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EPA's Liquefied Natural Gas
Regulatory Roadmap
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AUS 0 3 2006
July 2006
EPA230-B-06-001
EPA
230
B
06-
001
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About this Road map
Natural gas continues to play an important role in meeting our nation's growing energy
needs. In 2005, natural gas accounted for 23% of our nation's total energy consumption.1
The Department of Energy's Energy Information Administration (El A) projects that
domestic consumption of natural gas will continue to increase and that imports of
liquefied natural gas (LNG) will meet much of the increased demand.2
LNG, created when natural gas is converted into a liquid state by cooling it to a
temperature close to negative 260°F, presents an efficient way to transport natural gas via
ship from foreign production areas to the United States. The cooling process reduces the
volume of natural gas by a factor of more than 600, enabling one ship to transport close
to five percent of the nation's average daily demand for natural gas (or enough energy to
heat more than 43,000 homes per year).3 Once LNG arrives at an import facility, the
LNG is typically stored in insulated, pressurized tanks before it is converted back into a
gaseous state for shipment via pipeline or, in some instances, transported via truck to
market. Anticipating the use of this type of technology, EIA projects that total capacity
of U.S. LNG import facilities will rise from 1.4 trillion cubic feet in 2004 to 4.9 trillion
cubic feet in 2015.4
Along with many other federal agencies, the U.S. Environmental Protection Agency
(EPA) plays an important role in the approval and permitting of LNG import projects (or
LNG projects), whether the approval is for the development of a new project or the
expansion of an existing project. EPA's LNG Regulatory Roadmap catalogs the
numerous points zt which EPA's statutory and regulatory duties require the Agency to
participate in the LNG project approval and permitting process. The Roadmap is
designed to serve not only as an aid to the regulated community, but also to assist the
Agency in meeting its regulatory responsibilities in a timely and effective manner.
Because LNG import projects can be quite different in terms of their physical siting and
operational design, and the applicable law also varies, EPA's role varies on a project-by -
project basis. The Roadmap acknowledges these permutations and focuses on the
following key areas of Agency involvement:
1. The LNG project approval and environmental review process;
2. Requirements and decision making related to air emissions;
3. Requirements related to water quality; and
4. Other permitting requirements and considerations.
1 U.S. Department of Energy, Energy In format Ion Administration, Monthly Energy Review
www. eia. doe, go v/mer/cont cnt s. htm 1 .
U.S. Department of Energy, Energy Information Administration, A nnual Energy Outlook 2006
wvw.cia. doe.gov/oiaPaeo/indcx.html .
U.S. Department of Energy, Liquefied Natural Gas: Understanding the Basics, August 2005
www.fe.doe.gov/Drogrdms/oileas/publitations/ing/LNG primerupd.pdf.
U.S. Department of Energy, Energy Information Administration, Annual Energy Outlook 2006.
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The Roadmap presents discussions of EPA requirements that may appty to oflshore
projects (i.e., located beyond state seaward boundaries), as well as onshore and near
shore projects (i.e., located within state weters).
Figure 1. provides an overview of EPA's role in the environmental review process.
Figure 1. EPA's role in the LNG
Project Approval and
Environmental Review Process
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arrvironmantal Impact
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under CAA f 309 :
Within 45 days tffief the final
public hearing, the AdmMstralar is
to provide recommendation on
whether to approve or disappwe
the applic^ion and to inform DOT
if the deepwater port :wM rat
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CAA,CWAandMPRSA
Acronym* and AbbmvWioM
GA*- Clean Air Act
CWA-Ctoan Water Act
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EPA- US. Envfronmenttl ProtecBon Agency •
-Pedei^ Energy RefluWfiiiyComirtRee ,:! ,.
LNG -Uquefied Natural Gas
MARAD - U.8. Department of TramvortaBon Maritime Admintabatton
MPRSA-MarftwPro«Bctk«,Reseait*,areJSerKituerleaAd
NEPA- National EnvironmemafPoBcy ^Ai* '" ;;
111
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Similariy, Figure 2. provides an overview of EPA's role in permitting requirements
and other considerations.
Figure 2. EPA's role in the LNG
Project Permitting Process
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IV
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The Technical Appendix provides a detailed description of the various requirements
discussed in the Roadmap. To the extent possible, the Technical Appendix attempts to
distinguish how permitting and approval requirements may vary based upon design
characteristics (e.g., the technology used to re-gasify LNG) and the location of associated
activities such as pipeline construction.
The Roadmap and the Technical Appendix are only intended to provide a general sense of
and guidance on the types of information and permit applications that EPA may request
from applicants looking to propose or expand an LNG project. The statutory and
regulatory provisions described in the Roadmap are legally binding. EPA's policies do
not carry such legal weight and are not legally enforceable as indicated by the use of non-
mandatory language, such as, "may/'"should," and "can." The Roadmap is not intended
to replace the need of the regulated community to consult the appropriate statutes and
regulations. Because individual permit and approval requirements are determined on a
project-by-project basis, project operators are strongly encouraged to engage EPA
Regional and Headquarters staff early in the development of their project.
LNG Project Approval and Environmental Review Process
Projects Proposed Offshore in Federal Waters
The Deepwater Port Act5 established an expedited license process for authorizing the
ownership, construction and operation of deepwaterports in United States' waters located
beyond state seaward boundaries. The U.S. Coast Guard (USCG) administers the
licensing processes, though substantive decision-making is delegated to the Maritime
Administration (MARAD), which issues the actual deepwaterport license.
EPA involvement in the licensing and environmental review process for LNG projects
proposed offshore in federal waters generally occurs at the following points:
• USCG regulations require LNG project operators to include applications for other
applicable federal permits when they submit their deepwaterport license
application. This requirement includes relevant EPA permits;
• USCG/MARAD forward deepwaterport license applications to the appropriate
EPA Regional Office for consideration under laws administered by EPA
including the Clean Air Act (CAA), the Clean Water Act (CWA) and the Marine
Protection Research, and Sanctuaries Act (M PRSA). EPA Regional staff have at
least five working days to review the application and determine if the application
is complete in relation to these federal environmental statutes. If EPA determines
that the application is not complete for its purposes, USCGyM ARAD suspends the
review period until the applicant supplies missing inform at ion;
33. US.C. §§ 1501-1524.
33 C.F.R 148J05(z)& (bb); 33 US.C. § 1518(aXI).
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» Within 45 days after the last public hearing on the license app Hcation, the EPA
Administrator is to provide the Secretary of Transportation a recommendation on
whether to approve or disapprove the application and to inform the Secretary if
the deepwaterport will not conform with all applicable provisions of the CAA,
CWA, ortheMPRSA;7
• EPA reviews any prepared Environmental Impact Statement as a cooperating
agency and pursuant to the Agency's responsibilities under Section 309 of the
CAA; and
» EPA is a cooperating agency for Deepwater Port Act LNG projects and must use
the USCG/MARADNEPA document to support any EPA permitting action that
is subject to NEPA (i.e., NPDES permitting).8
Onshore Projects and Projects Proposed in State Waters
Under the Natural Gas Act,9 the Federal Energy Regu latory Commission (FERC) has
jurisdiction over the siting, construction and operation of facilities used to transport
natural gas in interstate commerce and of facilities used for the export or import of
natural gas. This includes LNG projects onshore and in state waters.
EPA involvement in the approval process for LNG projects proposed both onshore and
near shore in state waters generally occurs at the following points:
• LNG Project applicants must comply with FERC's pre-filingprocedures. This
pre-filing process involves agencies working together to develop a single NEPA
document to address each agency's requirements;"
• FERC regulations require applicantsto consult with the ^propriate federal and
state agencies during the planning stages of a proposed project to ensure that all
potential environmental impacts are identified, and to submit applications for all
federal and state approvals as early as possible in the planning process. This
includes applicable EPA issued or approved permits;1
• EPA may serve as a cooperating agency to assist FERC in the preparation of an
Environmental Assessment or Environmental Impact Statement; and
• When FERC prepares an Environmental Impact Statement, EPA reviews and
comments on the document as part of EPA's responsibility under section 309 of
the Clean Air Act.
7 33 U.S.C. § 1504(eX2) and 33 U.S.C. § 1503(cX6).
8 33U.S.C. § 1504(f).
9 15U.S.C. §l\letseq.
10 15 U.S.C. § 717a(l IKdefinition of" LNG temrinal").
" 15 U.S.C. §7l7(n>l(a)& I8C.F.R I57.21(a).
12 18C.F.R. 380.3(bX3)&(4).
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Requirements and Decision Making Related to Air Emissions
The Clean Air Act has requirements for emission limitation and reduction and generally
implements these requirements through permits. To determine the specific requirements
and permits that apply for new LNG projects, the following must be evaluated:
• The project design (e. g., the equipment, fuels, or pollutant-containing materials to
be used at the project);
• The applicable regulations of the nearest adjacent coastal state given the location
of the project, as well as the location of any associated construction activities;
and
• What emissions are part of the stationary source (e.g, whether certain vessel-
based emissions are included) and the size of emissions (e.g., whether the project
is a major source for certain pollutants).
Sources of air emissions from new LNG projects may include, depending on the project
design and applicable law:
• Construction activities;
• Operation of stationary equipment once the project is built; and
• Vessels associated with operation of theproject.
Permitting requirements vary on a project-by-project basis. For this reason, not all LNG
projects appfy for the same permits or are subject to the same requirements. In some
instances, LNG projects may need to appfy for the following permits and consider the
following types of requirements:
» New Source Review Permitting (Prevention of Significant Deterioration,
nonattainment New Source Review, and minor source New Source Review);
« T it le V Op erat ing Perm it s;
» New Source Performance Standards;
» Hazardous Air Pollutant Standards; and
• Other state air regulations (i.e., odor, emergency episode plans).
Projects Offshore in Federal Waters
If the LNG project is located offshore, seaward of state waters, EPA:
• Issues air permits based on the Clean Air Act and the air regulations that would
otherwise be applicable in the nearest adjacent coastal state, as long as the state
or local requirements are applicable and not inconsistent with federal law and the
Deepwater Port Act. (Related onshore construction activities may be permitted
by the state or local control agency, if authorized);
o Depending on the source and its location, EPA may need to identify
technology standards, emissions offsets and complete ambient air quality
analyses.
