**Application for Permit to Construct**

**and**

**Non-Attainment New Source Review Approval**

**AES SPARROWS POINT LNG TERMINAL PROJECT**

**600 Shipyard Road**

**Baltimore, MD 21219**

**Submitted To:**

**Maryland Department of the Environment**

**1800 Washington Boulevard**

**Baltimore, MD 21230**

**Submitted By:**

**AES Sparrows Point LNG, LLC**

**140 Professional Way**

**Lockport, NY 14094**

**Prepared By:**

**Haley & Aldrich**

**200 Town Centre Drive, Suite 2**

**Rochester, NY 14623-4264**

**January 2007**

# Table Of Contents {#table-of-contents .unnumbered}

[Table Of Contents i](#table-of-contents)

[1.0 Introduction 3](#introduction)

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

[2.1 Project Location 5](#project-location)

[2.2 Facility Overview 5](#facility-overview)

[2.3 LNG Terminal Emission Sources and Operating Assumptions
6](#lng-terminal-emission-sources-and-operating-assumptions)

[2.4 Estimated Facility Emissions 10](#estimated-facility-emissions)

[3.0 Air Quality Regulations Applicability and Compliance
11](#air-quality-regulations-applicability-and-compliance)

[3.1 Existing Air Quality 11](#existing-air-quality)

[3.2 New Source Review Requirements 12](#new-source-review-requirements)

[3.3 MDE Title V and State Operating Permit Requirements
17](#mde-title-v-and-state-operating-permit-requirements)

[3.4 New Source Performance Standards Requirements
17](#new-source-performance-standards-requirements)

[3.5 National Emissions Standards for Hazardous Air Pollutants
Requirements
18](#national-emissions-standards-for-hazardous-air-pollutants-requirements)

[3.6 National Emissions Standards for Hazardous Air Pollutants for
Source Categories Requirements
18](#national-emissions-standards-for-hazardous-air-pollutants-for-source-categories-requirements)

[3.7 Acid Rain Program Requirements and Clean Air Interstate Rule (CAIR)
19](#acid-rain-program-requirements-and-clean-air-interstate-rule-cair)

[3.8 MDE Emission Standards 20](#mde-emission-standards)

[3.9 EPA Chemical Accident Prevention Provisions and OSHA Process Safety
Management
23](#epa-chemical-accident-prevention-provisions-and-osha-process-safety-management)

[4.0 Control Technology Analysis 25](#control-technology-analysis)

[4.1 LAER and BACT Analysis for NO~X~ Emissions from Hot Water Heaters
25](#laer-and-bact-analysis-for-nox-emissions-from-hot-water-heaters)

[4.2 LAER and BACT Analysis for CO and VOC Emissions from Hot Water
Heaters
35](#laer-and-bact-analysis-for-co-and-voc-emissions-from-hot-water-heaters)

[4.3 LAER and BACT Analysis for Emissions from Emergency Engines
36](#laer-and-bact-analysis-for-emissions-from-emergency-engines)

[5.0 Air Quality Impact Analysis 42](#air-quality-impact-analysis)

[5.1 Air Quality Modeling Analysis Scope and Objectives
42](#air-quality-modeling-analysis-scope-and-objectives)

[5.2 Model Selection 43](#model-selection)

[5.3 Emissions and Source Parameters
44](#emissions-and-source-parameters)

[5.4 Good Engineering Practice (GEP) Stack Height Analysis
45](#good-engineering-practice-gep-stack-height-analysis)

[5.5 Meteorological Data and Site Characteristics
46](#meteorological-data-and-site-characteristics)

[5.6 Receptors and Terrain Data 47](#receptors-and-terrain-data)

[5.7 Background Air Quality 48](#background-air-quality)

[5.8 Model Results 48](#model-results)

[5.9 Cumulative Impacts Analysis 49](#cumulative-impacts-analysis)

[5.10 Cooling Tower Impact Analysis 50](#cooling-tower-impact-analysis)

**Figures**

1.  Site Location Map, AES Sparrows Point LNG, LLC

2.  General Arrangement

3.  USGS Site Location Map, AES Sparrows Point LNG, LLC

4.  Facility Plot Plan Overview

5.  Facility Plot Plan -- Fabrication Building

6.  Facility Plot Plan -- Tank Area

7.  Facility Plot Plan -- Process Area

```{=html}
<!-- -->
```
1.  BPIP Model Setup, Building/Structure Identification

2.  BPIP Model Setup, 3D Building Representation

3.  AERMOD Model Setup Showing Buildings, Fenceline, Plant Boundary and
    Near-Field Receptors

4.  AERMOD Model Setup Showing Polar Receptor Grid and Domain Boundaries

**Tables**

1.  Hot Water Heaters Emissions

2.  Diesel Fire Water Pump (Fresh Water) Emissions

3.  Diesel Fire Water Pump (Salt Water) Emissions

4.  Standby Generator Emissions

5.  Vent Stack Heater Emissions

6.  LNG Tanker Ship Unloading Operations Emissions -- Assumptions

7.  LNG Tanker Ship Unloading Operations Emissions

8.  LNG Terminal Stationary Source Emissions Summary

9.  National and Maryland Ambient Air Quality Standards

10. Air Quality Control Region Attainment Status

11. Representative Ambient Background Data from Monitoring Stations

```{=html}
<!-- -->
```
1.  Stack Parameters and Emission Rates for Model Input

2.  Source Groups Used In Modeling Analysis

3.  Building/Structure Dimensional Data

4.  Sectors and Site Characteristics Used for AERMET Input

5.  Representative Ambient Background Data From Monitoring Stations

6.  Summary of AERMOD Modeling Results by Scenario and Model Year

7.  Summary of Maximum AERMOD Impacts By Model Scenario

8.  Maryland Counties Emissions Inventory (2001)

9.  Comparison of Project Direct and Indirect Emissions With County
    Emissions Inventory

**Appendices**

A Permit Application Forms

B. State-Wide Compliance Certification

C. Preliminary Vendor Data

D. CD Containing Dispersion Modeling Input/Output Files

E. Alternatives Analysis

# Introduction

AES Sparrows Point LNG, LLC (Sparrows Point LNG) proposes to construct,
own, and operate a new liquefied natural gas (LNG) import, storage, and
regasification terminal (LNG Terminal) at the Sparrows Point Industrial
Complex situated on the Sparrows Point peninsula east of the Port of
Baltimore in Maryland. LNG will be delivered to the LNG Terminal via
ship, offloaded from the ship to shoreside storage tanks, regasified on
the LNG Terminal site (Terminal Site), and transported to consumers via
pipeline. The LNG Terminal will have a regasification capacity of 1.5
billion standard cubic feet of natural gas per day (bscfd), with
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 natural gas pipeline (Pipeline) to be constructed and
operated by Mid-Atlantic Express, LLC (Mid-Atlantic Express). The
Pipeline will extend from the LNG Terminal to interconnections with
existing 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 AES Sparrows Point LNG and Mid-Atlantic
Express (hereinafter collectively referred to as AES) are subsidiaries
of The AES Corporation. The stationary emission sources to be located at
the LNG Terminal are the subject of this application for Permit to
Construct (PTC) and Nonattainment New Source Review (NNSR) Approval.

The principal components of the proposed LNG Terminal include marine
terminal facilities, three full-containment onshore LNG storage
tanks[^1], a vaporization system, a vapor handling system, site
utilities, administrative and support buildings, instrumentation and
control systems, communications and security systems, and fire
protection, hazard detection and safety systems. Potential emissions
sources subject to air permitting are combustion sources necessary for
the LNG regasification and sendout and for fire protection and emergency
standby power generation. These emissions sources include four installed
natural gas-fired hot water heaters, a total of eight diesel
reciprocating engines used for emergency fire water pumping and standby
electricity generation, and a heated vent stack, which will be used to
heat boil off vapors from the LNG Terminal if a power failure renders
the vapor handling systems inoperable. Although LNG ships will not be
owned or operated by AES, estimated emissions from LNG ships associated
solely with LNG offloading activities were also added to potential
emissions from proposed LNG Terminal stationary sources for the purpose
of evaluating applicability of Prevention of Significant Deterioration
(PSD) and NNSR requirements. This analysis demonstrates that potential
emissions will be less than U.S. Environmental Protection Agency (EPA)
Major Stationary Source thresholds for each regulated pollutant, with
the exception of ozone precursor nitrogen oxide (NO~X~) emissions.
Therefore, the LNG Terminal will be a major source with respect to NO~X~
emissions in an ozone nonattainment area, and will be subject to NNSR
permitting requirements. The LNG Terminal will be considered a minor
source with respect to volatile organic compounds (VOCs) and all
attainment pollutants and, therefore, will not be subject to NNSR for
VOC or PSD review for any attainment pollutants.

AES is considering the possibility of constructing and operating a 300
megawatt (MW) combined-cycle cogeneration power plant (Power Plant) on
the Terminal Site. The Power Plant, which would provide heat to the LNG
vaporizers and generate electricity for the local utility electric
system, would operate in lieu of or in conjunction with the hot water
heaters, depending on the operating scenario. The Power Plant is not
included in the scope of the current permit application. However, AES
understands that if it decides to construct and operate the Power Plant,
it will not be considered separate from the LNG Terminal with respect to
New Source Review (NSR) requirements. The combined emissions from the
LNG Terminal and Power Plant will be used for the purpose of PSD and
NNSR applicability determinations even if AES receives permits for the
LNG Terminal stationary sources and subsequently submits applications
for the Power Plant. If NNSR or PSD review applies with the addition of
the Power Plant, all requirements will apply to LNG Terminal and Power
Plant sources. In anticipation of the potential future addition of the
Power Plant, emissions limits and controls for currently proposed LNG
Terminal sources have been incorporated into the design in order to meet
potentially-applicable future LAER and BACT criteria.

This document serves as AES's formal application for the required PTCs
and NNSR Approval for the proposed LNG Terminal. Section 2.0 describes
the LNG Terminal, including site location, LNG Terminal overview and
detailed descriptions of the stationary sources and operating
assumptions used in developing potential emissions estimates. Section
3.0 provides a detailed analysis of potentially-applicable air quality
regulatory requirements and demonstrations of compliance with applicable
requirements. Section 4.0 presents the Lowest Achievable Emission Rate
(LAER) control technology demonstrations and also discusses how
presently-proposed controls will meet potential future LAER and Best
Available Control Technology (BACT) criteria in the event that AES
decides to construct and operate the Power Plant. Although an air
quality impact evaluation is not an applicable requirement of the
present permit application, a summary of the dispersion modeling
analysis conducted for the FERC application for Certificate of Public
Necessity and Convenience is presented in Section 5.0. Completed
application forms, detailed calculations and other documentation are
provided in the appendices.

# Project Description

## Project Location

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

The Terminal Site is situated on a promontory that extends into the
Chesapeake Bay east of the Port of Baltimore as shown on Figure 2-1.
More specifically, the Terminal Site is located on the Marine Channel
adjacent to the Fort McHenry channel near the confluence of the Fort
McHenry Channel and the Brewerton Angle. The boundaries of the main
property where the LNG Terminal will be located, including both
land-side and riparian rights area, the proposed turning basin and
approach channel, are shown on Figure 2-2. Figure 2-3 depicts the
location of the Terminal Site location on a USGS topographical map.

## Facility Overview

The principal components of the proposed LNG Terminal include marine
terminal access and facilities, three full-containment onshore LNG
storage tanks, a vaporization system, a vapor handling system, site
utilities, administrative and support buildings, instrumentation and
control systems, communications and security systems, and fire
protection, hazard detection and safety systems. The LNG Terminal
facilities have been sited and will be designed, constructed and
operated in accordance with all applicable standards and requirements
established by the U.S. Department of Transportation (USDOT) (49 CFR
Parts 192 and 193), the Federal Energy Regulatory Commission (FERC) (18
CFR Parts 153 and 380) and the U.S. Coast Guard (USCG) (33 CFR Parts
105, 127, 157 and 160), as well as additional standards and regulations
cited in the FERC application for Certificate of Public Necessity and
Convenience.

The following facility plot plans are provided, depicting the major LNG
Terminal components:

-   Figure 2-4 Facility Plot Plan -- Overview

-   Figure 2-5 Facility Plot Plan -- Fabrication Building

-   Figure 2-6 Facility Plot Plan -- Tank Area

-   Figure 2-7 Facility Plot Plan -- Process Area

The LNG Terminal design regasification/sendout capacity will be 1.5
bscfd, at a maximum sendout pressure of 2,080 pounds per square inch
(psig). It is expected to operate continuously in a baseload mode of
operation, and will be designed to allow the potential addition of a
fourth tank and a potential expansion in vaporization and sendout
capacity of up to 2.25 bscfd. The Terminal design includes
pre-investment in features and equipment, including blanked off pipe
connections, to facilitate this future expansion. If and when the time
comes to pursue this expansion, AES will perform a more detailed study
on the expansion case to identify changes required to the existing LNG
Terminal facilities.

## LNG Terminal Emission Sources and Operating Assumptions

Emissions from operation of the LNG Terminal would primarily involve
criteria pollutants and hazardous air pollutants (HAPs) from operation
of the High Temperature Fluid (HTF) heating system used to provide heat
to the LNG vaporizers and LNG ship auxiliary power systems used during
offloading of LNG to the LNG Terminal. Emissions will also result from
operation of emergency diesel engine powered fire water pumps, a diesel
engine powered standby electricity generator and other minor auxiliary
combustion equipment. This air permit application specifically addresses
emissions from the following stationary sources and activities at the
LNG Terminal:

-   Four natural gas-fired hot water heaters, each rated at 345 MMBtu/hr

-   One 375 HP diesel engine powered fire pump (freshwater)

-   Six 700 HP diesel engine powered fire pumps (seawater)

-   One 2 MW diesel engine powered emergency generator,

-   One natural gas-fired heated vent stack rated at 5.5 MMBtu/hr, and

-   LNG ship offloading operations.

-   Dredged Material Recycling Facility

It should be noted that the LNG storage tanks are not considered
stationary sources of air pollution subject to permitting review. The
LNG tanks are not vented and the principal components of vaporized LNG
are not regulated air pollutants. During normal terminal operation and
LNG ship unloading, a boiloff gas (BOG) compression system will be used
to control the BOG pressure in the storage tanks. As discussed in
section 2.3.5, boiloff vapors will be directed to the heated vent stack
for safety purposes in the event that BOG compressors are inoperative
due to power failure or other emergency.

### Hot Water Heaters

Four hot water heaters are proposed for installation at the LNG Terminal
to provide heat required for LNG vaporization as part of the HTF heating
system. Three of the hot water heaters would normally be operated for
the equivalent of up to 8,760 hours per year at up to 100 percent rated
capacity with the fourth hot water heater operated in hot standby using
a heating coil. Each hot water heater would be rated at 345 million
British thermal units per hour (MMBtu/hr) maximum heat input and will be
fueled exclusively with natural gas. It was assumed that there would be
two catalyst malfunctions per hot water heater per year, lasting 48
hours each, resulting in uncontrolled emissions. Furthermore, it was
assumed that each hot water heater would undergo three cold iron
startups per year, each lasting one hour at an average of 15 percent
load before controls were effective. This was the operating scenario
used as a basis for the estimated short-term and annual potential
emissions. Table 2-1 summarizes maximum emission rates for the hot water
heaters based on these assumptions. Criteria pollutant emissions factors
were based on a review of recent BACT and LAER determinations for
similar types and sizes of natural gas-fired hot water heaters, and from
preliminary emissions guarantees from potential vendors. The emissions
control systems would include low-NO~X~ burners and/or flue gas
recirculation for preliminary NO~X~ control, selective catalytic
reduction (SCR) for final NO~X~ control, and oxidation catalysts for
carbon monoxide (CO) and VOC control.

### 375 HP Fire Pump (Fresh Water)

The 375 HP fire pump will be diesel engine-driven and used to provide
redundancy to an electric motor-driven fresh water fire pump in the
event of a fire during an electrical power failure. This system is
capable of providing two hours of design flow fire water. The assumed
worst-case operating scenario for this diesel engine fire pump is 60
hours per year to conduct periodic testing and to allow for an emergency
event. Emissions were estimated based on representative engine
manufacturers' performance and emissions data for criteria pollutants
other than sulfur dioxide (SO~2~) and on EPA AP-42 emission factors for
SO~2~ and hazardous air pollutants. SO~2~ emissions were based on diesel
fuel containing a maximum 15 parts per million (ppm) sulfur content.
Short term and annual emissions rates for this engine are summarized in
Table 2-2.

The Code of Maryland Regulations (COMAR) Section 26.11.02.10 provides a
list of sources exempt from permitting and approval requirements. This
list includes "stationary internal combustion engines with an output
less than 500 brake horsepower (373 kilowatts) and which are not used to
generate electricity for sale or for peak or load shaving". Because the
size of this fire pump will not be above the permitting/approval
threshold, this unit is exempted and a permit to construct is not being
sought for it. However, its potential emissions are included in the
total facility potential emissions for purposes of determining major
source status. In addition, a condition will need to be included in the
NNSR Approval restricting operation of this source to 60 hours per year.

