EPA’s Liquefied Natural Gas

Regulatory Roadmap

July 2006

EPA230-B-06-001
About this Roadmap 

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 (EIA) 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 at 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-byproject 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 Information Administration, Monthly Energy Review

www.eia.doe.gov/mer/contents.html . 2

 U.S. Department of Energy, Energy Information Administration, Annual Energy Outlook 2006

www.eia.doe.gov/oiaf/aeo/index.html . 3

 U.S. Department of Energy, Liquefied Natural Gas: Understanding the Basics, August 2005

www.fe.doe.gov/programs/oilgas/publications/lng/LNG_primerupd.pdf . 4

 U.S. Department of Energy, Energy Information Administration, Annual Energy Outlook 2006. 

ii 
The Roadmap presents discussions of EPA requirements that may apply to offshore 

projects (i.e., located beyond state seaward boundaries), as well as onshore and near 

shore projects (i.e., located within state waters). 

Figure 1. provides an overview of EPA’s role in the environmental review process. 

iii 
Similarly, Figure 2. provides an overview of EPA’s role in permitting requirements 

and other considerations. 

iv
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 nonmandatory 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 Act

5

 established an expedited license process for authorizing the 

ownership, construction and operation of deepwater ports 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 theMaritime 

Administration (MARAD), which issues the actual deepwater port 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 deepwater port license 

application. This requirement includes relevant EPA permits;

6 

 USCG/MARAD forward deepwater port 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 (MPRSA). 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, USCG/MARAD suspends the 

review period until the applicant supplies missing information; 

5

 33. U.S.C. § § 1501-1524.

6

 33 C.F.R. 148.105(z) & (bb); 33 U.S.C. § 1518(a)(1).

v 
 Within 45 days after the last public hearing on the license application, 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 deepwater port will not conform with all applicable provisions of the CAA, 

CWA, or theMPRSA;

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/MARAD NEPA 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 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. This includes LNG projects onshore and in state waters.

10 

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-filing procedures. This 

pre-filing process involves agencies working together to develop a single NEPA 

document to address each agency’s requirements;

11 

 FERC regulations require applicants to consult with the appropriate 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;

12 

 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(e)(2) and 33 U.S.C. § 1503(c)(6). 8

 33 U.S.C. § 1504(f). 9

 15 U.S.C. § 717 et seq. 10 15 U.S.C. § 717a(11)(definition of “ LNG terminal”). 11 15 U.S.C. §717(n)-1(a) & 18 C.F.R. 157.21(a). 12 18 C.F.R. 380.3(b)(3)&(4).

vi 
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 vesselbased 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 the project. 

Permitting requirements vary on a project-by-project basis. For this reason, not all LNG 

projects apply for the same permits or are subject to the same requirements. In some 

instances, LNG projects may need to apply 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); 

 Title V Operating Permits; 

 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 on theMARAD/USCG general conformity analysis, if applicable. 

vii 
Onshore Projects and Projects in State Waters 

For onshore LNG projects, EPA: 

 Issues air permits only in cases where EPA has not delegated 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 projectsthat 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 theMarine 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 apply for the same permits or are subject to the same requirements. In some 

instances, LNG facilities may need to comply with the following types of requirements: 

 National Pollutant Discharge Elimination System Program (NPDES) permitting, 

which may include: 

o Effluent limitations for discharged pollutants, both for process wastewater 

and for storm water associated with industrial activity, based on:

 Technology-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 apply 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 of the 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 
Onshore Projects and Projects in State Waters 

For onshore and near shore projects, EPA: 

 Serves as the NPDES permitting authority only 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 or tribe 

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 Corps 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 for the dumping of materials (other than dredged 

materials) seaward of the territorial seas (3 nautical miles) pursuant to section 102 

of theMarine 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. 

ix 
Other Permitting Requirements and Conside rations 

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 Res ponse 

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. 

Environmental 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. 

x 
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 statutes governing the approval and environmental review of these projects, specifically 

the National Environmental Policy Act (NEPA), as well as the Deepwater Port Act (DPA) 

and the Natural Gas Act (NGA), which are administered primarily by the Department of 

Transportation (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 of these 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. 

11 
Table of Contents 

LNG Project Approval and Environmental Review Process......................................12 

General Overview - The National Environmental Policy Act.................................12 

Projects Offshore 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) Permitting Overview....................................................18 

Title V Operating Permits..........................................................................................19 

New Source 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 Criteria...........................................................................................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 Materialsin UnitedStates’ Waters Generally.......................30 

Oil Spill Prevention.....................................................................................................30 

State Water Quality Certification 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 for protection of the environment. Section 102(2)(C) of 

NEPA requires federal agencies to prepare a “detailed statement” for proposed major

actions which significantly affect the quality of the human environment. The statement

must include the environmental impacts of the proposed action, alternatives to the proposed

action, and any adverse environmental impacts that cannot be avoided should the proposal

12 
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 fromthe standpoint of public health or welfare or environmental 

quality, EPA refers the matter to the President=s Council on Environmental Quality. 