• Consults ontheMARAD/USCG general conformity analysis, if applicable.
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Onshore Projects and Projects in State Waters
For onshore LNG projects, EPA:
• Issues air permits only in cases where EPA has not delected such authority to the
state or local control agency or approved their permit program into the State
Implementation Plan. This may include any air permits that might be needed
during the construction of associated pipelines; and
• Consults on the FERC general conformity analysis, if applicable.
Requirements Related to Water Quality
During the approval and permitting process for LNG projects that propose to discharge
pollutants into United States' waters, EPA or the authorized state, tribe or U.S. territory
implements applicable Clean Water Act sections that vary depending on where the
discharge occurs. EPA also evaluates whether and how the Marine Protection, Research,
and Sanctuaries Act applies to a project's activities. EPA's regulatory and oversight
actions for LNG projects vary based upon the location and design of an individual LNG
project, as well as associated construction and operational activities.
Permitting requirements vary on a project-by-project basis. For this reason, not all LNG
projects epply forthe same permits or are subject to the same requirements. In some
instances, LNG facilities may need to comply with the follow ing types of requirements:
• National Pollutant Discharge Elimination System Program (NPDES) permitting,
which may include:
o Effluent limitations for discharged pollutants, both forprocess wastewater
and for storm water associated with industrial activity, based on:
• Techno logy-based standards that vary according to pollutant
• Applicable water quality standards, including state water quality
certification
• Ocean discharge criteria
o Cooling water intake requirements;
• Requirements that appty to the disposition of dredged or fill material; and
• Oil spill prevention.
Projects Offshore in Federal Waters
For projects located offshore in federal waters, EPA:
• Serves as the NPDES permitting authority for discharges of pollutants from a
point source into waters ofthe United States and identifies technology-based and
water quality-based limits and conditions based on best professional judgment;
• Issues NPDES storm water discharge permits for discharges associated with
industrial activity where industrial activity and materials are not sheltered to
prevent exposure to storm water; and
• Evaluates the potential effects of discharge on the marine environment during
NPDES permit review under the provisions of Clean Water Act section 403.
VIII
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Onshore Projects and Projects in State Waters
For onshore and near shore projects, EPA:
• Serves as the NPDES permitting authority onty if a state, tribe or U.S. territory is
not authorized to do so. In such instances, EPA develops permit conditions for
near shore projects based on best professional judgment;
• Issues NPDES permits for storm water discharges associated with industrial
activity, including construction activity, under either a general permit or an
individual NPDES permit (when EPA is the NPDES permitting authority);
» Maintains a regulatory and enforcement role for oil spill prevention activities
under Clean Water Act section 311 for onshore and near shore non-transportation
related facilities landward of the coastline. EPA generally has primary
enforcement authority for inland oil spills; and
• Issues a Clean Water Act section 401 certification if the relevant state ortribe
does not have authority to do so.
Projects that involve dredging and dumping of materials in water
EPA maintains an oversight role in the regulation of certain dredging activities and
dumping of materials in ocean waters. However, the Agency's involvement varies based
upon the type and location of the activity. EPA generally will become involved in the
following instances:
• The U.S. Army Coips of Engineers (Corps) issues aMarine Protection, Research,
and Sanctuaries Act section 103 permit for the disposal of dredged material into
the territorial sea using EPA's environmental criteria and subject to EPA's
concurrence;
• The Corps issues a Clean Water Act section 404 permit for the discharge of
dredged material into waters of the United States that lie inland from the baseline.
The discharge of dredged material into the territorial sea for the primary purpose
of fill is also evaluated in accordance with Clean Water Act section 404. EPA
comments on these permits and can elevate concerns through a formal dispute
resolution process and has the authority to veto section 404 permits;
• EPA may issue permits forthe dumping of materials (other than dredged
materials) seaward of the territorial seas (3 nautical miles) pursuant to section 102
of the Marine Protection, Research, and Sanctuaries Act; and/or
• The Corps issues a permit under section 10 of the Rivers and Harbors Act to
regulate activities that affect navigation in all domestic waters. EPA comments
on these permits as part of the public interest review process and can elevate
specific concerns through a formal dispute resolution process.
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Other Permitting Requirements and Considerations
Hazardous Waste Generation
Operators may be subject to federal hazardous waste generator regulations. In some
cases, EPA may serve as the permitting authority under the Resource Conservation and
Recovery Act.
Emergency Response
The Comprehensive Environmental Response, Compensation, and Liability Act
(CERCLA) better known as the "Superfund Act," addresses cleanup of hazardous
substances. CERCLA and its implementation documents empower EPA and other
agencies to identify and prioritize sites for cleanup, and to order or carry out
environmental remediation.
En vironmen tal Justice
Parties intending to operate LNG projects may wish to consider whether or not their
proposed actions present environmental justice issues before they submit their permit
applications to EPA.
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LNG Regulatory Roadmap Technical Appendix
Overview
The Technical Appendix is divided into several sections that outline areas where EPA
engages in permitting and approval processes for proposed LNG projects. First, the
Technical Appendix provides a more comprehensive overview of EPA's role in the
approval and environmental review of LNG projects. The Technical Appendix discusses
the stautes governing the approval and environmental review of these projects, specifically
the National Environmental Policy Act (NEPA), as well as the Deep water Port Act (DPA)
and the Natural Gas Act (NGA), which are administered primarily by the Department of
Transportiion (via the Maritime Administration) and the U.S. Coast Guard and the Federal
Energy Regulatory Commission, respectively.
Next, the Technical Appendix turns to EPA's role in the implementation of relevant
provisions of the Clean Air Act (CAA), the Clean Water Act (CWA) and the Marine
Protection, Research, and Sanctuaries Act (MPRSA). Because states implement some
provisions ofthese federal laws, the Technical Appendix also describes the role of states
under these statutes.
Finally, the Technical Appendix discusses other EPA permitting requirements and
considerations, including federal hazardous waste generator regulations, hazardous
substance release regulations and environmental justice.
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Table of Contents
LNG Project Approval and Environmental Review Process 12
General Overview- The National En vironmental Policy Act 12
Projects OffshoK in Federal Waters. 13
Onshore Projects and Projects in State Waters 16
Requirements and Decision Making Related to Air Emissions 16
General Overview- The Clean Air Act. . 17
NewSource Review (NSR) PermittingOverview 18
Titk V Operating Permits. 19
NewSource Performance Standards. 20
CAA Section 112 Hazardous Air Pollutant Standards 21
CAA Section 176(c) General Conformity 21
Requirements Related to Water Quality 22
National Pollutant Discharge Elimination System Permit Program. 22
Effluent Limitations for Discharged Pollutants. 23
Technology-Based Effluent Limits 24
State Water Quality Standards. 25
Ocean Discharge Catena. 25
Cooling Water Intakes. ..25
Storm Water Discharges Associated with Industrial Activity. 26
Permitting for Dredged or Fill Material. 27
Regulation of Ocean Dumping, .28
Discharges Affecting Navigation. 29
Disposition of Solid Materials in United States' Waters Generally. 30
Oil Spill Prevention 30
State Water Quality CertiScatioo of Certain Federal Licenses or Permits 31
Other EPA permitting requirements and considerations 31
Resource Conservation and Recovery Act. 32
Comprehensive Environmental Response, Compensation, and Liability Act 34
Environmental Justice. 34
Appendix A: Acronyms and Abbreviations. 36
LNG Project Approval and Environmental Review Process
General Overview- The National Environmental Policy Act
The National Environmental Policy Act of 1969 (NEPA), 42 U.S.C. 4321- 4347,
establishes the national policy forprotection ofthe environment. Section 102(2)(C) of
NEPA requires federal agencies to prepare a ''detailed statement" for proposed major
actions which significantly affect the quality ofthe human environment. The statement
must include the environmental impacts ofthe proposed action, alternatives to theproposed
action, and any adverse environmental impacts that cannot be avoided should the proposal
12
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be implemented. NEPA also provides for public participation in the development of both
the scope of review and NEPA documents. 42 U.S.C. § 4332(2)(C).
Under Clean Air Act section 309, EPA reviews and comments on the environmental
impacts of various actions of other federal agencies, including all actions subject to the
NEPA requirement to prepare an Environmental Impact Statement (EIS). EPA comments
in writing and makes its comments available to the public. If EPA determines that the
action is unsatisfactory from the standpoint of public health or welfare or env ironmental
quality, EPA refers the matter to the Presidents Council on Environmental Quality.
Projects Offshore in Federal Waters
The Deepwaer Port Act, 33 U.S.C. § § 1501 - 1524 (DPA), established an expedited
licensing process for authorizing the ownership, construction, and operation of deepwater
ports in United States' waters located beyond state seaward boundaries. Congress enacted
the DPA for several reasons, including:
• Authorizing and regulating "the location, ownership, construction, and operation of
deep water ports beyond the territorial limits of the United States";
• Promoting "the construction and operation of deepwater ports as a safe and
effective means of import ing crude oil and natural gas into the United States while
minimizing tanker traffic and risks attendant thereto"; and
• Providing "for the protection of the marine and coastal environment to prevent or
minimize any adverse impact which might occur as a consequence of the
development of such ports." 33 U.S.C. § 1501(a).
The authority to issue a deepwater port license was given to the Secretary of
Transportation. The DPA defines a "deep water port" for natural gas to mean "any fixed
or floating manmade structure other than a vessel, or any g-oup of such structures,... used
or intended for use as a port orterminal for the transportation, storage, or further handling
of natural gas for transportation to any State,... include[ing] all components and
equipment, including pipelines, pumping or compressor stations, service platforms, buoys,
mooring lines, and similar facilities that are proposed or approved for construction and
operation as part of a deepwater port, to the extent th£ they are located seaward of the
high water mark and do not include interconnecting facilities." 33 U.S.C. § 1502(9). A
deep water port is deemed to be a "new source" for purposes of the Clean Air Act (CAA)
and Clean Water Act (CWA). Id.