### Six 700 HP Fire Pumps (Salt Water)

The set of six 700 HP diesel engine-driven fire pumps, installed at the
water\'s edge, will provide additional backup fire water from the
Patapsco River. These backup pumps can provide full flow to the onshore
fire water system, and can also provide tank deluge flow in the event of
a tank fire. The assumed worst-case operating scenario for these diesel
engine fire pumps is 60 hours per year to conduct periodic testing and
to allow for an emergency event. Emissions were estimated based on
representative engine manufacturers' performance and emissions data for
criteria pollutants other than SO~2~ and on EPA AP-42 emission factors
for SO~2~ and hazardous air pollutants. SO~2~ emissions were based on
diesel fuel containing a maximum 15 ppm sulfur content. Short term and
annual emissions rates for this engine are summarized in Table 2-3.

### 2 MW Emergency Generator

The 2 MW diesel engine-powered standby generator set will be used in the
event of a utility power failure and will be capable of providing
sufficient power to maintain LNG circulation via operation of one low
pressure (LP) pump and to provide for LNG Terminal lighting, all control
systems, and the operation of all other necessary auxiliary systems. The
assumed worst-case operating scenario for this diesel engine generator
is 60 hours per year to conduct periodic testing and to allow for an
emergency event. Emissions were estimated based on representative engine
manufacturers' performance and emissions data for criteria pollutants
other than SO~2~ and on EPA AP-42 emission factors for SO~2~ and
hazardous air pollutants. SO~2~ emissions were based on diesel fuel
containing a maximum 15 ppm sulfur content. Short term and annual
emissions rates for this engine are summarized in Table 2-4.

### Heated Vent Stack

The boiloff gas (BOG) compression system will consist of three
reciprocating type BOG compressors, two of which will be used during
active LNG ship unloading. During normal terminal operation, when no LNG
ships are unloading, one BOG compressor will be needed to control the
BOG pressure in the storage tanks. If the BOG compressor is inoperative
due to power failure or other emergency, the boiloff vapors will be
directed to the heated vent stack for safety purposes. Because this is a
safety/emergency system, air emissions from this source will be
infrequent and intermittent. The heated vent stack will be a small (5.5
MMBtu/hr) natural gas-fired combustion source and is assumed to operate
no more than 50 hours per year. Anticipated emissions from the heated
vent stack were estimated to be very low based on vendor emission
factors and are summarized in Table 2-5. However, even if this unit were
operated 8,760 hours per year at maximum rated capacity, the potential
emissions of each pollutant would be less than 1 ton per year (TPY).
Based on its low potential to emit, this unit would be exempt from the
requirement for a permit to construct under the provisions of COMAR
26.11.02.10.

### LNG Ship Offloading Operations

As discussed in Sections 1.0 and 3.1, emissions from LNG ship offloading
operations have been aggregated with potential emissions from stationary
sources at the LNG Terminal for purposes of determining PSD and NNSR
permit applicability. For the purposes of conservatively estimating
marine vessel emissions, the estimated annual emissions from these
mobile sources are based on up to 180 LNG ship arrivals[^2] of various
capacity ships; three tug boats, and two security or escort boats
participating in the arrival, berthing and departure of each LNG ship;
and emissions during LNG offloading and idling while stationary at berth
(hoteling). AES estimates that LNG ships will arrive at the Terminal
Site with a typical frequency of two to three ships per week depending
on the capacity of the ship). Each ship will remain stationary at the
berth for a maximum of 24 hours, about 12 to 18 hours of which for
transferring of LNG, depending on the capacity of the ship and an
average unloading rate of about 11,500 cubic meters per hour.

AES obtained information concerning the type of propulsion, power
generation, fuel types, operating scenarios and other parameters
necessary to estimate emissions during offloading activities at the LNG
Terminal. Based on this information, the current fleet of LNG ships (182
within AES's design range of 125,000 to 217,000 cubic meter capacity)
exclusively run on conventional steam-electric power plants for both
propulsion and auxiliary power and are fueled with boil-off gas or heavy
fuel oil. AES has also determined that there are currently 117 LNG ships
on order or under construction within AES's design capacity envelope for
the LNG Terminal. These consist of 61 (52 percent) that are steam
powered ships and 57 (48 percent) that are powered by slow speed or
medium speed diesel engines for propulsion and auxiliary power. The
diesel engines can be fueled with low sulfur distillate (1.5 percent
sulfur), heavy fuel oil (2.7 percent sulfur) or dual fuel mixtures
(e.g., Marine Gas Oil (MGO), typically consisting of 90 to 95 percent
gas and 5 to 10 percent low sulfur oil). Because AES will not own or
operate the LNG ships that will deliver LNG to the LNG Terminal, a
number of different power plant and fuel scenarios were evaluated in
order to conservatively estimate the range of emissions to be expected
from LNG ship movements and transfer operations. The scenarios evaluated
ranged from natural gas fired steam-electric power plants to diesel
engines firing 2.7 percent sulfur heavy fuel oil. An assumed mix of
technologies and fuels was then used to estimate annual emissions, based
on AES's evaluation of the representative levels of technologies and
fuels currently in use and projected to be in use in the LNG shipping
industry. Detailed assumptions used for all calculations are summarized
in Table 2-6. AES believes these are conservative assumptions; however,
the assumptions may need to be refined in the future based on actual
shipping assignments and/or availability, actual ship operating
conditions, and trends in the industry for the various sizes of LNG
ships.[^3] The emission estimates based on these assumptions and EPA
emission factors are presented in Table 2-7.

### Dredged Material Recycling Facility (DMRF)

A dredged material recycling facility (DMRF) will also be constructed
and operated at the LNG Terminal construction site, involving use of
hoppers, conveyors, pug mills for mixing additives, and stacking
equipment. Pug mills and the additive delivery system will be equipped
with separate baghouse dust collectors to control PM~10~ and PM~2.5~
emissions. Marine vessels and equipment used for offshore dredging
activities will include a clamshell dredge or suitable alternative
required by permit, in addition to tug boats, survey/work boats, crew
boats and inspecting/diving vessels. These mobile sources are not
subject to stationary source permitting requirements.

AES will use the mitigation measures to minimize the fugitive dust
emissions associated with transfer of the processed dredged material
(PDM) once it has been processed in the DMRF. These measures may include
the application of water or dust suppressants, covering of haul trucks,
use of paved roads to the extent possible, limiting vehicle speed and
stabilizing disturbed areas.

The majority of materials handled in the DMRF will be high
moisture-content dredged materials with little potential for dust
emissions. Dry additive filling, storage and transfer equipment will be
contained in enclosed structures with baghouse dust collectors for
high-efficiency dust control. As a result, PM~2.5~/PM~10~ emissions from
the DMRF will be negligible, with uncontrolled emissions currently
estimated at less than 1 TPY. Based on estimated uncontrolled
PM~2.5~/PM~10~ emissions, the DMRF additive material storage, transfer,
mixing and dust control equipment would be exempt from the requirement
for a permit to construct under the provisions of COMAR 26.11.02.10.

## Estimated Facility Emissions

Total LNG Terminal potential emissions based on the operating scenarios
and assumptions discussed herein and calculations presented in Tables
2-1 through 2-7 are summarized below and in Table 2.8.

  --------------- ----------- ---------- ---------- ------------- ---------- -------------- ------------ -------------
  **Potential                                                                                            
  Emissions                                                                                              
  (tons/year)**                                                                                          

  **Pollutant**   **Hot Water **Fire     **6 Fire   **Emergency   **Stack    **LNG Ship     **Total LNG  **Major
                  Heaters**   Pump       Pumps      Standby       Vent       Offloading**   Terminal**   Source
                              (Fresh     (Salt      Generator**   Heater**                               Threshold**
                              Water)**   Water)**                                                        

  NO~X~           18.1        0.1        1.6        1.3           0.0007     11.84          32.9         25

  CO              34.9        0.009      0.1        0.1           0.003      1.8            37.0         100

  VOC             18.9        0.002      0.03       0.03          0.003      0.30           19.3         25

  PM-10           34.2        0.002      0.009      0.007         0.001      0.393          34.6         100

  SO~X~           0.5         0.000      0.00       0.00          0.001      3.05           3.6          100

  Total HAPs      8.6         3.1E-04    1.3E-03    9.2E-04       2.6E-04    2.9E-02        8.6          25
  --------------- ----------- ---------- ---------- ------------- ---------- -------------- ------------ -------------

Based on total premise emissions, and as discussed in Section 3.2, the
proposed LNG Terminal will be a Major Stationary Source of ozone
precursor NO~X~ emissions and will be subject to NNSR for NO~X~. The LNG
Terminal will not be a Major Stationary Source with respect to any other
pollutant and will, therefore, not be subject to PSD review.

# Air Quality Regulations Applicability and Compliance

Emissions from operation of the LNG Terminal would be subject to
applicable federal and state air quality regulations. This section
provides a detailed evaluation of applicability of specific air
regulations to emissions units and demonstrations of compliance with
applicable requirements.

## Existing Air Quality

### Ambient Air Quality Standards

EPA has established primary and secondary national ambient air quality
standards for certain air pollutants, including CO, lead (Pb), nitrogen
dioxide (NO~2~), ozone, particulate matter less than 10 microns
(PM~10~), particulate matter less than 2.5 microns (PM~2.5~) and SO~2~,
which are referred to under the Clean Air Act CAA as \"criteria
pollutants.\" National Ambient Air Quality Standards (NAAQS) have been
established for each of the criteria pollutants. Standards are
designated as primary or secondary. Primary standards are set at levels
designed to protect public health. Secondary standards are set to
protect welfare values such as vegetation, visibility and property
values. States are free to adopt standards more stringent than the
NAAQS. Maryland has adopted all of the NAAQS. Table 2-9 summarizes the
NAAQS as well as the corresponding Maryland Ambient Air Quality
Standards.

### Ambient Air Quality Attainment Status

The LNG Terminal is proposed to be located in Baltimore County,
Maryland. Baltimore County is contained in the Metropolitan Baltimore
Intrastate Air Quality Control Region (AQCR 115). The EPA has designated
AQCR 115 as being either in attainment with the NAAQS or
unclassifiable/attainment for certain criteria air pollutants, including
SO~2~, CO, and NO~2~ and PM~10~. With respect to the one-hour ozone
(O~3~) standard (revoked as of June 25, 2005), AQCR 115 is classified as
severe-15 non-attainment. With respect to the new 8-hour ozone standard,
AQCR 115 is classified as moderate non-attainment. For PM~2.5~, AQCR 115
has been classified as non-attainment.[^4] For Total Suspended
Particulate (TSP), portions of AQCR 115 that do not include the LNG
Terminal have been classified as nonattainment. Although TSP attainment
designations are listed in 40 CFR 81, there no longer are TSP NAAQS and
TSP-directed State Implementation Plan (SIP) programs. EPA revised the
primary and secondary NAAQS for particulate matter on July 1, 1987 by
eliminating TSP as the indicator for the NAAQS and replacing it with the
PM~10~ indicator. Table 2-10 summarizes the attainment status for AQCR
115.

Because AQCR 115 is classified as non-attainment with respect to the old
one-hour ozone standard and had 1-hour design values greater than or
equal to 0.121 ppm, it is categorized as \"subpart 2\" non-attainment
with respect to the new 8-hour ozone standard. As such, the AQCR is
subject to specific requirements that must be incorporated into SIPs for
attaining the national ozone air quality standards. In addition,
Maryland is considered part of the Ozone Transport Region (OTR). The OTR
encompasses eleven northeast states and the District of Columbia, all of
which have at least some areas not meeting the NAAQS for ozone. Because
ozone attainment is a region-wide problem involving interstate transport
of ozone precursors, projects locating in all areas within the OTR must
meet more stringent non-attainment new source review requirements. The
applicable emissions thresholds triggering major new source review in
the Metropolitan Baltimore Intrastate AQCR are 25 TPY for either VOCs or
NO~X~. New stationary sources with the potential to emit VOC or NO~X~
above these thresholds would be classified as Major Stationary Sources
subject to more stringent NNSR requirements.

### Existing Ambient Air Quality Monitoring Data

The Maryland Department of the Environment (MDE) monitors ambient
concentrations of certain criteria pollutants at a number of monitoring
stations located in the vicinity of the LNG Terminal. The monitored
data, which are available from EPA's AirData website
(http://www.epa.gov/air/data/reports.html), were evaluated to determine
representative air quality levels for the area around the LNG Terminal.
Table 2-11 summarizes the most recent three-year averages of the data
available from monitoring stations with the most representative
locations with proximity to the LNG Terminal. The assumptions used in
developing the most representative three-year average concentrations are
also detailed in Table 2-11. The monitoring data demonstrates that all
monitored pollutants are meeting the NAAQS, with the exception of
one-hour and 8-hour average ozone and annual average PM~2.5~
concentrations in Baltimore. The monitored 24-hour average PM~2.5~
concentrations in Baltimore County also exceed the recently (12/18/06)
promulgated revised standard (35 µg/m^3^); however, the Maryland SIP
will need to be revised to address NSR and other requirements related to
PM~2.5~ attainment.

## New Source Review Requirements 

The NSR provisions of the CAA apply to new Major Stationary Sources or
Major Modifications to Major Stationary Sources under two separate
programs. For sources located in areas designated as attaining the
Ambient Air Quality Standards, with respect to a specific regulated
criteria pollutant, the requirements of the PSD program (40 CFR § 52.21)
apply. For Major Stationary Sources located in areas that do not attain
the Ambient Air Quality Standards, the requirements of the NNSR Program
(40 CFR Parts 51 and 52) apply to each non-attainment pollutant. The LNG
Terminal will involve construction and operation of a new stationary
source in Maryland. Evaluation of the applicability of NSR regulations
to these sources is discussed below. Administration of NSR programs in
Maryland is provided by MDE's SIP-approved regulations promulgated under
COMAR Section 26.11 with respect to the LNG Terminal.

As discussed in Section 1.0 and 2.3.6, for the purposes of the Major
Stationary Source applicability determinations under PSD and NNSR rules,
total potential emissions associated with operation of the LNG Terminal
are assumed to include the combination of emissions from stationary
emission units at the LNG Terminal with those emissions from LNG ships
associated solely with LNG offloading activities while the LNG ships are
at berth. The offloading activities are included in the major source
applicability determination because the transferring of fuels from LNG
ships is directly connected to the function of the LNG Terminal. This
conservative approach was taken because this procedure is consistent
with EPA guidance provided in the 1990 Draft New Source Review Workshop
Manual as well as several EPA policy documents on this subject[^5].

### PSD Requirements

MDE's approved SIP provides the authority to issue air permits in
accordance with federal PSD regulations (40 CFR § 52.21), which are
designed to ensure that the air quality in current attainment areas does
not significantly deteriorate beyond baseline concentration levels. The
PSD regulations specifically apply to the construction of EPA-defined
Major Stationary Sources and Major Modifications to existing Major
Stationary Sources in areas designated as attainment for at least one of
the following criteria pollutants: SO~2~, NO~2~, PM~10~, CO, O~3~, and
Pb. In addition, pursuant to EPA's proposed implementation of PM~2.5~
standards, states are in the process of developing SIP revisions that
would include applicability and review criteria for PM~2.5~ emissions.
In the meantime, EPA guidance to the states is to utilize the PM~10~
requirements as a surrogate for PM~2.5~. For PSD purposes, a Major
Stationary Source is defined as one of 28 listed source categories with
the potential to emit 100 TPY or more of any pollutant regulated under
the CAA. A non-listed Major Stationary Source is defined as a source
with the potential to emit 250 TPY or more of any regulated pollutant.
PSD applies on a pollutant-specific basis at Major Stationary Sources
for each pollutant with the potential to be emitted at greater than
EPA-defined Significant Emission Rates: 100 TPY CO; 40 TPY NO~X~, SO~2~
or VOC; 25 TPY TSP; 15 TPY PM~10~; 0.6 TPY Pb. For PM~2.5~, EPA has
proposed to apply a Significant Emission Rate of 10 TPY of direct
PM~2.5~ emissions and 40 TPY of precursor SO~2~ emissions. If other
precursors are included for determination of major source applicability
to PM~2.5~, a 40 TPY Significant Emission Rate would be used for
precursor NO~2~ emissions and other Significant Emission Rate thresholds
may apply to precursor VOC and ammonia emissions, as determined by the
state's SIP.

Based on the attainment status of the area (see Section 3.1.2) and on
projected emission levels (see Section 2.4), the LNG Terminal will not
be considered a Major Stationary Source with respect to the PSD
regulations and is not subject to PSD review, regardless of whether the
100 TPY or 250 TPY applicability threshold is determined to apply (i.e.,
potential emissions of all attainment pollutants are below 100 TPY)[^6].
However, if AES decides to construct and operate the Power Plant, it
would be subject to PSD review for NO~2~ and CO if the 100 TPY threshold
applies, but would not be subject to PSD review if the 250 TPY threshold
is determined to apply in this case. AES is in the process of contacting
EPA and MDE to further evaluate PSD applicability to the Power Plant and
to request a formal determination. If AES decides to construct and
operate the Power Plant, it will apply for the appropriate permits, as
necessary, based on the outcome of that discussion.

