4.12-1 4.12 – Reliability and Safety

4.12 RELIABILITY AND SAFETY 

Three federal agencies share regulatory authority over the siting, design, construction and 

operation of LNG import terminals: the FERC, the Coast Guard, and the DOT. The FERC 

authorizes the siting and construction of LNG import facilities and is the lead federal agency 

responsible for the preparation of analyses required under the NEPA for impacts associated with 

terminal construction and operation. The Coast Guard has authority over the safety of the LNG 

facility marine transfer area and over the safety of LNG marine traffic. The Coast Guard also 

has authority over security plans for LNG marine traffic, as well as for the entire LNG facility. 

The DOT has exclusive authority to promulgate and enforce safety regulations for on-shore LNG 

facilities beginning at the last valve immediately before the LNG storage tank(s). In 1980, the 

DOT established a set of safety standards, “Liquefied Natural Gas Facilities: Federal Safety 

Standards,” under Title 49, CFR, Part 193, which apply to the construction, operation, and 

maintenance of on-shore LNG facilities. 

In February 2004, the three participating agencies entered into an Interagency Agreement to 

assure that they work in a coordinated manner to address the full range of issues regarding safety 

and security at LNG import terminals, including the terminal facilities and tanker operations, and 

to maximize the exchange of information related to the safety and security aspects of the LNG 

facilities and related marine operations. The FERC closely coordinates its pre-authorization 

review of the proposal with the Coast Guard and the DOT to ensure a seamless safety and 

security review. 

The operation of the proposed Jordan Cove LNG terminal poses a potential hazard that could 

affect the public safety without strict design and operational measures to control potential 

accidents. The primary concerns are those events that could lead to an LNG spill of sufficient 

magnitude to create an off-site hazard, including events occurring during the course of LNG 

carrier transits. However, it is also important to recognize the stringent requirements for the 

design, construction, operation and maintenance of the facility as well as the extensive safety 

systems to detect and control potential hazards. 

With the exception of the October 20, 1944 fire at the LNG facility in Cleveland, Ohio, the 

operating history of U.S. LNG facilities has been free of LNG safety-related incidents resulting 

in adverse effects to the public or the environment. The 1944 Cleveland incident was attributed 

to the use of materials inadequately suited for cryogenic temperatures and the lack of spill 

impoundments at the site.1

 Another operational accident occurred in 1979 at the Cove Point 

LNG facility in Lusby, Maryland. A pump seal failed, resulting in gas vapors entering an 

electrical conduit and settling in a confined space. When a worker switched off a circuit breaker, 

the gas ignited, causing heavy damage to the building and a worker fatality. Lessons learned 

from this accident resulted in changing the national fire codes, with the participation of the 

FERC, to ensure that the situation would not occur again. The proposed facilities would be 

designed, constructed, and operated in compliance with these codes. 

On January 19, 2004, a blast occurred at Sonatrach’s Skikda, Algeria LNG liquefaction facility 

that killed 27 and injured 56 workers. No members of the public were injured. Preliminary 

 

1

 For a description of the incident and the findings of the investigation, see U.S. Bureau of Mines, Report on the Investigation of 

the Fire at the Liquefaction, Storage, and Regasification Plant of the East Ohio Gas Co., Cleveland, Ohio, October 20, 1944, 

dated February 1946. 
4.12-2 4.12 – Reliability and Safety

findings of the accident investigation suggest that a cold hydrocarbon leak occurred at 

Liquefaction Train 40 and was introduced to the high-pressure steam boiler by the combustion 

air fan. An explosion developed inside the boiler firebox which subsequently triggered a larger 

explosion of the hydrocarbon vapors in the immediate vicinity. The resulting fire damaged the 

adjacent liquefaction process and liquefied petroleum gas separation equipment of Train 40, and 

spread to Trains 20 and 30. Although Trains 10, 20, and 30 had been modernized in 1998-1999, 

Train 40 had been operating with its original equipment since start-up in 1981. 

Although there are major differences between the equipment involved in the accident at Skikda 

and that proposed by Jordan Cove (i.e., high-pressure steam boilers that power refrigerant 

compressors would not be used here nor are they used at any LNG facility under the FERC’s 

jurisdiction), the sequence of cascading events identifies potential failure modes that warrant 

further evaluation. As a result, we have provided a recommendation in section 4.12.2, Front-End 

Engineering Design Review, to address this issue. 

A discussion of the principal properties and hazards associated with LNG is presented in section 

4.12.1. A summary of our preliminary design and technical review of the cryogenic aspects of 

the LNG terminal is presented in section 4.12.2. Storage and retention systems are discussed in 

section 4.12.3. An analysis of the thermal radiation and flammable vapor cloud hazards resulting 

from a credible land-based LNG spill is presented in section 4.12.4, while the safety aspects of 

LNG transportation by carrier is discussed and summarized in section 4.12.5. Emergency 

response and evacuation planning is discussed in section 4.12.6, and conclusions on LNG carrier 

safety are provided in section 4.12.7. A discussion on security awareness related to terrorism is 

presented in section 4.12.8 and the reliability and safety issues related to the natural gas pipeline 

are discussed in section 4.12.9. 