The DPA established a total timeframe of 356 days from the receipt of a complete license
application to complete the deepwater port licensing process, although the "clock" may be
suspended due to outstanding information needs or if requested by the applicant. The
license application process is administered jointly between MARAD and the U.S. Coast
Guard (USCG), with M ARAD primarily responsible for project financial reviews and the
USCG primarily responsible for project engineering, operations, safety, and environmental
13
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reviews, which include compliance with NEPA.13 EPA permit actions are not subject to
the time constraints ofthe Deepwater Port Act, but should be completed in time to avoid
delay of a deepwater port's construction and operation.
The DPA requires the Secretary of Transportation, in cooperation with other involved
Federal agencies and departments, to comply with NEPA as part ofthe licensing process.
33 U.S.C. § 1504(f). The DPA also states that the Secretary's NEPA compliance fulfills
the requirements of all Federal agencies in carrying out their responsibilities under NEPA.
Id.
Under the DPA, the Secretary of Transportation also designates "adjacent coastal State[s]",
whose Governor has an opportunity review and approve the license. The DPA defines an
adjacent coastal state as "any coastal state which ... would be directly connected by
pipeline to a deepwater port ..., would be located within 15 miles of any such proposed
deep water port, orthat is so designated by the Secretary." 33 U.S.C. § 1502(1). States also
may request designation as an adjacent coastal state. In addition, the DPA declares that the
law ofthe nearest adjacent coastal state, whose seaward boundaries, if extended beyond
three miles, would encompass the site ofthe deepwaterport, is the law ofthe United States
and applies to a deepwaterport tothe extent applicable and not inconsistent with federal
law. 33 U.S.C. § 1518(b). There is only one "nearest" adjacent coastal state for a DPA
license applicant. EPA's actions may be affected by the "federalized" law ofthe nearest
adjacent coastal state.
On May 20, 2004, the White House Task Force on Energy Project Streamlining distributed
a Memorandum of Understanding (MOU) Related tothe Licensing of Deepwater Ports.14
ThisMOU was signed by ten participating agencies, with responsibilities related to the
licensing of deepwater ports, including EPA. The MOU specifies agency responsibilities
and establishes an important coordination mechanism to ensure timely and efficient review
of deepwater port licenses.
The USCG/MARAD has 21 days from receipt of a deepwaterport license application to
determine whether or not it is complete. 33 U.S.C. § 1504(c)(l). A complete deepwater
port license application must contain all applications for federal authorizations that are
required for ownership, construction and operation of a deepwater port. 33 U.S.C.
1504(c)(2)(J)&(L) & 33 C.F.R. 148.105. This requirement includes relevant EPA permits.
33 C.F.R. 148.105(z)&(bb) & 33 U.S.C. §1518(a)(l). Once USCG/MARAD receives a
DPA license application it forwards a copy(s) ofthe application to other responsible federal
agencies, includingthe appropriate EPA Region, for a completeness review. EPA reviews
the application for completeness under laws administered by EPA, including the CAA,
CWA, and Marine Protection, Research, and Sanctuaries Act (MPRSA). UndertheMOU,
EPA Regional staff has at least five working days to review the application and determine
if it is complete. If the license application is incomplete from EPA's perspective, EPA
13 Seethe Memorandum of Understanding for inter-agency coordination on licensing of Deepwater Ports
www.ett'energy.gov/Dd fe/DPA MOU.pdf. The Secretary of DOT delegated in 49 C.F.R. I46(s)to the
USCG authority to process applications for licenses under the DPA.
vvww.ett'energy.gov/nd fe/DPA MOU. pdf.
14
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notifies the USCG/MARAD by letter of the missing information. In such cases, the
USCG/MARAD suspends the running of the review period until the applicant supplies the
missing information.
Under the DPA, Federal agencies, including EPA, must review DPA license applications
and, within 45 days after the last public hearing on the proposed action, provide a
recommendation to the Secretary of Transportation to approve or disapprove the
application. 33 U.S.C. § 1504(e)(2). A recommendation to disapprove the application
must include a description of why the application does not comply with the laws and
regulations the agency administers and any conditions or amendments necessary so that the
application will comply. Id. Similarly, the Secretary cannot issue a DPA license unless the
Governor of each adjacent coastal State approves, or is presumed to approve, the license.
33 U.S.C. 1503(c)(8). A Governor must transmit his/her approval or disapproval to the
Secretary no later than 45 days after the last public hearing on the license application. 33
U.S.C. § 1508(b)(l). If a governor fails to transmit his/her approval or disapproval within
this time frame, approval is conclusively presumed. Id. Finally, the Secretary may not
issue the license if the EPA Administrator informs the Secretary within 45 days of the last
public hearing on the proposed license "that the deepwater port will not conform with all
applicable provisions" of the CAA, CWA, or theMPRSA. 33 U.S.C. § 1503(c)(6).
The issuance of an EPA National Pollutant Discharge Elimination system (NPDES) permit
pursuant to section 402 of the CWA for a deepwaterport requires supporting N EPA
documentation because the DPA deems a deepwater port to be a "new source." s Under
the DPA the NEPA review conducted by the USCG/M ARAD fulfills the NEPA
requirements for all Federal agencies, including EPA. 33 U.S.C. § 1504(f). Therefore,
EPA is a cooperating agency for DPA projects and uses the USCG/MARAD NEPA
document to support its NPDES permit action. The EPA Regional NEPA compliance staff
coordinates with USCG/MARAD to ensure that the NEPA document for the project has the
necessary information and analysis to support the decision on the NPDES permit. EPA
may sign on to the USCG/MARAD Record of Decision (ROD) or Finding of No
Significant Impact (FONSI), but more typically issues its own NEPA ROD or FONSI.
EPA also could use the permit as the ROD, providing the permit contains all the
information a ROD would contain.
In addition, EPA reviews and comments on EISs prepared by USCG/MARAD underthe
authority of section 309 of the CAA.
DPA licenses also may be subject to other federal environmental statutes (e.g., Endangered
Species Act, Coastal Zone Management Act, Magnuson Stevens Fishery Conservation and
Management Act, and National Historic Preservation Act).
15 Generally, most EPA actions under the CWA are exempt from NEPA. 33 U.S.C. § 1371(c). EPA actions
under the CAA also are exempt from NEPA. 15 U.S.C. § 793(cXl).
15
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Onshore Projects and Projects in State Waters
Under the Natural Gas Act (NGA) 15 U.S.C. § 717 et seq., the Federal Energy Regulatory
Commission (FERC) has jurisdiction over the siting, construction and operation of
facilities used to transport natural gas in interstate commerce and of facilities used for the
export or import of natural gas, which includes LNG projects onshore and in state waters.
FERC also has jurisdiction over the pipeline portion of a deep water port that is located
landward of the high water mark and over interconnecting facilities, which are not part of
the deep water port.16 With respect to approvals of these projects, the Energy Policy Act of
2005 designated FERC as the lead agency for puiposes of coordinating all applicable
federal authorizations and for thepurposes of complying with NEPA. Underthis authority,
FERC establishes the schedule for all Federal authorizations and sets deadlines, and
maintains a complete consolidated record of all administrative decisions made with respect
to any federal authorization.
17
LNG project applicants must comply with FERC's pre-filing procedures. 15 U.S.C.
§717(b)-l(a) & 18 C.F.R. 157.21(a). This pre-filing process involves agencies working
together to develop a single NEPA document to address each agency's requirements.18
FERC's NEPA regulations require applicants to "[c]onsul with the appropriate Federal,
regional, State and local agencies during the planning stages of the proposed action to
ensure that all potential environmental impacts are identified" and to "submit applications
for all Federal and State approvals as early as possible in the planning process." 18 C.F.R.
380(b)(3)&(4). This would include applicable EPA permits.
Once an application has been filed, FERC prepares either an environmental assessment
(EA) or an EIS to fulfill its obligations under NEPA. When appropriate, EPA can serve as
a coop crating agency to assist FERC in the preparation of an EA or EIS. When FERC
prepares an EIS, EPA reviews and comments on the document as part of EPA's
responsibility under section 309 of the CAA.
Unlike deepwater ports, onshore projects are not considered "new sources," under the
CWA. Therefore, under CWA section 51 l(c), the issuance of any required NPDES permit
is exempt from NEPA's EIS requirement.
In addition, NGA licenses also may be subject to other federal environmental statutes (e.g.,
Endangered Species Act, Coastal Zone Management Act, Magnuson Stevens Fishery
Conservation and Management Act, and National Historic Preservation Act).
Requirements and Decision Making Related to Air Emissions
This section of the Technical Appendix presents an overview of the potentially applicable
sections of the Clean Air Act (CAA) and associated EPA regulations. In addition, this
16
See 33 U.S.C. 150(t>X9XC).
17 Energy Policy Act of2005. Pub. L. No. 109-58 Sec. 313 which amended 15 U.S.C. 717n.
18 For more information on theFERC pre-filing process see fere.gov/help/process es/flow/Ine-1.asp
16
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section includes a discussion of EPA's role in the air permitting (and oversight of
permitting) of offshore, near shore and onshore projects.
General Overview- The Clean Air Act
Important provisions of the CAA include regulation of criteria pollutants and hazardous air
pollutants through emission limitations and standards, often including requirements for
emission control equipment and the requirement that each state have a state implementation
plan (SIP). A SIP contains additional state-specific measures that provide for the
attainment and maintenance of the national primary and secondary ambient air quality
standards. Additional provisions central to the CAA are requirements that new sources
apply for, and obtain, permits to construct before start ing construct ion and that major
sources, and certain non-major sources, obtain a title V operating permit. Operators of
prospective LNG projects should contact the appropriate air permitting agencies, including
their EPA Regional Office and EPA Headquarters, early in the project planning phase in
order to discuss air permitting requirements.
CAA permitting requirements vary based on the design of the project and its location. For
new LNG projects, factors that come into play include the project design (e.g., process and
fuel burn ing select ion; air emissions levels), which could determine whether permits are
needed and, if so, what emissions are part of the stationary source (e.g., whether certain
vessel-based emissions are included). In addition, some state (or nearest coastal state)
requirements may apply to LNG projects located in federal waters and these state
requirements may be more stringent than, or in addition to, federal requirements.