If PSD review is triggered, all stationary sources at the premise must
demonstrate compliance with PSD requirements for each pollutant with
potential premises emissions above Significant Emission Rates. AES
understands that, if it decides to construct and operate the Power
Plant, it will not be considered separate from the LNG Terminal with
respect to NSR requirements. Even if AES applies for and receives
permits for the LNG Terminal stationary sources and subsequently submits
applications for the Power Plant, the combined emissions from the LNG
Terminal and Power Plant will be used for the purpose of PSD and NNSR
applicability determinations. If PSD review applies, all requirements
will apply to LNG Terminal and Power Plant sources.

PSD review for Major Stationary Sources and Major Modifications includes
the following: an assessment of the existing air quality; the use of
analytic dispersion models to demonstrate compliance with the NAAQS and
applicable PSD Increments; a demonstration that BACT has been applied to
the subject emission sources; and an assessment of the impact of new
emissions on the environmental resources such as soils and vegetation.
If the source is located within 100 kilometers (km) (62 miles) of a
federal Class I area, the impacts must be evaluated at these areas based
on the more stringent Class I PSD increments. The PSD permit would
contain emission limits and other operating, monitoring, record keeping,
and reporting requirements.

The air quality modeling includes emissions from the proposed Major
Stationary Source or Major Modification and other sources in the area to
ensure protection of the NAAQS and to prevent emission increases beyond
a specified amount, called a PSD Increment. Because the LNG Terminal and
associated LNG ship unloading operations, without the Power Plant, will
not be a Major Stationary Source subject to PSD review, an air quality
modeling demonstration is not required by MDE or EPA PSD regulations
specifically for that LNG Terminal configuration. However, if it is
determined that the 100 TPY PSD applicability threshold applies to the
Power Plant, the Power Plant will trigger PSD review for the Power Plant
and the LNG Terminal sources, including the air quality modeling
demonstrations. In that case, the results of the air quality dispersion
modeling analysis demonstrating compliance with the NAAQS and PSD
Increments will be included in the PSD permit application submitted to
the Maryland Public Service Commission (MPSC) for review by that agency
with input from MDE (see Section 3.2.3). If AES proceeds with the Power
Plant option, the PSD permit application for the Power Plant will be
submitted to MPSC.

Separate from the potentially applicable PSD modeling requirements, AES
completed an air quality modeling analysis for both LNG Terminal options
(with and without the Power Plant) to satisfy the FERC Staff's
interpretation of its obligation under National Environmental Policy Act
(NEPA) to evaluate anticipated air quality impacts for the Project (see
Section 5.0). This modeling analysis includes an analysis of impacts
from the LNG Terminal with and without the Power Plant, and includes
impacts from LNG ship offloading operations. Separate model runs were
also performed to evaluate impacts of marine vessels associated with LNG
ship movements in the Project Area.

The emission limits contained in the PSD permit are required to
represent the BACT. BACT is determined on a case-by-case basis, taking
into account energy, environmental, and economic impacts and costs. The
LNG Terminal is not currently subject to PSD review or BACT
requirements. However, if AES elects to construct and operate the Power
Plant, the LNG Terminal sources will be subject to PSD review, including
BACT. Based on a review of previous BACT and LAER determinations for
other boiler and hot water heater equipment, the proposed controls and
emission limits for the LNG Terminal are considered representative of
BACT (see Section 4.0).

The PSD program was designed to protect air quality in areas where
existing air quality was considerably better than the NAAQS. The program
established a set of increments of new air pollution that would be
allowed over a baseline level for three classes of areas. Class I areas
are areas of special national or regional value from a natural, scenic,
recreational, or historic perspective and include such areas as National
Parks, Fish and Wildlife Service Areas and National Wilderness Areas. In
addition to restrictive Class I PSD increments for SO~2~, PM and NO~2~,
select Class I areas were additionally protected through adoption of
visibility protection requirements. For a project meeting the PSD
regulatory definition of a Major Stationary Source or Major Modification
and with emission source(s) typically located within 100 km (62 miles)
of a Class I area, an impact analysis must be performed to demonstrate
that stringent Class I PSD increments will not be exceeded and that
other air quality related values (AQRVs) are not adversely impacted. The
LNG Terminal is not currently subject to PSD review. However, the
nearest PSD Class I areas to the LNG Terminal site were identified as
the Shenandoah National Park in Virginia (about 145 km southwest of the
LNG Terminal and Power Plant) and Brigantine National Wilderness Area in
southeastern New Jersey (about 193 km east of the site). The LNG
Terminal would be located more than 100 km (62 miles) from the nearest
Class I area and, as such, a Class I area impact analysis would not be
automatically triggered in this case. However, as part of the PSD review
process (if the Power Plant will be subject to PSD review), the MDE will
likely provide information on the LNG Terminal's estimated emissions and
impacts to the Federal Land Manager responsible for overseeing the
nearest Class I areas.

### Non-attainment New Source Review Requirements

The CAA established more stringent provisions for NSR of Major
Stationary Sources proposed to be located in non-attainment areas. MDE
regulations implementing those provisions are codified in COMAR
26.11.17. Because the LNG Terminal and Power Plant will be located in
Baltimore and the Baltimore AQCR has been designated as nonattainment
with respect to certain criteria air pollutants, the LNG Terminal is
potentially subject to certain NNSR requirements if potential emissions
of NO~X~ or VOC will be greater than 25 TPY. In addition, the MDE may
establish requirements under NNSR for emissions of PM-2.5, for which the
Baltimore AQCR also has been classified as non-attainment.

Based on the attainment status of the area (see 3.1.2) and on projected
emission levels (see Section 2.4), the LNG Terminal will be subject to
NNSR for NO~X~. Applicable NNSR permitting requirements would include an
emission limitation that represents LAER for the source, obtaining NO~X~
equivalent emission reductions (offsets) from existing sources in the
area in the ratio of 1.3 to 1 for sources located in Baltimore (although
the one-hour standard has been rescinded at the federal level, the area
continues to be subject to the severe nonattainment rules in Maryland's
approved SIP, COMAR 26.11.17.03.B(3)(a)), and an alternatives analysis
to demonstrate that the benefits of the proposed source significantly
outweigh the environmental and social impacts. The control technology
analysis demonstrating compliance with LAER is provided in Section 4.0.
A detailed alternatives analysis fulfilling the NNSR requirements is
provided in Resource Report 10 to the FERC application for a Certificate
of Public Necessity and Convenience. A formal filing of Resource Report
10 has been submitted to FERC on January 8, 2007 of which a copy was
provided to the MDE.

### State Permit to Construct Requirements

Pursuant to COMAR 26.11.02.09, all air pollution sources subject to PSD,
NNSR, NSPS, and National Emissions Standards for Hazardous Air
Pollutants (NESHAPS) requirements and all other sources, except those
specifically exempted in COMAR 26.11.02.10, are required to apply for
and obtain a permit to construct. Maryland is authorized by EPA through
its approved SIP to implement both the PSD and NNSR programs. Therefore,
in addition to the permit to construct, sources subject to PSD and/or
NNSR are required to obtain additional PSD and NNSR permits, called
Approvals. The purpose of the permit to construct is to ensure that any
new, modified, replaced or relocated source of air pollution complies
with all applicable State and federal air quality regulatory
requirements. The NNSR and PSD Approvals are required to enforce
applicable PSD and NNSR requirements. Therefore, the four hot water
heaters, six emergency fire water pumps and emergency generator at the
LNG Terminal will require permits to construct.

As discussed in Sections 2.3.2 and 2.3.5, the 375 HP diesel engine fire
pump and the natural gas fired vent stack heater are exempt from the
necessity to apply for permits to construct. The 375 HP diesel engine
fire pump will have a rated output less than 500 brake horsepower (373
kilowatts) and will not be used to generate electricity for sale or for
peak or load shaving. Based on operation of the vent stack heater at
maximum rated capacity for 8,760 hours per year, potential emissions of
each pollutant would be less than 1 TPY. Therefore, each of these minor
sources meet the permit exemption criteria in COMAR 26.11.02.10.

If AES elects to construct and operate the Power Plant, which will be
rated at greater than 70 MW, it will be subject to review by the MPSC.
In that case, AES will be required to apply for a Certificate of Public
Convenience and Necessity from the MPSC, which includes a review of the
Power Plant's potential air impacts instead of pursuing its air permit
approvals via the MDE. The MPSC has been authorized and SIP-approved to
issue PSD and NNSR Approvals, with MDE input, for all power plants in
Maryland with a generating capacity greater than 70 MW.

## MDE Title V and State Operating Permit Requirements

Under MDE's Title V Facility Permit regulations (COMAR 26.11.03), a
Title V permit is required for Major Stationary Sources (as defined
under COMAR 26.11.02.01). For Title V applicability purposes, a Major
Stationary Source is defined differently than a Major Stationary Source
under PSD review, with potential emissions thresholds established at 10
TPY for any individual HAP, 25 TPY for any combination of HAPs, 25 TPY
for NO~X~ or VOC in Baltimore and 100 TPY for any other regulated air
pollutant. Based on the estimated potential emissions from the LNG
Terminal as presented in Section 2.4, the LNG Terminal will be a Major
Stationary Source subject to Title V permitting. The owner or operator
of a source that becomes subject to the requirement to obtain a Part 70
permit must submit an application not later than 12 months after the
date that the source commences operations or becomes subject to the
requirements for a Part 70 permit, whichever is later (COMAR
26.11.03.02.B(4)). The purpose of the Title V operating permit is to
combine, into a single document, all the State and federal air quality
requirements applicable to all sources located on the same premise.
Title V does not impose new substantive requirements above and beyond
the State requirements.

## New Source Performance Standards Requirements

As natural gas-fired hot water heaters with heat inputs greater than 100
MMBtu/hr, the four proposed heaters at the LNG Terminal are subject to
Standards of Performance for Industrial-Commercial-Institutional Steam
Generating Units (NSPS, 40 CFR Part 60, Subpart Db). Although Subpart Db
contains emissions standards and/or control requirements for SO~2~ and
PM from boilers combusting coal, oil, wood and other fuels, it contains
no SO~2~ or PM standards applicable to natural gas fired boilers. The
most stringent Subpart Db NO~X~ emission standard applicable to gas
fired boilers with a low heat release rate is 0.1 pounds per million
British thermal unit (lb/MMBtu). The hot water heaters associated with
the LNG Terminal will be designed and operated in accordance with the
applicable Subpart Db NO~X~ emission standard. The proposed NO~X~
emission rate (less than 0.004 lb/MMBtu) would easily meet the
applicable emission standard. AES will also comply with the applicable
monitoring, record keeping and reporting requirements consistent with
Subpart Db.

If AES elects to construct and operate the Power Plant, the proposed
combustion turbine generator (CTG) would have a heat input greater than
10 MMBtu/hr and would be constructed after February 18, 2005. Therefore,
the CTG and associated heat recovery steam generator (HRSG) would be
subject to Standards of Performance for Stationary Combustion Turbines
(Subpart KKKK), which were promulgated July 6, 2006 and are applicable
to CTGs with a heat load input greater than or equal to 10 MMBtu/hr and
were constructed, modified or reconstructed after February 18, 2005.
Stationary CTGs subject to Subpart KKKK are exempt from requirements of
Subpart GG, which is applicable to combustion turbines constructed,
modified, or reconstructed after October 3, 1977. In addition, HRSGs
subject to Subpart KKKK are exempt from the requirements in Subparts Da,
Db and Dc. Subpart KKKK sets emission limits for NO~X~ and SO~2~. For
new CTGs firing natural gas at a heat input rate of greater than 850
MMBtu/hr, such as the CTG preliminarily designed for the Power Plant,
the applicable NO~X~ emission limit would be 15 ppmvd at 15 percent
O~2~. The proposed NO~X~ emission limit, which will also be proposed to
meet BACT and LAER, is two ppmvd at 15 percent O~2~ and, therefore, the
CTG will easily meet the applicable limit in Subpart KKKK. The
continuous emission monitoring system (CEMS) proposed for the Power
Plant would also comply with the Subpart KKKK NO~X~ monitoring
requirements. The Subpart KKKK SO~2~ limit applicable to all CTGs
regardless of size or fuel type is 0.58 lb/MWh gross energy output or
fuel sulfur content of 0.05 percent by weight. The proposed CTG with
HRSG would be fueled exclusively with natural gas, and will meet the
fuel sulfur content specification.

Subpart Kb, Standards of Performance for Volatile Organic Liquid Storage
Vessels (Including Petroleum Liquid Storage Vessels) for Which
Construction, Reconstruction, or Modification Commenced After July 23,
1984, was reviewed for applicability to the LNG storage tanks at the LNG
Terminal. This subpart applies to storage vessels above 75 cubic meters
capacity used to store Volatile Organic Liquids (VOL). VOL is defined as
any organic liquid that can emit VOC as defined in 40 CFR § 51.100. The
principal organic compounds with the potential to be emitted only in
trace amounts from LNG storage tanks are methane and ethane, both of
which are specifically exempted in 40 CFR § 51.100 from the definition
of VOC. Therefore, this subpart is not applicable to the LNG storage
tanks.

Subpart IIII, Standards of Performance for Stationary Compression
Ignition Internal Combustion Engines, promulgated July 11, 2006, will
apply to emergency fire pump engines and the emergency standby generator
proposed for the LNG Terminal. The rule requires manufacturers of such
engines to meet emission standards that are phased in for the size, type
of engine application and model year of the engine. Owners and operators
of covered engines are required to configure, operate and maintain the
engines according to specifications and instructions provided by the
engine manufacturer and to maintain records demonstrating compliance.
AES will comply with the requirements applicable to owners and operators
of covered engines.

## National Emissions Standards for Hazardous Air Pollutants Requirements

The NESHAPs, codified in 40 CFR Part 61, regulate HAP emissions. Part 61
was promulgated prior to the 1990 CAAA and regulates only eight types of
hazardous substances (asbestos, benzene, beryllium, coke oven emissions,
inorganic arsenic, mercury, radionuclides, and vinyl chloride). The
proposed LNG Terminal and Power Plant do not fall under one of the
source categories regulated by Part 61; therefore, the requirements of
Part 61 are not applicable to the LNG Terminal.

## National Emissions Standards for Hazardous Air Pollutants for Source Categories Requirements

Boilers and process heaters that are located at new or existing Major
Stationary Sources of HAPs must meet NESHAPs for Source Categories,
Subpart DDDDD - National Emission Standards for Industrial / Commercial
/ Institutional Boilers and Process Heaters, commonly referred to as
Boiler Maximum Achievable Control Technology (MACT) standards. Subpart
DDDDD emission limitations applicable to "large" (greater than 10
MMBtu/hr) gas fired boilers and process heaters include PM (0.03
lb/MMBtu), hydrogen chloride (0.0009 lb/MMBtu) and CO (400 ppm at three
percent O~2~). The hot water heaters at the LNG Terminal would be
classified as a large boiler or process heater under the regulations and
estimated emissions would easily comply with these limitations based on
vendor data and/or EPA emissions factors as summarized in Table 2-1. The
HRSG at the potential Power Plant would be classified as a waste heat
boiler, which is not subject to the regulation, because the supplemental
burners to the HRSG would not be 50 percent or more of the total heat
input to the HRSG based on preliminary engineering design. Based on
estimated potential emissions of federal HAPs summarized in Table 2-8,
the LNG Terminal would not be classified as a Major Stationary Source of
HAPs (i.e., those that have the potential to emit 10 TPY or more of a
single HAP or 25 TPY or more of a combination of HAPs that are
specifically listed in or pursuant to section 112(b) of the CAA).
Therefore, the proposed LNG Terminal will not be subject to Subpart
DDDDD*.*

Other NESHAPs for Source Categories, or MACT standards, potentially
applicable to LNG Terminal stationary sources include Subpart ZZZZ
(NESHAP for Stationary Reciprocating Internal Combustion Engines) and
Subpart YYYY (NESHAP for Stationary Combustion Turbines, if the Power
Plant is constructed). Both of these NESHAPs are only applicable to
Major Stationary Sources of HAPs. Based on estimated potential HAP
emissions, neither the proposed LNG Terminal nor the Power Plant will be
Major Stationary Sources of HAPs. Therefore, these NESHAPs do not apply
to the LNG Terminal. Moreover, with regard to Subpart YYYY, based on
EPA's August 18, 2004 stay of effectiveness with regard to applicability
of this NESHAP to lean premix gas-fired turbines and diffusion flame
gas-fired turbines, Subpart YYYY would not apply to the CTG proposed for
the Power Plant, as the proposed CTG will be a lean premix dry low-NO~X~
design.