Projects Offshore in Federal Waters 

The Deepwater 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 

deepwater ports beyond the territorial limits of the United States”; 

 Promoting “the construction and operation of deepwater ports as a safe and 

effective means of importing 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 “deepwater port” for natural gas to mean “any fixed 

or floating manmade structure other than a vessel, or any group of such structures,. . . used 

or intended for use as a port or terminal 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 that they are located seaward of the 

high water mark and do not include interconnecting facilities.” 33 U.S.C. § 1502(9). A 

deepwater 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 MARAD primarily responsible for project financial reviews and the 

USCG primarily responsible for project engineering, operations, safety, and environmental 

13 
reviews, which include compliance with NEPA.

13 EPA permit actions are not subject to 

the time constraints of the 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 of the licensing process. 

33 U.S.C. § 1504(f). The DPA also statesthat 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 

deepwater port, or that isso 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 of the nearest adjacent coastal state, whose seaward boundaries, if extended beyond 

three miles, would encompass the site of the deepwater port, is the law of the United States 

and applies to a deepwater port to the 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 of the nearest 

adjacent coastal state. 

On May 20, 2004, the White House Task Force on Energy Project Streamlining distributed 

a Memorandum of Understanding (MOU) Related to the Licensing of Deepwater Ports.

14 

This MOU 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 deepwater port license application to 

determine whether or not it is complete. 33 U.S.C. § 1504(c)(1). 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)(1). Once USCG/MARAD receives a 

DPA license application it forwards a copy(s) of the application to other responsible federal 

agencies, including the 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). Under theMOU, 

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 See the Memorandum of Understanding for inter-agency coordination on licensing of Deepwater Ports 

www.etf.energy.gov/pdfs/DPA_MOU.pdf . The Secretary of DOT delegated in 49 C.F.R. 146(s) to the 

USCG authority to process applications for licenses under the DPA. 14 

www.etf.energy.gov/pdfs/DPA_MOU.pdf . 

14 
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)(1). 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 deepwater port requires supporting NEPA 

documentation because the DPA deems a deepwater port to be a “new source.”

15 Under 

the DPA the NEPA review conducted by the USCG/MARAD 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 usesthe 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 under the 

authority of section 309 of the CAA. 

DPA licenses also may be subject to other federal environmental statutes (e.g., Endangered 

Species Act, Coastal ZoneManagement 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(c)(1). 

15 
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 deepwater port that is located 

landward of the high water mark and over interconnecting facilities, which are not part of 

the deepwater port.

16 With respect to approvals of these projects, the Energy Policy Act of 

2005 designated FERC as the lead agency for purposes of coordinating all applicable 

federal authorizations and for the purposes of complying with NEPA. Under this 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)-1(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 applicantsto “[c]onsult 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 cooperating 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 511(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(b)(9)(C). 17 Energy Policy Act of 2005, Pub. L. No. 109-58 Sec. 313 which amended 15 U.S.C. 717 n.

18 For more information on the FERC pre-filing process see ferc.gov/help/processes/flow/lng-1.asp . 

16 
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, permitsto construct before starting construction 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 burning selection; 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 the project. An LNG project 

may emit many different air pollutants, including nitrogen oxides (NOx), particulate matter 

(PM), volatile organic compounds (VOC), sulfur dioxide (SO2), 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 

17 
quality status of the 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. 

New Source Review (NSR) Permitting Overview 

The CAA requires each state to have an EPA-approved SIP for the attainment and 

maintenance of the national primary and secondary ambient air quality standards.

19 Section 

110 of the Act requires that each SIP include a program to regulate the construction and 

modification of any stationary 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 pipelines) must generally obtain 

air permits before commencing construction.

20 

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 NSR – depending on the 

proposed quantity of air emissions and location of the 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 will 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 that 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 of the CAA) and the nonattainment NSR program (Title I, Part D of the 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 of the 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 

applicable to the source. Major source thresholds for the PSD program vary depending on 

the type of the source. The major source threshold for the federal nonattainment NSR 

program may also vary depending on the pollutant and severity of nonattainment in a given 

19 CAA § 110(a). 20 See CAA §§ 110(a)(2)(C), 165, and 172(c)(5).

18 
area. State PSD and nonattainment NSR programs approved into the 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 existing 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 NSR permit 

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 Operating 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. A part 71 operating permit 

21 40 C.F.R. 52.21; see also 40 C.F.R. 51.166 (requirements for state PSD programs). 22 CAA § 173. 23 State operating permits will vary and may include permits other than Title V permits.

