-357-000; CP05-357-001; CP05-357-002; CP05-358 and
CP05-359) Cheniere is authorized to site, construct and operate the
Creole Trail LNG import terminal in Cameron Parish, Louisiana. The
terminal would include four LNG storage tanks that would have the
capability to store up to 640,000 m3 of natural gas and have a send-out
capability of an average of 3.3 bscfd. The Commission also authorized
Cheniere to construct and operate the Creole Trail Pipeline comprising
116.8 miles of dual 42-inch diameter pipeline from the outlet of Creole
Trail's proposed LNG terminal through Cameron, Calcasieu, Beauregard,
Jefferson Davis, Allen and Acadia Parishes, Louisiana, to interconnect
with markets throughout the United States through existing interstate
pipelines.

**Port Arthur LNG and Port Arthur Pipeline** -- (Docket Nos. CP05-83;
CP05-84; CP05-85; and CP05-86) The Commission granted Port Arthur LNG
authority to site, construct and operate the new Port Arthur LNG
terminal and related facilities near Port Arthur, Texas. The facilities
include six LNG storage tanks with a nominal capacity of 160,000 m3
each. The project would be constructed in two phases and would
ultimately provide an average of three bscfd to existing interstate
pipeline systems in Texas and Louisiana, connecting to markets in the
Midwest and Northeast. Port Arthur Pipeline may construct and operate a
new 70-mile, 36-inch diameter pipeline from the LNG terminal to an
interstate interconnection. The Commission also authorized the company
to construct and operate a three-mile, intrastate pipeline from the LNG
terminal to an interstate interconnection with facilities owned by
Natural Gas Pipeline Company (NGPL in Jefferson County, Texas.

**Crown Landing LNG Project** -- (Docket No. CP04-411) Crown Landing
LLC, a wholly owned subsidiary of BP America Production Company,
proposes to construct and operate a new onshore LNG import terminal in
Logan Township, New Jersey. The proposed terminal would store up to
450,000 m3 of LNG equivalent to 9.2 bscfd of gas, vaporize LNG and send
it out through a connecting pipeline at a base load rate of 1.2 bscfd.
The entire capacity of the Crown Landing project is committed for the
next 20 years (Crown Landing FEIS 2006). The project would interconnect
with a new 11-mile pipeline that the Commission also approved. The
pipeline would be constructed by Texas Eastern Transmission Company
(TETCO) (Docket No. CP04-416) and would extend from the terminal through
Delaware County, Pennsylvania, to transport the vaporized LNG to various
markets in the United States. Crown Landing and TETCO also anticipate
interconnections with facilities operated by Transcontinental Gas Pipe
Line Corporation (Transco) and Columbia Gas Transmission Company
(Columbia). Crown Landing hopes to begin service from the facility in
late 2008. Operational service by 2008 is dependent upon a favorable
decision by the United States Supreme Court concerning a challenge by
the State of Delaware as to the jurisdiction of Delaware or New Jersey
over certain improvements appurtenant to the New Jersey shore of the
Delaware River. A special master was appointed on January 23, 2006 to
hear testimony in the proceeding. There is no timetable for resolution
of the challenge, and the outcome is uncertain.

Even if the Supreme Court rules in a manner that allows the Crown
Landing project to be constructed, the addition of significantly greater
new pipeline infrastructure, both directly related to the Crown Landing
project (i.e., additional lateral pipelines, lateral pipelines of
greater diameter, or some other means to accommodate additional volumes
of natural gas) and within the interconnected pipeline systems, would be
needed to fully meet the increased natural gas demands predicted in the
Mid-Atlantic Region. As described in more detail in the CEA report in
Attachment 10A, the fact that the forecasted demand in the Mid-Atlantic
Region is large enough to require the construction of both the Project
and the Crown Landing facility, as well as the fully subscribed volumes
anticipated at the expanded Cove Point facility, the physical structures
and equipment within the Crown Landing facility would effectively have
to be doubled to account for the volumes anticipated to be brought into
the region by the Project.

**Golden Pass LNG Terminal Project** -- (Docket No. CP04-386-000 and
CP04-400-000) Exxon Mobil Corporation proposed to construct an LNG
import facility at Sabine Pass, Texas, comprising two phases -- 1.0
bscfd (Phase 1), 2.0 bscfd (Phase 2). Commission approval was provided
July 2005, and the facility is under construction. In addition, the
Golden Pass Pipeline project, which is approximately 77 miles in length,
would have the capacity to deliver up to 2.5 bscfd of natural gas. The
pipeline would cross four counties in Texas and one parish in Louisiana.
At this time, up to 11 interconnections with existing intrastate and
interstate pipelines are possible.

**Sabine Pass LNG Terminal** -- (Docket No. CP04-47-000) Cheniere Sabine
Pass Pipeline Company proposed to construct an LNG import terminal at
Sabine Pass Channel, Louisiana, with capacity of 2.6 bscfd via three
160,000 m3 tanks. Commission approval was provided December 2004, and
construction began in March 2005. Terminal operations are expected to
commence in 2008. The natural gas from the Sabine Pass LNG terminal will
pass through the Cheniere Sabine Pass LNG pipeline into the natural gas
transmission network. The Cheniere Sabine Pass Pipeline will run 16
miles from the Sabine Pass LNG terminal to Johnson Bayou. The proposed
pipeline will interconnect with several interstate and intrastate
pipelines. The pipeline is designed to transport 2.6 bscfd of natural
gas.

**Technip U.S.A. Corp., Saipem Technigaz SA and Zachry Construction
Corp.** -- (Docket No. CP03-75-000) Technip USA Corporation proposed to
develop a new LNG import facility at Freeport, Texas, comprising two
phases of development -- 1.5 bscfd in two 160,000 m3 tanks (Phase 1),
and 2.5 bscfd in one 160,000 m3 tank (Phase 2). The Commission approved
the proposal in June 2004 and Phase 1 is under construction. The first
phase of the terminal will have a send-out capacity of 1.5 bscfd
beginning in early 2008. The construction of the terminal's Phase I
started on January 17, 2005, and is scheduled to be completed within 35
months. Phase II will incorporate a second marine berthing dock and
associated unloading facilities, expanded vaporization, 7.5 billion
cubic feet (Bcf) of underground storage and a third LNG storage tank.
The current schedule envisages that the construction of Phase II will
start in 2006 and that the expansion will be on stream in 2008 with the
exception of the third tank, which will be completed in 2009.
Engineering and planning for the Phase II expansion are underway,
including building a 7.5 Bcf integrated underground salt cavern storage
facility.

**Cameron** -- (Docket No. CP02-374-000) Sempra Energy, LNG proposed a
new LNG facility at Hackberry, Louisiana, comprising 1.5 bscfd of
capacity in three 160,000 m3 tanks. Commission approval was provided
September 2003, and construction is under way. In addition to the
terminal, Sempra Pipelines & Storage will also be constructing a 35-mile
pipeline to transport natural gas from the facility to connect with
existing interstate pipelines to the north.

**Weaver's Cove LNG Project** -- (Docket No. CP04-36-000 and
CP04-41-000) Weaver's Cove Energy, LLC (Hess LNG) proposed a new LNG
facility at Fall River, Massachusetts, comprising 0.8 bscfd of capacity
in one 200,000 m3 tank. Commission approval was provided July 2005 and
other required permits are still in process. Massachusetts recently
issued its certificate finding the project in compliance with the
state's environmental policy act. In addition to the terminal, Mill
River Pipeline will also be constructing two 6-mile pipelines to
transport natural gas from the facility to connect with existing
interstate pipelines to the north.

**Ingleside Energy Center LNG Project** -- (Docket No. CP05-13-000)
Occidental Energy Ventures Corp. proposed a new LNG facility to be
located at Ingleside, Texas and comprising 1.0 bscfd of capacity in two
160,000 m3 tanks. Commission approval was provided in July 2005. The
Ingleside Energy Center LNG Project terminal and related facilities will
be located in San Patricio County, Texas. The terminal is designed to
provide an option for extracting natural gas liquids in addition to
importing, storing and vaporizing one Bcf of gas per day. In addition to
the terminal, Occidental Energy Ventures Corp proposes to construct and
operate 26.4 miles of 26-inch diameter pipeline extending from the
tailgate of Ingleside\'s LNG terminal to potential interconnections with
nine interstate and intrastate pipelines located in San Patricio County.

**Vista del Sol LNG Terminal Project** -- (Docket Nos. CP04-395-000,
CP04-405-000, CP04-374-000) ExxonMobil Corporation proposed an LNG
facility to be located at Corpus Christi, Texas, and comprising 1.0
bscfd of capacity in three 155,000 m3 tanks. Commission approval was
provided June 2005, and construction was reported to be pending. Exxon
Mobil announced on September 25, 2006 that it has dropped plans for this
project and was exploring a sale with an unidentified party.

**Cheniere Corpus Christi LNG Terminal Project** -- (Docket Nos.
CP-37-000, CP04-44-000, CP04-45-000, CP04-46-000) Corpus Christi LNG, LP
proposed an LNG facility to be located in Corpus Christi, Texas and
comprising 2.6 bscfd capacity in three 160,000 m3 tanks. Commission
approval was provided April 2005, and construction is pending. Cheniere
began site preparation in the second quarter of 2006 and expects to
commence terminal operations in early 2010. The natural gas from the
Corpus Christi LNG terminal will pass through the Cheniere Corpus
Christi LNG pipeline into the existing natural gas transmission network.
The Cheniere Corpus Christi Pipeline will run 24 miles from the terminal
to a connecting pipeline north of Sinton, Texas. The proposed pipeline
will interconnect with several interstate and intrastate pipelines. The
pipeline is designed to transport 2.6 Bcf per day of natural gas.

**Excelerate Energy, L.L.C.** -- Excelerate currently owns and operates
the only offshore LNG terminal in the United States. The terminal, which
is based on a transport and regasification vessel, is located in the
Gulf of Mexico offshore of Louisiana. The terminal requires use of a
specialized LNG ship, which is able to dock at a mooring system made up
of a submerged turret buoy and flexible riser connected to a natural gas
pipeline on the seafloor. This design does not provide for LNG storage
so it must be limited to an LNG fleet with regasification equipment on
all of the vessels. Currently, there are only two such ships in the
world, but a third ship was scheduled to be completed late in 2006, and
two more ships have been ordered and are scheduled to be delivered in
2008 and 2009, respectively. Due to the travel times to and from LNG
producing countries, more specialized ships would be necessary to ensure
continuous delivery of natural gas to such offshore receipt points.

10.4.1.2  LNG Terminal Expansions

The Commission also authorized expansions at four previously authorized
LNG facilities. In each case the Commission requires the applicant to
deliver the LNG in a format that is compatible with the existing natural
gas infrastructure. Descriptions for each of these projects were derived
from the Final Crown Landing FEIS.

**Elba Island - Southern LNG, Inc.** (Southern LNG) -- (Docket No.
CP05-388-000). Southern LNG owns and operates an LNG import terminal
located at Elba Island along the Savannah River in Chatham County,
Georgia. Southern Natural Gas filed an application for an expansion, and
for authorization to construct and operate, a total of 176.43 miles of
24-inch and 30-inch diameter pipeline, three new compressor stations
(totaling approximately 31,050 hp) and other appurtenant facilities. The
pipeline project, known as the Cypress Pipeline Project (located in
Georgia and Florida), would be constructed in three phases with phased
in-service dates of May 1, 2007; May 1, 2009 and May 1, 2010. On
December 21, 2005, Southern LNG (through El Paso Corporation) announced
proposals to further expand the Southern LNG terminal. The proposed
expansion, referred to in the announcement as the Elba Island Expansion
and Related Pipeline Project, would more than double the LNG storage
capacity at the terminal and would add 0.9 bscfd of send-out capacity,
increasing the total send-out capacity of the terminal to 2.1 bscfd. In
addition, a new 191-mile interstate natural gas pipeline with a total
capacity of 1.1 bscfd would also be constructed from Elba Island to
markets in Georgia and through interconnections with other pipelines to
the Southeastern and Eastern United States.

**CMS Trunkline LNG Company, L.L.C.** (Trunkline LNG) - (Docket Nos.
CP02-60-000 and CP02-60-001) currently owns and operates an LNG import
facility in Calcasieu Parish, Louisiana. The existing LNG terminal
includes three 95,000 m3 storage tanks, a ship unloading dock with a
full design capacity of 120 ships per year, and vaporization facilities
with a maximum send-out capacity of 1.0 bscfd. In December 2002, the
Commission approved plans to add a second ship unloading dock, a 140,000
m3 LNG storage tank, three first stage LNG pumps, four second stage LNG
pumps, three vaporizers and two electric generators. With the addition
of these facilities, which are currently under construction, the LNG
terminal will have a sustainable send-out capacity of about 1.2 bscfd
(1.3 bscfd maximum) and a ship unloading capacity of about 175 ships per
year. In February 2004, Trunkline LNG and a related subsidiary, CMS
Trunkline Gas Company, L.L.C. (Trunkline Gas), announced plans to
further expand send-out capacity of the terminal by adding pumps,
vaporizers and new unloading facilities to a second dock at the terminal
and constructing a new 23-mile-long, 30-inch diameter pipeline between
the LNG terminal and Trunkline Gas's existing mainline pipeline system.
If approved, these new facilities would increase the maximum send-out
capacity of the terminal to about 1.8 to 2.1 bscfd.

**Sabine Pass LNG** -- (Docket No. CP05-396) The Commission approved an
expansion of the proposed Sabine LNG project, which was authorized in
December 2004 to be constructed and operated in Cameron Parish,
Louisiana. In its decision, the Commission also approved Phase II of the
project, which includes three additional 160,000 m3 storage tanks and
related facilities that would provide an average send-out capacity
ranging from 2.6 bscfd to 4 bscfd. The Sabine LNG Phase II facilities
are proposed to be adjacent to or within the boundary of the Phase I
site.

**Dominion Cove Point LNG** -- (Docket Nos. CP05-130-000, CP05-130-001,
CP05-130-002; CP05-132-000, -001) Dominion Cove Point owns and operates
an LNG import facility near Lusby, Calvert County, Maryland and a
pipeline, known as the Cove Point pipeline (Docket No. CP05-131), that
extends approximately 88 miles from the LNG terminal to connections with
several interstate pipelines in Loudoun and Fairfax Counties, Virginia.
Currently, the LNG terminal has a storage capacity of 7.8 Bcf and a peak
send-out capacity of 1.0 bscfd. The Commission recently approved an
expansion of the Cove Point facility to increase its storage capacity to
14.5 Bcf and its send-out capacity to 1.8 bscfd. The approved expansion
will increase the expected number of ships calling at the terminal from
90 to 120 ships per year to approximately 200 ships per year. By
agreement with the Sierra Club, including its Maryland Chapter and
Maryland Conservation Council, Inc. dated March 1, 2005, Dominion Cove
Point LNG, L.P. agreed to limit future expansion such that maximum
future total capacity would be no more than 18.85 Bcf (4.35 Bcf above
currently planned storage capacity).

**Conclusions Regarding Approved LNG Terminal Alternatives**

Given the forecasted decrease in production of natural gas in certain
supply basins, LNG is projected to supply not only incremental natural
gas demand, but it also could replace the projected reduction in other
supply components (i.e., natural gas imports from Canada and certain
United States production basins). Alternatives outside of the defined
market area are not considered commercially feasible for serving the
Mid-Atlantic Region due to tariff transportation charges and/or pipeline
constraints. Delivery of natural gas from LNG terminals outside of the
defined market would require construction of additional delivery
capacity over significantly greater distances than required for in-area
projects; thus, leading to greater human and environmental impacts.
Finally, all of the LNG projects located outside of the Mid-Atlantic
Region would not have the same Project benefit of introducing new
natural gas storage capacity into the area.

By the 2020 time period, AES has forecasted that incremental design day
demand of approximately 4.921 bscfd will not only require the 1.5 bscfd
from the Sparrows Point Project but will also require approximately two
additional natural gas supply projects that are larger than the size of
the Sparrows Point Project. In other words, by 2020, the Mid-Atlantic
Region would have sufficient demand of approximately 4.921 bscfd which
would not only absorb the Sparrows Point volume of 1.5 bscfd, but also
the Crown Landing volume of 1.2 bscfd, the Cove Point expansion of 0.8
bscfd, and still require approximately 1.4 bscfd of other supply.
Further expansion of the Cove Point terminal or, if it is allowed to be
constructed in the first instance, the Crown Landing terminal would
likely require upgrades (or, in the case of Cove Point, further
upgrades), to the accommodate the additional gas volumes required to
fill in the expected shortfall in the Mid-Atlantic Region. Compression
may also be required on connecting or downstream pipelines. These
potential restrictions (including the associated environmental impacts)
would limit the ability for expansions at these terminals to meet the
anticipated natural gas needs in the Mid-Atlantic Region. Restrictions
on the ability of Cove Point to further expand its facility beyond 18.85
Bcf might also impact the ability of that facility to meet the
anticipated future natural gas needs. Finally, water depth restrictions
applicable to the Crown Landing facility (see discussion below in
Section 10.5.1.1), in conjunction with existing shipping traffic volumes
on the Delaware River, might impact the ability of that facility to meet
the anticipated additional natural gas needs in the Mid-Atlantic Region.
In any event, as evidenced by recent natural disasters that
temporarily-affected clustered energy production facilities, it makes
good sense to allow for a certain amount of geographical separation so
as to enhance the reliability of the nation's energy infrastructure.

For these reasons, neither the expansion of the existing LNG terminals
nor the proposed construction of the approved LNG terminal projects
listed above (inlcuding in light of the uncertainty of the recently
approved Crown Landing project), would be a viable system alternative to
the Project. The majority of the projects listed above propose to serve
natural gas markets substantially farther north or south of those
intended to be served by the Project. An LNG facility that is not
located within the defined market analyzed by AES could not serve the
Mid-Atlantic Region without substantial expansions of existing pipeline
systems and possibly the addition of compression.

10.4.1.3  Proposed LNG Terminals

Several other proposals for LNG Terminals are pending before the
Commission or USCG, including the following:

**Northeast Gateway** -- (USCG Docket No. 22219) Excelerate Energy LLC
is proposing to construct the Northeast Gateway deepwater port offshore
from Gloucester, Massachusetts. The terminal would have a send-out
capability of an average of 0.8 bscfd. No storage tanks are proposed.
The USCG deemed the Northeast Gateway application complete on September
2005, and the FEIS was issued in October, 2006.

**Neptune** -- (USCG Docket No. 22611) Tractebel (Suez Energy) is
proposing to construct the Neptune deepwater port offshore from
Gloucester, Massachusetts. The terminal would have a send-out capability
of an average of 0.8 bscfd. No storage tanks are proposed. The USCG
deemed the Neptune application complete on October 2005, and the FEIS
was issued in November, 2006.