## Acid Rain Program Requirements and Clean Air Interstate Rule (CAIR)

The Acid Rain Program is codified in 40 CFR Parts 72 through 78. This
program aims to reduce acid rain by reduction of SO~2~ and NO~X~ from
utility units that have a nameplate electricity generation capacity
greater than 25 MW. A "unit" is defined as a "fossil fuel-fired
combustion device" and "fossil fuel-fired" is defined as "the combustion
of fossil fuel, alone or in combination with any other fuel, independent
of the percentage of fossil fuel consumed in any calendar year". The hot
water heaters at the LNG Terminal will not be used to generate
electricity; however, the combined cycle Power Plant, if constructed,
would have a generation capacity greater than 25 MW and will be subject
to Acid Rain program requirements. If the Power Plant is constructed,
the Acid Rain permit application must be filed at least 24 months before
the unit commences operation. An affected unit is required to follow the
continuous emissions monitoring requirements of 40 CFR Part 75 and to
hold sufficient SO~2~ allowances to cover expected emissions of SO~2~
when operation commences. In the event that the Power Plant is
constructed, AES would apply for the Acid Rain Permits; install, certify
and operate the required monitoring systems; and comply with the
required emissions allowances, monitoring, and reordkeeping
requirements.

The Clean Air Interstate Rule (CAIR), 40 CFR Parts 96 and 97,
established a new cap and trade program for SO2 and NOX emissions across
28 eastern states and the District of Columbia. The CAIR requires
certain states, including Maryland, to achieve significant, phased
reductions in annual and ozone-season NOx emissions (as a precursor to
fine particulate matter (PM2.5) and ozone formation) and annual SO2
emissions (as a precursor to PM~2.5~ formation), consistent with
state-specific emissions budgets established by EPA. To achieve those
reductions, affected states may choose to participate, to the extent
applicable, in cap and trade programs for annual NOx, ozone-season NOx
and annual SO~2~ emissions. Affected states must submit to EPA proposed
revisions to its State Implementation Plan (SIP) that include the
requisite NOx and SO~2~ emissions reductions and specify the
CAIR-affected sources and control mechanisms that will be required by
the state. Alternatively, affected states may elect to adopt the CAIR
Federal Implementation Plan (FIP), meaning that EPA would administer the
CAIR program for that state. Because the State of Maryland has not yet
submitted its CAIR SIP to EPA for review and approval or indicated its
intention to adopt the CAIR FIP, it is not yet clear how the State will
comply with the rule and whether the emissions reduction requirements
will apply to sources other than coal-fired electric generating units.
However, if AES proceeds with construction of the Power Plant, AES will
comply with any CAIR requirements that may be applicable to the natural
gas-fired units at the plant.

The Clean Air Mercury Rule (CAMR) establishes standards of performance
for new and existing coal-fired electric generating units pursuant to
Section 111(d) of the CAA. CAMR sets annual caps for mercury emissions
from such units and creates a market-based trading program. States were
required to submit SIP revisions to EPA by November 17, 2006, to
implement the obligations under CAMR. Many states, including Maryland,
failed to meet the SIP submittal deadline and it is not yet clear
whether Maryland will develop a state plan to adopt the CAMR or will
become subject to the CAMR FIP, which was published by EPA on December
8, 2006. Under either scenario, the State\'s CAMR program is not
anticipated to apply to new, natural gas-fired electric generating
units, such as the units that would be installed at the Power Plant, if
constructed.

## MDE Emission Standards

In addition to the MDE permit to construct, permit to operate and PSD
and NNSR Approval requirements, the following state emission standards
and other requirements were evaluated for applicability to the LNG
Terminal sources:

-   COMAR 26.11.05: Air Pollution Episode System -- This chapter
    requires sources designated by the Secretary or the Secretary\'s
    designee to submit standby emission reduction plans and to implement
    such plans if a designated level of air pollution is reached.
    Designated sources primarily include coal and oil fired electric
    power generating facilities, coal and oil fired steam producing
    facilities, large manufacturing industries and refuse incinerators.
    Any other source of air pollutants not specifically designated in
    the regulation may be required to submit standby plans, upon written
    request of the MDE, describing emission cutbacks to be taken if an
    air pollution Alert is called. Because the LNG Terminal and Power
    Plant do not involve emission sources specifically designated by
    regulation to prepare and submit standby plans, AES would not be
    subject to this requirement unless specifically requested by MDE.

-   COMAR 26.11.06: General Emission Standards, Prohibitions and
    Restrictions -- This chapter contains emissions standards and other
    requirements applicable to certain air pollution sources. Specific
    requirements pertain to visible emissions, emissions of particulate
    matter, CO, SO~2~, VOC and fluorides, and to odors and other
    nuisance air pollution. The proposed hot water heaters, diesel
    engines and vent stack heater at the LNG Terminal and the CTG with
    HRSG at the Power Plant will be designed to meet all applicable
    standards and operate in compliance with applicable limitations.

-   COMAR 26.11.06.03.D: Particulate Matter from Materials Handling and
    Construction. This regulation requires reasonable precautions to
    prevent particulate matter from becoming airborne due to material
    handling, transport, or storage, or due to construction or
    demolition activities, use of roads and other activities. Reasonable
    precautions specified in the regulation include, but are not be
    limited to:

    -   Use of water or chemicals for control of dust in the demolition
        of existing buildings or structures, construction operations,
        the grading of roads, or the clearing of land.

    -   Application of asphalt, oil, water, or suitable chemicals on
        dirt roads, materials stockpiles, and other surfaces that can
        create airborne dusts.

    -   Installation and use of hoods, fans, and dust collectors to
        enclose and vent the handling of dusty materials. Adequate
        containment methods shall be employed during sandblasting of
        buildings or other similar operations.

    -   Covering, at all times when in motion, open-bodied vehicles
        transporting materials likely to create air pollution. Alternate
        means may be employed to achieve the same results as would
        covering the vehicles.

    -   The paving of roadways and their maintenance in clean condition.

    -   The prompt removal from paved streets of earth or other material
        which has been transported there by trucks or earth moving
        equipment or erosion by water.

AES will require its contractors to use the mitigation measures to
minimize the fugitive dust emissions associated with construction of the
Project. These measures may include the application of water or dust
suppressants, covering of haul trucks, use of paved roads to the extent
possible, limiting vehicle speed and stabilizing disturbed areas.

-   COMAR 26.11.09: Control of Fuel-Burning Equipment, Stationary
    Internal Combustion Engines, and Certain Fuel-burning Installations
    -- This chapter contains emissions standards and other requirements
    applicable to certain fuel-burning equipment, including boilers,
    vent heater, and diesel engines at the LNG Terminal, and the CTG
    with HRSG at the potential Power Plant. Specific requirements
    pertain to visible emissions, emissions of particulate matter, SO~2~
    and Major Stationary Sources of NO~X~. The proposed combustion
    equipment at the LNG Terminal and Power Plant will be designed to
    meet all applicable standards and operate in compliance with
    applicable limitations.

-   COMAR 26.11.15 and 26.11.16: Toxic Air Pollutants -- Fuel burning
    equipment as defined in COMAR 26.11.09.01, such as boilers and
    stationary internal combustion engines associated with the LNG
    Terminal and the CTG with HRSG associated with the Power Plant, are
    exempt from the requirements of this chapter.

-   COMAR 26.11.17: Requirements for Major New Sources and Modifications
    -- This chapter applies to Major Stationary Sources and Major
    Modifications with respect to non-attainment pollutants NO~X~, VOC
    and CO. Based on estimated potential emissions from the LNG Terminal
    emission units, the requirements of this chapter apply to NO~X~, as
    the LNG Terminal will be a Major Stationary Source of NO~X~
    emissions when LNG ship offloading emissions are included. The LNG
    Terminal, even with offloading emissions, will not be a Major
    Stationary Source of VOC emissions and, therefore, will not be
    subject to the requirements of this chapter for VOC. In addition,
    the LNG Terminal will not be located in a non-attainment area for
    CO. However, based on estimated potential emissions, the LNG
    Terminal with the Power Plant, and including LNG offloading
    emissions, will be a Major Stationary Source of NO~X~ and VOC and,
    therefore, will be subject to the NNSR requirements in this chapter.
    The applicable requirements for sources subject to NNSR are
    summarized in section 9.2.3.1.2.

-   COMAR 26.11.29 and 26.11.30: NO~X~ Reduction and Trading Program --
    These chapters apply to affected trading sources, which are defined
    as fossil fuel fired electric generating units that serve a
    generator with a name plate capacity greater than 25 MW or
    non-electric generating units that have a maximum design heat input
    greater than 250 MMBtu/hr. The proposed hot water heaters at the LNG
    Terminal are fossil fuel fired stationary boilers with a maximum
    design heat input of 345 MMBtu/hr and are, therefore, classified as
    non-electric generating units subject to the requirements. The CTG
    with HRSG at the proposed Power Plant would be a fossil fuel fired
    electric generating unit that would serve a generator with a name
    plate capacity of approximately 300 MW and will sell electricity.
    Therefore, the combined cycle Power Plant would also be subject to
    Maryland's NO~X~ Reduction and Trading Program. In general, COMAR
    26.11.29 requires an affected trading source to acquire sufficient
    NO~X~ allowances for the control period each year at least equal to
    the affected trading source's NO~X~ emissions for the control
    period. Allowances from a "set-aside pool" are made available by the
    MDE to accommodate new affected trading sources or "clean air
    projects", defined as a new or modified fossil fuel electric
    generator with state-of-the-art NO~X~ controls demonstrated to be
    more efficient than existing electric generation. An affected
    trading source must also install, operate, maintain, and certify a
    NOx CEM or other approved monitoring method in accordance with 40
    CFR Part 75, Subpart H and comply with the monitoring requirements
    in 40 CFR Part 96, Subpart H. COMAR 26.11.30 is referenced
    throughout Chapter 26.11.29 and establishes procedural requirements
    to implement Maryland's NO~X~ Reduction and Trading Program. The
    proposed hot water heaters at the LNG Terminal and combined cycle
    Power Plant will be designed to meet all applicable standards and
    operate in compliance with applicable monitoring and NO~X~ emissions
    trading requirements.

## EPA Chemical Accident Prevention Provisions and OSHA Process Safety Management

40 CFR Part 68, Chemical Accident Prevention Provisions, are Federal
regulations designed to prevent the release of hazardous materials in
the event of an accident and minimize impacts when releases do occur.
The regulation contains a list of substances and threshold quantities
for determining applicability of the rule to a facility. If a facility
stores, handles or processes one or more substances on this list and at
a quantity equal or greater than specified in the regulation, the
facility must prepare and submit a risk management plan (RMP). If a
facility does not have a listed substance on-site, or the quantity of a
listed substance is below the applicability threshold, the facility is
not required to prepare an RMP. However, it still must comply with
requirements of the general duty provisions in Section 112(r)(1) of the
1990 CAAA if it has any regulated substance of other extremely hazardous
substance on-site. The general duty of the provision is as follows:

"The owners and operators of stationary sources producing, processing,
handling and storing such substances have a general duty to identify
hazards which may result from such releases using appropriate hazard
assessment techniques, to design and maintain a safe facility taking
such steps as are necessary to prevent releases, and to minimize the
consequences of accidental releases which do occur."

With the exception of natural gas constituents (*e.g.*, methane, ethane,
propane, etc.), no regulated substance would be handled or stored in
quantities greater than the applicability threshold. Natural gas
pipelines are not covered if they are regulated by the USDOT or an
equivalent state natural gas program certified by USDOT in accordance
with 49 U.S.C § 60105. In addition, storage of natural gas incidental to
transportation (*e.g.*, gas taken from a pipeline during non-peak
periods and placed in storage, then returned to the pipeline when
needed) is not covered. Consequently, an RMP is not required for any
portion of the Project. AES would be required to maintain awareness of
hazard issues and meet the goals of the above-listed general duty
provisions.

The applicability of the Occupational Safety and Health Administration
(OSHA) standard 29 CFR 1910.119, Process Safety Management of Highly
Hazardous Chemicals (PSM), to the Project was also evaluated. Based on
standard interpretations published by OSHA in response to questions on
PSM applicability to LNG facilities, OSHA has concluded that current
USDOT regulations in 49 CFR Parts 192 and 193 and enforced by the
Pipeline and Hazardous Materials Safety Administration cover LNG and gas
transmission and distribution processes, and that OSHA is precluded from
enforcing the PSM standard with respect to working conditions associated
with fire and explosion hazards of these processes. Therefore, the
Pipeline and LNG Terminal, which are subject to 49 CFR Parts 192 and
193, respectively, are not subject to the PSM regulations.

# Control Technology Analysis

## LAER and BACT Analysis for NO~X~ Emissions from Hot Water Heaters

The LNG Terminal will be subject to LAER for NO~X~ because estimated
potential emissions of NO~X~ will be greater than the 25 TPY Major
Stationary Source threshold applicable to an O~3~ precursor in a serious
O~3~ nonattainment area. LAER, as defined in 40 CFR 51.165(a)(1)(xiii)
is the most stringent emissions limitation that is contained in the
implementation plan of any State for such class or category of
stationary source, unless the owner or operator of the proposed
stationary source demonstrates that such limitations are not achievable;
or the most stringent emissions limitation that is achieved in practice
by such class or category of stationary sources. This section
demonstrates that the proposed NO~X~ emissions and controls meet the
requirements of LAER. In addition, because LAER requirements are at
least as stringent as BACT and BACT would potentially apply to NO~X~
emissions from the LNG Terminal, if AES elects to construct and operate
the Power Plant, the LAER analysis also satisfies the BACT demonstration
for NO~X.~

### Estimated Emissions and Minimum Regulatory Requirements

AES is proposing a NO~X~ emission rate of 0.004 lb/MMBtu, to be achieved
with low-NO~X~ burners and/or flue gas recirculation for preliminary
NO~X~ control and selective non-catalytic reduction (SCR) technology for
final NO~X~ control. The remainder of this section will demonstrate that
the proposed emission rate and controls meet both LAER and BACT
requirements.

Table 4-1 summarizes the minimum EPA and MDE regulatory limits
applicable to NO~X~ emissions from gas-fired boiler projects:

**Table 4‑1 -- Regulatory Limits Applicable to NO~X~ Emissions**

  ---------------------------------------------------------------------------------
  **Pollutant/Parameter**   **Regulatory Limit**             **Citation**
  ------------------------- -------------------------------- ----------------------
  NO~X~                     0.20 lb/MMBtu                    NSPS -- 40 CFR
                                                             60.44b(a)(1)

  NO~X~                     0.20 lb/MMBtu                    COMAR §
                                                             26.11.09.08(B)(1)(c)
  ---------------------------------------------------------------------------------

There are no other specific EPA or MDE emissions standards applicable to
NO~X~ emissions from combustion sources.

### Identification of NO~X~ Control Technologies

Based on a review of currently permitted boilers identified in the EPA's
RACT/BACT/LAER Clearinghouse (RBLC), California Air Resources Board
Statewide BACT Clearinghouse, and a literature review of NO~X~ controls
for gas-fired boilers and heaters, the following NO~X~ control
technologies were identified as potentially applicable to the hot water
(HW) heaters:

-   Low Excess Air (LEA)

-   Overfire Air (OA)

-   Flue Gas Recirculation (FGR)

-   Low-NO~X~ Burners (LNB)

-   Selective Catalytic Reduction (SCR)

-   Selective Non-Catalytic Reduction (SNCR)

The following subsections provide brief overviews of these technologies.

#### Low Excess Air

When fuel is combusted, the fuel molecules combine with oxygen molecules
and release energy in the form of heat. In order to ensure that all of
the fuel is combusted, more oxygen is supplied to the combustion chamber
than necessary; this is known as excess air. With LEA systems, less
excess air is supplied to the burners than normal. This reduces the
temperature of the flame, and thus lowers the amount of thermal NO~X~
created. Additionally, more of the fuel-bound NO~X~ becomes nitrogen
gas, further reducing NO~X~ levels. LEA requires continuous monitoring
of oxygen levels in the fuel gas to ensure that oxygen levels are within
a narrow range.

#### Overfire Air

In this method of NO~X~ control, the initial combustion is performed
with less than the required amount of oxygen at the burners, then the
remaining required air is added shortly downstream. This staged
combustion process reduces thermal NO~X~ by lowering the flame
temperature, and keeps the oxygen levels low and reduces mixing to
minimize fuel NO~X~. However, this tends to result in more incomplete
combustion, resulting in higher CO and hydrocarbon emissions.

#### Flue Gas Recirculation

In flue gas recirculation, a portion of the cooled flue gas is combined
with the fresh air entering the combustion zone. Since most of the
oxygen in the flue gas has been used in the original combustion,
recirculating a portion of the flue gas reduces the oxygen available to
the combustion process. This reduces the temperature and lowers thermal
NO~X~. Typically, 5 percent to 20 percent of the gas is recirculated.

#### Low-NOX Burners

Low-NO~X~ burners work under the same principle as overfire air, except
that the staging is performed at the burner rather than later in the
combustion chamber. This staging can be achieved as either staged air or
staged fuel. Each of these technologies requires two combustion zones.