19 
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 it to be deficient), or because the source is located on the Outer 

Continental Shelf (OCS) or in Indian county, where state 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 neighboring 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 proposed part 70 permit. If EPA does not object to the 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). 

New Source 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. 60.110b – 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 that have a capacity greater than 151 m3

 (39,890 gallons) and that store a liquid 

with a maximum true vapor pressure less than 3.5 kPa (0.5 psia). Section 60.111b defines 

a volatile organic liquid as “any organic liquid which can emit volatile organic compounds 

24 40 C.F.R. 70.8(d)

25 40 C.F.R. 70.5(a)(1)(iii) and 40 C.F.R. 71.5(a)(1)(iii).

20 
(as defined in 40 C.F.R. 51.100) into the atmosphere.” 40 C.F.R. 51.100(s)(1) 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 generating 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 60.41b 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 generating 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 generating units, and if so then Subpart Db does not apply. A NSPS 

determination, if applicable, for an individual LNG project will based upon information 

submitted in the permit 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). These programs 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 not 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 

21 
increases are already included in SIP; (2) obtaining an agreement from a state to include 

increases in a SIP; (3) modeling 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 deepwater ports, MARAD/USCG completesthe 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,

26 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 theMarine 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 

permitting requirements. 

National Pollutant Discharge Elimination System Permit Program 

Under the CWA, the dischargers of pollutants from any point source into waters of the 

United States, including the territorial seas, are required to obtain an National Pollutant 

Discharge Elimination System (NPDES) permit.

27 Section 402 of the 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.

28 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 of the United States of

America). 27 See CWA §§ 301(a) & 402(a). 28 See CWA § 502 (12) (definition of“ discharge of a pollutant”).

22 
bed of the ocean, contiguous zone, or waters of the United States for the purpose of energy 

development. In most cases, the NPDES permit program is administered by authorized 

states

29 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 apply 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. 

According to 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 writer 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 C.F.R. 125.3(c). 

In deriving BPJ limits, the permit writer considers: (1) the appropriate technology for the 

category or class of point sources of which the permit 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 pollutantsthat 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 controltechnology 

29 

cfpub.epa.gov/npdes/statestats.cfm . 30 For more information about the NPDES permit program see cfpub.epa.gov/npdes/ . 

23 
(BCT) for conventional pollutants, and best available technology economically achievable 

(BAT) for toxics and non-conventional pollutants). 

In addition, for any pollutant, section 301(b)(1)(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 Effluent 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 of the 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 identifying technology-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 of the 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 employing 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 following 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 noncontact 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 MARAD must either approve or deny the 

application, the license for the deepwater port is conditioned upon the applicant receiving 

24 
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 regasification 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 a publicly 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 (1) 

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 regarding 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 with 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 for permitting 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. 

Cooling 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.epa.gov/watersci ence/standards/handbook/ . 

25 
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 cooling water systems and subjected to thermal, 

physical or chemical stresses).

32 

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. 40 C.F.R. 125.81.33 The 

Phase I regulations apply to any new onshore projectsthat (1) use cooling water intake 

structures to withdraw water from waters of the 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 C.F.R. 125.81. If a new onshore LNG project 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). 40 C.F.R. 125.80(c).

34 

EPA has stated that “water 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 water 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 C.F.R. 125.83 & 125.133 

(definition of cooling 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-generating plants. 40 C.F.R. 125.91(a)(3). Finally, EPA has 

chosen not to promulgate national section 316(b) performance standards for any other 

existing 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 Water 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 www.epa.gov/waterscience/316b/ . 33 For more information see www.epa.gov/npdes/pubs/LNG_clarification_memo.pdf . 34 For more information see www.epa.gov/npdes/pubs/LNG_clarification_memo.pdf . 

26 
regulation on the first phase of this program, establishing permit application requirements 

for “storm water discharges associated with industrial activity.” In addition, EPA’s NPDES 

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, as opposed to a state’s 

Construction General Permit.

36 

Permitting for Discharges of Dredged or 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 stepsto avoid impacts to all waters of the United States; 

 Minimized 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 the primary 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)(1) guidelines. 

35 For more information on the storm water MSGP see cfpub.epa.gov/npdes/stormwater/msgp.cfm . 36 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 of Intent forms and filing instructions can be found at 

www.epa.gov/npdes/stormwater . 