4.12.1 LNG Hazards 

LNG’s principal hazards result from its cryogenic temperature (-260°F), flammability, and vapor 

dispersion characteristics. As a liquid, LNG will neither burn nor explode. Although it can 

cause freeze burns and, depending on the length of exposure, more serious injury or death, its 

extremely cold state does not present a significant hazard to the public, which rarely, if ever, 

comes in contact with it as a liquid. As a cryogenic liquid, LNG will quickly cool materials it 

contacts, causing extreme thermal stress in materials not specifically designed for such 

conditions. These thermal stresses could subsequently subject the material to brittleness, 

fracture, or other loss of tensile strength. These hazards, however, are not substantially different 

from the hazards associated with the storage and transportation of liquid oxygen (-296°F) or 

several other cryogenic gases that have been routinely produced and transported in the United 

States. 

LNG vaporizes rapidly when exposed to ambient heat sources such as water or soil. When 

released from its containment carrier and/or transfer system, LNG will generally produce 620 to 

630 standard cubic feet of natural gas for each cubic foot of liquid. A large quantity of LNG 

spilled without ignition would form a vapor cloud that would travel with the prevailing wind 

until it either dispersed below the flammable limits or encountered an ignition source. If a large 

quantity of LNG is spilled in the presence of an ignition source, the resulting pool fire would 

produce high levels of radiant heat in the area surrounding the LNG pool. 
4.12-3 4.12 – Reliability and Safety

A rapid phase transition (RPT) can occur when a portion of LNG spilled onto water changes 

from liquid to gas, virtually instantaneously. Unlike an explosion that releases energy and 

combustion products from a chemical reaction, an RPT is the result of heat transferred to the 

liquid inducing a change to the vapor state. The rapid expansion from the liquid to vapor state 

can cause locally large overpressures. RPTs have been observed during LNG test spills onto 

water. In some test cases, the events were strong enough to damage test equipment in the 

immediate vicinity of the LNG release point. The sizes of the overpressure events have been 

generally small and are estimated to be equivalent to several pounds of trinitrotoluene (TNT). 

Although such a small overpressure is not expected to cause significant damage to an LNG 

carrier, the RPT may increase the rate of LNG pool spreading and the LNG vaporization rate for 

a spill on water. 

Methane vapors, the primary component of natural gas, are colorless, odorless and tasteless, and 

are classified as a simple asphyxiant. Methane vapors may cause extreme health hazards, 

including death, if inhaled in significant quantities within a limited time. Although very cold 

methane vapors may cause freeze burns, any cloud resulting from an LNG spill would be 

continuously mixing with the warmer air surrounding the spill site. Dispersion modeling 

indicates the majority of the cloud would generally be within 25°F of the surrounding 

atmospheric temperature, with colder temperatures closest to the spill source. In addition, this 

modeling estimates that most of the cloud would be below concentrations resulting in oxygen 

deprivation effects, including asphyxiation, with the highest methane concentrations closest to 

the spill source. Therefore, asphyxiation and freezing normally represent a negligible risk to the 

public from LNG facilities. 

Although LNG will not burn, methane vapors in a 5 to 15 percent mixture by volume with air are 

flammable. Once a flammable vapor-air mixture from an LNG spill has been ignited, the flame 

front will propagate back to the spill site if the vapor concentration along this path is sufficiently 

high to support the combustion process. Combustible materials within the flammable portion of 

the cloud may be within the flame and could be ignited. However, any events leading to a 

containment failure would most likely be accompanied by a number of ignition sources. The 

result would be an LNG pool fire, and subsequent radiant heat hazards, rather than the formation 

of a large unconfined vapor cloud. 

Although, LNG is not explosive as it is normally transported and stored, natural gas vapors 

(primarily methane) can explode if contained within a confined space, such as a building or 

structure, and ignited. Occasionally, various parties have expressed the energy content of an 

LNG storage tank or LNG carrier in equivalent tons of TNT, as an implied measure of explosive 

potential. However, such a simplistic analogy fails to consider that explosive forces are not just 

a function of the total energy content but also of the rate of energy release. For a detonation to 

occur, the rate of energy release must be nearly instantaneous, such as with a TNT charge 

initiated by a blasting cap. Unlike TNT or other explosives which inherently contain an oxidizer, 

an unconfined vapor cloud must be mixed with oxygen within the flammability range of the fuel 

for combustion to occur. For a large unconfined vapor cloud, the flammability range tends to 

exist at the mixing zone at the edges of the cloud. When ignited, flame speeds about 20 to 25 

meters per second (66 to 82 feet per second) and local over pressures up to 0.2 psig have been 

estimated for unconfined methane-rich vapor clouds. These are well below the flame speeds and 

over pressures associated with detonation. 
4.12-4 4.12 – Reliability and Safety

The potential for unconfined LNG vapor cloud detonations was investigated by the Coast Guard 

in the late 1970s at the Naval Weapons Center at China Lake, California. These experiments, as 

well as other subsequent tests, are mentioned in Appendix C of the Sandia National Laboratories 

report entitled, Guidance on Risk Analysis and Safety Implications of a Large Liquefied Natural 

Gas (LNG) Spill Over Water, December 2004 (2004 Sandia Report). Using methane, the 

primary component of natural gas, several experiments were conducted to determine if 

unconfined vapor clouds would detonate. The tests indicated unconfined methane-air mixtures 

could be ignited, but no test produced unconfined detonation. There is no evidence suggesting 

that methane-air mixtures will detonate in unconfined open areas. 