#### Selective Catalytic Reduction (SCR)

SCR is a flue‑gas treatment technology for reducing NO~X~ that involves
injection of ammonia (NH~3~), a reducing agent, into the flue gas
downstream of the boilers and then passing the gas through a catalyst
bed. It is one of the most effective ways to control NO~X~ with a
control efficiency up to about 90 percent. In the SCR process, ammonia
injected into the exhaust gas reacts with nitrogen oxides and oxygen to
form nitrogen and water by the following reactions:

> 4NO + 4NH~3~ +O2 → 4N~2~ + 6H~2~O (1)
>
> 6NO + 4NH~3~ → 5N~2~ + 6H~2~O (2)
>
> 2NO~2~ + 4NH~3~ + O~2~ → 3N~2~ + 6H~2~O (3)
>
> 6NO~2~ + 8NH~3~ → 7N~2~ + 12H~2~O (4)
>
> NO + NO~2~ + 2NH~3~ → 2N~2~ + 3H~2~O (5)

The reactions take place on the surface of a catalyst. The function of
the catalyst is to effectively lower the activation energy of the NO~X~
decomposition reaction and accelerate the reduction of NO~X~ by ammonia
to nitrogen gas and water. Several different catalyst compositions
having different properties are available. The catalyst also has a low
activity level for other potentially competing reactions such as ammonia
or sulfur dioxide oxidation. The reaction of NO~X~ and ammonia is
temperature dependent, and each catalyst has its own operating range, or
\"temperature window\".

The upper temperature boundary is a function of the physical properties
of the catalyst used and different catalysts cover the range from 500˚F
to over 1000˚F. In addition, at temperatures greater than 900˚F, the
ammonia is reported to thermally decompose to form NO~X~. This
decomposition does not appear to be a significant problem up to at least
960˚F.

Control of ammonia injection is an important parameter for an SCR
system. Ammonia is injected in proportion to the amount of NO~X~ in the
gas stream. A molar ratio of 1.0 to 1.3 is typically used, depending
upon the degree of control and final effluent NO~X~ concentration
required. NO~X~ is measured either upstream of the system (feed-forward
controls) or downstream of the system (feedback controls), depending
upon the supplier\'s system, and multiplied by a gas flow signal to
adjust the ammonia injection rate. Some systems are equipped with an
ammonia analyzer downstream of the SCR system so that escape of ammonia
(\"ammonia slip\") can be monitored. These analyzers are usually part of
a feedback control system that will reduce the ammonia injection rate in
the event of unacceptable slip.

Sulfur content of the fuel can be a concern for systems that employ SCR.
If burning pipeline quality natural gas, the low sulfur content (less
than 2 grains per 100 SCF) should allow for a reasonable catalyst life.
However, higher sulfur contents can cause the catalyst systems to
promote partial oxidation of sulfur dioxide (from trace sulfur in gas)
to sulfur trioxide (SO~3~), which combines with water to form sulfuric
acid. At lower temperatures, SO~3~ and sulfuric acid may react with
excess ammonia to form ammonium salts. These ammonium salts may be
emitted from the stack as increased emissions of PM~10~ and PM~2.5~.
Sulfates and nitrates emitted from the stack are also precursors to
atmospheric formation of PM~10~ and PM~2.5~. Under some circumstances,
fouling may eventually lead to increased system pressure drop over time
and decreased heat transfer efficiencies. Fortunately, ammonium salts
may be removed by water washing, although this process requires an
outage to allow cooling, washing and restart of the system.

The SCR process in general is subject to catalyst deactivation over
time. Catalyst deactivation occurs through two primary mechanisms:
physical deactivation and chemical poisoning. Physical deactivation is
the result either of prolonged exposure to excessive temperatures or
masking of the catalyst due to entrainment of particulate from ambient
air or internal contaminants. Chemical poisoning is caused by the
irreversible reaction of the catalyst with a contaminant in the gas
stream and is a permanent condition. Catalyst suppliers typically only
guarantee a 3-year lifetime for very low emission level, high
performance catalyst systems.

The potential environmental impacts associated with the use of SCR are
summarized below:

-   Some unreacted ammonia would be emitted to the atmosphere as ammonia
    slip; ammonia is a PM~10~ and PM~2.5~ precursor; and

-   There are safety issues associated with the transportation,
    handling, and storage of aqueous ammonia. Aqueous ammonia is
    typically used in lieu of anhydrous ammonia to alleviate these
    concerns.

#### Selective Non-Catalytic Reduction

In the SNCR process, either ammonia or urea is injected into the
post-combustion zone of the furnace to react directly with the NO~X~ in
the flue gas. This process does not include a catalyst, and thus the
temperature of the gas must be higher than that required for SCR.
Required temperatures generally range between 1,600˚F to 2,000˚F with
residence times of one second or more; however, effective reduction has
been achieved in some units with temperatures as low as 800˚F when
additional proprietary flue gas additives are utilized. Below these
temperatures, the reaction rate of ammonia and NO~X~ to nitrogen gas and
water slows to ineffective levels, resulting in both high NO~X~ emission
levels and ammonia emissions.

Molar ammonia injection rates must be carefully controlled so that there
is enough ammonia to effectively reduce NO~X~ levels, but not so much
that significant levels of ammonia are emitted from the stack. In some
cases, an SCR is installed downstream of the SNCR installation to
capture excess ammonia/urea slip and remaining NO~X~. Reduction of NO~X~
by SNCR can approach 70 percent control efficiencies.

### Identification of Most Stringent SIP Limitation in Any State

The first step in a LAER analysis requires identification of the most
stringent emissions limitation that is contained in the SIP of any State
for such class or category of stationary source. States that contain the
most severe O~3~ nonattainment areas typically contain the most
stringent NO~X~ limits in their SIPs. Therefore, the NO~X~ control rules
potentially applicable to steam generating units and power plants fired
with natural gas were reviewed and summarized for the following states
and/or Air Quality Control Management Districts (AQMD) comprising the
major O~3~ nonattainment areas in the US:

**Table 4‑2 -- NO~X~ SIP Limitations In Other Nonattainment States**

  -----------------------------------------------------------------------
  **State or AQMD** **Regulatory Limit**           **Citation**
  ----------------- ------------------------------ ----------------------
  Bay Area AQMD, CA 30 ppmvd @ 3% O~2~ for gaseous BAAQMD Regulation 9,
                    fuel-fired electric power      Rule 11, 9-11-305
                    steam generating boiler \<     
                    1,500 MMBtu/hr (equivalent to  
                    0.04 lb/MMBtu)                 

  San Joaquin       9 ppmvd @ 3% O~2~ (0.011       SJVUAQMD Rule 4306,
  Valley Unified    lb/MMBtu) for standard option; Boilers, Steam
  AQMD              6 ppmvd @ 3% O~2~ (0.007       Generators and Process
                    lb/MMBtu) for enhanced option  Heaters -- Phase 3

  Texas Commission  0.030 lb/MMBtu                 Chapter 117 -- Control
  on Environmental                                 of Air Pollution from
  Quality                                          Nitrogen Compounds
                                                   §117.106

  New Jersey        0.20 lb/MMBtu for gas-fired    New Jersey
  Department of     boilers serving electric       Administrative Code,
  Environmental     generating units               Title 7:27-19.4
  Protection                                       

  Massachusetts     0.20 lb/MMBtu, for large       310 CMR 7.19 --
  Department of     boilers (100+ MMBtu/hr)        Reasonably Available
  Environmental     burning only gas               Control Technology for
  Protection                                       Sources of Nitrogen
                                                   Oxides

  New York State    0.20 lb/MMBtu for large or     6NYCRR, Chapter III,
  Department of     very large boilers burning gas Part 227: Stationary
  Environmental     only                           Combustion
  Conservation                                     Installations, Subpart
                                                   227-2 - Reasonably
                                                   Available Control
                                                   Technology (RACT) for
                                                   Oxides of Nitrogen
                                                   (NO~x~)

  Connecticut       0.20 lb/MMBtu for a gas-fired  RCSA 22a-174-22
  Department of     boiler rated at 5 MMBtu/hr or  Control of Nitrogen
  Environmental     more at a Major Stationary     Oxides Emissions
  Protection        Source of NO~X~                

  Pennsylvania      0.10 lb/MMBtu for a gas-fired  Title 25 of the PA
  Department of     boiler rated between 100 and   Code, Subpart C,
  Environmental     250 MMBtu/hr; 0.17 lb/MMBtu    Article III Air
  Protection        for a boiler rated at or above Resources § 129.201.
                    250 MMBtu/hr                   Additional NO~X~
                                                   Requirements for
                                                   Boilers

  Delaware          0.20 lb/MMBtu for gas-fired    Regulation 12 --
  Department of     fuel-burning equipment rated   Control of Nitrogen
  Natural Resources at 100 MMBtu/hr or more        Oxides Emissions
  and Environmental located at a Major Stationary  
  Control           Source of NO~X~                

  Illinois          0.20 lb/MMBtu for new          Title 35, Illinois
  Environmental     gas-fired fuel-burning sources Administrative Code,
  Protection Agency rated at 250 MMBtu/hr or more  Subtitle B, Chapter I,
                                                   Subchapter C, Part 217
                                                   -- Nitrogen Oxides
                                                   Emissions
  -----------------------------------------------------------------------

The most stringent NO~X~ emission limitation applicable to gas-fired
boilers identified from this review of SIPs comprising the most severe
O~3~ nonattainment areas was 0.007 lb/MMBtu (6 ppmvd @ 3 percent O~2~).
The AES proposed NO~X~ emission limit for the HW heaters is 0.004
lb/MMBtu (3 ppmvd @ 3 percent O~2~), which is more stringent than the
most stringent SIP limitation found.

### Most Stringent Emission Limitation Achieved In Practice

The next step in a LAER analysis requires the identification of the most
stringent emission limitation achieved in practice for the same class or
category of stationary source proposed. The same procedure used for
identifying the "top" case for pollutants subject to BACT was used to
identify the most stringent NO~X~ limit achieved in practice for a large
gas-fired boiler. Specifically, the following sources were used to
identify the most stringent emission limitation:

-   Review of EPA\'s RACT/BACT/LAER Clearinghouse; and

-   Review of the California Air Resources Board Statewide BACT
    Clearinghouse.

Information compiled from the data gathering efforts pertaining to NO~X~
controls and permit limits for large gas-fired boilers are summarized in
Table 4-3. The most stringent NO~X~ emission rate identified is 0.004
lb/MMBtu. This emission rate is associated with a permit issued in 2002
for four 350 MMBtu/hr boilers located at Sunoco, Inc.'s Eagle Point
Refinery in New Jersey. The emission rate was achieved with the
combination of low-NO~X~ burners, flue gas recirculation and SCR, which
is the same control strategy proposed here for the AES HW heaters.

**Table 4‑3 -- Summary of NO~X~** Control Technology Determinations and
Permit Limits for Large Gas-fired Boilers

<table>
<colgroup>
<col style="width: 12%" />
<col style="width: 10%" />
<col style="width: 5%" />
<col style="width: 7%" />
<col style="width: 7%" />
<col style="width: 11%" />
<col style="width: 9%" />
<col style="width: 9%" />
<col style="width: 8%" />
<col style="width: 8%" />
<col style="width: 8%" />
</colgroup>
<thead>
<tr class="header">
<th rowspan="2"><strong>Project Name</strong></th>
<th colspan="2"><strong>Location</strong></th>
<th colspan="2"><strong>Size</strong></th>
<th rowspan="2"><strong>Fuel description</strong></th>
<th rowspan="2"><strong>Date initially permitted / In-service
date</strong></th>
<th colspan="3"><strong>Nitrogen Oxides</strong></th>
<th><strong>Ammonia Slip</strong></th>
</tr>
<tr class="odd">
<th><strong>City</strong></th>
<th><strong>State</strong></th>
<th><strong>MW total</strong></th>
<th><strong>MMBtu /hr each unit</strong></th>
<th><strong>Limit (lb/ MMBtu)</strong></th>
<th><strong>Avg. Period</strong></th>
<th><strong>Controls</strong></th>
<th><strong>Limit (lb/ MMBtu)</strong></th>
</tr>
</thead>
<tbody>
<tr class="odd">
<td>Arizona Clean Fuels Yuma</td>
<td>Tacna</td>
<td>AZ</td>
<td>101</td>
<td>346.0</td>
<td>Natural Gas or Refinery Fuel Gas</td>
<td>4/14/2005</td>
<td>0.0125</td>
<td>3-hour rolling average</td>
<td>LNB, SCR</td>
<td>0.0019</td>
</tr>
<tr class="even">
<td>Arizona Clean Fuels Yuma</td>
<td>Tacna</td>
<td>AZ</td>
<td>91</td>
<td>311.0</td>
<td>Refinery Fuel Gas or Natural Gas</td>
<td>4/14/2005</td>
<td>0.0125</td>
<td>3-hour average</td>
<td>LNB, SCR</td>
<td>0.0019</td>
</tr>
<tr class="odd">
<td>Arizona Clean Fuels Yuma</td>
<td>Tacna</td>
<td>AZ</td>
<td>96</td>
<td>328.0</td>
<td>Refinery Fuel Gas or Natural Gas</td>
<td>4/14/2005</td>
<td>0.0125</td>
<td>3-hour average</td>
<td>LNB, SCR</td>
<td>0.0019</td>
</tr>
<tr class="even">
<td>Arizona Clean Fuels Yuma</td>
<td>Tacna</td>
<td>AZ</td>
<td>245</td>
<td>419.0</td>
<td>Natural Gas</td>
<td>4/14/2005</td>
<td>0.0125</td>
<td>3-hour average</td>
<td>FGR, LNB</td>
<td>N/A</td>
</tr>
<tr class="odd">
<td>Genentech, Inc.</td>
<td>South San Francisco</td>
<td>CA</td>
<td>28</td>
<td>97</td>
<td>Natural Gas</td>
<td>permit date not listed, startup date 6-14-2006</td>
<td>0.0109</td>
<td>Three 30-min sampling periods</td>
<td>ULNB</td>
<td>N/A</td>
</tr>
<tr class="even">
<td>Amerada Hess - Sea Robin Gas Processing Plant</td>
<td>Venice</td>
<td>LA</td>
<td>106</td>
<td>363.0</td>
<td>Natural Gas</td>
<td>9/8/2005</td>
<td>0.04</td>
<td>Annual average</td>
<td>FGR, LNB</td>
<td>N/A</td>
</tr>
<tr class="odd">
<td>BP Cherry Point Refinery</td>
<td>Blaine</td>
<td>WA</td>
<td>106</td>
<td>363.0</td>
<td>Natural Gas</td>
<td>4/20/2005</td>
<td>0.028</td>
<td>calculated</td>
<td>FGR, ULNB</td>
<td>N/A</td>
</tr>
<tr class="even">
<td>AES Huntington Beach</td>
<td>Huntington Beach</td>
<td>CA</td>
<td><p>225</p>
<p>(output)</p></td>
<td>2088</td>
<td>Natural Gas</td>
<td>7/27/2004</td>
<td>0.0061</td>
<td>1-hour</td>
<td>LNB, FGR, SCR</td>
<td>0.0022</td>
</tr>
<tr class="odd">
<td>Sunoco Inc.</td>
<td>Franklin Furnace</td>
<td>OH</td>
<td>82</td>
<td>281.0</td>
<td>Natural Gas</td>
<td>7/27/2004</td>
<td>0.08</td>
<td></td>
<td>LNB, FGR</td>
<td>N/A</td>
</tr>
<tr class="even">
<td>Cargill - Blair Plant</td>
<td>Blair</td>
<td>NE</td>
<td>81</td>
<td>276.7</td>
<td>Natural Gas</td>
<td>6/22/2004</td>
<td>0.05</td>
<td>30-day average</td>
<td>LNB, induced FGR @ 16%</td>
<td>N/A</td>
</tr>
<tr class="odd">
<td>Midamerican Energy Company</td>
<td>Council Bluffs</td>
<td>IA</td>
<td>126</td>
<td>429.4</td>
<td>Natural Gas</td>
<td>6/17/2003</td>
<td>0.14</td>
<td></td>
<td>LNB</td>
<td>N/A</td>
</tr>
<tr class="even">
<td>Sunoco Inc., Eagle Point Refinery</td>
<td>Westville</td>
<td>NJ</td>
<td></td>
<td>350</td>
<td>Refinery Fuel Gas or Jet A Fuel</td>
<td>2002</td>
<td>0.004</td>
<td></td>
<td>LNB, FGR, SCR</td>
<td>??</td>
</tr>
<tr class="odd">
<td>Dow Texas Operations Freeport</td>
<td>Freeport</td>
<td>TX</td>
<td>448</td>
<td>382.0</td>
<td>Natural Gas, and Gas Mix</td>
<td>11/26/2002</td>
<td>0.02</td>
<td></td>
<td>LNB, SCR</td>
<td>0.004</td>
</tr>
<tr class="even">
<td>VA Power - Possum Point</td>
<td>Glen Allen</td>
<td>VA</td>
<td>29</td>
<td>99</td>
<td>Natural Gas</td>
<td>11/18/2002</td>
<td>0.036</td>
<td></td>
<td>LNB, low-NOx fuel</td>
<td>N/A</td>
</tr>
<tr class="odd">
<td>Weyerhaeuser Company</td>
<td>Pine Hill</td>
<td>AL</td>
<td>88</td>
<td>300.0</td>
<td>Natural Gas</td>
<td>11/15/2002</td>
<td>0.05</td>
<td></td>
<td>LNB</td>
<td>N/A</td>
</tr>
<tr class="even">
<td>Huntsman Polymers - Odessa Petrochemical Plant</td>
<td>Odessa</td>
<td>TX</td>
<td>108</td>
<td>370.0</td>
<td>Natural Gas</td>
<td>10/24/2002</td>
<td>0.05</td>
<td></td>
<td>Only gaseous fuels, DLNC, FGR</td>
<td>N/A</td>
</tr>
<tr class="odd">
<td>Huntsman Polymers - Odessa Petrochemical Plant</td>
<td>Odessa</td>
<td>TX</td>
<td>94</td>
<td>320.0</td>
<td>Natural Gas</td>
<td>10/24/2002</td>
<td>0.12</td>
<td>calculated</td>
<td>None</td>
<td>N/A</td>
</tr>
<tr class="even">
<td>Conoco - Lake Charles Refinery</td>
<td>Westlake</td>
<td>LA</td>
<td>78</td>
<td>268.0</td>
<td>Gaseous Fuel/Gaseous Fuel Mixtures</td>
<td>9/20/2002</td>
<td>0.06</td>
<td></td>
<td>LNB, external FGR</td>
<td>N/A</td>
</tr>
<tr class="odd">
<td>Conoco - Lake Charles Refinery</td>
<td>Westlake</td>
<td>LA</td>
<td>122</td>
<td>418.0</td>
<td>Gaseous Fuel/Gaseous Fuel Mixtures</td>
<td>9/20/2002</td>
<td>0.03</td>
<td>calculated</td>
<td>ULNB</td>
<td>N/A</td>
</tr>
<tr class="even">
<td>ExxonMobil - Baton Rouge Refinery</td>
<td>Baton Rouge</td>
<td>LA</td>
<td>105</td>
<td>360.0</td>
<td>Gaseous Fuel/Gaseous Fuel Mixtures</td>
<td>4/26/2002</td>
<td>0.04</td>
<td>calculated</td>
<td>ULNB</td>
<td>N/A</td>
</tr>
<tr class="odd">
<td>Liberty Generating Station</td>
<td>Linden</td>
<td>NJ</td>
<td>225</td>
<td>256.0</td>
<td>Natural Gas</td>
<td>3/28/2002</td>
<td>0.2</td>
<td></td>
<td>SCR</td>
<td></td>
</tr>
<tr class="even">
<td>Liberty Generating Station</td>
<td>Linden</td>
<td>NJ</td>
<td>59</td>
<td>200</td>
<td>Natural Gas</td>
<td>3/28/2002</td>
<td>0.036</td>
<td></td>
<td>SCR</td>
<td></td>
</tr>
<tr class="odd">
<td>Lyondell - Citgo Refining, LP</td>
<td>Houston</td>
<td>TX</td>
<td>66</td>
<td>226.4</td>
<td>Gaseous Fuel/Gaseous Fuel Mixtures</td>
<td>3/14/2002</td>
<td>0.036</td>
<td>calculated</td>
<td>SCR</td>
<td>0.004</td>
</tr>
<tr class="even">
<td>Lyondell - Citgo Refining, LP</td>
<td>Houston</td>
<td>TX</td>
<td>107</td>
<td>366.8</td>
<td>Gaseous Fuel/Gaseous Fuel Mixtures</td>
<td>3/14/2002</td>
<td>0.08</td>
<td>calculated</td>
<td>None</td>
<td>N/A</td>
</tr>
<tr class="odd">
<td>Agritechnology Montana LLC</td>
<td>Great Falls</td>
<td>MT</td>
<td>105</td>
<td>358.0</td>
<td>Natural Gas</td>
<td>11/6/2001</td>
<td>0.08</td>
<td></td>
<td>FGR, LNB</td>
<td>N/A</td>
</tr>
<tr class="even">
<td>FPL Energy Marcus Hook, L.P.</td>
<td>Marcus Hook</td>
<td>PA</td>
<td>1845</td>
<td>1575</td>
<td>Natural Gas</td>
<td>5/4/2001</td>
<td>0.05</td>
<td></td>
<td>GCP</td>
<td>N/A</td>
</tr>
<tr class="odd">
<td>Grays Ferry Cogen Partnership</td>
<td>Philadelphia</td>
<td>PA</td>
<td>328</td>
<td>1119</td>
<td>Natural Gas</td>
<td>3/21/2001</td>
<td>0.1</td>
<td></td>
<td>LNB</td>
<td>N/A</td>
</tr>
<tr class="even">
<td>Kal Kan Foods, Inc.</td>
<td>Los Angeles</td>
<td>CA</td>
<td>23</td>
<td>78.6</td>
<td>Natural Gas</td>
<td>6/28/1995</td>
<td>0.0109</td>
<td>15-min</td>
<td>LNB, SCR</td>
<td>0.009</td>
</tr>
<tr class="odd">
<td>Darling International, Inc.</td>
<td>Los Angeles</td>
<td>CA</td>
<td>32</td>
<td>110</td>
<td>Natural Gas or Propane</td>
<td>12/7/1993</td>
<td>operating: 0.0109 during startup: 0.0486</td>
<td>15-min</td>
<td>LNB, FGR, SCR</td>
<td>0.009</td>
</tr>
</tbody>
</table>