Depending on the project design and applicable law, sources of air emissions from new
LNG projects may include: construction activities, operation of stationary equipment once
the project is built, and vessels associated with operation of theproject. An LNG project
may emit many different air pollutants, includingnitrogen oxides (NOx), paniculate matter
(PM), volatile organic compounds (VOC), sulfur dioxide (802), carbon monoxide (CO),
and hazardous air pollutants (HAP).
If the LNG project is located offshore, seaward of state waters, the DPA requires that the
project receive applicable air permits from EPA. For these deepwater ports, EPA issues the
air permits based on the CAA and the air regulations that would otherwise be applicable in
the nearest adjacent coastal state, as long as the state or local requirements are applicable
and not inconsistent with federal law and the DPA. However, state or local control
agencies (if they have EPA-approved permitting programs) would issue any required air
permits for emissions that occur within state boundaries, such as any onshore associated
construction activities. These activities may include the construction of offshore projects
that are assembled on land or the modification or installation of new pipelines.
For onshore LNG projects, as well as those located in state waters, the states or local air
control agencies issue the applicable CAA permits (unless EPA has not delegated or
otherwise approved a state program for them in which case EPA will issue the permits).
The suite of required permits will vary, depending on the design of the project, the air
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quality status ofthe area, and the amounts of different air pollutants to be emitted. States
and local control agencies with authority for issuing federally-required construction and
operating permits would also be responsible for issuing any air permits that might be
needed to authorize construction and operation of associated pipelines in areas of state
jurisdiction.
Ne w Source Re vie w(NSR) Permitting O ver vie w
The CAA requires each state to have an EPA-approved SIP for the attainment and
maintenance ofthe national primary and secondary ambient air quality standards.19 Section
110 ofthe Act requires that each SIP include a program to regulate the construction and
modification of any stdionary source within the area covered by the plan as necessary to
ensure that the National Ambient Air Quality Standards (NAAQS) are achieved and
maintained. Pursuant to this requirement, the owners or operators of stationary sources of
air pollution, including new LNG projects, (and associated ppelines) must generally obtain
air permits before commencing construction.
This air permitting process is called New Source Review (NSR). The overall NSR
program is divided into three separate permitting programs - Prevention of Significant
Deterioration (PSD), nonattainment NSR, and minor source N SR - depending on the
proposed quantity of air emissions and location ofthe source. The PSD program applies to
new "major sources" and "major modifications" at existing major sources for pollutants
where the area is in attainment with or unclassifiable with respect to the NAAQS.
Nonattainment NSR applies to new "major sources" or "major modifications" at existing
major sources for pollutants where the area is not in attainment with the NAAQS. Minor
NSR requirements apply to nonmajor stationary sources (and, in some cases, to major
sources) and vary from state to state. An existing minor source wil 1 trigger NSR if it
undertakes a modification that in itself exceeds the major source threshold or if the source
requests a relaxation of a limit that was set to ensure thct the source would not trigger NSR.
40 C.F.R. 52.21 (r)(4).
The construction permitting programs for "major" sources are the PSD program (Title I,
Part C ofthe CAA) and the nonattainment NSR program (Title I, Part D ofthe CAA). For
each criteria pollutant (i.e., ozone, SO2, PM, lead, NO2, and CO), the applicable permitting
program is determined by the air quality designation ofthe area in which the source is
located. Because air quality designations are made on a pollutant-specific basis, a source
may simultaneously be in an attainment area for one or more pollutants and in a
nonattainment area for other pollutants. Each program has different requirements and
different thresholds (in terms of a facility's annual emissions) at which they become
applicable. The major source threshold is the emission rate at which the program becomes
app licable to the source. M ajor source thresholds for the PSD program vary depending on
the type ofthe source. The major source threshold for the federal nonattainment NSR
program may also vary depending on the pollutant and severity of nonatainment in a given
19 CAA § Il0(a).
20 See CAA §§ 110(aX2XC), 165, and 172(cX5).
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area. State PSD and nonattainment NSR programs approved intothe SIP may contain
lower major source emission thresholds.
In general, new LNG projects are subject to PSD if they propose to exceed the major
source threshold for any PSD regulated air pollutant. If PSD applies, then LNG projects
must: install the best available control technology (BACT) to reduce air emissions; model
compliance with air quality standards and PSD increments; evaluate impacts on Class I
areas (e.g., certain designated parks or wilderness areas); and address impacts on soils,
vegetation, and visibility.21 Proposed permits are subject to public notice and comment as
well as opportunity for public hearing.
If nonattainment NSR applies and the new LNG project will be a "major" source, the
project must emit the nonattainment pollutant (or precursors) at or below the "lowest
achievable emissions rate" (LAER), as well as "offset" these proposed emissions with
actual reductions in exist ing emissions (e.g., by installing emissions controls on existing air
emission sources).22 Like PSD permits, proposed nonattainment NSR permits are subject
to public notice and public comment as well as opportunity for public hearing.
A "minor" construction permit is needed if the proposed LNG project has the potential to
emit air pollutants in amounts below "major" source thresholds. Minor NSRpermit
requirements vary by state but generally prevent the construction of sources that would
interfere with attainment or maintenance of the NAAQS or violate a control strategy.
States are able to customize the requirements of their minor NSR programs as long as they
meet certain minimum requirements. Minor source requirements of some states include:
requirements that minor sources install BACT, limitations on sulfur content in fuels, and
emission limits based on process throughput.
Title V Opera ting Permits
Title V of the CAA requires "major sources" under any definition of the CAA to obtain an
operating permit. As with the NSR permitting program, the term "major source" is defined
differently for different criteria pollutants and varies according to the air quality
classification of the area where it is located. A major source for NSR purposes will also be
a major source for title V purposes. In addition, sources that are minor NSR sources may
still be subject to the title V permitting requirements. While it is possible that an LNG
project will not be subject to title V permitting requirements, to date all proposed LNG
facilities have been or will be subject to the title V permitting requirements.
A new LNG project that is required to get a title V permit will be issued either a state
operating permit pursuant to part 70 or a federal operating permit pursuant to part 71 and
title V.23 A part 70 operating permit program is implemented by a state, local, tribal, or
territorial air permitting control authority, based on state-adopted regulations that EPA
approves as meeting the requirements of its part 70 rules. Apart 71 op crating perm it
23
40 C.F.R. 5121; see also 40 C.F.R. 51.166 (requirements fcr state PSD programs).
CAA § 173.
State operating permits will vary and may include permits other than Title V permits.
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program is implemented by EPA or a delegated agency, based on the federal part 71 rules,
where a part 70 program is not in place (because one was never approved or one was
approved but EPA found 'A to be deficient), or because the source is located on the Outer
Continental Shelf (OCS) or in Indian county, where stie or local agencies do not have
jurisdiction. In addition, the federal government is the permitting authority under the DPA
and issues a federal operating permit pursuant to title V, but the federal government applies
the laws of the nearest adjacent coastal state to determine which clean air requirements are
applicable to the source.
A new LNG project will generally have up to one year from commencing operation before
it is required to submit a complete title V operating permit application (applicants should
contact their EPA Regional Office for more information on application submittal dates).
Once submitted, the permitting agency has 18 months to review it, request additional
information, if needed, and complete the administrative process necessary to issue a final
permit. The process for issuing the permit includes public notice, a 30-day public comment
period and notification to neighbor ing states (generally those within 50 miles; called
"affected states") that could be affected by the LNG project, and may include a public
hearing. If a state is issuing the permit (such as for an onshore LNG project when the state
has an approved title V program), EPA has a 45-day opportunity to review and object to
any proposedpart 70 permit. If EPA does not object tothe permit (it is not necessary for
EPA to concur), the state may issue the permit and the public has 60 days in which to
petition EPA to object. This 60-day period begins at the end of EPA's review period.24
Operating permits are issued for a five year term (or less if the permitting authority so
chooses). Generally, a source must apply for a renewed permit at least 6 months before the
permit expires.25 The permit renewal process is the same as the issuance process.
Title V and parts 70 and 71 also require all sources, including new LNG projects, to pay
annual fees to the permitting authority. Part 71 fees are based on the source's actual
emissions, while part 70 fees may be set on any basis (including emissions, source
category, actual processing costs, or any combination of these).
Ne wSource Performance Standards
The NSPS established under CAA section 111 and 40 C.F.R. Part 60 apply to new,
reconstructed, or modified equipment used in specific source categories. In general,
emissions units at new LNG projects that may be subject to NSPS include storage vessels
for volatile organic liquids and steam generating units.
NSPS Subpart Kb, 40 C.F.R. 60.1 lOb - 60.117b, applies to new vessels that store volatile
organic liquids if their capacity is greater than or equal to 40 m3 (10,567 gallons, though
the NSPS regulations contain several exemptions). The subpart, however, does not apply
to vessels tha have a capacity greater than 151m (39,890 gallons) and that store a liquid
with a maximum true vapor pressure less than 3.5 kPa (0.5 psia). Section 60.11 Ib defines
a volatile organic liquid as "any organic liquid which can emit volatile organic compounds
2440C.F.R. 7Q8(d)
25 40 CF.R. 70.5(aXlXi") and 40 C.F.R. 71.5(aXl)(iii).
20
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(as defined in 40 C.F.R. 51,100) into the atmosphere." 40 C.F.R. 51.100(s)(l) excludes
methane from the definition of volatile organic compound. If LNG storage tanks store
methane and do not store volatile organic liquids, they are not considered affected facilities
for the purposes of this NSPS.
NSPS Subpart Db (40 C.F.R. 60.40b(a)) applies to steam gen crating units that commence
construction, modification, or reconstruction after June 19,1984, and that have a heat input
capacity of greater than 100 MMBtu/hr. Section 60.4 Ib defines a "steam generating unit"
as:
a device that combusts any fuel or byproduct/ waste to
produce steam or to heat water or any other heat transfer
medium. This term includes any municipal- type solid waste
incinerator with a heat recovery steam generating unit or any
steam general ing unit that combusts fuel and is part of a
cogeneration system or a combined cycle system. This term
does not include process heaters as they are defined in this
subpart.