Further tests were conducted in the late 1970s to examine the level of sensitivity of an 

unconfined cloud to the presence of heavier hydrocarbons such as ethane and propane. As stated 

in Section 5 of Appendix C of the 2004 Sandia Report, detonation sensitivity is affected by the 

level of refinement of natural gas stored as LNG. The series of tests on ambient-temperature fuel 

mixtures of methane-ethane and methane-propane indicated that the addition of heavier 

hydrocarbons influenced the tendency of an unconfined vapor cloud to detonate. Less processed 

product with greater amounts of heavier hydrocarbons is more sensitive to detonation. During 

these experiments, all successful detonations were initiated with an explosive charge in wellmixed vapor clouds at correct stoichiometric proportions. These are not representative of 

conditions which would be expected during a large-scale LNG spill. The precise timing, 

necessary mixing, and required amount of initiating explosives render the possibility for 

detonation of a large unconfined vapor cloud as unrealistic. Detonation of the unconfined 

natural gas cloud is extremely difficult to achieve and is generally considered by scientists and 

researchers to be very unlikely to occur during an LNG spill. 

Consequently, the primary hazards to the public from an LNG spill either on land or water would 

be from dispersion of the flammable vapors or from radiant heat generated by a pool fire. 

4.12.2 Front-End Engineering Design Review 

As part of its application and in response to the FERC staff’s data requests, Jordan Cove 

provided a front-end engineering design (FEED) for its proposed project. The FEED and 

technical review emphasizes the engineering design and the safety concepts as well as the 

projected operational reliability of the proposed facilities. The principal areas of coverage 

include: materials in cryogenic environments; insulation systems; cryogenic safety; 

thermodynamics; heat transfer; instrumentation; cryogenic processes; and other relevant safety 

systems. 

In the course of the application review, FERC staff has evaluated information for the proposed 

design and installation of the Jordan Cove LNG import terminal. As a result of the technical 

review of the information provided by Jordan Cove in the submittal documents, a number of 

concerns were identified by FERC staff relating to the reliability, operability, and safety of the 

proposed design. In response to staff’s questions, Jordan Cove provided written responses prior 

to the technical conference held on December 12, 2007. However, 20 of Jordan Cove’s 

responses indicated that corrections or modifications would be made to the design in order to 

address issues raised in the information request. As a result, we recommend that: 

• Jordan Cove should provide information/revisions related to the 20 responses to the 

October 31, 2007 Engineering Information Request, which stated that corrections or 
4.12-5 4.12 – Reliability and Safety

modifications would be made to the design. The final design should specifically 

address response numbers 3, 9, 10, 16, 17, 26, 31, 37, 38, 39, 43, 62, 63, 64, 65, 68, 69, 

70, 71, and 74 using management of change procedures. 

On January 17, 2008, FERC issued another information request to Jordan Cove regarding design 

concerns that arose as a result of discussions at the technical conference. On March 28, 2008, 

Jordan Cove submitted revisions to the FEED to address those issues. However, three of the 

responses did not completely resolve the issues. Request item 2(g) indicated that the design 

should provide a minimum flow recycle line from the sendout pumps to the storage tanks. The 

revised FEED submitted by Jordan Cove instead provides a minimum flow recycle line from the 

sendout pumps to the boiloff gas condenser. Staff has concerns that this arrangement could 

allow the low pressure system to overpressurize due to the limited capacity of the condenser 

vessel. In addition, request item 2(h) indicated that LNG from relief valves and pressurized 

drains should be returned to storage. The revised FEED submitted by Jordan Cove instead 

directs LNG from pressurized drains and relief valves to a blow down drum. Staff has concerns 

that, in the case of significant drainage or liquid relief, this arrangement may allow LNG to 

overflow the drum and enter the vapor system. Lastly, request item 2(i) indicated that the design 

should not provide a pneumatically operated drain/bypass valve at the inlet to each vaporizer. 

The revised FEED submitted by Jordan Cove eliminates the entire drain/bypass line without 

describing other provisions for draining the vaporizers. 

As comments on the draft EIS, Jordan Cove proposed design modifications that address the 

following: the minimum flow recycle line from the sendout pumps to the LNG storage tanks; the 

discharge of relief valves and pressurized drains to the LNG storage tanks; and the draining of 

LNG from each vaporizer. These design modifications include: 

• the addition of a minimum flow recycle line from the sendout pumps to the LNG storage 

tanks in which the piping would have the same pressure and temperature rating as the 

pump discharge; 

• the outlet of the blowdown drum, which encompasses the discharge of relief valves and 

pressurized drains, would be routed to the LNG storage tanks; and 

• the manual bypass around the thermal relief valve would be used to remove LNG from 

each vaporizer. 

FERC staff believes the proposed design modifications would resolve the issues as described 

above. Therefore, we recommend that: 

• The final design should include the modifications to the minimum flow recycle line, 

the outlet of the blowdown drum, and the manual bypass for each vaporizer as 

specified in Jordan Cove’s December 5, 2008 responses to the draft EIS. 