**Main Pass Energy Hub Deepwater Port Project** -- (USCG Docket No.
17696) Freeport-McMoRan Energy LLC is proposing to construct the Main
Pass Energy Hub Deepwater Port in the Gulf of Mexico offshore from
Louisiana. The terminal would have a send-out capability of an average
of 1.0 bscfd. Natural gas storage facilities have not been proposed. The
NEPA review process was suspended in August 2005.

**Compass Port Terminal Project** -- (USCG Docket No. 17659)
ConocoPhillips is proposing to construct the Compass Port Terminal
Project approximately 11 miles off the coast of Alabama near Dauphin
Island. The terminal would have a send-out capability of an average of
1.0 bscfd with storage facilities for 250,000 m3 of natural gas. The
NEPA review timeline was suspended as of August 2005.

**Beacon Port Deepwater Port Project** -- (USCG Docket No. 21232)
ConocoPhillips is proposing to construct the Beacon Port Deepwater Port
Project off the coast of Louisiana, in the Gulf of Mexico. The terminal
would have a send-out capability of an average of 1.0 bscfd with two
natural gas storage tanks. The NEPA review timeline has been suspended.

**Broadwater LNG Facility** -- (FERC Docket No. PF-05-4-000) TransCanada
Corporation and Shell US Gas & Power LLC are proposing to construct the
Broadwater LNG Facility within the Long Island Sound in New York. The
terminal would have a send-out capability of an average of 1.0 bscfd
with a floating regasification unit with 350,000 m3 of natural gas
storage capacity. Broadwater LNG Facility was filed with the Commission
in January 2006, and the FEIS for the project was issued November 17,
2006. Additional discussion of the Broadwater LNG Facility is provided
in Section 10.5.1.1.

**Casotte Landing LNG** -- (FERC Docket No. CP05-420-000) Bayou Casotte
Energy LNG proposed an LNG facility at Bayou Casotte, Mississippi,
comprising 1.3 bscfd of capacity in three 160,000 m3 tanks. The
application was filed in October 2005, and environmental review is
underway. The proposed Casotte Landing project, to be located adjacent
to Chevron\'s Pascagoula Refinery, will process imported LNG for
distribution to industrial, commercial and residential customers in
Mississippi and the U.S. Southeast region, including the growing Florida
market.

**LNG Clear Energy** -- (FERC Docket No. CP06-12-000, CP06-13-000) Gulf
LNG Energy, LLC has proposed an LNG facility to be located at
Pascagoula, Mississippi and comprising 1.5 bscfd capacity in two 160,000
m3 tanks. The application was filed October 2005. The Project will be
sited on land controlled by the Jackson County Port Authority and
Jackson County. The site is adjacent to the Bayou Casotte ship channel
(east harbor).

**Quoddy Bay LNG** -- (FERC Docket No. CP07-38-000) Quoddy Bay, LLC
proposed an LNG facility at Pleasant Point, Maine and comprising 0.5
bscfd capacity in three 160,000 m3 tanks. The NEPA Pre-filing process
was initiated December 2005 and the formal application was filed in
December 2006. The LNG import terminal will be located at the Pleasant
Point Reservation of the Passamaquoddy Tribe. The storage facility will
be located in the Town of Perry. The Project includes a 35.8-mile
natural gas send-out pipeline to transport natural gas from the LNG
Terminal to the interstate natural gas pipeline in the Town of
Princeton. The send-out pipeline originates at the import facility in
Western Passage of Passamaquoddy Bay, and extends northwest through the
reservation and the Towns of Perry, Pembroke, Charlotte, Cooper,
Alexander and Princeton before reaching the interstate natural gas
pipeline interconnect.

**Conclusions Regarding Proposed LNG Terminal Alternatives**

Given the forecasted decrease in production of natural gas in certain
supply basins, LNG is projected to supply not only incremental increases
in natural gas demand, but it also could replace the projected reduction
in other supply components (i.e., natural gas imports from Canada and
certain United States production basins). Alternatives outside of the
defined market area are not considered commercially feasible for serving
the Mid-Atlantic Region. Delivery of natural gas from LNG terminals and
other sources outside of the defined market would require construction
of additional delivery capacity, over significantly greater distances
than required for in-area projects, with resultant additional
environmental and landowner impacts, effectively limiting them from
serving the Mid Atlantic Region10.

In addition, with respect to terminals proposed in the Northeast, it is
highly unlikely that any natural gas delivered to those terminals could
be delivered to the Mid-Atlantic Region, even assuming the additional
pipeline infrastructure required was constructed, due to the tremendous
demands in the greater New York City region and other nearby areas.
Those demands would effectively siphon off all incremental supplies
before they could reach the Mid-Atlantic Region. Similarly, LNG
introduced into Maine or Massachusetts will be used to meet growing
demand in New England, and therefore would not be available to the
Mid-Atlantic Region.

Moreover, proposed projects without storage capability (e.g.,
Excelerate, Neptune) would only be able to provide interruptible service
as compared to the firm service that likely would be available from the
Sparrows Point Project. [^10] Projects that make use of specialized
ships are similarly prone to interruptions. These considerations make
such alternatives even less viable than other fixed base facilities when
determining their potential use in lieu of the Project proposed by AES.

### Pipeline System Alternatives

An alternative to constructing the proposed Project is utilizing or
expanding existing pipeline systems to provide an equivalent 1.5 bscfd
of natural gas to the Mid-Atlantic Region. The first drawback to such an
alternative is the fact that onshore conventional natural gas production
is anticipated to decline from 4.8 Tcf in 2004 to 4.2 Tcf in 2030, while
net pipeline imports are expected to decline from 2004 levels of 2.8 Tcf
to about 1.2 Tcf by 2030, due to resource depletion and growing domestic
demand in Canada. The decline in overall supply from the west coast of
the United States and Canada is coupled with a projected increase in
consumption from 22.4 Tcf of natural gas in 2004 to 26.9 Tcf in 2030
(EIA 2006). Not only does reliance on this alternative not meet the
Project objective of introducing a new source of natural gas into the
Mid-Atlantic Region, it also has a negative effect on the supply/demand
equation as this alternative looks to decreasing supplies to meet
increasing demands.

The second, more obvious, drawback to this alternative is the fact that
it does not meet the stated Project objective of increasing access for
the Mid-Atlantic Region to world natural gas production centers. The
United States is expected to depend increasingly on imports of LNG to
replace Canadian pipeline imports and tap the world supply of natural
gas. Approximately 74 percent of the world natural gas reserves are
located in the Middle East and Eurasia, compared with less than four
percent within North America (EIA 2006). To meet a projected demand
increase of 4.5 Tcf from 2004 to 2030, and to offset an estimated 1.6
Tcf reduction in pipeline imports, the United States is expected to rely
on the world supply of natural gas through LNG.

Finally, the alternative of utilizing or expanding existing pipeline
systems to provide an equivalent 1.5 bscfd of natural gas to the
Mid-Atlantic Region would not carry the additional benefit of
introducing new facilities for natural gas storage in the Region.

10.4.2.1  Existing Pipeline Systems

Existing pipeline systems in the Mid-Atlantic Region, including those
owned and operated by TETCO, Columbia, and Transco (see Figure 10.4.2-1)
were also evaluated. All of these pipeline systems primarily provide
natural gas from production areas in Canada and the Gulf Coast. Because
the production from conventional natural gas reserves in the United
States and Canada is anticipated to decline, it is unlikely that
pipeline alternatives connected to these reserves would be able to meet
the Project objective of providing up to a maximum rate of an additional
1.5 bscfd of natural gas to the Mid-Atlantic Region (EIA 2006).

Furthermore, even if incremental supplies become available through the
new and proposed Gulf Coast LNG relieving terminals, based on
information obtained during its recent discussions with Columbia,
Transco, and TETCO, AES has determined that the existing pipeline
systems do not have sufficient forward haul capacity to deliver the
incremental volumes proposed by AES without expansion. The Commission's
evaluation of the Columbia and Transco pipeline systems conducted during
the preparation of the Dominion Cove Point Expansion EIS (Dominion FEIS
2006), confirmed that the systems are fully subscribed and there is no
capacity to transport additional gas supplies without substantial
expansion or modifications similar or greater than those proposed by the
Project. Deliveries by AES to these interstate pipelines in the Eagle,
Pennsylvania area will allow delivery of natural gas closer to the
market consuming areas. Volume from these interconnections will be able
to be delivered on a firm back haul basis to markets south and west of
these interconnects, and, at least initially, on an interruptible basis
to markets north and east of these interconnects. In addition, existing
firm shippers would have the ability to segment their existing long haul
capacity by accepting additional supply from the Project, which greatly
increases transportation options available. As the market requires more
incremental firm forward haul delivery capacity expansions from the
point of the proposed Pipeline and forward, those interconnects should
be less costly and have less environmental impact.

It is anticipated that proposals to expand existing pipelines will
continue to increase the capacity of existing natural gas pipeline
systems to the Mid-Atlantic Region. However, these projects alone cannot
meet the Project objective of providing access to new natural gas
supplies from around the world in the Mid-Atlantic Region. Further, the
significant pipeline expansion projects that would be required to
deliver the same gas volumes to the Mid-Atlantic Region as proposed by
AES would typically result in short and long term impacts on water
resources, upland vegetation, wetlands, wildlife habitats, traffic
patterns, and land use, as well as impacts to landowners. In addition to
construction-related effects, the operation of such longhaul pipelines
requires compressor stations that would result in permanent noise and
adverse air quality impacts. Because this alternative does not meet the
Project objective of providing access to new natural gas supplies from
around the world, and there are a vast variety of expansion
alternatives, it was not reasonably practical to attempt to quantify
these impacts.

10.4.2.2  Proposed Pipeline Systems

Current proposals to deliver natural gas reserves from the western
Unites States and Canada to the eastern market were evaluated by AES in
its consideration of potential alternatives to the Project. No similar
project proposals in the Gulf Coast region of the United States were
identified.

Rockies Express Pipeline, which is being developed by Rockies Express
Pipeline LLC, is a joint development between Kinder Morgan Energy
Partners and Sempra Pipeline & Storage (Rockies Express Pipeline 2006).
The project consists of a proposed 1,663-mile natural gas pipeline
system from Rio Blanco County, Colorado, to Monroe County, Ohio.

The Mackenzie Gas Project proposes to build an approximate 760-mile
30-inch diameter pipeline system along the Mackenzie Valley (Mackenzie
2004). The project will connect three discovered natural gas fields in
the Mackenzie Delta - Taglu, Parsons Lake and Niglintgak to distribution
systems in Alberta Canada for transmission to markets in Canada and the
United States. The pipeline is also anticipated to be utilized by other
companies exploring for natural gas in northern Canada to supply as much
as 1.2 bscfd of natural gas through the Mackenzie Valley Pipeline.

While construction of these new pipelines could increase the amount of
natural gas available to the Mid-Atlantic Region, and such new pipelines
might originate at production centers not currently used to supply the
Mid-Atlantic Region, such alternatives cannot meet the Project objective
of increasing access to new natural gas supplies from around the world
in the Mid-Atlantic Region. Further, significant new pipeline
construction projects that would be required to deliver the same gas
volumes to the Mid-Atlantic Region as proposed by AES, typically would
result in short and long term impacts on water resources, upland
vegetation, wetlands, wildlife habitats, traffic patterns, and land use,
and impacts to landowners. In addition to construction-related effects,
the operation of such longhaul pipelines requires compressor stations
that would result in permanent noise and adverse air quality impacts.
Because this alternative does not meet the Project objectives described
above, no attempt was made to quantify these impacts.

## Aboveground Alternatives 

AES conducted an alternatives analysis of all major aboveground
facilities, specifically the location for the LNG Terminal. Other major
aboveground facilities associated with this Project are not anticipated,
including compressor stations along the Pipeline Route. AES also
evaluated design alternative options for the LNG Terminal, including
pier design, regasification methods, and dredge method and dredge
disposal alternatives.

### LNG Terminal Site Alternatives

Following the system alternatives analysis, AES evaluated several
factors to determine the extent to which alternative LNG terminal site
locations would fulfill the purpose for the Project (i.e., introducing a
new incremental supply of natural gas from world production centers into
the Mid-Atlantic Region, which includes the Baltimore area market, to
meet the growing demand for energy in those markets in a safe, reliable
and economic manner). To meet this purpose, AES determined that, at a
minimum, an LNG terminal site would need to satisfy the criteria below.
The noted criteria are listed in no particular order of importance;
rather, all of the criteria are considered important to the
determination of site alternatives.

-   [Geographic Location]{.underline}. Given the impracticality of LNG
    Terminal System Alternatives to serve the intended markets (see
    discussion in Section 10.4.1), it is necessary to locate the Project
    within the Mid-Atlantic Region to allow adequate interconnection
    with existing natural gas pipeline systems in the vicinity of the
    Terminal Site. Furthermore, due to the projected increase in demand
    for natural gas throughout the country, the location of the project
    is crucial to ensure that the increase in capacity (or the great
    majority thereof) is used to satisfy the increased demand within the
    Mid-Atlantic Region.[^11] Because the project also adds storage
    capacity in the region, it will ensure immediate availability
    without regard to pipeline capacity constraints in times of peak
    demands. The specific definition of the intended market area for
    this Project, and the basis for the need for the Project are
    described in Resource Report 1, *General Project Description*¸ in
    Sections 1.1 and 1.2.

-   [Distance from Residential Concentrations]{.underline}. AES
    considered only locations for a terminal site and associated LNG
    transit vessel routes that were -- at all times -- greater than one
    mile from residential communities and population centers. Although
    the Commission has recently approved projects with ship transit
    routes closer to residential areas (Crown Landing -- approximately
    0.6 miles from Wilmington and similar distances from other cities or
    towns in both Delaware and New Jersey; Weaver's Cove --
    approximately 0.5 miles from Fall River), and while not required by
    any applicable regulations or recent practice, AES has made the
    corporate decision to follow this one-mile guideline in order to
    remove certain possible objections (regardless of merit) and thereby
    minimize potential public opposition to the project and the
    attendant costs associated with responding to each opposition. The
    guideline adapted by AES is based on recent studies conducted by
    Sandia National Laboratory (SNL) that sets out a worst-case
    marine-related thermal event as causing potential harm to persons
    within approximately one mile (5,280 feet or 1,600 meters) of an LNG
    spill. Studies cited by SNL corroborate this distance. [^12] This
    distance is also addressed in comments submitted by the LNG
    Opposition Team wherein the group makes citation to Massachusetts
    legislation that would require a terminal set-back distance from
    residential areas of 5,000 feet and a ship transit set-back distance
    of 1,500 feet.

-   [Land Use Compatibility]{.underline}. Development of LNG projects
    has emerged as one of the most contentious energy infrastructure
    issues in recent years. There are several possible explanations for
    the attention such projects have drawn, including (i) the regulatory
    process has encouraged, and sometimes required, public participation
    often prior to the time the applicant has completed site-specific
    studies; (ii) the projects are generally of significant size (a
    project cost of \$500 million is not unusual) so that they are
    difficult to ignore or overlook; (iii) a great deal of
    misinformation exists about LNG; and (iv) because of the relatively
    small number of major LNG import terminals in the United States,
    large scale LNG projects are perceived as unsafe. In such a
    situation, it is incumbent upon the applicant to identify areas for
    potential terminal location that are not inconsistent with existing
    land use and published community development plans. As described
    more fully in Resource Report 5, *Socioeconomics*, and Resource
    Report 8, *Land Use, Recreation and Aesthetics*, the Terminal Site
    was elected because it complied with the industrial zoning
    designation, and does not conflict with the Dundalk Renaissance Plan
    titled *Dundalk, A Second Century Vision*, and the Turner Station
    Community Conservation Plan.

-   [Technical and Economic Feasibility]{.underline}. AES investigated
    the technical and economic feasibility of constructing and operating
    an LNG terminal at the proposed site. Factors considered in this
    investigation included: site access to nearby deepwater port
    facilities (requiring a nominal 45-foot draft); access to adequate
    constructible land (requiring a nominal 40 acres); availability of
    adequate air draft under bridge crossings and distance of bridge
    locations from the proposed site; proximity to (or, preferably,
    location within) natural gas markets intended to be served by the
    Project[^13]; ability of the site to accommodate LNG terminal
    facilities (*i.e.*, vessel berthing and off-loading facilities, LNG
    storage tanks, regasification plant, administration buildings and
    other associated facilities); and ability to avoid or minimize
    disruption of channel traffic while LNG vessels are in transit or at
    berth using the currently published security zones distance
    applicable to the Cove Point facility of 500 yards. 33 CFR § 165.502
    and 503.

-   [Safety and Security]{.underline}. The selected site must be able to
    satisfy all applicable safety and security standards. As pointed out
    in the second criterion above, Distances from Residential
    Concentrations, it may be appropriate to consider going beyond the
    minimum safety and security standards established by the applicable
    regulations to facilitate community acceptance of the terminal.

-   [Site Acquisition]{.underline}. The ability of AES to gain site
    control in a reasonable and timely manner is an important criterion
    in selecting the terminal site as an appropriate location for the
    LNG Terminal. To meet the Commission's requirement that the
    applicant demonstrate site control before filing an application, the
    site must be available to AES (i.e., at open market commercial
    terms, without the need for extraordinary acquisition methods or
    condemnation required for site control).

-   [Environmental Impact]{.underline}. A siting criterion employed by
    AES is the ability to avoid or minimize potential impacts to the
    natural environment, cultural resources and stakeholders associated
    with the proposed Project. The information contained in Resource
    Reports 2 through 13 provides ample evidence that this criterion has
    been satisfied with the selection of the Terminal Site.

Consideration of the criteria noted above led to numerous site
alternatives located both on and offshore within the Mid-Atlantic
Region. Alternatives outside of the general geographic region were not
considered feasible for the reasons described in Section 10.4.1, which
described LNG terminal alternatives in the Gulf of Mexico and northeast
areas of the United States. A discussion of the more important design
features considered by AES, and a review of potential alternative
offshore and onshore site locations based on these design features, is
provided below.

10.5.1.1  Design Factors -- Technical and Economic Feasibility

**Deepwater Access**

Of the design factors, the most important design factor considered by
AES was site access to nearby deepwater port facilities. Without such
access, the LNG ships required to bring the new source of natural gas to
the Mid-Atlantic Region from world production centers could not unload
their cargos. This would serve to frustrate the stated objectives of the
Project. Dredging of any significant magnitude also presents the
potential to seriously disturb or impair the human and natural
environments in the vicinity of the dredging activities. [^14] While
other design factors (e.g., adequate constructible land, adequate air
draft under bridges and distance from bridges, proximity to natural gas
markets intended to be served by the Project and ability of the site to
accommodate LNG terminal facilities) also have the potential to disturb
or impair the human and natural environments, the impacts are
considerably less than the impacts associated with significant dredging
and are considered manageable. Accordingly, AES conducted a detailed
review of vessel drafts and waterway depths.