### LAER and BACT Proposal for NO~X~ Emissions

Based on the results of this analysis, a NO~X~ permit limit of 0.004
lb/MMBtu is proposed as LAER for the HW heaters at the LNG Terminal. AES
proposes to achieve this emission rate with the combination of LNB
and/or FGR and SCR. The 0.004 lb/MMBtu emission rate meets EPA's LAER
criteria by being more stringent than the most stringent emission limit
contained in any State SIP and it is equivalent to the most stringent
emission rate achieved in practice for a large gas-fired boiler. If AES
elects to construct and operate the Power Plant, NO~X~ emissions from
the HW heaters may potentially be subject to BACT in addition to LAER
requirements. In that case, becayse LAER is, by definition, more
stringent than BACT, the proposed NO~X~ limit is also demonstrated as
BACT.

## LAER and BACT Analysis for CO and VOC Emissions from Hot Water Heaters

As discussed in Section 2.4, the LNG Terminal as currently proposed will
be a Major Stationary Source only for NO~X~ emissions and will not be
subject to NNSR for VOC or PSD review for any attainment pollutant.
However, in the event that AES elects to construct and operate the Power
Plant at the Terminal Site, the entire LNG Terminal, including the
sources that are the subject of this permit application package, could
potentially be classified as a Major Stationary Source for NO~X~, VOC
and CO emissions. In that case, all LNG Terminal with Power Plant
emission sources will be subject to NNSR for NO~X~ and VOC and PSD
review for NO~2~ and CO. Accordingly, LAER determinations would need to
be made for NO~X~ and VOC and BACT determinations would need to be made
for NO~2~ and CO. Because by definition, LAER is more stringent than
BACT, the LAER determination proposed for NO~X~ in this application
would meet the BACT requirements for NO~2~. In addition, oxidation
catalysts for control of CO and VOC emissions from the HW heaters are
currently proposed in order to meet potentially-applicable future LAER
criteria for VOC and BACT criteria for CO. This section provides
documentation in support of this determination.

### Identification of CO Control Technologies

CO is formed as a result of incomplete combustion of fuel. Providing
adequate fuel residence time and high temperature in the combustion
device to ensure complete combustion can minimize CO emissions. However,
these combustion techniques can sometimes increase NO~X~ emissions.
Conversely, a low NO~X~ emission rate achieved by flame temperature
control can result in higher CO emissions. Therefore, a compromise must
be reached whereby the flame temperature reduction is set to achieve the
lowest NO~X~ emission rate possible while maintaining CO emission rates
at acceptable levels.

There are two basic techniques for controlling CO emissions from
combustion units: good combustion practices and add-on oxidation
catalysts. "Good combustion practices" is the predominant control
technique used for minimizing CO emissions from natural gas-fired
boilers and heaters, although more recent installations have included
the use of oxidation catalysts.

Good combustion practices are intended to control the parameters that
affect the formation of CO. Optimizing the excess air, flame
temperature, residence time at flame temperature, combustion zone
design, and turbulence result in reduced CO formation. Combustion
controls have no additional environmental impacts, do not result in
increased emissions of other pollutants, and incur no additional cost
for the combustion equipment.

A CO oxidation catalyst is an add-on control option in which the
catalyst is placed in the exhaust stream generally in the range of 700°F
to 1,100°F. At lower temperatures, CO conversion efficiency falls off
rapidly. Above 1200°F catalyst sintering may occur, thus causing
permanent damage to the catalyst. Within the context of a BACT analysis,
a CO oxidation catalyst is considered the "top" control technology for
CO emissions from fossil fuel fired sources.

AES proposes to install an oxidation catalyst on each of the four HW
heaters to reduce CO emissions to achieve emission rates that will
satisfy BACT requirements. The oxidation catalyst will reduce CO
emissions to a level of 10 ppmvd, which is equivalent to 0.0074
lb/MMBtu. Based on a review of recent determinations listed in EPA's
RBLC, as documented in Table 4-4, this is consistent with the low rates
required of recently permitted large boilers and water heaters.

### Identification of VOC Control Technologies

VOC emissions are also formed as a result of incomplete combustion of
fuel. The same principles that apply to CO control also apply to VOC
control (although the quantity of VOC generated is smaller than CO).
Formation of VOC can be minimized by providing adequate fuel residence
time and high temperatures, but these conditions can increase NO~X~
emissions. Because the same types of controls are effective at reducing
VOC emissions as CO emissions, the controls described in the BACT
analysis for CO are relevant for VOC control as well. As such, the
control proposed for CO -- an oxidation catalyst -- will reduce the
concentration of VOC to 10 ppmvd @ 3% O~2~, which is equivalent to
0.0042 lb/MMBtu (as methane).

VOC emission rates and controls from recently permitted units were
reviewed (see Table 4-5). The proposed emissions rate of 0.0042 lb/MMBtu
and use of an oxidation catalyst is consistent with the lowest VOC
levels achieved.

## LAER and BACT Analysis for Emissions from Emergency Engines

AES is proposing to install one 375 HP and six 700 HP diesel engine
emergency fire pumps and a 2 MW diesel engine emergency generator to
provide fire protection and auxiliary backup power, respectively, to the
LNG Terminal in the event that a fire or electricity transmission line
outage occurs during a power interuption. These engines are expected to
operate for less than 60 hours per year only for emergency situations
and engine testing purposes. Based on manufacturer's data, at 60 hours
per year of operation, total potential emissions of NO~X~ from the eight
emergency engines will be less than 3 TPY and CO will be limited to 0.22
TPY. All other pollutants will be emitted at much less than 1 TPY.

Control techniques for diesel engines are primarily directed at NO~X~
and CO emissions as they are the primary pollutants from these engines.
Available controls for diesel engines include parametric controls, such
as adjustment of ignition timing, air-to-fuel ratio and derating, and
post-combustion controls, such as SCR and nonselective catalytic
reduction (NSCR). These controls are applied in base-load applications
where engines are operated primarily at high capacity for extended
periods of time for industrial and power generation purposes. However,
based upon a review of EPA's RBLC and other sources, no specific
controls were identified for diesel engines operating less than 100
hours per year only for emergency operation purposes.
Cost-effectiveness, evaluated on a cost per ton of pollutant controlled,
would be unreasonably high for any of the add-on controls in this
application. In addition, add-on controls such as SCR are not
technically feasible in applications requiring quick start-ups and short
operating durations.

In summary, no specific controls are proposed for the diesel emergency
fire pumps and generator. Limiting the diesel engines to 60 hours per
year of operation only for emergency and engine testing purposes is
proposed to meet BACT and LAER requirements.

Table 4‑4 - Summary of CO Control Technology Determinations and Permit
Limits for Large Gas-fired Boilers

  ---------------------------------------------------------------------------------------------------------------------
  **Project Name** **State**   **Size**             **Fuel          **Date       **Nitrogen              
                                                    description**   initially    Oxides**                
                                                                    permitted /                          
                                                                    In-service                           
                                                                    date**                               
  ---------------- ----------- ---------- --------- --------------- ------------ ------------ ---------- --------------
                               **MW       **MMBtu                                **Limit (lb/ **Avg.     **Controls**
                               total**    /hr each                               MMBtu)**     Period**   
                                          unit**                                                         

  Genentech, Inc.  CA          28         97        Natural Gas     permit date  0.0370       three      ULNB
                                                                    not listed,               30-min     
                                                                    startup date              sampling   
                                                                    6-14-2006                 periods    

  BP Cherry Point  WA          106        363.0     Natural Gas     4/20/2005    0.05                    GCP
  Refinery                                                                                               

  Arizona Clean    AZ          101        346.0     Natural Gas or  4/14/2005    0.04         3-hr       None
  Fuels Yuma                                        Refinery Fuel                             rolling    
                                                    Gas                                       average    

  Arizona Clean    AZ          91         311.0     Refinery Fuel   4/14/2005    0.04         3-hr       None
  Fuels Yuma                                        Gas or Natural                            rolling    
                                                    Gas                                       average    

  Arizona Clean    AZ          96         328.0     Refinery Fuel   4/14/2005    0.04         3-hr       None
  Fuels Yuma                                        Gas or Natural                            rolling    
                                                    Gas                                       average    

  Arizona Clean    AZ          245        419.0     Natural Gas     4/14/2005    0.016        3-hr       None
  Fuels Yuma                                                                                  rolling    
                                                                                              average    

  AES Huntington   CA          225        2088      Natural Gas     7/27/2004    0.0037       1-hr       oxidation
  Beach                        (output)                                                       (source    catalyst
                                                                                              test)      
                                                                                              24-hr      
                                                                                              (CEMS)     

  Sunoco Inc.      OH          82         281.0     Natural Gas     7/27/2004    0.076                   None

  Cargill - Blair  NE          81         276.7     Natural Gas     6/22/2004    0.14                    GCP
  Plant                                                                                                  

  Midamerican      IA          126        429.4     Natural Gas     6/17/2003    0.084                   GCP
  Energy Company                                                                                         

  VA Power -       VA          29         99        Natural Gas     11/18/2002   0.15                    GCP
  Possum Point                                                                                           

  Weyerhaeuser     AL          88         300.0     Natural Gas     11/15/2002   0.1                     None
  Company                                                                                                

  Huntsman         TX          108        370.0     Natural Gas     10/24/2002   0.065                   GCP
  Polymers -                                                                                             
  Odessa                                                                                                 
  Petrochemical                                                                                          
  Plant                                                                                                  

  Huntsman         TX          94         320.0     Natural Gas     10/24/2002   0.084                   None
  Polymers -                                                                                             
  Odessa                                                                                                 
  Petrochemical                                                                                          
  Plant                                                                                                  

  Liberty          NJ          225        256.0     Natural Gas     3/28/2002    0.0956                  CO Catalyst
  Generating                                                                                             
  Station                                                                                                

  Liberty          NJ          59         200       Natural Gas     3/28/2002    0.087                   CO Catalyst
  Generating                                                                                             
  Station                                                                                                

  Agritechnology   MT          105        358.0     Natural Gas     11/6/2001    0.05                    GCP
  Montana LLC                                                                                            

  FPL Energy       PA          1845       1575      Natural Gas     5/4/2001     0.075                   GCP
  Marcus Hook,                                                                                           
  L.P.                                                                                                   

  Grays Ferry      PA          328        1119      Natural Gas     3/21/2001    0.04                    GCP
  Cogen                                                                                                  
  Partnership                                                                                            

  Kal Kan Foods,   CA          23         78.6      Natural Gas     6/28/1995    0.2960       15-min     SCR
  Inc.                                                                                                   

  Darling          CA          32         110       Natural Gas or  12/7/1993    0.0740       15-min     \"add-on\" but
  International,                                    Propane                                              no description
  Inc.                                                                                                   
  ---------------------------------------------------------------------------------------------------------------------

Table 4‑5 - Summary of VOC Control Technology Determinations and Permit
Limits for Large Gas-fired Boilers

  ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
  **[Project       **[State]{.mark}**   **[Size]{.mark}**                    **[Fuel                 **[Date          **[Nitrogen                           
  Name]{.mark}**                                                             description]{.mark}**   initially        Oxides]{.mark}**                      
                                                                                                     permitted /                                            
                                                                                                     In-service                                             
                                                                                                     date]{.mark}**                                         
  ---------------- -------------------- ------------------- ---------------- ----------------------- ---------------- ------------------ ------------------ -----------------------
                                        **[MW               **[MMBtu /hr                                              **[Limit (lb/      **[Avg.            **[Controls]{.mark}**
                                        total]{.mark}**     each                                                      MMBtu)]{.mark}**   Period]{.mark}**   
                                                            unit]{.mark}**                                                                                  

  Sunoco Inc.      OH                   82                  281.0            Natural Gas             7/27/2004        0.005                                 None