27 
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)(1). 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 

interpretation of the environmental criteria used by the Corps in evaluating permit 

applications (i.e., the CWA section 404(b)(1) 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 (Michigan 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)(1) 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 dumping 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 dumping 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. TheMPRSA 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 

project would not constitute dumping. TheMPRSA definition of “dumping” also excludes 

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 et seq. 

37 This agreement applies to regulatory authorities under section 10 of the RHA of 1989; section 404 of the 

CWA; and section 103 of MPRSA. 

28 
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.

38 In the case of dredged material, the decision to 

issue a permit is made by the Corps, 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 dumping sites for all types of materials.

 39 

The criteria and procedures for ocean dumping permits and for the designation of ocean 

dumping sites can be found in EPA’s ocean dumping 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 Navigation 

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 watersthat 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 

dredging or 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 Corps’ 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. 148.105(aa). 

38 

www.epa.gov/owow/oceans/regulatory/dumpdredged/dredgemgmt.html . 39 

www.epa.gov/owow/oceans/regulatory/dumpdredged/oceansites.html . 

29 
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 

strongly 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 reporting the release of oil and hazardous 

substances. Thissection 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 resulting from human operational 

error or equipment failures, from reaching navigable waters.

40 

EPA does not exercise jurisdiction to regulate oil spill prevention activities for deepwater 

ports under CWA section 311(j)(1)(C). Under Executive Order 12777, the Department of 

Transportation has been delegated authority to regulate transportation-related onshore 

facilities, deepwater ports, and vessels under this section. 

40 For more information about EPA’s oil spill program and EPA’s SPCC compliance assistance guides see 

www.epa.gov/oilspill . 

30 
However, EPA maintains a regulatory and enforcement role under CWA Section 311 for 

onshore and near shore facilities landward of the coast line. Executive Order 12777 

delegated 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 nontransportation 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 EPAissued 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 certifying 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 that may affect its waters. 

CWA section 401 certifications generally are issued by states, or by tribes that EPA has 

determined to be eligible to be treated in the same manner as a state for purposes of the 

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 deepwater port licenses to provide evidence, to 

the extent available, that the requirements of CWA Section 401(a)(1) will be satisfied. 33 

C.F.R. 148.105(i)(1)-(2). If complete information is not available by the time MARAD 

must approve or deny the application, the license is conditioned on the applicant’s ability to 

meet the requirements of section 401(a)(1). Id. 

Other EPA permitting requirements and considerations 

31 
This section of the Technical Appendix presents an overview of other permitting 

requirements and considerations that may apply to LNG projects. 

Resource Conservation and Recovery Act 

Subtitle D of the Resource Conservation and Recovery Act (RCRA) focuses on state and 

local governments as the primary planning, regulating, and implementing 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, 

among other 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 or toxicity 

using a standardized test method or by applying general knowledge of the waste’s 

properties, pursuant to 40 C.F.R. 261 Subpart C. Operators at these projects must also 

analyze wastesthat 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]), according to 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 

32 
identification number for his/her LNG project by filling out 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 C.F.R. Part 262.34). Hazardous 

waste can be accumulated in containers, tanks, drip pads, or containment buildings, if 

applicable, as long as the operator complies with the 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 I, 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 identifying all 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 recordkeeping 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 Transportation requirements 

and then ship it using a registered hazardous waste transporter to a hazardous wasteTSDF 

(40 C.F.R. Parts 262.30 to 262.33). Project operatorsshipping 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 LNG projects 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 

33 
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 or treat hazardous waste pursuant 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, et seq., 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 reporting to 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. 

Environmental Justice 

EPA’s Office of Environmental Justice defines environmental justice as: 

34 
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 identifying 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 the 

National Environmental Policy Act states that “Environmental justice issues may arise at 

any step of the NEPA process and agencies should consider these issues at each and every 

step of the process, as appropriate. Environmental justice issues encompass a broad 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. 

41 More information from EPA’s Office of Environmental Justice can be found at

www.epa.gov/environmentaljustice/index.html . 42 Council on Environmental Quality, Environmental Justice: Guidance Under the National Environmental

Policy Act, 1997. ceq.eh.doe.gov/nepa/regs/ej/justice.pdf . 

35 
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 of Transportation 

DPA Deepwater Port Act 

EA Environmental Assessment 

EEZ Exclusive Economic Zone 

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 of Transportation) 

MPRSA Marine Protection, Research, and Sanctuaries Act 

MSGP Multi-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 Review 

OCS Outer Continental Shelf 

ORV Open Rack Vaporization 

36 
PM Particulate Matter 

PSD Prevention of Significant Deterioration 

RCRA Resource Conservation and Recovery Act 

RHA Rivers and Harbors Act 

ROD Record of Decision 

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 

37