Depending on the project's design, fuel burning units at LNG projects may not be
considered steam gen crating units, and if so then Subpart Db does not apply. ANSPS
determination, if applicable, for an individual LNG project will based upon information
submitted in thepermit application.
CAA Section 112 Hazardous Air Pollutant Standards
Pursuant to CAA section 112, EPA has not issued any National Emission Standard for
Hazardous Air Pollutants (i.e., Maximum Achievable Control Technology standards) for
LNG projects. However, states or local air control agencies may have applicable hazardous
air pollutant standards (HAP). Theseprograms vary from state to state and typically limit
hazardous or toxic air emissions to specified ambient thresholds.
CAA Section 176(c) General Conformity
Section 176(c) of the CAA prohibits Federal entities from taking actions in nonattainment
or maintenance areas that do not conform to the applicable implementation plan for the
attainment or maintenance of the NAAQS. The purpose of conformity is to ensure federal
actions do not interfere with a plan's attainment or maintenance of such standards. A
general conformity analysis is required for all federal actions unless otherwise exempt (
e.g.. actions covered by transportation conformity, actions with clearly de minimis
emissions, exempt actions listed in rule, or actions covered by an agency's own presumed
to conform list). Some emissions are excluded from a conformity determination, such as
those already subject to new source review; those that are riot reasonably foreseeable, and
those indirect emissions for which the federal entity has no continuing program
responsibility. A federal agency can demonstrate conformity under EPA's implementing
regulation, 40 C.F.R. Part 93, in a number of ways, including; (1) showing emission
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increases are already included in SIP; (2) obtain ing an agreement from a state to include
increases in a SIP; (3) model ing which shows that there will not be any new violations of
the NAAQS and/or no increase in the frequency/severity of existing violations; or (4)
offsets.
For deep water ports, MARAD/USCG completes the general conformity analysis, if
applicable, in consultation with the relevant state, and EPA provides comments on a draft
conformity determination. For onshore and near shore projects, FERC is responsible for
the general conformity analysis. For dredging projects, the USCG may do a separate
analysis.
Requirements Related to Water Quality
For any LNG project that involves the discharge of pollutants into waters of the United
States, including the territorial seas, or the contiguous zone or ocean, 6 EPA and, in some
cases, a state, tribe or U.S. territory, administers applicable Clean Water Act (CWA)
sections. EPA also evaluates whether and how the Marine Protection, Research, and
Sanctuaries Act (MPRSA) applies to a project's activities. EPA's regulatory and oversight
actions for LNG projects varies based upon the location and design of an individual LNG
project as well as associated construction and operational activities.
This section of the Technical Appendix presents an overview of potentially applicable
sections of the CWA and MPRSA (and associated EPA regulations), and briefly discusses
how these sections would apply for offshore projects and then for onshore and near shore
projects. This section also briefly discusses requirements for associated activities that
operators may need to consider that may take place at the location of the proposed project
or at a remote location. Prospective LNG project operators are encouraged to contact the
appropriate water permitting agencies, including the EPA Regional Office and EPA
Headquarters, very early in the project planning phase to discuss water quality-related
p ermitt ing requirem ents.
National Pollutant Discharge fJimination System Permit Program
Under the CWA, the dischargers of pollutants from any point source into waters ofthe
United States, including the territorial seas, are required to obtain an National Pollutant
Discharge Elimination System (NPDES) permit. Section 402 ofthe CWA establishes the
NPDES permitting program. The NPDES permit program also applies to any point source,
other than a vessel or floating craft, in the marine waters more than three nautical miles
from shore. Under EPA regulations at 40 C.F.R. 122.3(a), this exclusion for vessels and
other floating craft does not apply to discharges when the vessel is operating in a capacity
other than as a means of transportation, such as an energy facility or when secured to the
26 Waters beyond the territorial seas include the"contiguous zone" and "ocean". See CWA § 502 (9) & (10).
See also Presidential Proclamation 5030 (March 10, 1983) (Exclusive Economic Zone ofthe United States of
America).
27 See CWA §§ 301 (a) & 402(a).
28 See CWA § 502 (12) (definition of discharge ofa pollutant").
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bed of the ocean, contiguous zone, or waters of the United States forthepurpose of energy
development. In most cases, the NPDES permit program is administered by authorized
states2 or tribes, which are responsible for permitting discharges to state waters.30 EPA
issues all CWA section 402 NPDES permits for the discharges in marine waters more than
three miles from shore. NPDES permits are issued for a period of five years.
The NPDES permit includes limits on pollutants that represent application of various
technology-based standards, and any more stringent limits necessary to meet applicable
water quality standards. In addition, no NPDES permit authorizing a discharge into the
territorial sea, contiguous zone, or ocean can be issued except in compliance with EPA's
ocean discharge criteria. 33 U.S.C. § 1343(a). NPDES permits also regulate the location,
design, construction, and capacity of cooling water intake structures to minimize adverse
environmental impact. 33 U.S.C. § 1326(b). Finally, NPDES permits appfy to discharges
that are continuous and/or periodic, and regardless of whether the discharge results from an
industrial process or results from exposure of industrial activities and materials to
precipitation.
Accordingto NPDES regulations, "[t]echnology-based treatment requirements under
section 301 (b) of the Act represent the minimum level of control that must be imposed in
[an] NPDES permit." 40 C.F.R. 125.3(a). Technology-based limits are based on: national
regulations applicable to specific industrial point source categories; the "best professional
judgment" (BPJ) of the permit wrier if EPA has not established industry-wide regulations;
or a combination of the two methods when the nationally-applicable regulations apply only
to certain aspects of the discharger's operation or to certain pollutants. 40 CF .R. 125.3(c).
In deriving BPJ limits, thepermit writer considers: (1) the appropriate technology for the
category or class of point sources of which thepermit applicant is a member, based on all
available information, and (2) any unique factors relating to the applicant. EPA's
regulations require the statutory factors from CWA section 304(b)to be considered by
permit writers in setting case-specific limitations, as well as "factors unique to the
applicant." 40 C.F.R. 125.3(d)(3) & (c)(2)(ii). In addition, certain permit conditions apply
to all NPDES permits. 40 C.F.R. 122.41.
Effluent Limitations for Discharged Pollutants
CWA section 301(b) specifies the type of technology-based limitations applicable to
different types of pollutants that may be discharged. Conventional pollutants include
biochemical oxygen demand measured over five days (BOD5), total suspended solids
(TSS), fecal coliform, pH, and oil and grease. Toxic pollutants, including 126 "priority
pollutants," are listed in the regulations at 40 C.F.R. Part 423, Appendix A. All other
pollutants are "non-conventional" pollutants. The technology-based standards in section
301(b) vary depending on whether the relevant pollutants are conventional pollutants or
non-conventional pollutants and toxic pollutants (e.g., best practicable control technology
currently available (BPT) for all pollutants, best conventional pollutant control technology
29
30
cfoub.epa.gov/rmtics/stalesl'dt.s.c
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(BCT) for conventional pollutants, and best available technology economically achievable
(BAT) fortoxics and non-conventional pollutants).
In addition, for any pollutant, section 301(b)(l)(C) requires "any more stringent limitation
necessary" to meet water quality standards, which typically are issued by states and
submitted to EPA for approval (see discussion below of state water quality standards).
Technology-Based Effluen t Limits
Section 304(b) describes the relevant factors EPA considers in establishing the limitations
under the CWA's technology-based standards. Section 304(b) directs EPA to establish
regulations, commonly referred to as national effluent limitations guidelines (ELGs) that
establish nationally-applicable effluent limitations that reflect the pollutant reductions
attainable for a particular industrial point source category according to the CWA's
technology-based standards that vary depending on the pollutant parameter of concern.
Under the BAT standard, EPA considers: age of equipment and facilities involved; process
employed; engineering aspects ofthe application of various types of control techniques;
process changes; cost of achieving effluent reduction; non-water quality environmental
impact (including energy requirements); and such other factors as the Administrator deems
appropriate. ELGs are technology-based, meaning they apply regardless of receiving water
quality needs.
When identify ing techno logy-based BPJ permit conditions for offshore projects, EPA takes
into consideration the various available technology options. Open Rack Vaporization
(ORV) uses surrounding seawater at ambient temperature to heat and re-gasify LNG.
Submerged Combustion Vaporization (SCV) systems burn a portion ofthe re-gasified
natural gas product to re-heat warming water. Intermediate Fluid Vaporization (IFV)
systems, or "shell and tube" can operate in open or closed loop cycles.
Specific permitting conditions for projects employ ing closed loop technology (e.g., SCV
and IFV operating in a closed loop cycle) will vary by permit but conditions may be
established for the follow ing types of discharges: process-related discharges (e.g., periodic
blowdown from re-gasification equipment, non contact cooling water used in a ship's
electrical system to power the re-gasification system; anti-fouling additives and biocide
agents).
For projects designed to use open loop technologies (e.g., ORV and IFV systems operating
in an open loop mode), permit conditions may be established for process-related discharges
(e.g., thermal effects, anti-fouling additives and biocide agents) and intake-related solids
discharges (i.e., discharges of organisms through the system) as well as discharges related
to general operation (e.g., periodic blowdown from re-gasification equipment and non-
contact cooling water). Federal regulations require that deepwater port license applications
must include, to the extent available, information for the project's NPDES permit. If
complete information is not available by the time M ARAD must either approve or deny the
application, the license for the deepwater port is conditioned upon the applicant receiving
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1200 Pennsylvania Avenue, NW
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the required discharge permit from EPA before any discharge; activity that would require
such a permit can occur. 33 C.F.R. 148.105(z).
For near shore projects, authorized states must establish BPJ permit conditions similar to
those discussed previously for offshore facilities, assuming the project would have a direct
discharge to surface waters at all. Onshore projects typically employ closed loop re-
gasification technologies, which result in discharges of only non-contact blowdown. These
discharges, as well as any other general operation discharges, are most frequently
discharged to a local sewer system for treatment by apublicly owned treatment works.