The FEED and specifications submitted for the proposed facilities to date are considered to be 

preliminary but would be the basis for any detailed design to follow. A significant amount of the 

design involving final selection of equipment manufacturers, process conditions, and resolution 

of some safety related issues would be completed in the next phase of the project development if 
4.12-6 4.12 – Reliability and Safety

authorization is granted by the Commission. This information would need to be filed with the 

Secretary for review and written approval by the Director of OEP. 

In addition, several areas of concern related to the LNG terminal design and construction details 

have been noted and require additional consideration and/or action by the company. As a result, 

we are making recommendations to address these issues and ensure that appropriate features and 

modifications would be incorporated into the facility design to enhance the safety and operability 

of the proposed LNG storage facility. Compliance with these recommendations would need to 

be demonstrated by Jordan Cove prior to later stages of project development. Therefore, we 

recommend that: 

The following measures should apply to the Jordan Cove LNG terminal. Information 

pertaining to these specific recommendations should be filed with the Secretary for review 

and approval by the Director of OEP either prior to initial site preparation; prior to 

construction of final design; prior to commissioning; or prior to commencement of service, 

as indicated by each specific condition. Specific engineering, vulnerability, or detailed 

design information meeting the criteria specified in Order No. 683 (Docket No. RM06-24-

000), including security information, should be submitted as critical energy infrastructure 

information (CEII) pursuant to 18 CFR 388.112. See Critical Energy Infrastructure 

Information, Order No. 683, 71 Fed. Reg. 58,273 (October 3, 2006), FERC Stats. & Regs. ¶ 

31,228 (2006). Information pertaining to items such as offsite emergency response; 

procedures for public notification and evacuation; and construction and operating 

reporting requirements would be subject to public disclosure. All information should be 

submitted a minimum of 30 days before approval to proceed is required. 

• Complete plan drawings and a list of the hazard detection equipment should be filed 

prior to initial site preparation. The list should include the instrument tag number, 

type and location, alarm locations, and shutdown functions of the proposed hazard 

detection equipment. Plan drawings should clearly show the location of all detection 

equipment. 

• Jordan Cove should provide a technical review of its proposed facility that: 

a. identifies all combustion/ventilation air intake equipment and the distances to 

any possible hydrocarbon release (LNG, flammable refrigerants, flammable 

liquids and flammable gases); and 

b. demonstrates that these areas are adequately covered by hazard detection 

devices and indicates how these devices would isolate or shutdown any 

combustion equipment whose continued operation could add to or sustain an 

emergency. 

Jordan Cove should file this review prior to initial site preparation. 

• Complete plan drawings and a list of the fixed and wheeled dry-chemical, fire 

extinguishing, and other hazard control equipment should be filed prior to initial 

site preparation. The list should include the equipment tag number, type, size, 

equipment covered, and automatic and manual remote signals initiating discharge 

of the units. Plan drawings should clearly show the planned location of all fixed and 

wheeled extinguishers. 
4.12-7 4.12 – Reliability and Safety

• Facility plans showing the proposed location of, and area covered by, each monitor, 

hydrant, deluge system, hose, and sprinkler, as well as piping and instrumentation 

diagrams, of the firewater system should be filed prior to initial site preparation. 

• A copy of the hazard design review and list of recommendations that are to be 

incorporated in the final facility design should be filed prior to initial site 

preparation. 

• Drawings of the storage tank piping support structure and support of horizontal 

piping at grade should be filed prior to initial site preparation. 

• Procedures should be developed for offsite contractors’ responsibilities, restrictions, 

and limitations and for supervision of these contractors by Jordon Cove staff, prior 

to initial site preparation. 

• Complete plan drawings of the security fencing and of facility access and egress 

should be provided prior to initial site preparation. 

• The P&IDs in the final design should show and number all valves including drain, 

vent, main, and car sealed. 

• The final design should specify that piping and equipment that may be cooled with 

liquid nitrogen are designed for liquid nitrogen temperatures, with regard to 

allowable movement and stresses. 

• The final design should include a hazard and operability review of the completed 

design. A copy of the review and a list of the recommendations should be filed. 

• The final design should specify that the LNG tank carbon steel piping support plates 

and connections to piping supports should be designed to ensure that corrosion 

protection is adequately provided and provisions for corrosion monitoring and 

maintenance of carbon steel attachments are to be included in the design and 

maintenance procedures. 

• The final design of the tank foundation should include an inclinometer, 

instrumented to record and display tank settlement, and a minimum of eight 

permanent reference points, equally spaced around the base for elevation survey 

measurement. 

• The final design should include details of the LNG tank tilt settlement and 

differential settlement limits between each LNG tank and its piping, as well as 

procedures to be implemented in the event that those limits are exceeded. 

• The final design should include detailed drawings of the spill control system to be 

applied to the LNG tank roof. 

• The final design should include details of the BOG gas temperature measurement 

for each tank. 

• The final design should specify that the first isolation valve at the inlet to the 

sendout pumps would be a weld end shutoff valve. In the case that flanged valves 

are specified, the sendout system should be shutdown in the event of a leak. 

• The final design should specify that the first isolation valve at the inlet to the 

deethanizer feed pumps will be a weld end shutoff valve. In the case that flanged 

valves would be specified, the deethanizer system should be shutdown in the event of 

a leak. 