Within the Mid-Atlantic Region, there are only two waterways with
sufficient depth to potentially accommodate LNG vessel traffic for an
onshore terminal: the Chesapeake Bay region and the Delaware River
region. The Chesapeake Bay region has shipping channel depths of 50 feet
or more. The Delaware River region has shipping channel depths limited
to 40 feet. In order to determine whether the limited depth of the
Delaware River might impact the stated Project objectives, AES retained
marine advisers to review the range of LNG transport vessels anticipated
for use in connection with the Project and opine on the appropriate
range of sizes that would provide the maximum flexibility with respect
to supply source, both now and into the future.[^15] Such vessels
included both the existing world fleet of LNG ships and a limited number
of larger vessels currently in design and/or under construction.

There are currently approximately 207 LNG carriers in service worldwide.
These range in cargo carrying capacity from 1,100 m^3^ to 149,172 m^3^.
A review of the current shipbuilding backlog indicates that there are
currently 145 LNG ships on order (firm and options), out of which only
four have a capacity less than 125,000 m^3^. All four of those smaller
ships are to be dedicated for Coastal and inter-Mediterranean trades.
The remaining vessels on order have a capacity greater than 138,000
m^3^. In light of this above trend, AES has designed the LNG Terminal to
accommodate LNG carriers with a capacity ranging from 125,000 m^3^ to
217,000 m^3^. As outlined in Resource Report No. 1, the anticipated
draft of vessels expected to call at the proposed AES LNG Terminal is
anticipated to range from 37.7 to 40.5 feet.[^16] AES believes that the
use of smaller LNG carriers is not practical, as the current and aging
fleet of small LNG carriers with a capacity less than 125,000 m^3^ is
heavily dedicated[^17], and the vast majority of the proposed LNG
carriers on order have a cargo carrying capacity greater than 138,000
m^3^.

Figure 10.5.1-1 shows the distribution of the drafts for all of the
vessels currently operating in the Atlantic Basin (except the seven
vessels for which draft information was not available). It is important
to note that the distribution shown below is also representative of the
entire fleet of the currently operating LNG carriers in the
above-referenced capacity range.

![](media/image1.jpeg){width="5.997222222222222in"
height="4.101388888888889in"}

Figure 10.5.1-1 -- Distribution of the Draft of LNG Carriers in the
Atlantic Basin with a Cargo Carrying Capacity Greater than 125,000 m3

While it might appear that a vessel draft of 40.5 feet (12.3 meters),
which is the deepest draft vessel proposed to call at the LNG Terminal,
would fit within a 40 foot channel, this is not the case. The required
navigational channel depth is a function of the static draft of the
largest vessel expected to transit the waterway, squat, trim, vertical
ship motion due to wave action, fresh water adjustment, under keel
clearance, and tolerance for dredging and sounding accuracy. For
security, economical and practical reasons, LNG carriers must be able to
navigate at all tide conditions. As such, no tidal allowance must be
considered in defining the required minimum channel depth (i.e., it
cannot be assumed that a vessel will transit a waterway only at high
tide). Table 10.5.1-1 shows, by way of example, the required minimum
channel depth based on vessel transit speed to the proposed Crown
Landing LNG terminal.

Table 10.5.1-1: Minimum Channel Depth Parameters for Safe Transit of LNG
Vessels.

+--------------------------+-------------+---------------+------------+
| Parameters               | > Transit   |               |            |
|                          | > Speed     |               |            |
|                          | > (knots)   |               |            |
+--------------------------+-------------+---------------+------------+
|                          | > 0 to 3.0  | > 6 ^(2)^     | > 10 ^(3)^ |
|                          | > ^(1)^     |               |            |
+--------------------------+-------------+---------------+------------+
| Static Draft             | > 40.5      | > 40.5        | > 40.5     |
+--------------------------+-------------+---------------+------------+
| Squat                    | > 0         | > 0.7         | > 2.3      |
+--------------------------+-------------+---------------+------------+
| Trim                     | > 0         | > 0           | > 0        |
+--------------------------+-------------+---------------+------------+
| Exposure Allowance       | > 0         | > 0           | > 0        |
+--------------------------+-------------+---------------+------------+
| Fresh water Adjustment   | > 1         | > 1           | > 1        |
+--------------------------+-------------+---------------+------------+
| Under keel Requirement   | > 3         | > 3           | > 5        |
+--------------------------+-------------+---------------+------------+
| Dredging Tolerance and   | > 0.5       | > 0.5         | > 0.5      |
| Sounding Accuracy        |             |               |            |
+--------------------------+-------------+---------------+------------+
| Minimum Required Depth   | > 45.0      | > 45.7        | > 49.3     |
+--------------------------+-------------+---------------+------------+

Notes:

\(1\) Final approach to the terminal, turning, and docking

\(2\) Transit to the terminal while made fast to tugs

\(3\) Transit from the mouth of the Delaware to the proposed Crown
Landing LNG terminal

According to the above, the minimum channel depth required for a slow
transit speed is about 45.0 feet and 49.0 feet for a fast transit speed.
Thus, a channel depth of 40 feet as available in the Delaware River
would not be sufficient for Project purposes. [^18] Note that drafts
less than that required for a slow transit speed (i.e., during
tug-assisted maneuvering and docking) are allowed. Given the discussion
above, AES estimated that approximately 59.4 million yards of dredging
would be required to obtain the required depth in the Delaware River to
support the Project. This estimate is based on the current average depth
of the channel of approximately 40 feet, that the required depth is 50
feet, and that the distance from the Brown Shoals to the Crown Landing
facility is approximately 38 miles at a width of 800 feet. The 800 foot
channel width is consistent with information provided in the Crown
Landing FEIS at p. 3-34 (Crown FERC 2006).

**Disruption of Maritime Traffic**

Another important design factor considered by AES was the ability of the
site to avoid disruption of maritime recreational and other commercial
traffic while LNG vessels are in transit or at berth. AES has held
meetings to discuss potential impacts associated with the proposed
project with the Maryland Department of Natural Resources (DNR) Tidal
Fisheries and Sport Fish Advisory Commissions, and with three fishing
associations: the Maryland Waterman's Association, the Maryland
Saltwater Sport Fisherman's Association and the Upper Bay Charter
Captains Association. These three associations were selected in an
effort to cover the range of fishing that takes place in the Chesapeake
Bay -- commercial, recreational and charter boat. The organizations
expressed several common concerns, the most significant being the impact
of a moving security zone that might impact their activities, alleged
overly aggressive enforcement of the existing security zone at Cove
Point by the USCG, and the fear that the same aggressive enforcement
policies would be applied in the upper portions of the Chesapeake Bay.
AES is currently working in conjunction with the USCG to develop LNG
vessel transit schedules and security zones that would provide the
maximum amount of protection for LNG vessels, while at the same time
minimizing disruption to commercial and recreational traffic. Different
approaches to establishing and enforcing a moving security zone around
inbound LNG tankers were explored in an effort to accommodate as many
waterway users as possible, without lessening security to an
unacceptable degree. The potential strategies, including modified
arrival schedules and modified moving security zones for LNG vessels,
fall under the jurisdiction of the USCG. The ultimate strategies to be
applied to the Project will be determined through the Waterway
Suitability Assessment (WSA) process, which is further described in
Resource Report 11, Reliability and Safety.

In a proactive effort to minimize disruption to communities and
commercial and recreational vessel traffic, AES sought out a vessel
transit route that would allow an LNG ship to maintain a minimum one
mile distance from populated shore areas during transit and while at
berth. Additionally, AES sought a berth site where the anticipated fixed
security zone that will be enforced around the berthing area would not
impact other vessels transiting the main shipping channels. [^19] By
locating the berthing area far from the designated transit routes, i.e.,
more than 500 yards, impacts to deeper draft vessels, including both
commercial and recreational, will be minimized. The qualitative
assessment of this design factor led to the same conclusion as the
assessment of the need for deep water access for an onshore facility --
the Chesapeake Bay is the only water body within the general vicinity of
the Mid-Atlantic Region capable of accommodating the objectives of the
Project.

**Conclusions Regarding Design Factors**

Even if it were technically, economically and environmentally feasible
to undertake the dredging required to access sites within the Delaware
River region, AES determined that no site within this region would be
capable of satisfying its other selection criteria, principally the
ability to locate the site and conduct LNG vessel transit one-mile
distant from residential communities and other population centers, and
to minimize impact to other vessel traffic while at berth. In addition,
AES is unable to determine whether it could obtain site control for any
acceptable site in this region on acceptable terms. For these reasons,
AES eliminated those sites within the Delaware River area from its
alternatives evaluation, leaving for further consideration alternative
sites within the Chesapeake Bay area.

10.5.1.2  Offshore LNG Terminal Sites

AES evaluated the feasibility of siting an LNG import terminal at a
deepwater location offshore from the Atlantic Coast within the
Mid-Atlantic Region. Such siting would be compatible with the range of
LNG vessels intended for use in the Project.

AES estimates that construction and operation of an offshore LNG
terminal within the open Atlantic Ocean of the Mid-Atlantic Region would
be extremely difficult due to the wind, wave and current patterns
experienced in this area. Extreme meteorological and oceanographic
forces would result in a shortened construction season and anticipated,
but unpredictable, setbacks due to weather. High wind, wave and strong
current patterns would interfere with safely berthing and mooring LNG
carriers and off-loading LNG, resulting in lost productivity and
deliverability. Furthermore, damage from severe storm events to the LNG
terminal and associated offshore pipeline would further complicate
operation and introduce potential impacts to the environment. These
concerns are especially pronounced in the winter season when storms
(other than hurricanes) in the Atlantic Ocean are more severe. Because
natural gas demands peak in the winter months, such severe weather would
negatively impact the predictable, constant flow of natural gas to the
intended markets.

Offshore locations within the Mid-Atlantic Region would also require
construction of a lengthy offshore and onshore pipeline system to reach
the Project's intended markets. Therefore, with certain limited
exceptions, such a terminal location and pipeline system would not be
considered a commercially viable alternative to the Project. [^20]

Potentially feasible offshore exceptions within the Mid-Atlantic Region
(i.e., offshore locations reasonably proximate to existing onshore or
offshore natural gas pipeline systems) are those off of the south shore
of Long Island and within the Long Island Sound. Locations off the south
shore of Long Island are exposed to the Atlantic Ocean; thus, these
locations likely would present the same wind, wave and current concerns
noted for other offshore locations within the Mid-Atlantic Region. Long
Island Sound, by comparison, is relatively sheltered from those
meteorological conditions characteristic of the open Atlantic Ocean.
However, to meet the stated objectives of the proposed Project, use of
the Long Island Sound offshore alternative would require construction of
a lengthy offshore and onshore pipeline system to reach the Project's
intended markets. [^21] Therefore, such a terminal location and pipeline
system would not be considered a commercially viable alternative to the
Project. Further, as described in more detail below with reference to
the Broadwater Energy LNG Facility, connection to the more reasonably
proximate pipeline systems near Long Island Sound still would not serve
the intended market objectives of the Project.

Broadwater Energy filed an application with the Commission to site,
construct and operate an LNG import terminal in Long Island Sound
(January 2006) and a Final Environmental Impact Statement was issued
November 17, 2006. That project proposes to serve natural gas markets in
New York, New Jersey, and Connecticut through an interconnection with
the existing Iroquois Gas Transmission System. These markets are located
substantially farther north of those intended to be served by the
Sparrows Point Project. Because Broadwater is located in a downstream
market (i.e., Long Island Sound) it would be able to provide service
only to certain markets that are within the defined market segment
intended to be served by the Project (i.e., New York and New Jersey). It
could not also serve markets that are at the southern limits of the
defined market analyzed by AES, such as North Carolina. To set realistic
boundaries on the market demand analysis, certain reasonable assumptions
were therefore made regarding markets and supply sources in the CEA
report.

AES also considered the feasibility of siting an LNG terminal at an
offshore location within the Chesapeake Bay. However, if sited within an
existing deep water channel, AES determined that such an alternative
location could have a significant adverse impact on commercial maritime,
recreational, and commercial and recreational fishing vessel traffic
within the Bay, due to the safety and security zones that likely would
apply to the offshore terminal location. [^22] Outside of the main
deepwater channel located in the center of the Chesapeake Bay, the
Chesapeake is a shallow estuary with an average depth of approximately
21 feet (Chesapeake Bay Foundation 2006). A location within the Bay, but
outside of an existing deep water channel, at a distance greater than
500 yards from the existing deep water channel for the security buffer,
and north of the southernmost onshore alternative sites described in
Section 10.5.1.2, was also eliminated from further consideration due to
the need to undertake significant dredging to accommodate the
anticipated draft of the LNG transport vessels and the proximity to
population centers. The only other locations within the Bay wide enough
to avoid significant impacts to vessel traffic when considering the
applicable safety and security zones would be those located farther
south than the proposed Terminal Site. Such locations would add
significant length to the natural gas send-out pipeline, thereby
increasing the potential environmental impacts associated with
construction and decreasing the economic viability of the Project.

Based on the above considerations, AES concluded that an offshore
terminal location, whether sited along the Mid-Atlantic seaboard or
within the Chesapeake Bay, would not be a feasible alternative to the
proposed Terminal Site.

10.5.1.3  Onshore LNG Terminal Sites

As noted above, AES determined that the only sites sufficiently
proximate to the natural gas markets that the Sparrows Point Project is
intended to serve, while providing a waterway having sufficient depth
and capacity to accommodate LNG vessel traffic, would need to be located
in the Delaware River or Chesapeake Bay regions. Upon further
investigation, AES determined that the depth of the approach waterways
in the Delaware River, and the narrowness of the Delaware River shipping
channel to population centers, effectively ruled out any alternative
site location within that area. Accordingly, AES limited its search of
alternative onshore sites to locations within the Chesapeake Bay.

[Alternative Onshore Sites]{.underline}

Within the Chesapeake Bay area, AES identified several alternative
locations to the Terminal Site for further evaluation, including: (1)
two sites near Cove Point, Maryland; (2) Greenbury Point; (3) Fishing
Point and other sites within the Baltimore Inner Harbor; (4) Swan Creek
immediately south of the Key Bridge; (5) Kent Island; and (6) an
alternative Sparrows Point peninsula site (Mittal Steel site). Each of
these alternative onshore site locations is discussed below. Figure
10.5.1-2 identifies the locations of the proposed alternatives.

The analysis was conducted using existing resource information available
on United States Geological Survey (USGS) 7.5-minute series topographic
quadrangle maps; Maryland Geographic Information System (GIS) data
layers; other available federal, state, and county resource maps; recent
high resolution aerial photography; and unmapped data. The analysis
focused on an evaluation of terminal site proximity to population
centers, as well as factors applicable to a send-out pipeline, including
route length, feasibility of using existing corridors, need for crossing
existing transportation features, the presence of wetlands and
waterbodies, threatened and endangered species and significant habitat,
land uses and vegetation cover types, the presence of federal and state
lands, and several other special land uses. A tabular summary of this
analysis is included within Table 10.5.1-2: Comparison of Proposed LNG
Terminal Location and Seven Alternative Locations for the AES Sparrows
Point Project.

Locations for the AES Sparrows Point Project:

[Proposed Sparrows Point Site]{.underline}

As compared to each of the alternative onshore sites, the proposed
Terminal Site is located relatively distant -- more than one mile --
from the nearest residential community, but still within an
industrially-zoned port area that is fully capable of supporting the
facilities and vessel traffic proposed by AES (Figure 10.5.1-3). The
separation distance of over one mile is maintained along the entire LNG
vessel transit route up to the Terminal Site. In addition, the proposed
Terminal Site is capable of satisfying all federal safety and security
requirements applicable to the design, construction and operation of LNG
terminal facilities and transit of LNG vessels. Construction of the LNG
Terminal within an existing industrialized area will avoid and minimize
the potential environmental impacts associated with the Project.
Further, the relatively close access to an existing well-maintained,
deep draft shipping channel will minimize potential impacts associated
with additional dredging that is needed to accommodate the range of
vessels being considered by AES for delivery of LNG to the proposed
Terminal Site.

Finally, consideration was given to the environmental and economic
feasibility of routing the Pipeline from the alternative LNG terminal
sites to the intended interconnection points. The proposed Terminal
Site, by comparison to the alternative sites considered, provides
superior access to existing utility ROWs, and thereby would minimize the
potential landowner and environmental impacts associated with
construction of the Pipeline required to connect the LNG Terminal to
both the local and the interstate natural gas pipeline grid. For these
reasons, AES determined that the proposed Terminal Site at Sparrows
Point, relative to any of the alternative terminal sites, would provide
the most favorable location for the Project.

[Two Sites Near Cove Point, Maryland]{.underline}

AES evaluated the area in the vicinity of the existing LNG terminal at
Cove Point, Maryland to identify an alternative location that would
satisfy its siting criteria. Specifically, AES was able to identify two
locations north of Cove Point that have limited industrial zoning
designations and for which the distance between the shipping channel and
the shoreline is one mile or greater: (1) the existing Dominion Cove
Point LNG terminal facility; and (2) the Calvert Cliffs Nuclear Power
Plant. Figure 10.5.1-4 identifies the locations, zoning designations and
key features (e.g., residential areas and shipping channel) for Calvert
Cliff's Nuclear Power Plant, and Figure 10.5.1-5 identifies the same for
the Dominion Cove Point alternative.

The existing Dominion Cove Point LNG terminal site would not satisfy
several of AES's screening criteria (Table 10.5.1-2: Comparison of
Proposed LNG Terminal Location and Seven Alternative Locations for the
AES Sparrows Point Project). AES would be unable to maintain a distance
of at least one mile between its onshore LNG storage tanks and the
closest residential communities (the nearest residential communities are
located less than one-third of a mile from the existing Dominion Cove
Point LNG storage tanks). In addition, unless AES were to construct an
offshore unloading platform similar to the existing Cove Point facility,
along with all the accompanying environmental impacts associated with
the construction and maintenance of such a structure, the final transit
location of the LNG vessels would also be within approximately one-third
of a mile from residential areas. The Cove Point unloading facility is
approximately the same distance to residential areas as the onshore
unloading facilities proposed by AES as part of the Sparrows Point
Project. Finally, collocation of the Project adjacent to the Dominion
Cove Point LNG terminal facilities also would result in greater
potential environmental impacts as compared to the proposed Terminal
Site because of the significantly longer length of the pipeline that
would be required to reach the terminus point near Eagle, Pennsylvania,
the absence of an existing utility corridor in this area through which
the pipeline could be routed, and the need to clear undeveloped land to
support the terminal facilities.