State Water Quality Standards
Section 303(c) of the CWA requires every state to adopt water quality standards applicable
to all water bodies or segments of water bodies that lie within the state. When a state (or
eligible tribe) adopts and submits new or revised water quality standards to EPA, EPA
approves or disapproves them. After EPA approval, the water quality standards are the
applicable water quality standards for CWA purposes. Water quality standards include (I)
designated beneficial uses, (2) narrative and/or numeric water quality criteria to achieve
those uses, and (3) an anti-degradation policy. States review their water quality standards
at least once every three years and revise them as necessary. When writing a permit, the
permit writer includes effluent limits as stringent as necessary to meet the most current
approved and applicable water quality standards. For more information regard ing how
procedures for water quality standards are developed, refer to EPA's Water Quality
Standards Regulation at 40 C.F.R. Part 131 and the Water Quality Standards Handbook:
Second Edition (1994).31 NPDES permits for onshore and near shore facilities include
limits that are more stringent than technology-based limits when necessary to meet state
water quality standards.
Ocean Discharge Criteria
Any NPDES permit issued for a discharge into the territorial sea or beyond also must
comply wfth the EPA guidelines established under CWA section 403. These guidelines,
the Ocean Discharge Criteria, are published at 40 C.F.R. Part 125 Subpart M. The Ocean
Discharge Criteria require evaluation of degree of degradation from such discharges on
marine resources, and specify procedures forpermitting marine discharges. Permits for
LNG projects that propose to discharge into waters of the territorial seas or beyond (i.e.,
near shore and offshore projects) may need to include conditions to comply with EPA's
guidelines under this section.
Coo/ing Water Intakes
CWA section 316(b) requires that the location, design, construction, and capacity of
cooling water intake structures reflect the best technology available for minimizing adverse
31
www.cpa. govAvatersci ence/standards/handbook/ .
25
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environmental impact. Such impacts include death or injury to aquatic organisms by
impingement (being pinned against screens or other parts of a cooling water intake
structure) or entrainment (being drawn into cool ing water systems and subjected to thermal,
physical or chemical stresses).
Cooling water intake structures operated by new onshore LNG projects are subject to
national performance standards promulgated under EPA's Phase I section 316(b) regulation
if they meet the eligibility criteria established by that regulation. 40C.F.R. 125.81. The
Phase I regulations apply to any new onshore projects that (1) use cooling water intake
structures to withdraw water from waters ofthe United States; (2) are required to obtain an
NPDES permit issued under CWA section 402; (3) have a design intake flow of greater
than two million gallons per day; and (4) use at least 25 percent of water withdrawn for
cooling purposes. 40 CP.R. 125.81. If anew onshore LNGproject uses less than 25
percent of its water for cooling purposes or does not meet the two million gallons per day
intake flow threshold, the project must meet section 316(b) requirements as specified by
the NPDES permit authority on a case-by-case basis using best professional judgment
(BPJ). 40C.F.R. 125.80(c).34
EPA has stated that "weter withdrawn for non-cooling purposes includes water withdrawn
for warming by liquefied natural gas facilities." 69 F.R. 41581. Consequently, warming
waters used by an LNG project would not be considered "water withdrawn for cooling
purposes" in determining whether an LNG project meets the threshold requirement of using
at least 25 percent of wier withdrawn for cooling purposes. Also, water used in a
manufacturing process either before or after it is used for cooling is considered process
water - not cooling water - for the purposes of calculating the percentage of a new
facility's intake flow that is used for cooling purposes. 40 CP.R. 125.83 & 125.133
(definition of cool ing water).
EPA has not promulgated national section 316(b) performance standards applicable to any
other type of LNG project. The recently promulgated Phase III section 316(b) regulations
for new facilities explicitly exclude new near shore and offshore LNG projects from that
rule. 40 C.F.R. 125.131(d). The Phase II section 316(b) regulations, in turn, apply
exclusively to existing power-gen crating plants. 40 C.F.R. 125.91(a)(3). Finally, EPA has
chosen not topromulgate national section 316(b) performance standards for any other
exist ing facilities. 71 Fed Reg. 35006 (June 16,2006). Therefore, new near shore and
offshore LNG projects, as well as all existing onshore, near shore or offshore LNG projects,
are subject to regulation under section 316(b) on a case-by-case BPJ basis. 40 C.F.R.
125.131(d); 40 C.F.R. 125.90(b).
Storm Wa ter Discharges Associated with Industrial Activity
CWA section 402(p) directed EPA to develop a phased approach to regulate storm water
discharges under the NPDES program. As relevant to LNG projects, EPA published a final
32 For more information see wwvv.epagov/\val.erscience/'316b/.
33 For more information see www.coa.gov/nDdes/pubs/LNG clarification mcmo.pdf.
34 For more information see www.eDaeov/npdes/Pubs/LNG clarification memo.pdf.
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regulation on the first phase of this program, establishing permit application requirements
for "storm water discharges associated with industrial activity." In addition, EPA'sNPDES
Multi-Sector General Permit (MSGP) for industrial storm water currently authorizes storm
water discharges associated with industrial activity for most areas of the U.S. where a state,
tribe, or territory is not authorized to administer the NPDES permit program.35
Discharges of storm water associated with construction activity are subject to the NPDES
permit program. This means, for example, the construction or expansion of an onshore
LNG project that would disturb more than five acres of total land area, and in many cases,
more than one acre. Storm water discharges associated with industrial activity at any LNG
project (onshore, near shore, or offshore) where industrial activity and materials are not
sheltered to prevent exposure to storm water also are subject to the NPDES permit
program. The operator of an LNG project could obtain coverage through either an
individual permit or an appropriate general permit during the onshore phase of any project
that requires large land area disturbance. Most states have been authorized to administer
the NPDES permitting program for storm water. For those few states (e.g., Massachusetts)
where EPA is the permitting authority, storm water discharges associated with construction
of the project would be need to be authorized under EPA's, £is opposed to a stye's
Construction General Permit.
36
Permitting for Discharges ofDredjgedor Fill Material
CWA section 404 establishes a permit program to regulate the discharge of dredged or fill
material into waters of the United States, including wetlands. The basic premise of the
program is that no discharge of dredged or fill material may be permitted if: (1) a
practicable alternative exists that is less damaging to the aquatic environment or (2) the
nation's waters would be significantly degraded. When applying for a permit, it is the
applicant's responsibility to show that it has, to the extent practicable:
" Taken steps to avoid impacts to all waters of the United States;
• M inimized potential impacts on waters of the United States; and
• Provided compensation for any remaining unavoidable impacts.
The U.S. Army Corps of Engineers (Corps) has theprimary responsibility for
administering the CWA section 404 regulatory permit program. Unless authorization is
available under a general permit, an individual permit is required. An individual permit is
required for potentially significant impacts. Individual permits are reviewed by the Corps,
which evaluates applications under a public interest review, as well as the environmental
criteria set forth in the CWA section 404(b)(l) guidelines.
For more information on the storm water MSGP see cfcub.eDa.gov/npdes/stormwater/msgp.ctn
See Final National Pollutant Discharge Elimination System General Permit for Storm Water Discharges
from Construction Activities, 68 FR 39087, July 1, 2003. A complete discussion of the Construction General
Permit with accompanying Fact Sheet, Notice oflntent forms and filing instructions can be found at
\vvvw.epa-KOv/nDdcs/stomiwater.
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For most discharges that will have only minimal adverse effects, a. general permit may be
appropriate. General permit authorization is available for activities that the Corps
determines are similar in nature, will cause only minimal adverse environmental effects
when performed separately, and will have only minimal cumulative adverse effect on the
environment. 33 U.S.C. § 1344(e)(l). The general permit process generally eliminates
individual review and allows certain activities to proceed with little or no delay, provided
that the general or specific conditions for the general permit are met.
Under its CWA section 404 authorities, EPA is responsible for the development and
interp relation of the environmental criteria used by the Corps in evaluating permit
applications (i.e., the CWA section 404(b)(l) guidelines) and maintains a review and
comment role in the issuance of section 404 permits. EPA has the ability to elevate
specific concerns through a formal dispute resolution process outlined in the 1992 CWA
Section 404(q) Memorandum of Agreement between the EPA and the Department of the
Army.37 EPA also has authority to prohibit, deny, or restrict the discharge of dredge or fill
material at a defined site under section 404(c) (i.e., veto authority). States also have a role
in section 404 permit decisions, through state program general permits, water quality
certification (see discussion below of state water quality certification), or program
assumption (M ichigan and New Jersey). EPA approves and oversees state and tribal
assumption of the 404 program. The procedures and criteria for the issuance of section 404
permits can be found in the Corps' regulations at 33 C.F.R. Parts 320 to 330. The section
404(b)(l) guidelines, and relevant definitions (such as waters of the United States) can be
found in EPA's regulations at 40 C.F.R. Part 230.
Regulation of Ocean Dumping
TheMarine Protection, Research, and Sanctuaries Act (MPRSA), 33 U.S.C. §§ 1401 et
seq., (also known as the Ocean Dumping Act) prohibitsthe dump ing of material into the
ocean that would unreasonably degrade or endanger human health or the marine
environment. The MPRSA regulates (1) the transportation of material from the U.S. for the
purpose of dumping it into ocean waters (those waters seaward of the baseline from which
the territorial sea is measured); (2) the transportation of material by a U.S. owned or
flagged vessel from any location for the purpose of dumping it into ocean waters; and (3)
the dump ing of material transported from outside the U.S. by a non-U.S. vessel in the
territorial sea and contiguous zone to the extent that the dumping of material affects the
territorial sea or U.S. territory. The MPRSA definition of "dumping" excludes construction
of any fixed structure or artificial island for a purpose other than disposal when otherwise
regulated by federal or state law or occurring pursuant to an authorized federal or state
program. Therefore, placement of a fixed structure for a near shore or offshore LNG
p reject would not const it ute dump ing The M PRSA definit ion of " dump ing" also exc ludes
a disposition of any effluent from any outfall structure to the extent that such disposition is
regulated under the provisions of the CWA. 33 U.S.C. §§ 1251 etseq.
37 This agreement applies to regulatory authorities under section 10 of the RHA of 1989; section 404 ofthe
CWA; and section 103 of MPRSA.