  Mid-American     IA                   126                 429.4            Natural Gas             6/17/2003        0.0055                                GCP
  Energy Company                                                                                                                                            

  VA Power -       VA                   29                  99               Natural Gas             11/18/2002       0.004                                 GCP
  Possum Point                                                                                                                                              

  Weyerhaeuser     AL                   88                  300.0            Natural Gas             11/15/2002       0.01                                  None
  Company                                                                                                                                                   

  Huntsman         TX                   108                 370.0            Natural Gas             10/24/2002       0.004                                 GCP
  Polymers -                                                                                                                                                
  Odessa                                                                                                                                                    
  Petrochemical                                                                                                                                             
  Plant                                                                                                                                                     

  Huntsman         TX                   94                  320.0            Natural Gas             10/24/2002       0.007                                 None
  Polymers -                                                                                                                                                
  Odessa                                                                                                                                                    
  Petrochemical                                                                                                                                             
  Plant                                                                                                                                                     

  Liberty          NJ                   225                 256.0            Natural Gas             3/28/2002        0.2                                   CO Catalyst
  Generating                                                                                                                                                
  Station                                                                                                                                                   

  Liberty          NJ                   59                  200              Natural Gas             3/28/2002        0.036                                 CO Catalyst
  Generating                                                                                                                                                
  Station                                                                                                                                                   

  FPL Energy       PA                   1845                1575             Natural Gas             5/4/2001         0.004                                 None
  Marcus Hook,                                                                                                                                              
  L.P.                                                                                                                                                      

  Grays Ferry      PA                   328                 1119             Natural Gas             3/21/2001        0.005                                 GCP
  Cogen                                                                                                                                                     
  Partnership                                                                                                                                               
  ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

# Air Quality Impact Analysis

Although PSD review is not applicable to the proposed LNG Terminal, an
air quality modeling analysis was performed as part of the FERC
application for Certificate of Public Necessity and Convenience to
satisfy the FERC Staff's interpretation of its obligation under NEPA to
evaluate potential air quality impacts associated with the Project. This
modeling analysis includes an evaluation of impacts from the LNG
Terminal with and without the potential future Power Plant, and a
cumulative analysis of impacts from the LNG Terminal, including LNG ship
offloading operations. Separate model runs were also performed to
evaluate the combined effects of the LNG Terminal and Power Plant
scenarios with LNG ship offloading, hoteling operations and marine
vessels associated with LNG ship movements in the vicinity of the LNG
Terminal and along the LNG ship transit route, specifically assist tugs
and USCG security and patrol boats within the security zone. The
modeling assumptions, procedures and results are summarized in this
section. A compact disk containing all modeling input and output files
is also provided in Appendix D. In the event that AES decides to
construct and operate the Power Plant and will be required to perform an
air quality impact analysis satisfying all requirements for PSD review,
AES will perform the required PSD modeling analyses and submit a
detailed modeling report as part of the permit application to the MPSC
and MDE.

## Air Quality Modeling Analysis Scope and Objectives

Atmospheric dispersion modeling was performed to evaluate impacts to air
quality due to operation of the LNG Terminal. The modeling was conducted
in accordance with objectives and procedures to satisfy NEPA impact
assessment criteria, as discussed in several teleconferences with the
FERC Staff. In addition, modeling guidance and meteorological input data
were obtained through consultation with MDNR's subcontractor,
Environmental Resources Management, Inc. (ERM), responsible for review
of air quality impact analyses under MPSC's consolidated licensing
program for power plants.

Based on the consultation with the FERC Staff, three distinct scenarios
were modeled for each of the LNG Terminal operating phase options (i.e.,
with and without the Power Plant):

> [(Option 1) Without Power Plant:]{.underline}

-   LNG Terminal emission sources only

-   LNG Terminal emission sources plus LNG ship offloading emissions

-   LNG Terminal emission sources, LNG ship offloading plus all other
    marine vessels within the security zone

> [(Option 2) With Power Plant:]{.underline}

-   LNG Terminal and Power Plant emission sources only

-   LNG Terminal and Power Plant emission sources plus LNG ship
    offloading emissions

-   LNG Terminal and Power Plant emission sources, LNG ship offloading
    plus all other marine vessels within the security zone

The scenarios were identified in this manner consistent with FERC
Staff's interpretation of its obligation under NEPA to evaluate
potential impacts from both primary and secondary emission sources
associated with the LNG Terminal. FERC Staff further advised that the
secondary mobile emission sources included in the modeling should be
geographically limited from the turning basin to the berth and include
emissions from all LNG ship transit, maneuvering, and hoteling
operations and assist tugs, security and patrol vessel operations in
this restricted area. Because the USCG has not yet determined the
preliminary extent of the security zone, it was assumed for the purposes
of the modeling analysis that it would be defined by a minimum radius of
500 yards from the LNG ship berth. In addition, the USCG will establish
a security zone around each LNG ship while it is in transit. For
purposes of the modeling analysis and determining the LNG Terminal
"fenceline" for restricted public access, this security zone was
conservatively assumed to extend 500 yards from each side of the LNG
ship. If the security zone ultimately established by the USCG is greater
than these assumptions, it would reduce the impacts at LNG Terminal
fenceline receptors. Similarly, if the security zone ultimately
established by the USCG is less than these assumptions, it would
increase the impacts at fenceline receptors.

Further following FERC Staff guidance to comply with NEPA impact
assessment requirements, the modeled impacts were first compared to EPA
PSD Significant Impact Levels (SILs). If maximum predicted impacts are
predicted to be less than the applicable SILs, FERC Staff presumes that
the source will not cause or significantly contribute to a PSD Increment
or NAAQS violation and no further impact assessment is required. If the
predicted impacts are greater than SILs, then maximum impacts are added
to representative ambient background concentrations and evaluated for
compliance with the NAAQS. In addition, if predicted impacts are greater
than SILs, FERC Staff has advised AES that it must complete a
qualitative cumulative impact analysis by comparing potential emissions
from the Project and other new or reasonably foreseeable projects in the
region with regional emission inventories.

## Model Selection

AERMOD (Version 04300), incorporating Plume Rise Model Enhancement
(PRIME) downwash algorithms was used in the refined modeling analyses
for simple and elevated terrain. The AERMOD model was run using the
Lakes Environmental ISC-AERMOD View (version 5.4.0) interface for EPA's
ISC and AERMOD models. AERMOD is an EPA-approved refined dispersion
model for evaluating impacts of land-based stationary sources. AERMOD
with PRME is one of the listed refined dispersion models in EPA's
*Guideline on Air Quality Models (*40 CFR Part 51 Appendix W, November
2005) that are required to be used for SIP revisions for existing
sources and for NSR and PSD programs.

AERMOD with PRIME (Plume Rise Model Enhancement) includes improved
building downwash algorithms capable of modeling receptors in both the
near-building wake (cavity) and far-building wake regions. The PRIME
algorithm takes into account the distance from each building or
structure to potentially affected sources in that building's region of
influence. The inclusion of the cavity predictions within AERMOD removes
a modeling discontinuity that existed with AERMOD without the PRIME
algorithm and obviates the need for additional cavity impact analysis
using the SCREEN3 or other calculation procedures.

Default AERMOD control options used in the modeling analysis consistent
with EPA recommendations include the following:

-   Final plume rise at all receptors

-   Stack-tip downwash

-   Buoyancy-induced dispersion

-   Calm wind processing routine

-   Default wind profile exponents

-   Default vertical potential temperature gradients

## Emissions and Source Parameters

The emissions and operating scenarios of all sources included in the
modeling analysis are described in Section 2.0. The specific primary and
secondary (mobile marine vessel) emission sources associated with the
LNG Terminal, LNG ships and nonjurisdictional Power Plant are summarized
as follows:

> [LNG Terminal]{.underline}

-   Four hot water heaters

-   One Fresh water emergency diesel engine fire pump

-   Six salt water emergency diesel engine fire pumps

-   One emergency diesel engine standby generator

-   One heated vent stack

-   LNG ship offloading operations

> [Marine Vessels Associated with LNG Ships]{.underline}

-   LNG ship hoteling operations at berth and in security zone

-   Three assist tug boats in security zone

-   Two security and patrol boats in security zone

> [Non-Jurisdictional Power Plant]{.underline}

-   One combined cycle combustion turbine with heat recovery steam
    generator (CTG/HRSG)

-   One cooling tower

Detailed assumptions and calculations used to develop emission rates,
operating scenarios and other stack parameters are provided for each of
the emission sources in Tables 2-1 through 2.7. Table 5-1 summarizes the
emissions and source parameters used for AERMOD input.

Different source groups were set up in the model in order to predict
impacts for each of the modeling scenarios identified in Section 5.1 for
each of the LNG Terminal options (with and without the Power Plant).
These source groups are identified in Table 5-2. The source
identification numbers (IDs) listed in the table correspond to the stack
numbers identified in Table 5-1. Additional notes and conservative
assumptions used in the modeling are also summarized in Table 5-2. For
example, worst-case operating assumptions for the HW heaters and CTG
assume air pollution control system malfunction conditions in one of the
hot water heaters for short-term average emission rates and startup
conditions are factored into the annual emission rates. With respect to
the CTG/HRSG, the worst-case short-term emission rates from the two CTG
manufacturers under consideration were used as model input. In addition,
worst-case emissions are based on continuous operation of the CTG and
HRSG at 100 percent load at an ambient temperature of -7ºF. In the event
that AES decides to construct and operate the Power Plant and it is
determined to be subject to PSD review, an analysis of impacts over a
range of operating loads and ambient temperatures will be conducted as
part of the PSD modeling analysis in order to verify the worst-case
impact scenario.

## Good Engineering Practice (GEP) Stack Height Analysis

Building and structure dimensional data for the GEP stack height, cavity
and downwash analyses are summarized in Table 5-3. The dimensional data
for all significant buildings/structures as well as the layout and
orientations on site are based on the site plan and general arrangement
plans presented in Figures 2-4 through 2-7 and also in Resource Report
13, *Engineering and Design Manual*, of the FERC application for
Certificate of Public Necessity and Convenience. In addition, typical
dimensions of LNG ships for input to the models were obtained from plan
and elevation drawings and photographs of a range of actual LNG ships
currently in use. For purposes of the modeling analyses, two LNG ships
were assumed to be at berth at the same time, one in the process of
offloading and the other hoteling[^7]. To cover the range of sizes of
LNG ships that could be accommodated at the LNG Terminal, one ship was
assumed to be a 138,000 cubic meter capacity and the other was assumed
to be 210,000 cubic meter capacity.  In addition, for modeling purposes,
an additional position for a 210,000 cubic meter LNG ship in the tuning
basin was assumed for one of the two ships at the terminal.  The
additional position was assumed so that maximum potential emissions from
the assist tugs and security and patrol boats operating during the
berthing process could be conservatively modeled accounting for the
downwash, cavity and wake effects that would result while an LNG ship is
at that location.

The buildings and structures were processed using the EPA Building
Profile Input Program (BPIP, version 04274) to determine GEP stack
heights as well as direction-specific building heights and widths for
each 10-degree azimuth direction for each source included in the
modeling analysis. BPIP input and output files are included in the
modeling compact disk provided in Appendix D. Figure 5-1 depicts the
BPIP model setup for the identified significant buildings or structures
on site. Figure 5-2 is a three-dimensional representation of the
significant buildings and structures.

GEP stack height calculations were performed with the BPIP program based
on the building/structure dimensions and the methodology described in
EPA's [Guideline for Determination of Good Engineering Practice Stack
Height (Technical Support Document for the Stack Height Regulations
(June 1985).]{.underline} The GEP stack height calculated for all
stacks, with the exception of the assist tugs and security and patrol
vessels was approximately 130 meters (427 feet), with some variation due
to differences in stack and building/structure base elevations. The
significant structures affecting the GEP stack height for each of these
stacks were the LNG storage tanks, each with a height of 51.65 meters
(169.5 feet). The GEP stack height calculated for the assist tugs and
security and patrol vessels was approximately 94 meters (308 feet),
based on the dimensions of the LNG ship in the turning basin. Each of
the proposed stack heights is less than the calculated GEP stack heights
and the stacks are also located within the 5L zone of influence from the
significant structures. Therefore, downwash and cavity zone impact
analyses, incorporated in the AERMOD with PRIME model, were performed
based on the dimensions of the controlling structures.

## Meteorological Data and Site Characteristics

For refined modeling, the *Guideline on Air Quality Models* recommends
one year of on-site data or 5 years of off-site representative data. For
this modeling analysis, 5 consecutive years of meteorological data were
provided by MPSC's air quality consultant (ERM) from the closest and
most representative National Weather Service (NWS) stations to the LNG
Terminal site. Surface data from NWS Station \# 93721 (Baltimore
Washington International Airport - BWI) and upper air data from NWS
Station \# 93734 (Sterling, Virginia), both for the years 1990 to 1994
were selected for input to AERMET, a meteorological pre-processor
program used in conjunction with AERMOD. BWI is located approximately 15
km (9.3 miles) southwest of the Terminal Site. AES concurs with ERM in
considering this station to have surface meteorological data and land
use characteristics that are representative of the Terminal Site.
Selection of BWI surface data is justified on the basis of spatial and
climatological (temporal) representativeness as well as the ability of
the selected site parameters to characterize the transport and
dispersion conditions in the area of concern. The representativeness of
the data is demonstrated based on: (1) The proximity of the
meteorological monitoring site to the area under consideration (BWI is
within the modeling domain and only 15 km from the emission sources);
(2) the similarity in the complexity of the terrain (both BWI and the
area surrounding the LNG Terminal have relatively flat terrain and have
similar urban land use); (3) the exposure of the meteorological
monitoring site; and (4) the period of time during which data are
collected.

ERM processed the raw data with AERMET (Version 04300), the
meteorological preprocessor for AERMOD. In accordance with EPA guidance
(*AERMOD Implementation Guide, September 27, 2005*), ERM developed the
season and sector specific surface inputs (albedo, Bowen ratio, and
roughness length) through the use of an in-house software program that
assigned these parameters based on land use within a 3 km area
surrounding the BWI airport divided into 12 equally-spaced sectors. Land
use information was extracted from USGS Composite Theme Grid (CTG)
files, and parameter values were assigned based on Tables 4-1 through
4-3 presented in the AERMOD user\'s guide. The site characteristics by
sector and season developed with this approach are summarized in Table
5-4. Land use surrounding BWI is predominately characterized as urban.
Therefore, the urban dispersion option was used for the AERMOD modeling
and the default value of 1.0 was used for the urban roughness length. In
addition, all land-based stationary sources associated with the LNG
Terminal were listed as urban sources.

## Receptors and Terrain Data

A non-uniform polar grid receptor network was initially set up in AERMOD
using rings of receptors spaced at 10 degree intervals on 36 radials
originating at the approximate center of the LNG Terminal emission
sources. A total of 19 receptor rings were defined at the following
distances in meters from the origin:

-   0 -- 2 km with 100 meter spacing

-   2 -- 5 km with 500 meter spacing

-   5 -- 10 km with 1,000 meter spacing

-   10 -- 16 km with 2,000 meter spacing

The extent of the receptor network was believed to be sufficient to
identify the significant impact area with sufficient resolution. In
order to import terrain elevations associated with each of the
receptors, the polar grid was converted into discrete Cartesian
receptors.

The portion of the LNG Terminal located on land will be fenced and not
accessible to the general public. In addition, the general public will
be restricted access to areas over water surrounding the LNG ships at
berth and while in transit. As discussed in Section 5.1., the USCG has
not yet determined the preliminary extent of the excluded security zone.
However, for the purposes of the modeling analysis, it was assumed that
it would be defined by a minimum radius of 500 yards from the LNG ship
berth. In addition, the USCG will establish a security zone around each
LNG ship while it is in transit. For purposes of the modeling analysis
and determining the LNG Terminal "fenceline" for restricted public
access, this security zone was conservatively assumed to extend 500
yards from each side of the LNG ship. If the security zone ultimately
established by the USCG is greater than these assumptions, it would
reduce the impacts at fenceline receptors. Similarly, if the security
zone ultimately established by the USCG is less than these assumptions,
it would increase the impacts at fenceline receptors.

A total of 56 discrete receptors were placed along the proposed
"fenceline", including 26 primary receptors at each node of the
fenceline polygon and 30 receptors at intermediate points between nodes.
Discrete Cartesian receptors located within the plant boundary were
eliminated since the property will not be accessible by the general
public. Figure 5-3 depicts the near-field receptors, fenceline and plant
boundary receptors with those within the plant boundary eliminated.
Figure 5-4 depicts the entire receptor network within the modeling
domain boundaries.

Terrain elevations at each of the receptor points were specified by
importing 7.5 minute USGS Digital Elevation Model (DEM) data into
ISC-AERMOD View interface. The DEM data was obtained from
[www.webgis.com](http://www.webgis.com/). UTM Zone 18 (NAD27) was used
as the common reference for model setup. The method used to select the
elevation for each receptor involved importing the highest elevation
from within a bounding polygon, where the bounding polygon is defined by
half the distance to adjacent receptor grid nodes.