The existing Calvert Cliffs Nuclear Power Plant site is located
approximately one mile from the closest residential communities, though
any collocated LNG terminal facilities would be sited within this
one-mile separation distance (Table 10.5.1-2: Comparison of Proposed LNG
Terminal Location and Seven Alternative Locations for the AES Sparrows
Point Project). This factor fails to satisfy AES's site screening
criteria. In addition, this site also would require the use of a
significantly longer length of pipeline (147.7 miles required to
interconnect near Eagle, PA) and lacks availability of an existing
utility corridor. In addition, the Calvert Cliffs Nuclear Power Plant
owner has announced plans to expand its facility. The Board of County
Commissioners (BOCC) for Calvert County voted to enter into an Agreement
with Constellation Generation Group, LLC (CGG) that could add a third
reactor at the Calvert Cliffs Nuclear Power Plant. Calvert Cliffs
Nuclear Power Plant currently houses two nuclear reactors that came
online in 1975 and 1977. The facility was originally designed for four
reactors. Finally, AES does not anticipate that it would be able to
obtain site control in this location within a reasonable and timely
manner.

On the above bases, the two alternative sites located near Cove Point,
Maryland were determined to be significantly less preferable than the
proposed location at Sparrows Point.

[Greenbury Point]{.underline}

AES evaluated the feasibility of siting its proposed LNG terminal
facilities at Greenbury Point on the north side of the mouth of Severn
River (Table 10.5.1-2: Comparison of Proposed LNG Terminal Location and
Seven Alternative Locations for the AES Sparrows Point Project). This
alternative location was determined to be significantly less preferable
to the proposed Sparrows Point location because of the proximity
(approximately less than 0.5 miles) of Greenbury Point to the closest
population centers (this site is zoned for residential use), the need to
construct a significantly longer natural gas pipeline (107.5 miles
required) to reach the terminus point near Eagle, PA (thereby increasing
the potential environmental impacts associated with construction of the
Project), and the more remote location of this site from the Chesapeake
deep water shipping route (greater than a three-mile distance), which
would require a greater area affected by dredging. AES also determined
that Greenbury Point's relatively close proximity to an existing Naval
Air Station (1,100 feet to the west-northwest) and Naval anchor zones
(4,200 feet to the west) likely could present potential conflicts with
U.S. military installations and operations. Figure 10.5.1-6 identifies
the location and key features of the Greenbury Point alternative site.

[Fishing Point and Other Sites Within the Baltimore Inner
Harbor]{.underline}

AES evaluated an alternative site in an existing industrialized area
north of the Key Bridge at Fishing Point, which is situated on the north
side of Curtis Bay. Figure 10.5.1-7 identifies this alternative site
location and key site features.

AES determined that this site would be significantly less preferable to
the proposed Terminal Site because transit of LNG vessels within the
Baltimore Inner Harbor would have a greater impact on commercial and
recreational vessel traffic and require substantially more dredging
(Table 10.5.1-2: Comparison of Proposed LNG Terminal Location and Seven
Alternative Locations for the AES Sparrows Point Project). Further, the
Pipeline would need to be routed through highly congested areas within
the City of Baltimore (thus increasing potential landowner impacts), and
the overall length of the Pipeline would be longer in order to reach the
terminus point near Eagle, PA (thus increasing construction-related
impacts). Additionally, installation of the gas pipeline across the main
shipping channel to the port of Baltimore at a depth that would avoid
impact to maintenance dredging, potential expansions by the port, and
shipping traffic during construction, cause this alternative to be cost
prohibitive and technically not feasible. While the terminal would be
located approximately 1.2 miles from the nearest residential
communities, by necessity the turning basin would bring LNG vessels
within 3,500 feet of the nearest residence. The factors described above
have eliminated the Fishing Point site from further consideration.

The potential sites in areas north of the Key Bridge were eliminated
generally from further consideration because such sites were (1)
occupied by BG&E facilities, (2) slated for future expansion by the Port
of Baltimore or (3) occupied or slated to be occupied by other
commercial or industrial users. In other words, AES could not obtain
site control at these potential alternative locations.

[Swan Creek]{.underline}

The Swan Creek site, which is located in an existing industrialized area
south of the Key Bridge and across the deep water channel from the
proposed site at Sparrows Point (i.e. south of Hawkins Point and north
of Cox Creek), was determined to be significantly less preferable than
the proposed Terminal Site at Sparrows Point for the reasons set forth
below. Figure 10.5-8 identifies this alternative site location and key
site features. Table 10.5.1-2: Comparison of Proposed LNG Terminal
Location and Seven Alternative Locations for the AES Sparrows Point
Project, summarizes the siting criteria of this alternative.

The alternative Swan Creek site is located less than one mile from the
closest residential communities. At this location, AES would need to
locate its proposed berthing facilities in an area that would require
greater dredging to avoid potential interference with shipping traffic
in the channel (in this area, the distance from the Brewerton Channel is
approximately 1.2 to 1.3 miles, and water depth is more shallow than
that along the Sparrows Point marine channel). Extensive filling of
wetlands (approximately 6.3 acres required) also would be required to
accommodate the LNG Terminal facilities, which may interfere with the
Maryland Port Authority's long-term dredge disposal plan that is being
implemented. This site would require construction of a longer natural
gas pipeline (91.3 miles required to access the Eagle, PA
interconnections) that either would have to be routed through
highly-congested areas to the south and west, or would require crossing
of the Patapsco River in order to follow a route similar to the proposed
route for the Sparrows Point site.[^23] Even if the Pipeline were routed
across the Patapsco River, the Pipeline would need to be installed at a
depth and with a sufficient buffer on either side of the River to
accommodate future deepening and widening of the River. Such a crossing
likely would span several miles in length, and could not be completed
using horizontal direction drill methods because of its length and
depth. If the crossing were completed using conventional methods,
construction of this segment of the pipeline would have considerable
potential impacts on commercial and recreational traffic, in addition to
increased environmental impact. The Swan Creek site thus was considered
to be a significantly less preferable alternative to the proposed
Sparrows Point site.

[Kent Island]{.underline}

AES evaluated an alternative site located on the north end of Kent
Island on the eastern side of the Chesapeake Bay. Figure 10.5.1-9
identifies this alternative site location and key site features.

This site also was eliminated from further consideration because the
site is located relatively close (approximately less than 0.5 miles) to
the nearest residence, and the size of the existing industrial zoned
area is not sufficient to accommodate the proposed LNG terminal
facilities, meaning that AES would need to obtain an industrial zoning
designation for adjacent land (Table 10.5.1-2: Comparison of Proposed
LNG Terminal Location and Seven Alternative Locations for the AES
Sparrows Point Project). For these reasons, the Kent Island alternative
was determined to be significantly less preferable than the proposed
site at Sparrows Point.

[Alternative Sparrows Point Site - Mittal Steel]{.underline}

AES investigated the possibility of siting its proposed terminal and
berthing facilities at certain locations further south along the
Sparrows Point peninsula, each of which currently is owned by Mittal
Steel USA (Mittal). Figure 10.5.1-10 identifies this alternative site
location and key site features. Table 10.5.1-2: Comparison of Proposed
LNG Terminal Location and Seven Alternative Locations for the AES
Sparrows Point Project, summarizes the application of AES's siting
criteria to this alternative. AES determined that it could not obtain
site control in these locations in a reasonable and timely manner
because of ongoing corporate strategies at Mittal and its parent company
that affect site ownership. Specifically, Mittal acquired the property
from International Steel Corporation (ISC) in 2005, [^24] and has been
working since that time to coordinate the Sparrows Point operation into
the operations of the larger company. In early 2006, a new plant manager
was appointed. Then, in June 2006, Mittal officials announced that it
had begun to showcase the steel mill to potential buyers, believing that
it might have to sell the plant for antitrust reasons arising out of a
takeover conflict for its biggest global rival, Arcelor SA. In July
2006, Mittal announced that it had successfully taken over Arcelor after
a five-month battle. On September 27, 2006, Mittal announced that it
planned to sell another mill rather than Sparrows Point if it were to be
compelled to dispose of a property located in the United States to
settle antitrust issues; however, the Justice Department must sign off
on which plant is sold and to what buyer.

Given the ongoing corporate activities at Mittal, the uncertainty as to
the timing of the resolution thereof, and the uncertainty as to the
timing of (or even any expression of interest in) negotiations with AES
for site use or acquisition, AES would not be able to demonstrate site
control as required by Commission regulations for submittal of its
application.

In addition to the ongoing corporate activities at Mittal, AES also
understands that the State of Maryland is evaluating the feasibility of
using a portion of the Mittal site for future dredged material placement
activities in support of a long-term dredged material management plan
and possible future marine terminal facilities for the Port of
Baltimore. Such evaluation has been ongoing for more than 10 years.
While dialogue with community, recreational, and environmental
stakeholders to address a variety of issues is ongoing, no decision on
this possible use of Sparrows Point is expected in the near future. Any
decision to pursue Sparrows Point as a dredged material management
project would initiate the multi-year NEPA process.

For the reasons provided above, location of the LNG Terminal and
berthing facilities further south along the Sparrows Point peninsula is
not considered to be a viable alternative for the proposed Project.

### Terminal Design Alternatives

10.5.2.1  Pier Designs

AES originally considered a pier design that would require installation
of pipe cylindrical piles that would support a concrete deck and
unloading platform. The pier would extend approximately 1,000 feet from
the shoreline and would require additional piles for mooring and
breasting dolphins to moor the ships. Upon review of public and agency
comments and consideration of potential environmental impacts, the pier
design was changed to utilize an existing structure, Pier 1, thereby
eliminating the need for installation of additional piles for the pier
or the breasting and mooring dolphins. The locations of the proposed
(preferred) and alternate pier locations are shown on Figure 10.5.2-1. A
more detailed description of the proposed pier design is included in
Resource Report 1, General Project Description. A discussion of the
relative merits of the alternate pier designs is set forth below.

[Preferred Design:]{.underline}

Advantages associated with the preferred pier design and location
includes the following:

-   The preferred pier design location will dramatically reduce the
    quantities of dredge material. AES estimates that the total dredge
    quantity will be reduced by approximately 1.7 million cubic yards to
    approximately 3.8 million cubic yards from the Alternate Pier
    design, which translates to overall less potential environmental
    impact while dredging and greater economic viability.

-   The existing pier structure will need only to be resurfaced and
    existing piles repaired. Additional piles into the water bottom will
    not be required; therefore, there will be no permanent bottom impact
    caused by driving piles for the pier or dolphins.

-   Security buffers at Pier 1 are provided by Pier 3. The existing Pier
    3 essentially acts as a screen that prevents small craft from having
    access to the ships. The screen provided by Pier 3 also allows for
    better overall security of the ship while it is berthed.

-   Environmental operating conditions are improved as this location
    provides for better shelter from environmental conditions, such as
    wind and wave action, which ultimately increases the berth
    availability of this location.

-   Cost effectiveness is enhanced due to reduced dredging and lower
    overall construction costs of building a pier from scratch.

-   A significant amount of wet bottom will be re-established as AES
    demolishes and removes Pier 2 in order to accommodate the vessels on
    the northern side of Pier 1.

There are also certain real or perceived disadvantages associated with
the proposed location of the LNG pier as compared to a location further
away. Perceived disadvantages associated with the preferred design
include the following:

-   The preferred design is located closer (approximately 5,808 feet
    from the nearest residence in Turner Station) to residential
    populations than the Alternate Pier design; however, the distance is
    still in excess of the one-mile guidance used by AES in its site
    selection criteria. The closest point of the turning basin
    associated with the proposed pier is located 4,950 feet from the
    nearest residence in Turner Station; however, the nearest residence
    in Turner Station to the bow of an LNG ship in the turning basin
    would still be 5,600 feet.

-   Security control may be perceived to be lessened while ships are at
    the berth because the preferred location is closer to Pier 3, which
    is not anticipated to be controlled by AES. This concern is
    mitigated by the fact that the security control or potential threats
    are not likely to change based on the slightly closer distance.
    Also, it is expected that the entire Sparrows Point peninsula will
    be an International Ship and Port Security code ISPS port facility
    and subject to similar safety procedures used by the LNG terminal.

-   The preferred pier location is closer to Bear Creek, which may have
    some impact on deep-draft recreational/commercial boats should these
    vessels be required to transit outside of the security zone while
    the LNG vessels are maneuvering. In conjunction with the USCG, AES
    will establish a fixed security zone around the marine side of the
    Terminal Site that will offer the maximum level of protection for
    the LNG Terminal and minimize the potential for impacts to
    commercial and recreational vessel traffic. At this time it is not
    anticipated that the fixed safety/security zone will impact
    commercial and recreational traffic utilizing the Bear Creek
    entrance channel. However, the moving safety/security zone that will
    be established for loaded LNG ships in transit may have a temporary
    impact on deeper draft recreational or commercial vessels during
    incoming maneuvering operations in the proposed turning basin,
    depending on the size of the safety/security zone as determined by
    the USCG.[^25] The incoming maneuvering operations are anticipated
    to last approximately 45 minutes based on real-time simulations
    performed for vessel transit evaluation from the Brewerton Channel
    to the dock at the LNG Terminal. Because the safety/security zone
    moves with the vessel, the potential disruption to deeper draft
    commercial or recreational vessel traffic transiting to or from Bear
    Creek (depending on the size of the zone as determined by the USCG)
    would be much less than the full transit time.

[Alternate Pier]{.underline}: This is a pier located at the site in
between Pier 1 and the Graving Dock. Advantages associated with the
Alternate Pier design include the following:

-   Location central to Terminal Site would allow for a shorter overall
    length of the unloading and vapor return lines. This would be an
    economic advantage.

-   This design would have the pier located approximately 6,608 feet
    from the nearest residence in Turner Station. Because the preferred
    design also maintains a separation distance greater than one mile,
    this advantage was not considered to be significant. The closest
    point of the turning basin associated with this alternative is
    located 6,000 feet from the nearest residence in Turner Station, and
    the closest point in Turner Station to the bow of the LNG ship would
    be 6,400 feet.

-   The Alternate Pier design contemplated removal of some of the finger
    piers along the shoreline. This would provide for establishment of
    additional wet bottom. Because the preferred design also
    contemplates the removal of approximately the same square footage by
    dismantling Pier 2 as the finger piers, this advantage is negated
    when comparing to the preferred design.

-   Environmental operating conditions, such as wind and wave action,
    are generally favorable at this location, which ultimately increases
    the berth availability of this location, but they are slightly less
    favorable than the preferred location due to Alternate Pier's closer
    distance to more open water.

Disadvantages associated with the Alternate Pier design of the LNG pier
include the following:

-   The Alternate Pier location and design would require higher
    quantities of dredging than the preferred design (estimated
    quantities of dredging required for this design are 5.5 million
    cubic yards). Additional dredging would lead to additional bottom
    impact during construction from dredging, recycling process,
    temporary storage and transportation to a final disposal area.

-   Installation of a new pier as contemplated by the Alternate Pier
    design would require installation of new piles to support the pier.
    Approximately 340 piles with an expected permanent bottom impact of
    3,060 square feet would be required for installation of the pier,
    platform and dolphins. This additional permanent bottom impact
    compares quite unfavorably to no bottom impact (or positive bottom
    impact if accounting for the removal of Pier 2) associated with the
    preferred design.

-   Site access to the pier due to the location of the pier in the
    center of the Terminal Site is more difficult than the preferred
    design. Such location would require that most maintenance work be
    performed off of barges. Due to the central location of the
    alternate pier alignment and proximity to the flood wall and LNG
    tank area, AES would have to design an access road to the pier over
    the top of the flood wall and down to the pier elevation. Because
    there is less than half of the area to accommodate such an access
    way compared to the preferred design, the access way would need to
    be made very narrow in comparison. The narrow access way and rather
    steep incline would limit vehicle access to the pier from the shore.
    Therefore, the majority of the maintenance required on the pier
    systems would need to be performed by using a barge as a working
    platform. This would increase the overall cost of maintenance as
    well as duration of the maintenance period. Although the preferred
    pier layout does not totally eliminate the need to perform barge
    maintenance on some pier systems, the design greatly enhances the
    ability to access pier systems from the shore using more
    conventional work equipment due to the width of the access way and
    gradual elevation change from the site road ways to the pier.

-   The cost of the additional dredging and associated reclamation, as
    well as the capital cost for this installation, makes this option
    the more expensive option considered.

10.5.2.2  Regasification

[Preferred Design]{.underline}

The preferred option for regasification methods involves the use of
steam from a boiler to warm an intermediate High-Temperature Fluid (HTF)
that will be circulated through a shell and tube vaporizer used to
vaporize the LNG.[^26] A schematic diagram of this process is shown in
Figure 10.5.2-2. Advantages inherent in this design include the
following:

-   Operation. The preferred design allows ease of operation and
    transfer of heat into the LNG at relatively high efficiencies.

-   Emissions for this process can be easily controlled and minimized to
    the lowest achievable levels using existing proven technology.

-   The preferred design allows for the integration of other heat
    sources into the vaporization loop with little or no impact on the
    current operation. Additionally, this system allows for the addition
    and integration of the combined cycle cogeneration Power Plant,
    presently being considered by AES, which will produce power using
    the natural gas that would have been used in the boilers. Natural
    gas consumed in the Power Plant produces waste heat that may be used
    in the LNG vaporization cycle and generates needed power for the
    area, thereby improving the overall efficiency of both operations
    with little to no increase in overall environmental impacts. The
    Power Plant is consistent with the policy underlying the Maryland
    Healthy Air Act of 2006, which mandates reductions from certain
    units at existing coal-fired power plants of 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). 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 (such as this area of
    Baltimore), clean-burning options such as those summarized here 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 will be less than would be
    experienced were a generating option with higher air emissions to
    fulfill that same demand.

-   Intermediate fluid loop. There is an intermediate loop of HTF that
    provides for additional protection from freezing of the vaporizers
    and also provides another system barrier between the LNG and other
    plant processes.

There also are certain disadvantages associated with the use of steam
from a boiler to warm an intermediate fluid that would be circulated
through a shell and tube vaporizer used to vaporize the LNG. Perceived
disadvantages include the following:

-   Efficiency. Initial efficiency of this operating cycle might be
    lower than those presented as alternates; however, the longer term
    integration with the combined cycle facility far outweighs any
    options presented in terms of overall emissions and cycle
    efficiencies.

-   Ease of operation. The preferred design is slightly more complicated
    than the other alternatives presented but not so much that it
    creates an impediment to overall plant safety and reliability.