• The final design should specify that the first isolation valve at the inlet to the NGL 

product pumps will be a weld end shutoff valve. In the case that flanged valves 

would be specified, the NGL system should be shutdown in the event of a leak. 
4.12-8 4.12 – Reliability and Safety

• The final design should provide provisions to shutdown the sendout pumps in the 

event that the discharge flow falls below the minimum recommended flow specified 

by the manufacturer. 

• The final design should specify that dual low low temperature elements and 

shutdown are to be provided at the discharge of the vaporizers. 

• The final design should include a pilot relief valve or operated vent valve sized for 

thermal relief at the discharge of each vaporizer, upstream of the isolation valves. 

• The final design should include P&IDs and drawings of the natural gas meter 

station. 

• The final design should include P&IDs and drawings of the NGL product meter 

station. 

• The final design of the vapor return system should specify that the vapor inlet 

piping to the desuperheater knockout drum, should be designed to ensure that 

LNG, from the desuperheater and LNG piping discharging to the drum, cannot 

back flow to the vapor return piping. 

• The final design should specify that all drains from high-pressure LNG systems are 

to be equipped with double isolation and bleed valves. 

• The final design should include piping specifications that include pressure ratings 

that are consistent with standard ratings of the flange classes proposed for the 

facility. 

• The piping specifications for the final design should specify that the minimum 

temperature for all piping in cryogenic service should be -325 °F. 

• The final design should specify that for LNG and natural gas service, branch piping 

and piping nipples less than 50mm (2 inches), should be no less than schedule 160. 

• The layout and elevation drawings of the process equipment that are appropriate 

for the proposed operation and maintenance of the facility should be included in the 

final design and filed with the FERC at the time that the EPC contractor issues the 

drawing for review. This milestone should be included in the project schedule. 

• The final design should include provisions for the future installation of an LNG 

pump for the desuperheater knockout drum. 

• The final design should include provisions for the future installation of an LNG 

pump for the BOG compressor suction drum. 

• The final design should specify that the vapor inlet piping to the BOG compressor 

suction drum should be designed to ensure that LNG, from the desuperheater and 

LNG piping discharging to the drum, cannot back flow to the vapor return piping. 

• The final design should ensure that the LNG spray control valve at the 

desuperheater, upstream of the BOG compressor suction drum and the associated 

controls are designed to prevent operation when boiloff vapor is not flowing through 

the drum. 

• The final design should include provisions to install temporary high pressure boiloff 

compression in the event that sendout operation is curtailed, or ceased for a period 

in excess of 30 days. Details should include plans and drawings of the BOG 

recovery system and specifications of the equipment and compressors to be 

installed. 
4.12-9 4.12 – Reliability and Safety

• The final design should specify that the design pressure of sendout equipment 

containing LNG in low pressure service should be not less than the design pressure 

of the piping system. 

• The final design should specify that LNG relief valves and LNG drains should not 

discharge into the vapor system. 

• The final design should include provisions to control venting of the deethanizer 

system to the flare vent. 

• The final design of the blow down drum should include a fail closed shutoff valve in 

the drain line, actuated by low temperature in the drum. 

• The final design should provide each LNG pump suction vessel with a pressure 

relief valve. 

• The final design should specify that, in addition to meeting the electrical design and 

installation code requirements for the Class 1 Group D hazardous area classification 

of the LNG pump area, vaporizer LNG inlet and outlet piping areas, the operating 

and maintenance for these areas procedures should be in accordance with Class 1 

Group D, Division 1. 

• The final design should include details of the air gaps to be installed downstream of 

all seals or isolations installed at the interface between a flammable fluid system and 

an electrical conduit or wiring system. Each air gap should vent to a safe location 

and be equipped with a leak detection device that should continuously monitor for 

the presence of a flammable fluid; should alarm the hazardous condition; and 

should shutdown the appropriate systems. 

• The final design of the hazard detection equipment should identify manufacturer 

and model. 

• The final design should specify that all hazard detection equipment should include 

redundancy and fault detection as well as fault alarm monitoring in all potentially 

hazardous areas and enclosures. 

• The final design of the fixed and wheeled dry-chemical, fire extinguishing and high 

expansion foam hazard control equipment should identify manufacturer and model. 

• The final design should include an updated fire protection evaluation carried out in 

accordance with the requirements of NFPA 59A 2001, chapter 9.1.2. 

• The final design of the firewater system should include provisions to measure and 

record the discharge flow and pressure from each of the firewater pumps. 

• The final design should include emergency shutdown of equipment and systems 

activated by hazard detection devices for flammable gas, fire, and cryogenic spills, 

when applicable. 

• The final design should include details of the shut down logic, including cause and 

effect matrices for alarms and shutdowns. 

• The final design should specify that all ESD valves are to be equipped with open and 

closed position switches connected to the DCS/SIS. 

• The final design of the BOG compressor shelter/building should provide permanent 

protection of the equipment and operating and maintenance personnel from adverse 

weather conditions. The design details and procedures to record and to prevent the 

tank fill rate from exceeding the maximum fill rate specified by the tank designer 

should be filed prior to commissioning. 
4.12-10 4.12 – Reliability and Safety

• The maintenance procedures to be filed prior to commissioning should state that a 

foundation elevation survey of all LNG tanks should be made on an annual basis. 