## Background Air Quality

Modeled pollutant concentrations are added to background air quality
data to evaluate compliance with NAAQS. Background air quality data are
conservatively used to account for pollutant concentrations that are
otherwise not accounted for in single-source or multiple-source modeling
analyses. Representative background concentrations were obtained from
the average of the most recent available three years of monitoring data
(2003-2005) from the three monitoring sites nearest to the LNG Terminal
site. Table 5-5 summarizes the background ambient data and the
monitoring sites determined to be most representative of the LNG
Terminal modeling domain in AQCR 115.

## Model Results

The AERMOD model was used to predict maximum ambient air quality impacts
for each of the scenarios identified in Section 5.1 for the LNG Terminal
with and without the Power Plant. Model results are summarized for each
of the scenarios in Table 5-6. Following FERC guidance, maximum impacts
were first compared to EPA SILs. If impacts were estimated to exceed the
respective SILs, representative ambient background concentrations were
then added to modeled impacts and the total concentrations were compared
to NAAQS. As summarized in Table 5-6, estimated impacts from the LNG
Terminal stationary sources with or without the Power Plant are less
than respective SILs for SO~2~, CO and Pb. When LNG ship offloading
emissions are added, only CO and Pb impacts are less than the respective
SILs. When secondary (marine vessel) sources are added to the modeling
scenarios, only Pb impacts are lower than the SIL. However, when
representative ambient background concentrations are added to modeled
impacts, compliance with all applicable NAAQS is demonstrated for all
pollutants currently included in Maryland's SIP, as shown in Tables 5-6
and 5-7.

It should be noted that the offsite areas where maximum modeled impacts
are predicted to exceed the SILs occur in close proximity to the LNG
Terminal. Even with the worst-case scenario involving all LNG Terminal
and Power Plant sources, LNG ship offloading and marine vessels, the
maximum distances to SILs were all within 1,500 meters from the
approximate center of the land-based LNG Terminal sources (within 1,250
meters from the property line) for all pollutants except CO and within
3,000 meters from the center (1,800 meters from the property line) for
CO. CO impacts above SILs were exclusively due to estimated emissions
from outboard gasoline engines used in security and patrol boats, which
have relatively high CO emission factors relative to all other modeled
sources.

It should also be noted that representative 24-hour and annual average
PM~2.5~ ambient background concentrations currently exceed the
applicable AAQS and that AQCR 115 has been designated nonattainment for
PM~2.5~. AES understands that Maryland is currently developing a SIP
revision to address the NNSR requirements applicable to the annual
average standard. However, due to the recent final rule revising the
PM~2.5~ 24-hour standard from 65 to 35 µg/m^3^ (effective December 18,
2006), nonattainment designations with respect to the 24-hour standard
are pending as are further SIP revisions to incorporate NNSR
requirements for the revised PM~2.5~ 24-hour standard. In addition, an
EPA final rule on implementation of the PM~2.5~ standards during the
transition period while SIPs are under development is still pending.
Therefore, AES understands that demonstration of compliance with the
NAAQS currently does not include PM~2.5~ impacts.

## Cumulative Impacts Analysis

Based of guidance provided by the FERC through consultation, AES
understands that NEPA requires a qualitative cumulative impact analysis
if predicted impacts are greater than SILs. AES further understands that
additional guidance for performing such an analysis is pending as some
of the details are being worked out with EPA and affected states. Other
similar projects have performed qualitative cumulative impact analyses
by comparing potential direct and indirect emissions from the Project
under review and other new or reasonably foreseeable projects in the
region with regional emission inventories. Based on discussion with the
FERC, AES understands that the FERC is considering using the predicted
significant impact area (offsite areas where maximum modeled impacts are
predicted to exceed the SILs) to define the region for identifying other
new and reasonably foreseeable projects to be included in the analysis.
Pending further guidance, AES also understands that a reasonable
approach for assessing the regional significance of cumulative emissions
is to compare them to a preliminary threshold equivalent to 10 percent
of the county-wide emission inventory. A project would not be considered
regionally significant if the cumulative emissions were predicted to be
less than 10 percent of the existing county inventory.

As discussed in Section 5.8, the worst-case significant impact area
based on the modeling results for the scenario involving all primary and
secondary emission sources extends less than 3,000 meters for CO and
less than 1,500 meters for all other pollutants from the approximate LNG
Terminal center point. Furthermore, the modeled significant impact area
for CO occurs entirely over water to the west of the LNG Terminal site
and the significant impact area for other pollutants occurs over the
Sparrows Point Industrial Complex to the east of the LNG Terminal
property lines. AES has not identified any new or reasonably foreseeable
projects located in these significant impact areas determined by the
modeling. Therefore, potential emissions from the Project alone were
compared to the most recent available Baltimore County emission
inventory (2001) data available from EPA
(<http://www.epa.gov/air/data/geosel.html>). The Baltimore County
emission inventory is summarized in Table 5-8 and the comparison of
Project direct and indirect emissions to the County inventory is
summarized in Table 5-9. The analysis shows that worst-case Project
emissions (including the LNG Terminal, Power Plant, LNG offloading and
indirect emissions associated with the Project in Maryland) are
estimated to be much less than 10 percent of the Baltimore County
emission inventory for all pollutants, with the exception of ammonia.
Maximum ammonia emissions, due primarily to worst-case ammonia slip
emissions from the Power Plant SCR system used to control NO~X~
emissions, are estimated to be 11.8 percent of the Baltimore County
ammonia emissions inventory. Based on this analysis, worst-case direct
and indirect emissions from the LNG Terminal are not considered
regionally significant because the significant impact areas are
predicted to be close to the LNG Terminal, no other new or reasonably
foreseeable sources are expected to be located within the small
significant impact area, and total LNG Terminal direct and indirect
emissions would be a small percentage of the Baltimore County emissions
inventory.

## Cooling Tower Impact Analysis

If AES decides to construct and operate the Power Plant, a mechanical
draft evaporative cooling tower will be used to remove waste heat from
the steam condenser cooling water when the Power Plant is operated
without LNG sendout (conservatively expected to be less than 33 percent
of the time if the Power Plant is constructed and operated). Mechanical
draft cooling towers can produce environmental impacts due to the liquid
water plume coming directly from the tower (known as "drift"), as well
as from the secondary liquid water formation caused by the condensation
of water vapor ("fogging"). These impacts include: local shading of the
sun due to a visible plume, fogging at ground level and ice build-up,
and deposition of dissolved salt particles.

A detailed modeling analysis of cooling tower impacts was performed to
evaluate the potential for these impacts from operation of the LNG
Terminal using the Seasonal/Annual Cooling Tower Impact (SACTI) model
(Version 09-01-86). The SACTI model was funded by the Electric Power
Research Institute (EPRI). It is based on studies conducted by Argonne
National Laboratory that evaluated the theory and performance of over 30
cooling tower plume and drift models. The SACTI model was used for this
analysis because it is a validated cooling tower plume and drift model
that has been widely used in preparing environmental assessments of
cooling towers for regulatory purposes. The SACTI model uses cooling
tower design and operational data along with hourly meteorological data
to predict the probable impact of cooling tower plumes.

The results of the analysis are summarized in Table 5-9 and the input
and output files are included on the compact disk in Appendix D. In
summary, the Power Plant cooling tower was evaluated for adverse
environmental impacts using the SACTI model. Based on this analysis, no
adverse off-site environmental effects are expected.

**Table 5-10** -- Summary of Cooling Tower Impact Analysis Results

  ----------------------- ----------------------- -----------------------
  **Cooling Tower Impact  **Estimated Impacts     **Estimated Location
  Description**           (units based on 5 years and Extent of Impacts**
                          of hourly               
                          meteorology)**          

  Plume Fogging           7.2 hours per year      Predominantly within
                                                  600 to meters
                                                  west-south-west of the
                                                  cooling tower.

  Rime Icing              0 hours per year        No icing is expected to
                                                  occur.

  Salt Deposition         Maximum 7,231           Predominantly within
                          kg/km^2^-month on site  100 meters of tower and
                                                  on site.

  Plume Shadowing         Maximum 200             Predominantly within
                          hours/5-years           200 meters
                                                  west-north-west of
                                                  tower and on site.

  Plume Visibility        Plume typically visible Visible plume
                          on site when cooling    predominantly located
                          tower is operating      onsite with dimensions
                          (max. 33% of time only  less than 100 meters in
                          if Power Plant is       length, 20 to 30 meters
                          operated)               in height and 10-15
                                                  meters in radius.
  ----------------------- ----------------------- -----------------------

**Figures**

**Tables**

**Appendix A**

**Permit Application Forms**

**Appendix B**

**State-Wide Compliance Certification**

**[COMPLIANCE CERTIFICATION]{.underline}**

As required under COMAR 26.11.17.03B.(1), I hereby certify that all
existing major stationary sources owned or operated by AES Sparrows
Point LNG, LLC, a wholly owned subsidiary of The AES Corporation, in the
State of Maryland are in compliance with all applicable emission
limitations or are in compliance with an approved federally enforceable
plan for compliance.

**Signed,**

**\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_**

**\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_**

**(Title)**

**\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_**

**(Date)**

**Appendix C**

**Preliminary Vendor Data**

**Appendix D**

**CD Containing Dispersion Modeling Input and Output Files**

**List of Model Input and Output Files**

  -------------------- -------------------- --------------------------------------------
  **Input Files:**     **Output Files:**    **Description**

  **AERMOD Refined                          
  Modeling Files**                          

  SPNO90.ADI           SPNO90.ADO           NOX, annual average, 1990

  SPNO91.ADI           SPNO91.ADO           NOX, annual average, 1991

  SPNO92.ADI           SPNO92.ADO           NOX, annual average, 1992

  SPNO93.ADI           SPNO93.ADO           NOX, annual average, 1993

  SPNO94.ADI           SPNO94.ADO           NOX, annual average, 1994

  SPSO390.ADI          SPSO390.ADO          SO2, 3-hr average, 1990

  SPSO391.ADI          SPSO391.ADO          SO2, 3-hr average, 1991

  SPSO392.ADI          SPSO392.ADO          SO2, 3-hr average, 1992

  SPSO393.ADI          SPSO393.ADO          SO2, 3-hr average, 1993

  SPSO394.ADI          SPSO394.ADO          SO2, 3-hr average, 1994

  SPSO2490.ADI         SPSO2490.ADO         SO2, 24-hr average, 1990

  SPSO2491.ADI         SPSO2491.ADO         SO2, 24-hr average, 1991

  SPSO2492.ADI         SPSO2492.ADO         SO2, 24-hr average, 1992

  SPSO2493.ADI         SPSO2493.ADO         SO2, 24-hr average, 1993

  SPSO2494.ADI         SPSO2494.ADO         SO2, 24-hr average, 1994

  SPSOA90.ADI          SPSOA90.ADO          SO2, annual average, 1990

  SPSOA91.ADI          SPSOA91.ADO          SO2, annual average, 1991

  SPSOA92.ADI          SPSOA92.ADO          SO2, annual average, 1992

  SPSOA93.ADI          SPSOA93.ADO          SO2, annual average, 1993

  SPSOA94.ADI          SPSOA94.ADO          SO2, annual average, 1994

  SPPMA90.ADI          SPPMA90.ADO          PM, annual average, 1990

  SPPMA91.ADI          SPPMA91.ADO          PM, annual average, 1991

  SPPMA92.ADI          SPPMA92.ADO          PM, annual average, 1992

  SPPMA93.ADI          SPPMA93.ADO          PM, annual average, 1993

  SPPMA94.ADI          SPPMA94.ADO          PM, annual average, 1994

  SPPM2490.ADI         SPPM2490.ADO         PM, 24-hr average, 1990

  SPPM2491.ADI         SPPM2491.ADO         PM, 24-hr average, 1991

  SPPM2492.ADI         SPPM2492.ADO         PM, 24-hr average, 1992

  SPPM2493.ADI         SPPM2493.ADO         PM, 24-hr average, 1993

  SPPM2494.ADI         SPPM2494.ADO         PM, 24-hr average, 1994

  SPCO190.ADI          SPCO190.ADO          CO, 1-hr average, 1990

  SPCO191.ADI          SPCO191.ADO          CO, 1-hr average, 1991

  SPCO192.ADI          SPCO192.ADO          CO, 1-hr average, 1992

  SPCO193.ADI          SPCO193.ADO          CO, 1-hr average, 1993

  SPCO194.ADI          SPCO194.ADO          CO, 1-hr average, 1994

  SPCO890.ADI          SPCO890.ADO          CO, 8-hr average, 1990

  SPCO891.ADI          SPCO891.ADO          CO, 8-hr average, 1991

  SPCO892.ADI          SPCO892.ADO          CO, 8-hr average, 1992

  SPCO893.ADI          SPCO893.ADO          CO, 8-hr average, 1993

  SPCO894.ADI          SPCO894.ADO          CO, 8-hr average, 1994

  SPPb2490.ADI         SPPb2490.ADO         Pb, 24-hr average, 1990

  SPPb2491.ADI         SPPb2491.ADO         Pb, 24-hr average, 1991

  SPPb2492.ADI         SPPb2492.ADO         Pb, 24-hr average, 1992

  SPPb2493.ADI         SPPb2493.ADO         Pb, 24-hr average, 1993

  SPPb2494.ADI         SPPb2494.ADO         Pb, 24-hr average, 1994

  **BPIP Prime                              
  Files:**                                  

  SP\*\*\*\*\*\*.BPI   SP\*\*\*\*\*\*.PRO   BPIP Input and Output Files For AERMOD Prime
                                            Refined Runs

  **SACTI Files:**                          

  Mult\*\*.out         Tables\*\*.out       SACTI model input and output files.

  Prep\*\*.out                               
  -------------------- -------------------- --------------------------------------------

**Appendix E**

**Alternatives Analysis**

Resource Report 10 has been formally filed with FERC on January 8, 2007
of which a copy was provided to the MDE because MDE is a cooperating
agency.

[^1]: The LNG Terminal will be designed to allow the potential addition
    of a fourth tank and a potential expansion in vaporization and
    sendout capacity of up to 2.25 bscfd. The Terminal design includes
    pre-investment in features and equipment, including blanked off pipe
    connections, to facilitate this future expansion. If and when the
    time comes to pursue this expansion, AES will perform a more
    detailed study on the expansion case to identify changes required to
    the existing LNG Terminal facilities. AES does not anticipate that
    the potential Terminal expansion will result in modifications to
    stationary sources proposed with this air permit application or
    additional stationary sources.

[^2]: AES expects two to three ships per week will arrive at the LNG
    Terminal, which equates to approximately 100 to 150 ships per year.
    Modeling 180 ship arrivals is therefore conservative.

[^3]: AES will attempt to negotiate LNG terminaling contracts under
    which tankers will operate preferably with natural gas and
    alternately with low sulfur marine diesel while stationary at the
    LNG Terminal, in order to minimize emissions and air quality
    impacts. At this time, AES cannot predict the success it will have
    in negotiating such contracts. Accordingly, the conservative
    assumptions outlined above and in more detail in Table 9-6 are even
    more appropriate at this time.

[^4]: It should be noted that, effective December 18, 2006, EPA revised
    the 24-hour PM~2.5~ NAAQS from 65 to 35 µg/m^3^ and revoked the
    24-hour PM~10~ NAAQS. Therefore, revised nonattainment designations
    are pending based on review of monitored PM~2.5~ 24-hour ambient
    data in comparison to the revised NAAQS.

[^5]: Letter from John Calcagni, EPA AQMD to Ken Waid, January 8, 1990
    re: clarification on questions concerning "secondary emissions" as
    defined in 40 CFR 52.21(b); Letter from Charles Sheehan, EPA
    Regional Counsel to Michael Cathey, October 28, 2003.

[^6]: The 28 listed source categories subject to PSD review for which a
    100 TPY applicability threshold would apply include fossil fuel
    boilers (or combination of them) totaling more than 250 million Btu
    per hour heat input and fossil fuel-fired steam electric plants of
    more than 250 million Btu per hour heat input. AES has not yet
    determined through consultation with MDE whether these source
    categories potentially would include the CTG with auxiliary fired
    HRSG and four hot water heaters. However, AES has determined that
    recent PSD applicability determinations have not treated similar
    sources at LNG terminals as falling within one of the 28 listed
    source categories. For example, the FERC Draft Environmental Impact
    Statement (DEIS) for the Broadwater Energy floating LNG storage and
    regasification unit (November 2006) was assumed not to be one of the
    listed 28 source categories and, on that basis, a 250 TPY
    applicability threshold was applied. Similarly, the DEIS for the
    Gulf LNG Energy Project discusses a May 1, 2006 applicability
    determination issued by the Mississippi Department of Environmental
    Quality indicating that the proposed LNG terminal would not be
    treated as one of the 28 listed source categories. On that basis,
    the terminal would not trigger PSD review as long as the potential
    to emit for all stationary sources at the terminal would not exceed
    250 TPY for any attainment criteria pollutant.

[^7]: While berthing of two ships at one time is contemplated in the
    design of the LNG Terminal, offloading of cargo will only be
    possible from one ship at a time.