Emissions are presented below in Table 10.5.2-1 for comparison.

Table 10.5.2-1 Emissions Associated with Alternative Regasification
Methods

  ------------------- ------------------------------ ------------------------- ----------------------
  **[Option           **[Technology]{.underline}**   **[Emission               **[Annual NOx
  \#]{.underline}**                                  Controls]{.underline}**   Emissions
                                                                               (TPY)]{.underline}**

  Preferred           Steam Boilers                  Low NOx Burners, Flue Gas 23
                                                     Recirc, SCR               

  1a                  Submerged Combustion           Conventional NOx Design   167.5
                      Vaporizers                                               

  1b                  Submerged Combustion           Low NOx Burners           54
                      Vaporizers                                               

  2a                  Gas Fired Heaters              Conventional NOx Design   175.5

  2b                  Gas Fired Heaters              Ultra Low NOx             56

  3                   Sea Water Vaporization         N/A                       0\*
  ------------------- ------------------------------ ------------------------- ----------------------

\* Due to cold seawater temperature, supplemental heating would be
required during cold months of the year; this table does not reflect NOx
emissions associated with impacts from these differing emissions.

[Alternative 1 (a & b)]{.underline}: Submerged Combustion Vaporizers
(SCV)

This system uses a burner to discharge heat from combustion directly
into a water bath. A schematic diagram of this process is shown in
Figure 10.5.2-3. The water bath is the medium to transfer heat to the
submerged LNG heating coil. Once the exhaust gases have transferred
their heat to the water bath they are exhausted out the stack. The water
bath continually transfers heat from the warmed water to the heating
coil thereby heating the LNG and causing a phase change from liquid to
gaseous state. The use of SCV offers certain advantages and
disadvantages as set forth below. Considering all factors, AES has
determined that the disadvantages outweigh the advantages when compared
to the preferred method of vaporization.

Advantages:

-   Simple operation. Use of the SCVs allows for easy integration with
    the cycle to vaporize LNG. As a result, operation of these units is
    fairly common in the LNG industry.

-   High efficiency. The SCVs have a relatively high efficiency rating
    that is slightly greater than that available from the preferred
    option.

Disadvantages:

-   The environmental impacts associated with the SCVs are greater due
    to the fact that overall air emissions cannot be controlled as well
    as in the case of the preferred option using existing proven
    technology. This would lead to an overall increase in annual air
    emission levels at the Terminal Site to vaporize the same quantity
    of gas.

-   The discharge system generates an acidic waste stream that needs to
    be neutralized prior to discharge, which increases overall
    maintenance requirements on the equipment.

-   Integration. The system does not integrate with The AES
    Corporation's potential future plans to build the cogeneration Power
    Plant, which means that the SCVs will be required to vaporize gas
    regardless of whether or not the cogeneration Power Plant is
    operating. The LNG Terminal would not be able to take advantage of
    waste heat from the cogeneration Power Plant cycle. This would
    increase overall emissions on an annual basis and reduce efficiency
    overall.

[Alternative 2 (a & b)]{.underline}: Gas Fired Heaters (GH)

This system uses a closed loop circulating HTF system for transfer of
heat from a gas-fired heater directly to the HTF. A schematic diagram of
this process is shown in Figure 10.5.2-4. The HTF is circulated through
the vaporizer where it transfers its heat to the LNG. The LNG enters the
vaporizer in liquid form and due to the heat transferred from the HTF
system, changes state and leaves the vaporizer in gaseous form. The use
of GH offers certain advantages and disadvantages as set forth below.
Considering all factors, AES has determined that the disadvantages
outweigh the advantages when compared to the preferred method of
vaporization.

Advantages:

-   Simple operation. Use of the GHs allows for easy integration with
    the cycle to vaporize LNG. As a result, operation of these units is
    fairly common in the LNG industry.

-   High efficiency. The GHs have a relatively high efficiency rating
    that is slightly greater than that available from the preferred
    option but less than the SCVs (Alternative 1).

Disadvantages:

-   The environmental impacts associated with the GHs is greater due to
    the fact that overall air emissions cannot be controlled as well as
    in the case of the preferred option using existing proven
    technology. This would lead to an overall increase in annual air
    emission levels at the Terminal Site to vaporize the same quantity
    of gas.

-   Integration. Because the system will operate at a higher
    temperature, the system does not integrate easily with AES's
    potential plans to build a cogeneration facility. This means that
    the GHs will be required to vaporize gas regardless of whether or
    not the cogeneration Power Plant is operating. The LNG Terminal
    would not be able to take advantage of waste heat from the
    cogeneration cycle, which would increase overall emissions on an
    annual basis and reduce efficiency overall.

[Alternative 3]{.underline}: Direct Seawater Vaporization

This system uses an open loop that requires water to be drawn directly
from the Chesapeake Bay, circulated through a shell and tube heat
exchanger where heat is transferred from the relatively warm water to
the colder LNG, and then returned back to the Bay at a much cooler
temperature. A schematic diagram of this process is shown in Figure
10.5.2-5. The LNG enters the shell and tube heat exchanger in liquid
form and due to the heat transferred from the water system, changes
state and leaves the vaporizer in gaseous form. The use of a direct
seawater vaporization system entails certain advantages and
disadvantages as set forth below. Considering all facotrs, AES has
determined that the disadvantages outweigh the advantages when compared
to the preferred method of vaporization.

Advantages:

-   Operation of this type of system is the simplest of all
    revaporization alternatives. Under this method, seawater would be
    withdrawn from the Patapsco River, run through a shell and tube heat
    exchanger or an open rack vaporizer where the LNG would be
    vaporized, then discharged back to the Patapsco River at a lower
    temperature.

-   There are no combustion emissions from this process other than for
    the power required to run the pumps, and for the periods during the
    colder months where vaporization would need to be supplemented by
    other means of heating (e.g., SCVs, GHs).

Disadvantages:

-   The volumes of seawater that would be required to be pumped out of
    the Patapsco River and then returned substantially cooler than their
    original condition would result in significant impacts to aquatic
    life. For this reason alone, this option was considered to be the
    least desirable of all presented.

-   The overall available heat from the Patapsco River is limited to the
    warmer periods of the year; therefore, supplemental heating would be
    required during winter months from additional equipment installed at
    the facility such as SCVs or boilers to meet supply commitments of
    the facility. This unnecessary duplication of equipment would result
    in economic waste.

-   The National Oceanic Atmospheric Administration National Marine
    Fisheries Service generally considers the aquatic impacts of this
    vaporization method unacceptable for locations within estuaries, due
    to the demand for high volumes of water and the associated
    impingement and entrainment impacts to aquatic life.

10.5.2.3  Dredge Method Alternatives

Construction of the proposed LNG Terminal will require offshore dredging
to widen and deepen the existing approach channel and create a turning
basin, both of which are necessary to safely accommodate the range of
LNG ships intended to be used to deliver LNG to the Terminal Site.
Dredging of the main approach channel is expected to be completed
primarily with the use of mechanical clamshell dredge or, if and where
required based on sediment composition and quality, an environmental
bucket technology. These same techniques will be used for dredging the
turning basin that will be located between the point where the approach
channel reaches the floating dry dock, the graving dock and the berthing
area. Limited near-shore areas will be excavated by backhoe dredge to
create new water bottom area at the east end of the berthing pier.

AES evaluated the use of hydraulic dredging as an alternative to its
proposed dredge methods. The use of hydraulic dredging was determined to
be less preferable than the proposed methods due to several factors,
including the increased volume of throughput, the large dewatering area
required, decreased rate of dewatering due to increased mixing of dredge
material in water, greater processing time, and greater potential
environmental impact due to suspension and dispersion of sediment
associated with the use of hydraulic dredging. As compared to hydraulic
dredging, the use of clamshell or bucket dredging will involve a lower
throughput volume, smaller dewatering area due to the use of barges to
complete the majority of the dewatering process and a smaller upland
area required to complete the processing of dredge material recycling,
and shorter overall processing time. AES's proposed dredging method
therefore was determined to be preferable to the use of hydraulic
dredging.

Turbidity, a measure of water clarity that is sometimes used as a proxy
for suspended sediment concentration, will be monitored during the
dredging operation. Various governmental sources report that the highest
turbidity production arises from dredging methods resulting from
conventional clamshell bucket mechanical dredging (USACE, 2001). The
lowest turbidity concentrations in dredging result from the use of
suction dredging technology. Environmental bucket mechanical dredging
methods result in turbidity levels between the suction dredging method
levels and conventional bucket mechanical method levels. In terms of
turbidity comparison for mechanical dredging utilizing a conventional
clamshell bucket versus an enclosed environmental clamshell bucket,
evidence indicates that the enclosed bucket will result in a 76-79
percent reduction in turbidity concentrations (USACE 2001).

Disposing of dredged materials in a confined disposal facility or at an
upland processing facility would not result in any turbidity in open
water other than that possibly generated by prop wash from tending
vessels (generation of prop wash depends on draft of the vessels, power
applied and depth of the waterway being traversed). No turbidity is
generated from mechanically offloading dredged material into a
processing system. Also, there is no turbidity generated by offloading
scows hydraulically into a confined disposal facility (except within the
cell itself). The only disposal method that would generate turbidity in
the disposition/handling processes described above would be ocean
disposal from bottom dump scows, and AES is not proposing open ocean
disposal at this time but will continue to investigate this alternative
method of disposal. Turbidity generated from dredge material dewatering
activities will adhere to a maximum acceptable level set by permit.

10.5.2.4  Dredge Disposal Alternatives

AES evaluated three potential alternatives to the use of a dredged
material recycling facility (DMRF) to handle dredge material, including
disposal of dredge material at an approved offshore location, upland
disposal of dredge material at a location other than the Terminal Site,
disposal at existing fill site(s) for which expansion is planned, and
innovative reuse as statutorily defined in Maryland law. A summary table
(Table 10.5.2-2) of key elements of the disposal options that are
described in detail below is attached, and includes potential final
disposal sites, apparent capacities, disposal methods and relative
costs. AES determined that the alternative of innovative re-use was
preferred over the other alternatives.

> *A. Offshore Disposal*
>
> AES has evaluated the feasibility of offshore disposal from the
> standpoint of sediment quality relative to other dredge management
> projects performed in the Port of Baltimore and Sparrows Point area,
> for purposes of determining if offshore disposal may be viable for all
> or a portion of the dredge material management.
>
> Sediment sampling has been performed in the area where the proposed
> dredging would take place. The sampling was performed during the
> period of May to June 2006, and the results are summarized in Section
> 2.4 of Resource Report 2, *Water Use and Quality*. The results show
> that sediment quality in the areas subject to dredging is comparable
> in chemical quality to other sediments that have been dredged from the
> Port of Baltimore for disposal in the area's Contained Disposal
> Facilities (CDFs: e.g., Hart-Miller Island; Cox Creek) and ocean
> disposal sites (e.g., Dam Neck Ocean Disposal Site). Environmental
> contaminants are present in the upper portion of the sediment profile,
> comprising primarily polycyclic aromatic hydrocarbons (PAHs --
> compounds formed by incomplete combustion of carbon-containing fuels
> such as wood, coal and diesel) and heavy metals. The sample results
> show that these compounds tend to decrease in concentration with depth
> and were generally not detected in sediments below approximately 10 to
> 15 feet or at the planned dredge depth of 45 feet below mean sea level
> (the new mudline surface that would remain once dredging has been
> completed).
>
> Ocean placement at a designated ocean site could be a viable placement
> location for the relatively clean dredge material located below the
> shallow sediments containing typical Port of Baltimore contaminant
> compounds. Approval of such location would be subject to EPA and Army
> Corps of Engineers (ACOE) approval, and would require evaluation
> consistent with the ACOE *Dredging and Dredge Material Placement*
> manual.
>
> AES has also determined in the course of dredge evaluation that the
> use of an approved offshore disposal site -- assuming that sediment
> quality is determined to be acceptable for placement at an EPA
> approved offshore site - would be less preferable than the use of the
> DMRF. This is due to the potential time required for vessels to travel
> to and from the offshore placement site, taking into consideration
> potential weather and other delays, and the nature of and timeframe
> required to obtain authorizations necessary to place the dredge
> material at an offshore location. Relative cost associated with this
> offshore disposal is also unknown and would be dependant on vessel
> capacity and shipping distance to an approved disposal location.
> However, given the results of the sediment sampling for the lower
> layers proposed to be dredged, this alternative might still prove
> practical if used in conjunction with the DMRF for dealing with the
> relatively large volumes of cleaner material.
>
> *B. Upland Disposal*
>
> The Commission Staff requested that AES evaluate the potential for
> upland disposition of dredge material if it is determined that some of
> the contaminated dredge material cannot be disposed of in the manner
> otherwise proposed herein (i.e., innovative reuse and/or open ocean
> placement). Comparison of the sediment quality anticipated from the
> proposed dredge area for the Project to sediment historically removed
> for maintenance dredging from the Patapsco River and Bear Creek area
> indicates the sediment quality is consistent. Historically, sediment
> dredged from the Patapsco and Bear Creek has been contained at the
> Hart-Miller Island site or placed at the Dam Neck Ocean Disposal Site.
> It is therefore anticipated that upland disposal would be dependant on
> finding a facility or facilities with capacity to accept the material
> either unprocessed as a solid waste, or processed as a useable
> product. Given the relatively clean quality of the sediment from the
> lower dredge depths, disposition of this clean portion of the dredge
> material at Hart-Miller Island, other CDFs in the area, or solid waste
> disposal facilities, would not be a compatible use of capacity of
> those facilities (i.e. the facility capacity is intended for disposal
> or waste materials, as opposed to relatively clean sediment).
> Alternatively, the relatively clean sediment could potentially be
> appropriately dewatered and used for daily cover or capping. It is
> therefore assumed that the volume of dredge material that may be
> subject to contained upland placement would be only a portion of the
> total dredge amount. An approximate percentage calculation of
> relatively contaminated (shallow) material vs. the relatively clean
> sediment at depth was developed based on the portion of potential
> dredge volume represented by the shallow and intermediate dredge
> material samples obtained and analyzed, as reported in Resource Report
> 2, *Water Use and Quality*, relative to the total dredge depth. This
> comparison indicates these shallow contaminated samples represent from
> 30 percent to 60 percent of the depth range of total dredge depth
> (i.e., where the sample for 0 to 10 feet depth was obtained from a
> location where dredging will remove 30 feet of sediment, the more
> contaminated samples represent 33 percent of the depth range and
> therefore approximately 33 percent of the final dredge volume). Based
> on this type of analysis over the entire dredge area, it is reasonably
> assumed that sediment that may be subject to upland disposal would be
> limited to 30 percent to 60 percent of the total dredge volume.
>
> Clean Earth Dredge Technology Inc. (CEDTI) is working with AES on
> dredge management options for the project. CEDTI has worked closely
> with numerous regional governmental and regulatory agencies to develop
> and implement programs for appropriately stabilizing dredged sediments
> for upland placement. Examples of these agencies include the New
> Jersey and Pennsylvania Departments of Environmental Protection, the
> NJ Department of Transportation, Office of Maritime Resources, the
> Pennsylvania Bureau of Abandoned Mine Reclamation, the New York State
> Department of Conservation and the Port Authority of New York & New
> Jersey. These engagements have provided CEDTI with significant
> experience in the range of research, development, and implementation
> of treatment and placement options for contaminated dredged sediments
> in the region. CEDTI has, in bench-scale and full-scale field
> operations, applied solidification/stabilization technology to
> numerous dredging projects, rendering the dredged sediments suitable
> for upland placement.
>
> For purposes of this evaluation, the alternative upland disposal
> methods (applicable to contaminated sediments that could not be
> processed, stored and then sold from the facility) comprised
> reclamation and remediation of an abandoned mine facility, such as the
> Bark Camp Mine Complex, an abandoned coal strip mine located in
> Pennsylvania (a CEDTI project), or similar mine
> stabilization/reclamation in Pennsylvania and/or Maryland. The Bark
> Camp Mine has approximately 6 to 10 million cubic yards of capacity
> required to complete reclamation, and has been approved for acceptance
> of stabilized contaminated dredge material, and could comprise an
> upland placement site option for processed dredge material. The states
> of Pennsylvania and Maryland also have significant acreage requiring
> reclamation beyond the capacity present in the Bark Camp site. The
> stated goal of the Maryland Abandoned Mine Reclamation Program is to
> promote the reclamation of all abandoned mined areas in Maryland that
> have been left in an inadequately reclaimed condition and continue to
> endanger the health or safety of the public, degrade the quality of
> the environment or diminish the beneficial use of land and water
> resources. Land in Maryland impacted by surface and underground coal
> mining prior to state and federal mining and reclamation regulatory
> programs is estimated at approximately 9,500 acres of land and 450
> miles of streams.
>
> AES determined that the use of an upland disposal site would be less
> preferable than the use of a DMRF at the Sparrows Point facility for
> processing, storage and sale/shipment to end users. (See discussion
> below relative to the preferred DMRF alternative.) This is due to the
> difficulty anticipated in identifying one or two sites nearby that
> could accept the volume of dredge material, the transportation
> requirements necessary to access an upland site, the need for
> unloading and additional processing once the dredge material is
> delivered to an upland site, and the nature of and timeframe required
> to obtain authorizations necessary to dispose of the dredge material
> at an upland location. Such disposition options are technically
> feasible, but would be difficult to manage in a timeframe consistent
> with the Project. The cost of such an alternative is currently
> unknown, and would be dependant on cost of use or establishment of a
> stabilization plant facility at the mine location (such as Bark Camp),
> haul distance and capacity available.
>
> *C. Disposal at a Fill Site*
>
> AES evaluated the feasibility of disposing of dredge material at the
> existing Hart-Miller Island dredged material containment facility in
> the Port of Baltimore area, and determined that the disposal facility
> currently does not have capacity available to handle the dredge
> material associated with the Project. While other fill sites in the
> general vicinity of the Project are planning to expand capacity in the
> future, AES understands that these capacity expansions will be limited
> to current or planned projects being undertaken by the Maryland Port
> Administration and other marine terminals in the Port of Baltimore.
> The expansions therefore are not considered to be available or
> sufficient to handle the additional dredge material associated with
> the Project, especially when the annual capacity of any existing or
> planned placement site is considered. [^27] For this reason, existing
> and planned dredged material placement facilities intended for
> material dredged from the navigational channels in the Chesapeake Bay
> outside of the Baltimore Harbor are not available to this material.
>
> The State of Maryland has a public participation process as part of
> its Dredged Material Management Program. That process undertook a
> multi-year effort to identify and recommend options available for a
> long-term (20 years) plan for managing material dredged from the
> Baltimore Harbor channels. Known as the Harbor Team, community
> representatives and other stakeholders came together to consider
> options for managing up to 1.5 million cubic yards annually of harbor
> dredged material. Five hundred thousand cubic yards is the average
> amount of material generated from the maintenance of existing
> channels. The additional one million cubic yards allows for new
> dredging projects in the harbor. Options to accommodate this quantity
> of material over the 20-year period led to several site-specific
> placement (containment facility) recommendations, as well as a
> recommendation for the innovative reuse of meaningful quantities of
> dredged material by 2023. The amount of material likely to be
> generated by the AES project exceeds what was planned for in the
> state's public process. AES understands that any expectation that the
> state's existing, planned, or proposed containment facilities will be
> able to accommodate dredged material from the Sparrows Point Project
> is not supportable.
>
> *D. Innovative Re-use*
>
> The innovative re-use alternative would involve constructing an upland
> dredged material processing facility adjacent to the existing waterway
> at the Terminal Site (see Section 1.5.1.2 of Draft Resource Report 1,
> *LNG Terminal Offshore Construction* describing dredge plan and
> recycling facility layout). A 10,000 cubic yard per day DMRF would
> occupy approximately five acres of upland property within the
> boundaries of the Terminal Site. The recycling facility would consist
> of duplicate (parallel) processing systems including hoppers,
> conveyors, pugmills for mixing additives and stacking equipment.
> Emissions from each pugmill and additive delivery system would be
> equipped with and controlled by separate baghouse dust-collection
> devices. Existing site roadways would be used to transport the
> processed dredged material from the pugmill processing system to the
> temporary Processed Dredged Material (PDM) storage area. The temporary
> PDM storage area would consist of an approximately 10-acre area
> covered by bituminous paving or lined with a 10-mil HDPE liner covered
> by 6- to 12-inches of existing site soil or imported soil. A scale
> house and truck scale would be located adjacent to the temporary PDM
> storage area for weighing of the outbound shipments of the PDM product
> upon sale. Existing site roadways or railroads would be used for
> outbound shipments of the PDM product.
>
> The recycling facility area and temporary PDM stockpile area would be
> graded as necessary and paved with bituminous concrete, and equipped
> with stormwater management controls tied to existing facilities for
> stormwater management (the existing Sparrows Point facility routes and
> manages stormwater for the exposed land area of the facility through
> several permitted outfalls associated with its operations). AES would
> occupy similar land area and would pursue stormwater permits through
> either the Maryland Industrial Stormwater Permit program (appropriate
> to the industrial code applied to the DMRF) or permitted discharge
> under a site-specific National Pollutant Discharge Elimination System
> (NPDES) permit to be applied for from the State of Maryland -- see
> Resource Reports 2 and 13 relative to stormwater management, testing,
> and permitting to be associated with the terminal and DMRF site. After
> civil work is completed, the DMRF would be erected at the site. All
> components of the processing systems would be fabricated off-site and
> delivered via truck to the construction site. Operation of the DMRF
> would occur during the LNG Terminal construction phase of the Project.
> Processing operations would commence following construction of the
> DMRF and simultaneously with the commencement of dredging operations.
>
> The use of the DMRF would enable AES to manage the dredge material at
> an upland location adjacent to the dredge site, and stockpile
> processed material until it is sent to market by truck, rail or ship.
> This method also could be scaled up or down to accommodate the timing
> and quantity of the dredge material management needs during the
> dredging phase of the Project, for example, to allow for continuous
> processing of the dredged material even when the dredging is limited
> to certain windows as a result of permit conditions.