• All valves including drain, vent, main, and car sealed, or locked valves should be 

tagged in the field during construction and prior to commissioning. 

• A tabulated list of the proposed hand-held fire extinguishers should be filed prior to 

commissioning. The information should include a list with the equipment number, 

type, size, number, and location. Plan drawings should include the type, size, and 

number of all hand-held fire extinguishers. 

• Operation and maintenance procedures and manuals, as well as safety procedure 

manuals, should be filed prior to commissioning. 

• The contingency plan for failure of the LNG tank outer containment should be filed 

prior to commissioning. 

• A copy of the criteria for horizontal and rotational movement of the inner LNG 

storage tank for use during and after cooldown should be filed prior to 

commissioning. 

• The FERC staff should be notified of any proposed revisions to the security plan 

and physical security of the facility prior to commencement of service. 

• Progress on construction of the project should be filed in monthly reports. Details 

should include a summary of activities, projected schedule for completion, problems 

encountered and remedial actions taken. Problems of significant magnitude should 

be reported to the FERC within 24 hours. 

In addition, we recommend that the following measures should apply throughout the life of 

the LNG facility: 

• The facility should be subject to regular FERC staff technical reviews and site 

inspections on at least an annual basis or more frequently as circumstances indicate. 

Prior to each FERC staff technical review and site inspection, Jordan Cove should 

respond to a specific data request including information relating to possible design 

and operating conditions that may have been imposed by other agencies or 

organizations. Up-to-date detailed piping and instrumentation diagrams reflecting 

facility modifications and provision of other pertinent information not included in 

the semi-annual reports described below, including facility events that have taken 

place since the previously submitted semi-annual report, should be included. 

• Semi-annual operational reports should be filed with the Secretary to identify 

changes in facility design and operating conditions, abnormal operating experiences, 

activities (including LNG carrier arrivals, quantity and composition of imported 

LNG, vaporization quantities, boil-off/flash gas, etc.), plant modifications including 

future plans and progress thereof. Abnormalities should include, but not be limited 

to: unloading/carrier problems, potential hazardous conditions from offsite vessels, 

storage tank stratification or rollover, geysering, storage tank pressure excursions, 

cold spots on the storage tanks, storage tank vibrations and/or vibrations in 

associated cryogenic piping, storage tank settlement, significant equipment or 

instrumentation malfunctions or failures, non-scheduled maintenance or repair 

(and reasons therefore), relative movement of storage tank inner vessels, vapor or 

liquid releases, fires involving natural gas and/or from other sources, negative 

pressure (vacuum) within a storage tank, and higher than predicted boiloff rates. 
4.12-11 4.12 – Reliability and Safety

Adverse weather conditions and the effect on the facility should also be reported. 

Reports should be submitted within 45 days after each period ending June 30 and 

December 31. In addition to the above items, a section entitled "Significant plant 

modifications proposed for the next 12 months (dates)" should also be included in 

the semi-annual operational reports. Such information would provide the FERC 

staff with early notice of anticipated future construction/maintenance projects at the 

LNG facility. 

• In the event the temperature of any region of any secondary containment becomes 

less than the minimum specified operating temperature for the material, the 

Commission should be notified within 24 hours and procedures for corrective action 

should be specified. 

• Significant non-scheduled events, including safety-related incidents (i.e., LNG or 

natural gas releases, fires, explosions, mechanical failures, unusual over 

pressurization, and major injuries) and security-related incidents (i.e., attempts to 

enter site, suspicious activities) should be reported to FERC staff. In the event an 

abnormality is of significant magnitude to threaten public or employee safety, cause 

significant property damage, or interrupt service, notification should be made 

immediately, without unduly interfering with any necessary or appropriate 

emergency repair, alarm, or other emergency procedure. In all instances, 

notification should be made to Commission staff within 24 hours. This notification 

practice should be incorporated into the LNG facility's emergency plan. Examples 

of reportable LNG-related incidents include: 

a. fire; 

b. explosion; 

c. estimated property damage of $50,000 or more; 

d. death or personal injury necessitating in-patient hospitalization; 

e. free flow of LNG that results in pooling; 

f. unintended movement or abnormal loading by environmental causes, such as an 

earthquake, landslide, or flood, that impairs the serviceability, structural 

integrity, or reliability of an LNG facility that contains, controls, or processes 

gas or LNG; 

g. any crack or other material defect that impairs the structural integrity or 

reliability of an LNG facility that contains, controls, or processes gas or LNG; 

h. any malfunction or operating error that causes the pressure of a pipeline or 

LNG facility that contains or processes gas or LNG to rise above its maximum 

allowable operating pressure (or working pressure for LNG facilities) plus the 

buildup allowed for operation of pressure limiting or control devices; 

i. a leak in an LNG facility that contains or processes gas or LNG that constitutes 

an emergency; 

j. inner tank leakage, ineffective insulation, or frost heave that impairs the 

structural integrity of an LNG storage tank; 

k. any condition that could lead to a hazard and cause a 20 percent reduction in 

operating pressure or shutdown of operation of a pipeline or an LNG facility; 

l. safety-related incidents to LNG carriers at or en route to and from the LNG 

facility; or 
4.12-12 4.12 – Reliability and Safety

m. an event that is significant in the judgment of the operator and/or management 

even though it did not meet the above criteria or the guidelines set forth in an 

LNG facility’s incident management plan. 