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39
Virtually all material from the U.S. that is dumped in the ocean today is dredged material
(i.e., sediments) removed from the bottom of navigable waters in order to maintain
navigation channels and berthing areas. In the case of dredged material, the decision to
issue a permit is made by the Coros, using EPA's environmental criteria and subject to
EPA's concurrence. For all other materials, EPA is the permitting agency. EPA also is
responsible for designating recommended ocean dump ing sites for all types of materials.
The criteria and procedures for ocean dumping permits and for the designation of ocean
dump ing sites can be found in EPA's ocean dump ing regulations at 40 C.F.R. Parts 220 to
229.
Proposed discharges of dredged or fill material into waters of the United States that lie
inland of the baseline from which the territorial sea is measured are evaluated under the
CWA. Because both CWA section 404 and the MPRSA apply to the disposition of
material to the waters of the territorial sea, there is a potential for a jurisdictional overlap
between these two programs. In general, where the discharge of dredged material into the
territorial sea would be for the primary purpose of fill, such as the use of dredged material
for beach nourishment, island creation, or construction of underwater berms, the discharge
is evaluated under CWA section 404. The disposal of dredged material in the territorial sea
is evaluated in accordance with the MPRSA.
Discharges Affecting Na vigation
Section 10 of the Rivers and Harbors Act of 1899 (RHA), 33 U.S.C. 403, establishes a
program to regulate activities affecting navigation in all domestic waters, including
wetlands. The RHA requires a permit for any work or structure, including construction,
excavation, or deposition of materials, in or affecting the course, condition, location, or
capacity of navigable waters of the United States (those waters that are subject to the ebb
and flow of the tide and/or are presently used, or have been used in the past, or may be
susceptible to use to transport interstate or foreign commerce) 33 C.F.R. 322.2(a) and
artificial islands, installations, or other devices in the subsoil or on the seabed of the outer
continental shelf. Activities requiring RHA section 10 permits include structures (e.g.,
piers, wharfs, breakwaters, bulkheads, jetties, weirs, transmission lines) and work such as
dredgingor disposal of dredged material, or excavation, filling, or other modifications to
the navigable waters of the United States.
Section 10 permits are issued by the Corps, often in conjunction with a CWA section 404
permit. EPA can comment on RHA section 10 permits as part of the Coips' public interest
review process (in response to the Public Notice for a permit application).
USCG regulations require that project operators must submit the information required to
obtain a permit for placement of structures and the discharge of dredged or fill material
with their deepwater port license application. 33 C.F.R. 148.l05(aa).
38 >vAv^v.cpa.gov/owow/ocuans/regulators'/dumpdrcde(xl/dredgemgnit.hi.ml.
vvvvw.t:pa.gov/owow/oceans/regulalors'/dumpdredeed/oceansites.htrnl .
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Disposition of Solid Materials in United States' Waters Generally
EPA maintains a review and comment role in the oversight of dredge and fill activities
depending on the nature and location of the activity. For example, pipeline construction
activities offshore, near shore, or onshore may require permits under the CWA, MPRSA, or
RHA. In other cases, significant impacts are often associated with the onshore fabrication
of the gravity-based structures (GBS) that eventually are transported offshore for placement
on the seabed. These impacts include coastal wetlands loss, sea grass bed disturbance and
loss, and dredged material management.
Project operators (offshore, near shore, or onshore) may engage in activities such as
dredging and pipeline construction in conjunction with the construction and/or operation of
their projects. EPA maintains a role in the review of many permits that these associated
activities may require, such as CWA section 404 permits and section 10 Rivers and
Harbors Act permits. Hundreds of miles of new natural gas pipelines have been proposed
through coastal wetlands in conjunction with LNG projects. Because individual permit and
approval requirements are determined on a project-by-project basis, project operators are
drvngly encouraged to engage EPA Regional and Headquarters staff early in the
development of their project.
Oil Spill Prevention
CWA section 311 establishes a program for the prevention and abatement of, and remedial
response to, oil and hazardous substance spills to the navigable waters of the United States,
adjoining shorelines, or into or upon the waters of the contiguous zone, or in connection
with activities under the Outer Continental Shelf Lands Act. 40 C.F.R. Parts 110, 112, 116,
and 117. Section 311 imposes requirements for reportingthe release of oil and hazardous
substances. This section is jointly administered by EPA and the USCG depending on the
location of the discharge and nature of the discharge (e.g., non-transportation related).
Subparts A through C of 40 C.F.R. Part 112 are often referred to as the "SPCC Rule"
because they describe the requirements for certain facilities to prepare, amend and
implement Spill Prevention, Control and Countermeasure (SPCC) Plans. SPCC Plans are a
cornerstone of EPA's strategy to prevent oil spills from reaching our nation's waters.
Unlike oil spill contingency plans that typically address spill cleanup measures after a spill
has occurred, SPCC Plans work to ensure that containment and other countermeasures are
in place to prevent and control oil spills, including those result ing from human operational
error or equipment failures, from reach ing navigable waters.
EPA does not exercise jurisdiction to regulate oil spill prevention activities for deep water
ports under CWA section 31 l(j)(l)(C). Under Executive Order 12777, the Department of
Transportation has been delegated authority to regulate transportation-related onshore
facilities, deep water ports, and vessels under this section.
40 For more information about EP A's oil spill program and EPA's SPCC compliance assistance guides see
\vww.epa.gov/oilspill.
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However, EPA maintains a regulatory and enforcement role under C WA Section 311 for
onshore and near shore facilities landward of the coast line. Executive Order 12777
delected authority to EPA to regulate non-transportation-related onshore projects and 40
C.F.R. 112 Appendix B further indicates that EPA retains jurisdiction for non-
transportation related offshore facilities landward of the coast line. For those facilities
within EPA jurisdiction, 40 C.F.R. 112 applies if the facility meets the applicability criteria
of the rule - i.e., the aggregate aboveground oil storage capacity is greater than 1,320
gallons or the aggregate completely buried storage capacity is greater than 42,000 gallons
and, due to facility location, could reasonably be expected to discharge oil in quantities that
may be harmful, as described in 40 C.F.R. part 110, into or upon navigable waters of the
United States or adjoining shorelines. The oil storage capacity of compressors and pumps
counts toward the aggregate oil storage capacity of the facility.
State Water Quality Certification of Certain Federal Licenses or Permits
CWA section 401 provides that any applicant for a federal license or permit (e.g., an EPA-
issued NPDES permit or a Corps-issued CWA section 404 permit) to conduct an activity
that may result in a discharge into inland waters of the state or its territorial seas shall
provide the federal permitting agency a certification from the state in which the discharge
originates certify ing that the license or permit complies with CWA requirements, including
applicable state water quality standards. For such federal permits or licenses, states and
authorized tribes can grant a CWA section 401 certification, condition its certification,
deny certification, or waive its certification. If the state or authorized tribe has denied
certification, the Federal agency may not issue the permit or license. 33 U.S.C. § 1341(a).
If the certification is conditioned, the Federal agency then may either incorporate those
conditions into the resulting permit or license or not issue the permit or license. 40 C.F.R.
124.55(a). As a result, the CWA section 401 certification process allows each state or
authorized tribe to have direct input into projects thst may affect its waters.
CWA section 401 certifications generally are issued by states, or by tribes thst EPA has
determined to be eligible to be treated in the same manner as a state for purposes ofthe
water quality standards program. EPA generally issues CWA section 401 certifications for
discharges in Indian country where tribes have not been authorized to administer the CWA
section 401 certification program. CWA section 401 applies to onshore and near shore
facilities that may result in a discharge.
Federal regulations require applicants for deepwaterport licenses toprovide evidence, to
the extent available, that the requirements of CWA Section 401(a)(l) will be satisfied. 33
C.F.R. 148.105(i)(l)-(2). If complete information is not available by the time MARAD
must approve or deny the ^plication, the license is conditioned on the applicant's ability to
meet the requirements of section 401(a)(l). Id.
Other EPA permitting requirements and considerations
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This section of the Technical Appendix presents an overview of other permitting
requirements and considerations that may ^>ply to LNG projects.
Resource Conservation and Recovery Act
Subtitle D of the Resource Conservation and Recovery Act (RCRA) focuses onstzte and
local governments as the primary planning, regulating and implement ing entities for the
management of non-hazardous solid waste, such as household garbage and non-hazardous
industrial solid waste. Subtitle D encourages environmentally sound solid waste
management practices that maximize the reuse of recoverable material and fosters resource
recovery. Subtitle C of RCRA is a comprehensive program to ensure that hazardous waste
is managed safely from the moment it is generated until it is disposed. Subtitle C regulates,
amongother things, hazardous waste generators and treatment, storage and disposal
facilities (TSDFs).
EPA does not anticipate that if operators of LNG projects were to generate hazardous waste
that it would be disposed of at these LNG projects. If storage or treatment were conducted,
it would likely be done in tanks or containers and treated hazardous waste would be sent
off-site within a period of 90 days for large quantity generators (LQGs) and 180 days for
small quantity generators (SQGs) (see below). It is not likely that a storage or treatment
permit would be required for LNG projects. Thus, operators at these projects would likely
be subject only to the hazardous waste generator requirements if in fact they generate
hazardous waste. A generator is any person, by site, whose processes and actions create
hazardous waste, but does not transport, treat, store or dispose of the wastes (see below for
details). A summary of the federal requirements for hazardous waste generators follows.
Many states have their own hazardous waste regulations based on the federal requirements;
however, some states have developed regulations that are more stringent than those in the
federal program. Project operators are encouraged to contact their EPA Regional Office,
EPA Headquarters and relevant state agencies to discuss permitting requirements.