## Pipeline Alternatives

> AES took two different approaches to its review of pipeline
> alternatives. First, AES evaluated natural gas transmission
> alternatives to its proposed Pipeline vis-à-vis different delivery
> points or methods for delivering the LNG from the LNG Terminal. Next,
> AES evaluated route alternatives between the Terminal Site and the
> proposed terminus point in Eagle, Pennsylvania.

### Delivery Alternatives

AES evaluated five natural gas transmission alternatives to its proposed
Pipeline, including (1) an alternative interconnection point to the
proposed interconnections near Eagle, Pennsylvania, (2) interconnection
solely with the existing Baltimore Gas & Electric Company (BG&E) natural
gas distribution system, (3) use of truck and rail methods instead of a
natural gas pipeline to transport LNG from the terminal, (4) combined
use of a single interconnection with the existing BG&E system and truck
and rail transport of LNG from the LNG Terminal, and (5) connection only
with the Columbia Gas pipeline system. None of these pipeline system
alternatives is considered to be a viable alternative to the proposed
Pipeline for the reasons discussed below.

AES first considered whether an alternative final interconnection point
other than the proposed interconnections near Eagle, Pennsylvania would
better serve the intended purpose of the Project. Because the Project is
expected to be a high load factor facility, one of the main concerns
regarding the final interconnection point is access to both substantial
throughput and natural gas storage. In order to maximize access to
markets and storage in the Mid-Atlantic Region, interconnection with the
three existing Mid-Atlantic Region interstate pipeline systems near
Eagle, Pennsylvania is necessary. Further, as noted in Section 10.3.2,
connection into the major interstate natural gas transmission lines that
pass through the Mid-Atlantic Region (Transco, TETCO, and Columbia) at
any other locations further south than Eagle, Pennsylvania would require
expansions of the existing lines to move the incremental gas to the
market areas. This would result in significant additional environmental
impacts, including an additional three to five crossings of the
Susquehanna River and operating impacts associated with those
expansions.

AES next evaluated the feasibility of connecting solely with the
existing BG&E natural gas pipeline system. While this system alternative
would allow local consumers to avoid certain transportation costs
associated with existing natural gas supplies transported from the Gulf
of Mexico and other regions in North America, interconnection with the
BG&E system alone would essentially reduce the function of the LNG
Terminal to an oversize peak-shaving facility, thus making the required
investment in terminal and marine facilities economically infeasible.
BG&E already has sufficient peak-shaving capacity for its system at
Spring Gardens in Baltimore, Maryland, and displacement of BG&E's entire
natural gas load was not considered to be viable (the highest daily
natural gas delivery in the BG&E system was approximately 0.8 bscfd for
January 23, 2003; the average is significantly less). This system
alternative not only would be commercially impractical, due to the costs
of the Project compared to the projected quantity of deliverable natural
gas, but would fail to provide a new incremental supply of natural gas
to markets in the entire Mid-Atlantic Region, which is the key component
of the overall purpose of the Project.

AES also considered the feasibility of using truck and rail transport to
distribute LNG from the proposed LNG Terminal. In certain areas of the
country, particularly the Northeast, small quantities of LNG are
transported by truck to outlying areas and to and from peak shaving
storage facilities. These outlying areas typically are located in
relatively close proximity to the LNG Terminal and one another,
resulting in relatively short truck transport distances. This same
situation does not exist in the Mid-Atlantic Region. In addition, there
currently is no commercial scale rail transport of LNG cargo. For these
reasons, truck and rail transport on the scale necessary to support the
take-away capacity of the proposed LNG Terminal was determined to be
impractical and no further consideration was given to this system
alternative.

A combination of truck and rail transport of LNG to markets in the
Mid-Atlantic Region and a single interconnection locally with the
existing BG&E natural gas distribution system was determined not to be a
viable transmission alternative to the proposed Pipeline because this
alternative would not be sufficient to support the take-away capacity of
the proposed LNG Terminal to interconnections with the pipeline grid
serving the Mid-Atlantic Region, and the use of rail and truck
transport, as discussed above, is not considered to be commercially
viable since there is currently no commercial-scale rail transport of
LNG cargo for the Project Area.

Finally, AES also evaluated the feasibility of connecting to the
existing Columbia Gas Line 1278 pipeline system just outside of
Baltimore. While this transmission alternative would reduce the required
length of send out pipeline required, this transmission alternative was
found to be unacceptable as Columbia's system was described as having
insufficient capacity to move the volume to the market and replacing
this line would have the same or greater landowner and environmental
impacts as the proposed Pipeline, plus interruption in service during
the construction period.

### Route Alternatives

The proposed route for the Pipeline generally parallels rights-of-way
for existing highways, overhead electric transmission lines, and
pipelines. In considering alternatives to the proposed Project to
determine whether it might be possible to reduce the human and
environmental impacts, AES evaluated alternative pipeline routes.
Alternatives that were considered include four major route alternatives
and numerous route variations. Figure 10.6.2-1 identifies the location
of the proposed route for the Pipeline. As proposed, the route consists
of four main segments:

-   The proposed route exits the former Sparrows Point Shipyard and
    steel mill property and travels north to northeast for approximately
    two miles (MP 0.0 to 2.0);

-   For approximately six miles (MP 2.0 to 8.0), the proposed route
    follows Route I-695 in a north and northwest direction, except for
    minor deviations necessary to avoid highway interchanges (sections
    of this route will require coordination with Maryland Department of
    Transportation (MDOT) for scheduling of safety vehicles to support
    crossing activities. Due to the length and coordination required for
    these limited sections, less than 3 miles, AES does not anticipate
    that this will lead to any delays in construction or potential
    impacts to overall Pipeline completion);

-   Near the Back River crossing, the proposed route heads north to
    northeast and follows a BG&E overhead transmission corridor for
    approximately 24.5 miles (MP 8.0 to 32.5); and

-   At the intersection with the right-of-way (ROW) for an existing
    Columbia pipeline, the proposed route heads northeast and generally
    parallels the existing pipeline ROW for approximately 54 miles (MP
    32.5 to 87.6) to its terminus near Eagle, Pennsylvania.

AES applied several screening criteria to identify a proposed route
between the Terminal Site and the interconnection points near Eagle,
Pennsylvania. Principal among its route screening criteria were the
desire to maximize use of existing ROW in order to avoid or to minimize
to the maximum extent possible construction-related impacts to the
environment, landowners and other stakeholders, taking into
consideration the technical and economic feasibility of constructing the
Pipeline. Although not the only criterion to be used in route selection,
the preference towards the use of existing corridors is an industry
standard and is consistent with 18 CFR §380.15, which concerns siting
and maintenance requirements for pipeline construction. Furthermore,
this criterion is consistent with the objectives of most regulatory
agencies, including the ACOE and the Commission. Using the standard
screening criteria specified by the Commission in its guidance, AES
identified four major route alternatives to the proposed route, which -
as in the case of its proposed route - included following existing ROW
and greenfield construction.

AES assessed each route alternative using a 100-foot wide corridor
centered on the proposed alignment for the majority of the constraints.
The analysis was conducted using existing resource information available
on United States Geological Survey (USGS) 7.5-minute series topographic
quadrangle maps; Maryland Geographic Information System (GIS) data
layers; other available federal, state, and county resource maps; recent
high resolution aerial photography; and unmapped data. The analysis
focused on an evaluation of route length, feasibility of using existing
corridors, extent of crossing existing transportation features, the
presence of wetlands and waterbodies, threatened and endangered species
and significant habitat, land uses and vegetation cover types, the
presence of Federal and states lands, and several other special land
uses. The major route alternatives are summarized on Figure 10.6.2-2. A
tabular summary of this analysis is included within Table 10.6.2-1. AES
also provided briefings to senior personnel of Maryland State agencies
responsible for managing federally funded highways concerning routing
that traversed federally funded highways, which are Interstates 95 and
695. Documentation of the briefings is included within Appendix B.

The following provides a summary of AES's initial screening analysis of
the four route alternatives.

### Major Route Alternatives

10.6.3.1  Dundalk West Alternative

The Dundalk West Alternative would deviate from the proposed route at
North Road (approximate MP 0.8), and follow an existing roadway for
approximately 1.2 miles before crossing Bear Creek (Figure 10.6.3-1).
The Dundalk West Alternative 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 route at MP 8.0.

A tabular summary of the environmental features along this alternative
is included within Table 10.6.2-1. The greatest advantage of the Dundalk
West Alternative is that it presents a straighter path through this area
and is approximately one mile shorter than the proposed route. However,
this alternative presents an apparent greater amount of environmental
and land use impact than the proposed route. Specifically, this
alternative would require a greater number of waterbody crossings, would
cross a substantially longer length of wetlands, and would potentially
impact more historic resources and residential properties. Additionally,
the Dundalk West Alternative would be located through a greater amount
of Dundalk residential neighborhood and encroach upon several school
properties. While these latter considerations would not rule out this
alternative by themselves, such proximity would likely cause greater
disturbance to nearby or adjacent residents and necessitate specialized
construction techniques in the more constrained areas. Public concern
over locating another pipeline in a corridor already hosting two
pipelines is another negative aspect associated with this alternative.

Special construction techniques, including a potential Horizontal
Directional Drilling (HDD), would be required to cross Bear Creek. In
addition, some restrictions due to existing utilities and bridge
structure at the Bear Creek crossing location, could potentially push
the alignment further to the north and potentially cause additional
impact to Cheekwood Park and the associated wetlands to the west side of
crossing. Congested areas near schools and businesses would require
restricted workspace, and a potentially compressed/limited construction
period, in order to minimize possible interference with local businesses
and schools. Because the ROW is extremely congested with other
utilities, it could require construction efforts to uncover and locate
existing utilities and potentially require hand digging in certain areas
to avoid interference with those utilities, adding time and cost to this
overall routing.

Overall, the Dundalk West Alternative, while shorter and resulting in
less total acreage of disturbance, has the potential for greater
environmental and land use impacts, and is thus not recommended.

10.6.3.2  Western Corridor Alternative

The Western Corridor Alternative would deviate from the proposed route
after the Back River crossing (MP 9.0) and traverse north for
approximately 21.0 miles along a northern-trending, two-tower BG&E
powerline corridor (Figure 10.6.3-2). Shortly after it crosses the
Baltimore and Harford County, Maryland line, the alternative route would
turn to the northeast and closely parallel the existing Columbia
pipeline corridor, rejoining the proposed route at MP 32.5.

A tabular summary of the environmental features along this alternative
is included within Table 10.6.2-1. While the Western Corridor
Alternative is located almost entirely within existing utility corridors
and would result in substantially fewer impacts to wetlands, the Western
Corridor Alternative presented several disadvantages from a
constructability standpoint. This existing corridor is already occupied
by several utilities, including two powerline lattice tower alignments
and one to two existing pipelines (depending on location along the
corridor). The ROW for this segment of the alternative route also would
be located closer to more densely populated areas than would the
proposed route, meaning that pipeline construction activities, while
temporary, nevertheless would impact more landowners than would
construction activities along the ROW for the proposed route.

There are several areas along this route where houses, fences and sheds
are built right up to the corridor, resulting in greater impacts to
residences. Additionally, there are several buried utilities in these
areas. All of these items lead to potentially constricted or reduced
work space, and potential special construction techniques including
exposing existing utilities and shoring them up to avoid damage during
installation of the Pipeline. This would lead to greater overall
construction time, cost and associated impacts. Additionally, where the
pipeline crosses Gunpowder Falls State Park, crossing of Gunpowder
Falls, a waterbody within the park, must be considered. Space for
performing an HDD in this location is heavily constricted by residential
housing, electric utility lines and substations at the south side of the
park. This would be a difficult crossing to plan and execute due to the
obstacles in this area.

Comparison of environmental impacts for this alternative route segment
(Table 10.6.2-1) indicates that the two alternatives are largely
comparable with the exception of a few elements. The proposed route is
approximately 1.6 miles longer and crosses more forested wetland than
the Western Corridor Alternative. Additionally, the proposed route has
the potential to affect more potential archaeological sites than the
Alternative. However, based on the various construction constraints
posed by this alternative and the densely populated residential
developments along its length, the proposed route offers the better
alternative for the project insofar as the forested wetland and
potential cultural resource elements are more manageable impacts to
surmount. These elements can be mitigated such that the additional
resource impacts associated with the preferred route will not result in
a long-term negative effect.

10.6.3.3  State Route 136 Alternative

The State Route (SR) 136 Alternative would deviate from the proposed
route at the intersection with the overhead electric transmission
corridor and I-95 at approximate MP 19.0 (Figure 10.6.3-3). The
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 route at approximate MP 40.0 at the existing
Columbia pipeline ROW.

A tabular summary of the environmental features along this alternative
is included within Table 10.6.2-1. The SR 136 Alternative was determined
to be less preferable than the proposed route for a number of reasons.
The majority of this route would require a new utility corridor and
would be routed parallel and adjacent to I-95 and SR 136 corridors. As
would be the case with any project adjoining or within the bounds of a
major highway ROW (such as Rt. 95, Rt. 695, or similar highway), close
coordination with the managing body (such as MDOT) and additional
construction safety requirements would be needed due to vehicular
traffic. Roadway construction requires substantially greater
coordination and potentially would lead to additional time to construct
due to restricted hours of construction imposed by the MDOT (such as the
need to avoid rush hour periods), and possibility of delays if approved
vehicles were not available. Additionally, there are several areas along
SR 136 where construction techniques would require reduced CROW due to
proximity of road and other utilities along side of the road. To avoid
impact to local businesses and residences it is expected that time of
day restrictions may be imposed that are more restrictive than much of
the preferred route through this area. These restrictions would lead to
extended construction time, cost and overall increase in associated
impacts. Where insufficient space exists between SR 136 and the adjacent
residences/commercial structures, it would be necessary to deviate from
the roadway corridor and create new pipeline corridor behind the
developed structures. Such creation of new greenfield ROW has an
additional set of impacts that should be avoided if an alternative
exists.

The SR 136 Alternative also potentially impacts a greater number of
residential and historical properties, particularly structures along SR
136. This alternative route also traverses the Finney House Historic
District in Churchville, Maryland, and could therefore affect
considerable Rural Legacy District area prior to reaching the pipeline
corridor.

Comparison of environmental factors (Table 10.6.2-1) indicates that the
two alternatives are largely comparable, with the exception of a few
elements. The proposed route crosses a longer segment of steep terrain,
which could have some effect on the construction process. However, the
SR 136 Alternative has several disadvantages including several
construction constraints, the crossing of more historic properties and
historic districts, and the overall impact associated with creation of
22 miles of new pipeline corridor through a rural residential area with
localized congestion.

10.6.3.4  US I-95 & Greenfield Alternative

The US I-95 & Greenfield Alternative would deviate from the proposed
route at the intersection with the overhead transmission corridor and
I-95 at approximate MP 19 (Figure 10.6.3-4). The US I-95 & Greenfield
Alternative would head north to northeast and follow I-95 for
approximately 20.0 miles. At this point, the alternative would divert
from I-95 and traverse 13.8 miles in a northerly direction cross-county,
necessitating the construction of a greenfield pipeline right-of-way.
Shortly after the pipeline crosses U.S. 1 in Harford County, Maryland,
this alternative route would reach the Columbia pipeline, rejoining the
proposed route at approximate MP 40.0.