In the event of an incident, the Director of OEP has delegated authority to take 

whatever steps are necessary to ensure operational reliability and to protect human 

life, health, property or the environment, including authority to direct the LNG 

facility to cease operations. Following the initial company notification, Commission 

staff would determine the need for an on-site inspection by Commission staff, and 

the timing of an initial incident report (normally within 10 days) and follow-up 

reports. 

4.12.3 Storage and Retention Systems 

LNG storage tanks come in a variety of categories. The following are descriptions of the tank 

designs most commonly used worldwide: 

• single containment cylindrical metal tanks (predominantly used in the United States); 

• spherical storage tanks (predominantly used in LNG carriers); 

• double containment cylindrical metal inner tank and metal or concrete outer tank 

(commonly thought of as an LNG tank with a high wall dike); 

• full containment cylindrical metal inner tank and metal or concrete outer tank (several 

authorized by the Commission; several applications currently proposed to the 

Commission, including this project); 

• pre-stressed cylindrical concrete tank with an internal metal membrane (membrane tank) 

(none in the United States); and 

• cryogenic cylindrical concrete tank, internal cryogenic tank, and pre-stressed concrete 

outer tank (one operational in the United States; the remainder worldwide). 

Single-, double-, and full-containment LNG storage tanks have been authorized by the FERC for 

use at new LNG import facilities or expansions of existing terminals. Although historically only 

single- and double-containment tanks have been constructed and operated at FERC regulated 

facilities, approximately 50 full-containment tanks have been constructed worldwide. In July of 

2008, the Freeport LNG terminal in Freeport, TX went into operation and become the first FERC 

regulated facility to use full-containment tanks. In addition, several other full-containment tanks 

are under construction in the United States and are expected to be operational in the near future. 

During the review of earlier proposals, a number of issues surfaced concerning the applicability 

of existing codes and regulations for full-containment tanks. Specifically, the term “full 

containment” does not appear in the Federal Safety Standards in 49 CFR 193. As a result, some 

project proponents have made the assumption that to design and construct a full-containment 

tank in accordance with European Standard 1473 - Installation and Equipment for Liquefied 

Natural Gas - Design of Onshore Installations (EN 1473) would satisfy the U.S. codes and 

standards. 

For example, it has been suggested that thermal exclusion zones are not required for a fullcontainment tank because EN 1473 does not consider a tank fire scenario for full-containment 

tanks with a pre-stressed concrete wall and concrete roof. The staffs of the FERC and the DOT 

do not agree because Part 193 does not exclude full-containment tanks from thermal exclusion 
4.12-13 4.12 – Reliability and Safety

zone requirements. As a result, a thermal exclusion zone analysis is required for an LNG storage 

tank fire at the top of the secondary container (see section 4.12.4 Siting Requirements). 

Further, EN 1473 does not specify a minimum distance to the property line for full-containment 

tanks because no tank fire scenario is considered. However, NFPA 59A, 2001 edition, requires a 

separation of 0.7 times the tank diameter from the property line. Jordan Cove’s proposed tank 

separation distance to the property line meets this separation requirement. 

Another issue regarding the full-containment design is that the tank outer wall (secondary 

containment) serves as the impoundment, a concept allowed under Parts 193.2161 and 193.2167, 

and under the “exception” on figure 2.2.2-6 of NFPA 59A, 2001 edition. A specific concern is 

the dual function of the concrete secondary container - it serves both the operational function of 

holding the insulation and gas pressure, and a safety function of containing liquid in the event of 

an inner tank failure. Conversely, in single- and double-containment tanks, independent systems 

provide operational and safety functions. While recognition must be given to the benefits of a 

concrete secondary container with respect to external events, such as projectiles or small aircraft, 

its ability to provide the dual functions while retaining its integrity has not been convincingly 

supported for all scenarios. This becomes increasingly important as proposed site acreage is 

reduced and buffer zones between adjacent properties are minimized. As such, the FERC staff 

considers it prudent design practice to provide some form of barrier to prevent liquid from 

flowing to an unintended area (i.e., outside the plant property) in the event that the storage tank 

primary and secondary containers fail. Jordan Cove has proposed a storm surge barrier around 

the LNG storage tanks that would confine the LNG to the terminal site if a hypothetical 

catastrophic event would occur. The storm surge barrier’s volumetric capacity would contain a 

single LNG tank’s maximum liquid capacity. 

Concerns have been expressed that the barrier could be considered a containment and prohibit 

certain equipment being located within the barrier and/or may conflict with other parts of the 

various codes with respect to hazardous and electrical code classifications. Other concerns are 

that the barrier could be considered an impounding area that would require new thermal and 

vapor cloud calculations. The purpose of the barrier is to prevent liquid from flowing off the 

plant property, and it is not the intent to define a containment or impounding area for thermal 

radiation or flammable vapor exclusion zone calculations or other code requirements. 