First, operators of LNG projects must determine if any of the wastes they generate at the
project are hazardous wastes according to 40 C.F.R. Part 262.10. Listed hazardous wastes
are defined in 40 C.F.R. 261, Subpart D. Additionally, operators must determine if the
project's waste exhibits the characteristics of ignitability, corrosivity, reactivity ortoxicity
using a standardized test method or by app |y ing general knowledge of the waste's
properties, pursuant to 40 CP.R. 261 Subpart C. Operators at these projects must also
analyze wastes that are potentially hazardous, such as used oil and antifreeze, to determine
whether they are hazardous waste or used oil (as defined in 40 C.F.R. Part 279) and
whether they need to be managed in accordance with RCRA Subtitle C regulations. 40
C.F.R. Parts 260-279. If operators generate hazardous waste, operators would then be
required to measure the amount of hazardous waste generated per month to determine their
generator category (e.g., large quantity generator [LQG], small quantity generator [SQG] or
conditionally exempt small quantity generator [CESQG]), accordingto 40 C.F.R. Part
262.10 (b) and 261.5 (b) & (c). If operators determine that hazardous waste is being
generated and their project is either a LQG or SQG, the operator must then obtain an EPA
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identification number for his/her LNG project by fillingout a copy of EPA Form 8700-12
and sending it to the contact listed on the form. 40 C.F.R. 262.12.
Operators of LNG projects may then accumulate hazardous waste on-site without a permit
for up to 90 days for LQGs and 180 days for SQGs (40 CP.R. Part 262.34). Hazardous
waste can be accumulated in containers, tanks, drip pads, or containment buildings, if
applicable, as longas the operator complies withthe specified technical standards for each
unit type, found in 40 C.F.R. 262.34,40 C.F.R. 265 Subpart J, 40 C.F.R. 265 Subpart 1,40
C.F.R. 265 Subpart W, and 40 C.F.R. 265 Subpart DD. Also, hazardous waste may be
treated in tanks or containers without the need to obtain a permit provided the treated
hazardous waste is sent off-site within a period of 90 days for LQG's and 180 days for
SQGs.
Operators that qualify as CESQGs must manage their hazardous wastes according to the
requirements in 40 C.F.R. 261.5, which include identify ing a 11 the hazardous waste
generated, accumulating no more than 1,000 kilograms of hazardous waste at any time, and
ensuring that hazardous waste is delivered to a person or facility that is authorized to
manage it. For CESQGs, hazardous waste can be accumulated until the generator has
generated more than 1,000 kilograms of hazardous waste, at which point the provisions in
40 C.F.R. 262 governing SQGs become applicable.
If applicable, operators of LNG projects must meet recordkeep ing requirements of 40
C.F.R. Part 262, Subpart D depending on their generator status. Specified records must be
maintained for 3 years according to 40 C.F.R. Parts 262.40 to 262.41. Additionally,
operators of LNG projects must meet emergency response and preparedness and prevention
requirements found in 40 C.F.R. 262.34 and 40 C.F.R. 265 Subparts C and D.
Operators of LNG projects must ensure that any hazardous waste that is generated meets
the appropriate treatment standards prior to land disposal and maintain a waste analysis
plan if treating hazardous waste on-site, according to 40 C.F.R. 268.7. Additionally, as
required, project operators must send notifications and certifications to the off-siteTSDF
that will be handling their hazardous waste. 40 C.F.R. 268.7.
If shipping hazardous waste off-site, operators of LNG projects must package, label, mark,
and placard their hazardous waste following Department of Transportstion requirements
and then ship it using a registered hazardous waste transporter to a hazardous waste TSDF
(40 C.F.R. Parts 262.30 to 262.33). Project operators shipping hazardous waste off-site
must also use an approved version of the manifest system (EPA Form 8700-22). 40 C.F.R.
262.12. If exporting or importing hazardous waste, operators of LNGprojects must follow
the requirements for exports and imports, including submission to EPA of notification of
intent to export and receiving from EPA an acknowledgement of consent from the
receiving country (40 C.F.R. 262 Subparts E & F).
Operators that qualify as large quantity generators must develop and implement a
contingency plan. 40 C.F.R. 262.34(a)(4). The contingency plan must be designed to
minimize hazards to human health and the environment from fires, explosions, or any
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unplanned sudden or non-sudden release of hazardous waste or hazardous waste
constituents to air, soil, or surface water (40 C.F.R. 262.34 (a)(4)). While operators that
qualify as SQGs are not required to develop a contingency plan, they are required to
maintain and operate their facilities to minimize the possibility of a fire, explosion, or any
unplanned sudden or non-sudden release of hazardous waste to the environment in
compliance with 40 C.F.R. 262.34 (d)(4).
If applicable, operators of LNG projects must use various monitoring and control
mechanisms for units that store ortreat hazardous wastepursuant to 40 C.F.R. Part 265
Subpart CC:
• Control volatile organic compound (VOC) emissions from hazardous waste
management activities.
• Reduce organic emissions from process vents associated with certain recycling
activities and equipment that is in contact with hazardous waste that has significant
organic content.
• Control VOCs from hazardous waste tanks, surface impoundments, and containers
using fixed roofs, floating roofs, or closed-vent systems routed to control devices.
Finally, when a hazardous waste generator ceases to generate hazardous waste, it is subject
to certain "closure" requirements. The generator must decontaminate and remove all
hazardous waste contaminated equipment, and structures, and minimize the need for further
maintenance of the site. 40 C.F.R. 262.34(a)(iv)(B) & 265.201 (d). Additionally, the
generator must meet unit-specific closure standards for tanks, containment buildings, and
drip pads, if applicable, according to 40 C.F.R. 265 Subpart G.
Comprehensive Environmental Response, Compensation, and Liability Act
The Comprehensive Environmental Response, Compensation, and Liability Act
(CERCLA), 42 U.S.C. §§ 9601, etseq., better known as the "Superfund Act," addresses
cleanup of hazardous substances. CERCLA and its implementation documents empower
EPA and other agencies to identify and prioritize sites for cleanup, and to order or carry out
environmental remediation. Subject to limited defenses, CERCLA imposes strict liability
for environmental cleanup on persons connected to facilities from which there are releases
into the environment. CERCLA also mandates reportingto the National Response Center
of hazardous substance releases. In conjunction with CWA section 311, CERCLA
provides for federal preparation of the National Contingency Plan for responding to a
hazardous substances release. CERCLA is administered by federal agencies, not states.
Operators are encouraged to discuss with their EPA Regional Office and EPA
Headquarters if they believe that their project could result in the release of hazardous
substances subject to EPA jurisdiction.
En \ironmental Justice
EPA's Office of Environmental Justice defines environmental justice as:
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The fair treatment and meaningful involvement of all people regardless of race,
color, national origin, or income with respect to the development, implementation,
and enforcement of environmental laws, regulations, and policies. EPA has this
goal for all communities and persons across this Nation. It will be achieved when
everyone enjoys the same degree of protection from environmental and health
hazards and equal access to the decision-making process to have a healthy
environment in which to live, learn, and work.
41
Pursuant to Executive Order 12898, Federal agencies "shall make achieving environmental
justice part of its mission by identify ing and addressing, as appropriate, disproportionately
high and adverse human health or environmental effects of its programs, policies, and
activities on minority populations and low-income populations in the United States and its
territories and possessions."
In particular, the NEPA review process, which EPA participates in for all types of LNG
projects, presents one of the critical avenues for agencies to consider environmental justice
issues. The Council on Environmental Quality's Environmental Guidance Under (he
National Environmental Policy Act states that "Environmental justice issues may arise at
any step ofthe NEPA process and agencies should consider these issues at each and every
step of theprocess, as appropriate. Environmental justice issues encompass abroad range
of impacts covered by NEPA, including impacts on the natural or physical environment
and interrelated social, cultural and economic effects."42
In conjunction with the federal agencies' consideration of environmental justice issues,
parties intending to operate LNG projects may wish to consider whether or not their
proposed actions present environmental justice issues before they submit their permit
applications to EPA.
More information from EPA's Office of Environmental Justice can be found at
www.epa.eov/environmentaljustice/index.html .
Council on Environmental Quality, Environmental Justice: Guidance Under the National Environmental
Policy Act, 1997. ccq.ch.doe.gov/nena/regs/ei/iusticc.pdf.
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Appendix A: Acronyms and Abbreviations
BACT Best Available Control Technology
BAT Best Available Demonstrated Control Technology
BCT Best Control Technology
BOD5 Biochemical Oxygen Demand Measured Over Five Days
BPJ Best Professional Judgment
BPT Best Practicable Control Technology Currently Available
CERCLA Comprehensive Environmental Response, Compensation, and Liability Act
CESQG Conditionally Exempt Small Quantity Generators
CFR Code of Federal Regulations
CO Carbon Monoxide
Corps United States Army Corps of Engineers
DOT Department ofTransportation
DPA Deep water Port Act
EA Environmental Assessment
EEZ Exclus ive Econom ic Z one
EIA Energy Information Administration
EIS Environmental Impact Statement
ELG Effluent Limitation Guideline
EPAct Energy Policy Act
FERC Federal Energy Regulatory Commission
FIP Federal Implementation Plan
FONSI Finding of No Significant Impact
GBS Gravity Based Structures
HAP Hazardous Air Pollutant
HAP Hazardous Air Pollutants
IFV Intermediate Fluid Vaporization
LEAR Lowest Achievable Emissions Rate
LNG Liquefied Natural Gas
LQG Large Quantity Generators
MACT Maximum Achievable Control Technology
MARAD Maritime Administration (U.S. Department ofTransportation)
MPRSA Marine Protection, Research, and Sanctuaries Act
MSGP M ulti-Sector General Permit
MTSA Maritime Transportation Security Act
NAAQS National Ambient Air Quality Standards
NEPA National Environmental Policy Act
NESHAP National Emissions Standards for Hazardous Air Pollutants
NO2 Nitrogen Dioxide
NOx Nitrogen Oxides
NPDES National Pollutant Discharge Elimination System
NSPS New Source Performance Standards
NSR New Source Rev iew
OCS Outer Continental Shelf
ORV Open Rack Vaporization
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PM Paniculate Matter
PSD Prevention of Significant Deterioration
RCRA Resource Conservation and Recovery Act
RHA Rivers and Harbors Act
ROD Record of Decis ion
SCR Selective Catalytic Reduction
SCV Submerged Combustion Vaporization
SIP State Implementation Plan
SO2 Sulfur Dioxide
SPCC Spill Prevention, Control and Countermeasures
SQG Small Quantity Generators
USC United States Code
USGS United States Coast Guard
VOC Volatile Organic Compounds
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Us
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