A tabular summary of the environmental features along this alternative
is included within Table 10.6.2-1. While this alternative crosses less
steep terrain, the US I-95 & Greenfield Alternative was determined to be
less preferable than the proposed route. The alternative impacts a
greater number of wetlands and waterbodies, and a greater number of
historical properties. As compared to the proposed route, the US I-95 &
Greenfield Alternative would also impact a greater number of residential
properties and would require over 13 miles of greenfield development
from I-95 north to the Columbia pipeline.

The segment of the alternative route that follows I-95 also is
significantly encroached upon by adjacent residential and commercial
development, and thus would increase potential impacts on residences and
construction-related constraints. The majority of this route would
require close coordination with the MDOT along the I-95 corridor and
additional construction safety requirements due to passing traffic. This
coordination would potentially lead to additional time to construct due
to restricted hours imposed by the MDOT (such as the need to avoid rush
hour periods), and possibility of delays if approved vehicles were not
available. This would lead to additional time, cost and related
potential impacts. Once leaving the I-95 corridor, much of the proposed
route is open agricultural land. This area would require seasonal
restrictions as well as additional requirements for topsoil segregation
and follow up mitigation efforts. Depending on sequencing of
construction and actual timing of when this area is reached, this
potentially could cause a temporary delay and additional associated
impacts due to the increased CROW for topsoil segregation planning and
follow up restoration and mitigation.

AES has consulted with the MDOT, Maryland State Highway Administration
(SHA), and the Maryland Transportation Authority (MdTA) regarding
routing along and crossing of I-95 and I-695. AES provided briefings to
senior personnel of these Maryland State agencies responsible for
managing these federally funded highways, and provided backup mapping to
the agencies' technical staff to allow initial review and feedback of
areas where the pipeline route may interfere with highway operation and
safety. AES has coordinated with the Maryland State agencies responsible
for managing federally funded highways during the surveying of the
proposed route. AES requested and was granted permission to perform its
surveys in or where the Project crosses segments of Rt. 695 and crossing
locations of I-95 (AES will continue to coordinate with them throughout
the process.

Overall, the primary advantage of the US I-95 and Greenfield Alternative
is to follow a route that minimizes encroachment on commercially and
residentially developed areas. While this Alternative does reduce impact
to residential areas and reduces construction difficulties associated
with developed areas along the other alternative segments, it has
substantially greater environmental impact in almost every sensitive
environmental resource category than the preferred route.

### Route Variations 

Minor route variations on the proposed route were identified in response
to issues raised by the public, engineering and environmental
constraints identified during field surveys, and other issues of
concern. Figures 10.6.4-1 through 10.6.4-14 present 25 identified
variations. Each potential variation on the proposed route was evaluated
according to key environmental and engineering parameters to arrive at a
preferred route through the area of concern. The purpose for developing
route variations was to further refine the proposed route in areas of
potential significant impacts, including heavily congested and
environmentally sensitive areas. Areas for focused route variations were
identified during the course of public meetings, by landowners, during
AES field surveys, and through regulatory agency input. Route variations
were considered at various stages of the Project routing and field
survey phases.

The process of public meetings, landowner contacts, and agency input has
resulted in numerous additional changes from the initial conceptual
route. Variations identified during this process in some cases were
incorporated into the Pipeline Route to improve overall routing from a
construction standpoint, and to minimize the overall impact to
landowners and environmental resources.

A summary of the route variations along the route is presented in Table
10.6.4-1, Summary of Variations, including an environmental analysis of
each variation.

**Route Variation 1**

Route Variation 1, from MP 3.70 to MP 4.65 as shown on Figure 10.6.4-1,
was developed as a potential alternative to 1.0 miles of the original
pipeline route to provide the best crossing location for I-695, and to
reduce environmental impacts to the area. This variation is located
between the east and west bound lanes of I-695, while the preferred
route is located between I-695 and railroad tracks.

While both routes follow the within the I-695 easement, this alternative
would present some additional constructability and safety concerns, with
a large section located between the traffic lanes. Upon visual
inspection, it appeared that the alternative route contained additional
wetlands. AES determined that the route variation does not reduce
construction-related constraints or minimize impacts to wetlands.
Therefore, due to environmental considerations, AES is not incorporating
Route Variation 1.

**Route Variation 2**

Route Variation 2, from MP 4.65 to MP 5.15 as shown on Figure 10.6.4-1,
was developed as a potential alternative to 0.50 mile of the original
pipeline route paralleling I-695, to avoid impacts to forested area and
reduce environmental impacts. This variation is located between I-695
and an area of commercial development. This variation would follow along
an existing commercial lot for the first portion of the route, cross a
forested wetland before crossing Beachwood Road, and turn back toward
the main route.

In the process of completing the evaluation of Route Variation 2a
(discussed below), surveys have indicated that both routes will pass
through a forested wetland area. AES determined that Variation 2 is
longer, has more bends, and does not significantly minimize impacts to
wetlands. Therefore, due to primarily environmental considerations, AES
is not incorporating Route Variation 2.

**Route Variation 2a**

Route Variation 2a, from MP 5.60 to MP 6.00 as shown on Figure 10.6.4-1
and located at the Cove Road I-695 Interchange, was developed as a
potential alternative to 0.40 miles of the original pipeline route, to
avoid impacts to residential properties and to address constructability
concerns.

The original proposed route would stay to the east of the interchange
where the crossing of Cove Road would be complicated by topography and
the railroad track to the east of the route; it would be located in a
forested area. While the variation would involve some tight working
conditions, it would avoid potential impacts to residences along the
original proposed route and reduce the impacts to forested areas. AES
determined that this route variation will reduce construction-related
constraints, the crossing of forested lands and impacts to residences,
and has incorporated this variation into the preferred route.

**Route Variation 3**

Route Variation 3, from MP 9.40 to MP 10.80 as shown on Figure 10.6.4-2,
was developed as a potential alternative to 1.38 miles of the original
pipeline route to reduce constructability concerns and environmental
impacts. The variation would leave the original proposed route and
continue to follow the southbound lane of I-695 until it turned north
along the high-speed railroad tracks until it reconnects with the
original route near the I-695 crossing.

AES has conducted a desktop survey of this route and determined that the
route is slightly longer and appears to utilize more commercial areas.
While this route appears to have some additional constructability
concerns, it may impact less wetlands and waterbodies. AES is still in
the process of evaluating Route Variation 3 to determine if the route
will reduce constructability issues and impacts in this congested
corridor.

**Route Variation 4**

Route Variation 4, from MP 10.80 to MP 18.75 as shown on Figure
10.6.4-3, was developed as a potential alternative to 8.0 miles of the
original pipeline route through this congested area, and parallels the
north-bound lane of I-695 before turning to the east, following the
north bound lane of I-95 until it connects with the originally proposed
route on the south side of the I-95 crossing.

AES has conducted a desktop survey of this route and determined that the
route is slightly longer, may impact less wetlands and waterbodies, and
appears to utilize more commercial and agricultural areas. However, this
route appears to be much more congested and has some additional
constructability concerns. AES is still in the process of evaluating
Route Variation 4 to determine if the route will reduce constructability
issues and impacts to this congested corridor.

**Route Variation 5**

Route Variation 5, from MP 14.35 to MP 14.70 as shown on Figure
10.6.4-4, was developed as a potential alternative to 0.30 miles of the
original pipeline route to reduce environmental impacts, and is located
along an abandoned section of the overhead electrical transmission line
route.

AES found that the original route through this area crossed forested
wetland areas with standing water and had additional waterbody
crossings. Route Variation 5 was located within the cleared area of an
abandoned power line corridor with much less wetland impacts. Route
Variation 5 significantly reduces wetland and waterbody impacts, and
therefore AES has incorporated this route variation into the preferred
route.

**Route Variation 6**

Route Variation 6, from MP 15.00 to MP 15.50 as shown on Figure
10.6.4-4, was developed as a potential alternative to 0.50 miles of the
original pipeline route to reduce environmental impacts, and would be
located on the northern side of the existing overhead electrical
transmission line.

AES evaluated Route Variation 6 and found that it would cross a large
open water pond/quarry as well as paralleling a section of Whitemarsh
Run. While this alternative would result in two less crossings of
Whitemarsh Run, the crossing of the large pond/quarry significantly
limits the constructability of this variation. Therefore, due to
environmental considerations, AES is not incorporating Route Variation
6.

**Route Variation 7**

Route Variation 7, from MP 17.80 to MP 17.90 as shown on Figure
10.6.4-5, was developed as a potential alternative to 0.10 miles of the
original pipeline route in this congested area. This route variation was
originally developed to avoid potential structures located near the
existing power line ROW.

AES evaluated Route Variation 7 on the ground and found that it did not
aid in the avoidance of residential structures. Therefore, AES is not
incorporating Route Variation 7.

**Route Variation 8**

Route Variation 8, from MP 18.50 to MP 18.75 as shown on Figure
10.6.4-5, was developed as a potential alternative to 0.25 miles of the
original pipeline route through this utility line congested area, and is
located to the west of the proposed route; it would pass through an
agricultural field to connect to an existing power line corridor.

While both route variations involve creating new ROW, this area is owned
by BG&E and contains numerous power line crossings. The route variation
would involve one extra 90-degree bend in the pipeline route as well as
create a crossing of Rafael Road. Therefore, because of these
engineering and construction constraints, AES is not incorporating Route
Variation 8.

**Route Variation 8a**

Route Variation 8a, from MP 33.65 to MP 34.00 as shown on Figure
10.6.4-6, was developed as a potential alternative to 0.30 miles of the
original pipeline route to reduce environmental and residential impacts
along the existing pipeline easement. This variation turns north leaving
the existing pipeline easement and travels through an actively
cultivated field. The variation then turns to the east and crosses Grier
Nursery Road and connects back into the existing pipeline easement.

AES evaluated Route Variation 8a and found that the variation avoided
crossing a wetland area adjacent to a farm pond, created a better
crossing of the small unnamed tributary in the area, created a better
crossing of Grier Nursery Road, and avoided a very congested
residential/commercial area. Therefore, due to primarily landowner and
environmental considerations, AES has incorporated this route variation
into the preferred route.

**Route Variation 9**

Route Variation 9, from MP 35.30 to MP 35.60 as shown on Figure
10.6.4-7, was developed as a potential alternative to 0.30 miles of the
original pipeline route, and would parallel the north side of the
existing pipeline easement. This alternative was identified after
evidence of new construction was noted near the existing pipeline ROW.

During the survey of the area, it was found that the landowner had built
a new garage very close to the existing pipeline easement, reducing the
potential area for a second line along the southern side of the existing
ROW. The variation does not result in greater environmental impact, thus
AES has incorporated Route Variation 9 to avoid a newly constructed
garage.

**Route Variation 10**

Route Variation 10, from MP 36.20 to MP 38.10 as shown on Figure
10.6.4-7, was developed due to public comment as an alternative to 1.5
miles of the original pipeline route. At MP 36.20, this route variation
would turn north towards Mine Branch Road and then head northeast on the
north side of Mine Branch Road past Ady Road. Continuing northeast, the
route variation would be located south of Dublin Road to MP 38.10 where
it would rejoin the proposed route.

AES is in the process of performing an engineering evaluation of Route
Variation 10 to avoid residential structures, steep terrain, waterbodies
and wetlands. Upon completion of this analysis, AES will provide its
recommended routing through this area to the Commission.

**Route Variation 11**

Route Variation 11, from MP 36.50 to MP 39.00 as shown on Figure
10.6.4-8, was developed as a potential alternative to 0.50 miles of the
original pipeline route through a residential area along the south side
of the existing pipeline easement. This variation would leave the
existing ROW and traverse the Scarboro Landfill Property passing the
current borrow pit location.

This variation would involve two larger tributary crossings and would
still be located near the residential area. In addition, it would be a
longer route involving all greenfield location, This variation also
conflicted with the future plans of the landfill. Therefore, AES is not
incorporating Route Variation 11.

**Route Variation 12**

Route Variation 12, from MP 38.85 to MP 39.90 as shown on Figure
10.6.4-8, was developed as a potential alternative to 1.05 miles of the
original pipeline route, and would parallel the north side of the
existing pipeline easement. This route variation involves turning north
off of the existing pipeline easement and following the edge of an
actively cultivated field before entering a forested area. Once in the
forested area the variation would then turn back to the easement. This
variation was identified to avoid a residential area with some
structures in close proximity to the existing easement.

AES was not able to fully evaluate route Variation 12 in the field due
to denial of access by landowners. The pipeline is still able to be
sited along the existing pipeline corridor with minimal additional
impact to residential areas. The variation would involve greenfield
development through forested areas. In addition, the variation is
longer, involves three large bends in the pipeline, and has additional
waterbodies mapped along the route. Therefore, due to increased
environmental and construction constraints, AES is not incorporating
Route Variation 12.

**Route Variation 13**

Route Variation 13, from MP 51.50 to MP 53.00 as shown on Figure
10.6.4-9, was developed as a potential alternative to 1.35 miles of the
original pipeline route through this congested area partly based on
public comment. The variation would turn north after the Brabson Road
crossing into an open field prior to crossing Kirks Mill Road. The
variation would then continue north into a pasture area prior to turning
east to cross Brow Road and connecting with an existing power line
easement. The variation would then follow this easement until it
connects back with the existing pipeline easement.

AES evaluated Route Variation 13 and found that it did avoid residential
structures and congested areas while traversing mostly pasture and
existing utility ROW, and thus has incorporated this variation into the
preferred route.

**Route Variation 14**

Route Variation 14, from MP 64.90 to MP 65.10 as shown on Figure
10.6.4-10, was developed as a potential alternative to 0.25 miles of the
original pipeline route in this lightly residential area and continues
along the existing pipeline easement.

A portion of this variation was not able to be evaluated due to lack of
landowner permission to access the property. The variation would involve
placing the pipeline in closer proximity to one residential structure
creating a constructability concern. In addition, it appears that there
will be additional wetland and waterbody impacts associated with this
variation. The preferred route utilizes the edge of agricultural fields
and allows for a perpendicular crossing of Faggs Manor Road. Due to
primarily environmental considerations, AES does not find that this
variation will result in an environmentally preferable route, and is not
incorporating Route Variation 14.

**Route Variation 15**

Route Variation 15, from MP 74.85 to MP 76.50 as shown on Figure
10.6.4-11, was developed as a potential alternative to 1.25 miles of the
original pipeline route through this congested area. This variation
would be located partially along the existing pipeline easement, and
then veer to the northwest of the existing pipeline easement through
fields and forested areas until connecting back with the original
proposed route north of Romansville Road.

Although this alternative would involve some greenfield development
through forested and light residential areas, AES found that the route
avoided planned developments, residential structures, and had less
impact to wetlands and waterbodies. Although greenfield development is
often not preferred, overriding environmental and landowner impact
concerns justify incorporation by AES of Route Variation 15 into the
preferred route.

**Route Variation 16**

Route Variation 16, from MP 74.85 to MP 76.50 as shown on Figure
10.6.4-11, was developed as a potential alternative to 1.25 miles of the
original pipeline route located though planned and existing residential
areas, and is located along the existing pipeline easement.

AES conducted a desktop and site survey of this route and determined
that this variation would involve crossing heavily residential areas,
and would involve additional wetland and waterbody impacts. AES has
determined this variation will not result in a lesser environmental
impact. Therefore Route Variation 16 is no longer under consideration.

**Route Variation 17**

Route Variation 17, from MP 77.00 to MP 78.10 as shown on Figure
10.6.4-12, was developed as a potential alternative to 1.1 miles of the
original pipeline route through this congested area, and would be
located to the east of the proposed route along the existing pipeline
easement.

Although this variation runs through the middle of a residential
community, AES will be able to site the line with minimal impact to
residential structures. The originally proposed route crossed a Town
Park in an area that contains forested walking paths and a children's
play area, as well as impacted additional residences. This route
variation would follow the existing pipeline easement, avoid new ROW
impacts to the Town Park playground and wooded walking trails, have less
impact on surrounding residences, and is the shorter route. Route
Variation 17 has been incorporated into the preferred route.

**Route Variation 18**

Route Variation 18, from MP 78.70 to MP 79.70 as shown on Figure
10.6.4-12, was developed as a potential alternative to 1.0 mile of the
original pipeline route through this congested area, and would be
located to the east of the proposed route. This is an area where there
are two existing pipeline easements that separate at this point.

While both routes follow existing pipeline corridors, the proposed route
takes advantage of additional commercial areas, but does impact a
greater amount of wetland and waterbody. A portion of the pipeline
easement along the route variation is located in King St. through a
heavily populated residential area. Based on the surveys completed to
date and public comments, AES believes that the proposed route through
the minor commercial area would result in fewer impacts and is not
incorporating Route Variation 18.

**Route Variation 19**

Route Variation 19, from MP 80.70 to MP 81.10 as shown on Figure
10.6.4-13, was developed as an alternative to 0.60 miles of the original
pipeline route through this congested area, and is located to the north
and west of the original proposed route. This route would separate from
the existing pipeline easement prior to crossing Rock Raymond Road, and
head north up a steep hill to connect to a second pipeline easement
where it would turn to the east to connect back to the first easement.

The originally proposed route through this area traverses a fairly steep
hill with some areas of severe side slopes. According to public
comments, this area has been prone to severe erosion events and flooding
during previous construction projects in the area. Although AES has been
unable to review this route in the field due to denial of access by
landowners, at this time AES believes that Route Variation 19 would
avoid residential structures, avoid an area of side slope construction,
still utilize an existing pipeline ROW for a portion of the route, and
therefore would likely result in less impacts. Therefore, subject to
completion of field reviews, AES has incorporated Route Variation 19
into the preferred route at this time.

**Route Variation 20**

Route Variation 20, from MP 81.10 to MP 81.70 as shown on Figure
10.6.4-13, was developed as a potential alternative to 0.75 miles of the
original pipeline route through this congested area, and would be
located to the east of the proposed route. This variation would follow a
second pipeline easement to the east to the end of the residential area,
and then turn to the north and join the first pipeline easement.

AES has conducted a desktop survey of this route and determined that the
route is almost twice as long, contains three additional large degree
bends, would require a greenfield easement through a significant section
of forested area, but would reduce impacts to a fairly populated
residential area. AES is in the process of evaluating Route Variation 20
to determine if the route will reduce constructability issues and
impacts to this residential area through a congested corridor.

**Route Variation 20a**

Route Variation 20a, from MP 84.80 to MP 86.30 as shown on Figure
10.6.4-14, was developed as an alternative to 1.75 miles of the original
pipeline route through this congested area, and is located to the east
of the proposed route. This variation is in an area where the existing
pipeline easement splits and would leave one branch and turn east to the
second branch of the easements south of the Town Park. The variation
would then go through the park and cross I-76 (PA Turnpike) and follow
Park Road to US-1 (Pottstown Pike), where it would turn north and meet
back with the proposed route.

This variation would involve additional greenfield construction through
a forested area and traverse the center of the Town Park, and there is
not a significant reduction in construction-related constraints. The
proposed route follows an existing pipeline easement but traverses a
heavily residential area. AES is in the process of performing an
engineering evaluation of Route Variation 20a to determine if the route
will reduce constructability issues through a congested corridor. Upon
completion of this analysis, AES will provide its recommended routing
through this area to the Commission.

**Route Variation 21**

Route Variation 21, from MP 85.25 to MP 86.30 as shown on Figure
10.6.4-14, was developed as a potential alternative to 1.75 miles of the
original pipeline route through this congested area, and is located to
the east of the proposed route along Park Road and Pottstown Pike. This
route variation was developed in response to a comment made by the
Township of Upper Uwchlan at a public hearing on June 6, 2006.

Since that public hearing, AES has met with the Township on June 20,
2006, and has been working with the Township to develop a viable route
variation as represented on Figure 10.6.4-14. This variation (combined
with portions of Route Variation 20a) would limit the impacts to the
Town Park, and residential areas, and would maximize the use of roadways
and commercial areas. Although there is a church and school located
along this variation, at this point, AES believes that Route Variation
21 would reduce residential and environmental impact, and has
incorporated it into the preferred route.

**Route Variation 22**

Route Variation 22, from MP 86.50 to MP 87.30 as shown on Figure
10.6.4-14, was developed as an alternative to 0.50 miles of the original
pipeline route through this congested area, and would be located to the
west of the proposed route. This route was developed partially based on
public comment. This variation would leave the preferred route on the
north side of the Catholic Church property and cross Fellowship Road.
The variation would then travel along the back of the Lexus Dealership,
across the landscape supply business, and continue north around the
wastewater treatment facility. At this point, the variation would turn
to the east and rejoin the original proposed route.

AES evaluated Route Variation 22 and would be able to site the line to
avoid residential and commercial development. The original route is
shorter and contains fewer large turns, but it does travel along a
highly congested road where workspace is limited and close to a
residential subdivision. Although Route Variation 22 is longer, at this
point, AES believes that it would reduce residential and environmental
impact, and has incorporated this route variation into the preferred
route.

## Summary

The North American natural gas industry is facing a critical period over
the next 10 to 15 years when increased supply availability will be
essential. Given that the unsatisfied demand for energy supply available
from natural gas is not considered to be acceptable to consumers (i.e.,
consumers demand natural gas due to the efficiencies and environmental
benefits it offers) alternatives not meeting the purpose and need of the
Project were not considered viable, including the No-Action alternative.

System alternatives for the proposed LNG Terminal were considered. These
alternatives include the expansion of existing or approved LNG
terminals, including Crown Landing LNG and Dominion Cove Point LNG. In
addition, AES evaluated trans-continental pipeline projects such as the
Rockies Express Pipeline and the Mackenzie Gas Project. Given the
forecasted decrease in production of natural gas in supply basins that
serve the Mid-Atlantic Region, LNG is projected to supply not only
incremental increases in natural gas demand, but also to replace the
projected reduction in other supply components (i.e. natural gas imports
from Canada and certain United States production basins). For this
reason, neither the expansion of existing or proposed LNG terminal
projects nor the proposed trans-continental pipeline projects would be
an adequate system alternative to the Project. In addition,
trans-continental pipeline projects, without accompanying construction
of one or more LNG terminals, would not serve the Project purpose of
accessing supplies of natural gas from world production centers, and
would likely result in greater landowner and environmental impact. The
commercial feasibility of serving the Mid-Atlantic Region from sources
outside the Region (whether those sources are production basins in North
America or LNG terminals) further limits the acceptability of such
alternatives. Finally, the additional Project benefit of introducing new
natural gas storage facilities into the area would not be realized.

AES used seven criteria to evaluate locations of an LNG terminal,
including alternatives for offshore and onshore options. Consideration
of design features, including deepwater access, distance to residential
areas so as to provide a wide margin of safety for the public in any
worst-case event, and minimization of disruptions to maritime traffic,
led to the conclusion that only projects sited along the Mid-Atlantic
seaboard or within the Chesapeake Bay would be a feasible LNG terminal
site alternative to the proposed site at Sparrows Point. Once all
offshore terminal locations were eliminated from further consideration,
seven onshore alternative locations within the Chesapeake Bay were
evaluated in detail. Four of the alternative sites were eliminated due
to close proximity to residential areas. Two other alternatives were
eliminated because obtaining site control within a reasonable and timely
manner did not appear likely. Finally, one alternative was eliminated
because it would require routing the associated natural gas pipeline
through more densely populated areas than the preferred location at the
proposed Terminal Site.

Four pipeline system alternatives to the proposed Pipeline were
evaluated, none of which is considered to be a viable alternative. In
accordance with conventional pipeline routing principles, collocation
with existing utility corridors to the maximum extent possible was the
primary routing strategy. The primary strategy was supplemented by
evaluation of a range of environmental, engineering, and socio-economic
variables. An existing natural gas pipeline corridor controlled by
Columbia, which traverses northeasterly across northeastern Maryland and
southeastern Pennsylvania, was identified as the primary route corridor
for the northern portion of the Pipeline. This portion of the proposed
Pipeline Route would comprise approximately 65 percent of the total
Pipeline length. The Columbia corridor offers the proper direction and
shortest distance, thereby decreasing potential physical, natural and
human resource impacts. The proposed Pipeline Route and four route
alternatives were evaluated south of the Susquehanna River in Maryland.
Based on a combination of variables, a combination of route alternatives
having the least overall environmental and socio-economic impact was
selected for the southern portion of the route. AES also has evaluated
25 minor route variations along the preferred route, and has
incorporated many of those into its proposal.

LNG terminal design alternatives, dredging methods and dredged material
management alternatives were also evaluated in order to avoid or
minimize environmental impacts, and impacts on waterway users based on
public input received, and consistent with local available options such
as access to land. Based on the analyses presented above, AES believes
that the identified preferred alternatives meet the goals of
implementing a Project that avoids or minimizes potential human resource
and environmental impacts.

## References

1\. American Council for an Energy-Efficient Economy. 2003. Natural Gas
Price Effects of Energy Efficiency and Renewable Practices and Policies.
December 2003 as cited within the Federal Regulatory Commission. 2006.
Final Environmental Impact Statement on the Crown Landing LNG and Logan
Lateral Projects (FERC Docket Nos. CP04-411-000 and CP04-416-000)
Issued: April 28, 2006.

2\. Chesapeake Bay Foundation 2006. http://www.cbf.org (Retrieved August
2, 2006)

3\. Federal Regulatory Commission. 2006. Final Environmental Impact
Statement on Dominion Cove Point Expansion Project (FERC Docket Nos.
CP05-310-000 et al.) Issued: April 28, 2006 (Dominion FEIS 2006)

4\. Federal Regulatory Commission. 2006. Final Environmental Impact
Statement on the Crown Landing LNG and Logan Lateral Projects (FERC
Docket Nos. CP04-411-000 and CP04-416-000) Issued: April 28, 2006 (Crown
FEIS 2006)

5\. Imperial Oil Limited. 2003. The Mackenzie Gas Project.
http://www.mackenziegasproject.com/ (Retrieved July 3, 2006)

6\. Report of the National Petroleum Council titled, Balancing Natural
Gas Policy --Fueling the Demands of a Growing Economy, dated September
25, 2003

7\. Rockies Express Pipeline LLC. June 15, 2006. Rockies Express
Pipeline. http://www.rexpipeline.com/ (Retrieved July 3, 2006)

8\. Mackenzie Gas Project, submittal of regulatory filings to Northwest
Territories agencies, October 2004. http://www.mackenziegasproject.com.

9\. U.S. Army Corps of Engineers, Dredge Bucket Comparison Demonstration
at Boston Harbor, March 2001, Publication No. ERDC/CHL CHETN -- VI-35.
http://chl.erdc.usace.army.mil/library/publications/chetn/pdf/chetn-vi-35.pdf

10\. U.S. Department of Energy, Energy Information Administration (EIA
2006). Annual Energy Outlook with Projections to 2030, February 2006.

11\. U.S. Department of Energy, Energy Information Administration (EIA
2005). Annual Energy Outlook with Projections to 2025, February 2005.

12\. U.S. Department of Energy, Energy Information Administration, (EIA
2003). Annual Energy Outlook with Projections to 2025, January 2003.

Appendix 10A

Concentric Energy Advisors

Demand and Supply Analysis of the Mid-Atlantic Natural Gas Markets
2005-2030

Appendix 10B

Email documenting discussions with Maryland agencies

responsible for managing federally funded highways

Appendix 10C

FERC Data Request Response Matrix

[^1]: More specific information on the markets to be served and energy
    needs of the region may be found below and in Resource Report 1 --
    *General Project Description*.

[^2]: Access to natural gas reserves from production areas outside of
    North America by conventional pipeline is not practical. The nearest
    non-North American production areas are thousands of miles from the
    Mid-Atlantic Region and are separated from North America by large
    bodies of water.

[^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]: A significant portion of the expected total energy demand will be
    met with use of natural gas. See discussion in Section 10.3.1 below.
    Expected contributions from other energy sources are noted in
    Section 10.3.2.

[^5]: As noted in Section 10.4.1.1, recently approved LNG import
    projects in the Mid-Atlantic Region (i.e., the Cove Point expansion
    and the Crown Landing project) meet only a portion of the expected
    demand in the intended market area. The Broadwater LNG Facility
    might also be considered to be located in the Mid-Atlantic Region,
    but the intended market for natural gas delivered from that project
    is distinct from the market intended to be served by either Cove
    Point, Crown Landing, or the Project. Specifically, the Broadwater
    market is Long Island, Greater New York City, and Connecticut. No
    other import projects are proposed in the Mid-Atlantic Region at
    this time.

[^6]: Section 10.4.2.1 discusses the capacity constraints of existing
    pipelines currently serving the Mid-Atlantic Region.

[^7]: Shipping distances to the Project from Atlantic Basin LNG
    suppliers, however, are shorter than to the terminals in the Gulf
    States Region. This fact increases the likelihood that the all-in
    delivered cost of LNG to the Project will be less than the all-in
    delivered cost of LNG to terminals in the Gulf.

[^8]: Crown Landing FEIS at 3-4.

[^9]: The Final Environmental Impact Statement on the Crown Landing LNG
    and Logan Lateral Projects (FERC Docket Nos. CP04-411-000 and
    CP04-416-000) correctly notes that, "\[f\]rom a commercial
    perspective, the best location of an LNG terminal is close to the
    market it is intended to serve." The great distance of terminals in
    the Gulf of Mexico Region "effectively limits them from serving the
    Mid-Atlantic market."

[^10]: Offshore terminals may experience interruptions caused by high
    seas or other inclement weather that affect the ships' ability to
    stay moored and off-load at open ocean moorings.

[^11]: It was noted in Section 10.4.1 that small amounts of natural gas
    imported through the LNG terminals at Lake Charles and Elba Island
    might find their way into the Mid-Atlantic Region, and that
    expansions of those terminals were recently approved by FERC.
    Regardless of the size of the approved expansions, existing pipeline
    capacities from those areas do not allow for the introduction of the
    same quantities of natural gas as proposed to be delivered through
    the Project without significant expansions of those existing
    pipeline systems, or construction of new pipeline systems. Pipeline
    systems alternatives are discussed in Section 10.4.2.

[^12]: *Guidance on Risk Analysis and Safety Implications of a Large
    Liquefied Natural Gas (LNG) Spill Over Water*, Sandia National
    Laboratories SAND2004-6258 (December 2004), cited to four recent LNG
    spill-modeling studies that included reports by Lehr and
    Simicek-Beatty, Fay, Quest, and Koopman. The calculated "skin burn"
    distances (the point at which a heat flux value of 5kW/m^2^ could be
    conservatively measured) in each of these reports was listed as 500
    meters (Lehr), 1,900 meters (Fay), 490 Meters (Quest), and 1,290
    meters (Koopman). In a subsequent study, Fay indicated that the
    "skin burn" distance was 1,100 meters (*Spills and Fires from LNG
    and Oil Tankers in Boston Harbor*, March 26, 2003).

[^13]: See discussion in Section 10.4 regarding system alternatives. In
    summary, alternatives outside of the defined market area are not
    considered commercially feasible for serving the same market as the
    Sparrows Point Project due to the need to construct additional
    pipeline delivery capacity over significantly greater distances than
    required for in-area projects. Resource Report 1, *General* *Project
    Description* (summary of the market to be served); and footnote 11,
    Section 10.4.2.

[^14]: It is recognized that dredging may also result in certain
    benefits to a particular waterbody. These situations occur where
    contaminated sediments may be safely and permanently removed and
    disposed of properly. See for example papers presented at
    ***"Environmental Forensics: Urban Ports & Harbors - Sediment
    Assessments in Complex Systems",*** conducted in Baltimore, Maryland
    on 26-27 September, 2006.

[^15]: ^?^ AES has not identified a supply source for the Project;
    neither does it own overseas natural gas reserves, liquefaction
    facilities, or a fleet of ships. Because it is not committed to any
    single source or supply, and its customer(s) will most likely
    receive supply from a new source due to long-term commitments of
    existing sources, additional consideration needed to be given to
    maintaining the maximum flexibility possible with respect to
    facility design. Should a new supply source commence operation, and
    should that supply source commit to build a fleet of vessels that
    required deeper drafts than the current fleet, AES would not be able
    to access that supply were it to build the LNG Terminal so as to
    accommodate only lesser draft vessels.

[^16]: Current plans exist for LNG ship designs up to 250,000 m^3^ in
    cargo carrying capacity. AES eliminated ships larger than 217,000
    m^3^ in capacity for reasons similar to the rationale for not
    limiting the project to use of ships with capacities less than
    138,000 m^3^ -- the distribution suggests that the widest possible
    use of the LNG Terminal will be made up of ships between the 125,000
    m^3^ and 217,000 m^3^ classes.

[^17]: Energy Information Administration (EIA -- 2001 to 2006) indicates
    that spot market shipment availability is only recently becoming
    available, primarily due to new ship construction, indicating
    subscription for existing fleet vessels (including smaller capacity
    ships) is full to nearly full.

[^18]: According to NOAA/US Department of Commerce Navigation Chart No.
    12312, the dredged depth for the navigation channel in the Delaware
    River is 40 feet, which is significantly less than the required
    minimum depth.

[^19]: While, as noted above, standoff distances around the LNG Terminal
    berth will ultimately be determined by a quantitative review
    performed by the USCG during the WSA process, AES performed this
    initial qualitative assessment using the currently published
    security zone for the Cove Point terminal of 500 yards to try to
    locate a terminal location that would minimize impacts to passing
    vessel traffic while the LNG vessels slow in their approach to the
    berth, while they are at berth, and after they leave the berth
    (assuming the security zone is fixed at all times ships are at
    berth, to the maximum extent practicable).

[^20]: In order to maintain the commercial viability of the Project, AES
    considered a pipeline length of 100 miles to be reasonable. See
    Resource Report 1, *General* *Project Description,* for definition
    of these elements. In comparison with the various transcontinental
    pipelines described above in Section 10.3.2, the 100-mile send-out
    pipeline scenario would have substantially smaller relative
    landowner and environmental impact. Siting of an offshore LNG
    facility would require several miles of offshore pipeline to reach
    shore (it would be reasonable to assume offshore siting distances in
    the range of 7 to 13 miles consistent with the siting of Northeast
    Gateway and Neptune mentioned above). In addition, the distance of
    an onshore pipeline route needed to reach the same interstate
    pipeline systems as will be served by the proposed Project is a
    minimum distance of approximately 100 miles inland. The combined
    environmental impact and disturbance to land and property owners on
    this combined length of off shore and onshore route can be
    reasonably concluded to be greater than that of the proposed
    Project.

[^21]: ^?^ An offshore terminal in Long Island Sound would necessitate
    construction of a more lengthy natural gas pipeline that would
    extend from the offshore location (about 10 miles) to the onshore
    interconnection points (about 175 miles), thereby increasing the
    potential landowner and environmental impacts associated with
    construction and, as noted above, decreasing the economic viability
    of the Project.

[^22]: AES assumed a minimum safety and security zone of 500 yards
    around such offshore terminal facility. If the facility were placed
    within the existing deepwater channel the safety and security zone
    would effectively prohibit vessel traffic in the channel. However,
    vapor exclusion zones would need to be calculated to determine how
    far downwind natural gas vapors or a cloud could travel from an
    offshore LNG facility and still be flammable, which may be a greater
    distance than the assumed 500-yard safety and security zone.

[^23]: As indicated earlier in this Resource Report, interconnect
    locations near Eagle, Pennsylvania comprise the interstate pipeline
    tie-in locations in order to serve the target market of the Project.
    Siting an LNG terminal south of Sparrows Point, will increase the
    pipeline distance necessary to reach the same interconnection
    endpoints. Unless such a pipeline were to route through a water
    crossing of the Patapsco River (which adds approximately 2 miles of
    pipeline length, assuming environmental approvals could be obtained
    for such a crossing), the minimum length of pipeline added would be
    on the order of five miles (for a site at Fishing Point) to 20+
    miles (for a site near the Patapsco-Chesapeake confluence) to reach
    a potential pipeline corridor from near the City of Baltimore and
    west of the Patapsco River/Port of Baltimore, then north to target
    interconnect locations. Connection with the Baltimore Gas and
    Electric (BG&E) local distribution system would still be feasible
    within this hypothetical route, however the remaining take-away
    capacity would not be feasible without the interconnect locations
    near Eagle, Pennsylvania, therefore the total length would be on the
    order of the 88-miles of the proposed Project, plus a minimum of 5
    to 20 miles of additional pipeline length from the area south of
    Sparrows Point.

[^24]: ISC bought the site in 2003 from Bethlehem Steel Corporation
    (BSC) in a bankruptcy proceeding that was initiated by BSC in 2001.

[^25]: The safety/security zone restrictions only apply when the LNG
    vessel is loaded. Thus, when the vessel departs from the LNG
    Terminal, no restrictions will apply.

[^26]: The HTF is expected to be a mix of ethylene glycol.

[^27]: A statutory requirement for material dredged from within the
    Baltimore Harbor, as determined by an imaginary line between North
    Point in Baltimore County and Rock Point in Anne Arundel County, is
    that it be treated as contaminated material and disposed at a
    contained disposal facility, regardless of chemical quality of the
    material to be dredged. Contained disposal is not required if the
    material is beneficially reused or processed for innovative reuse.