The proposed terminal would be designed to withstand the effects of hurricane force winds, 

storm surges, and flooding. Moffatt & Nichol International performed a wind study for Jordan 

Cove using wind data from two weather stations operated by the National Oceanic and 

Atmospheric Administration and the National Weather Service. Wind speeds ranged from zero 

mph (no wind) to 28 mph. Three excessive wind speeds that have been recorded at these stations 

were between 100 mph and 130 mph. Therefore, the LNG storage tanks and other critical 

structures and facilities would be designed for a wind velocity of 150 mph per the requirements 

of 49 CFR 193.2067. Non-critical portions of the terminal would be designed to a wind speed of 

85 mph, as referenced in Section 6 of ASCE-7. Jordan Cove would also incorporate several 

flood control techniques such as shore protection features, a storm surge barrier that surrounds 

the LNG storage tanks, and a storm water collection/drain system to collect and remove rain and 

flood water from the terminal site. 
4.12-14 4.12 – Reliability and Safety

The terminal site elevations were established by reviewing the DOGAMI’s tsunami maps for the 

local area that includes the proposed terminal site. The proposed elevation for the LNG storage 

tanks would be +20 feet from mean sea level and would be surrounded by an earthen storm surge 

barrier with an elevation of +55 feet. The top of the unloading platform would be set at an 

elevation of +30 feet. The main processing equipment, control room and administration 

buildings would be located at an elevation of +55 feet. Jordan Cove believes that with the flood 

control techniques described above and the various site elevations, the terminal site would be 

adequately designed to withstand the effects of hurricanes and storm events experienced in this 

area. Based on the site elevations and plant design, the FERC staff believes the terminal would 

be able to withstand the effects of hurricane force winds, storm surges, and flooding. 

Jordan Cove also believes that the storm surge barrier with a crest at +55 feet elevation would 

provide sufficient protection from a tsunami. Jordan Cove provided modeling that confirmed 

this design assumption in a filing with the FERC on December 1, 2008. 

4.12.4 Siting Requirements 

4.12.4.1 Regulatory Requirements 

The LNG facilities proposed in this project must comply with the siting requirements of 49 CFR 

193, Subpart B. On March 30, 2000, the DOT revised 49 CFR 193 to incorporate the 1996 

edition of NFPA 59A into the LNG regulations. On April 9, 2004, the DOT further revised 49 

CFR 193 to incorporate the 2001 edition of NFPA 59A. The following sections specifically 

address siting requirements: 

• Part 193.2001, Scope of part, excludes any matter other than siting provisions 

pertaining to marine cargo transfer systems between the marine carrier and the last 

manifold or valve immediately before a storage tank; 

• Part 193.2051, Scope, states that each LNG facility designed, replaced, relocated or 

significantly altered after March 31, 2000, must be provided with siting requirements in 

accordance with subpart B and NFPA 59A, 2001 edition. In the event of a conflict with 

NFPA 59A, then Part 193 prevails;

• Part 193.2057, Thermal radiation protection, requires that each LNG container and 

LNG transfer system have thermal exclusion zones based on three radiation flux levels in 

accordance with section 2.2.3.2 of NFPA 59A, 2001 edition;

• Part 193.2059, Flammable vapor-gas dispersion protection, requires that each LNG 

container and LNG transfer system have a dispersion exclusion zone in accordance with 

sections 2.2.3.3 and 2.2.3.4 of NFPA 59A, 2001 edition; and

• Part 193.2155(b), Structural requirements, specifies the minimum distance an LNG 

storage tank must be from the ends of an airport runway or from the nearest point on a 

runway, which ever is longer. 

For the following LNG facilities that are proposed in this project, we have identified the 

applicable siting requirements from Part 193 and NFPA 59A, 2001 edition: 

• two 1,006,000-barrel (160,000 m3) full containment LNG storage tanks - Parts 193.2057 

and 2059 require the establishment of thermal and flammable vapor exclusion zones for 

LNG tanks. NFPA 59A, 2001 edition, section 2.2.3.2 specifies four thermal exclusion 

zones based on the design spill and the impounding area. Sections 2.2.3.3 and 2.2.3.4 
4.12-15 4.12 – Reliability and Safety

specify a flammable vapor exclusion zone for the design spill which is determined with 

section 2.2.3.5. Part 193.2155 requires that an LNG storage tank must be at least 1 mile 

from the ends of an airport runway or 0.25 mile from the nearest point on a runway, 

which ever is longer; 

• one LNG carrier unloading berth and a marine cargo transfer system consisting of a total 

of four marine unloading arms, three 16-inch-diameter liquid transfer arms, and one 16-

inch-diameter vapor return arm. A 36-inch-diameter transfer line would carry the LNG 

to the onshore storage tanks - Parts 193.2001, 2057, and 2059 require thermal and 

flammable vapor exclusion zones for the transfer system. NFPA 59A, 2001 edition, does 

not address LNG transfer systems; 

• four 5,325 gpm in-tank pumps (two per tank with a spare pump column in each tank); 

and six 2,262 gpm sendout pumps - Parts 193.2057 and 2059 require thermal and 

flammable vapor exclusion zones. NFPA 59A, 2001 edition, section 2.2.3.2 specifies the 

thermal exclusion zone and section 2.2.3.3 and 2.2.3.4 specify the flammable vapor 

exclusion zone based on the design spill in a process area; 

• six SCVs - Same requirements as for LNG pumps; and 

The incorporation of the NFPA 59A requirements into Part 193 has resulted in some confusion 

and possible misinterpretation in applying the siting requirements. Parts 193.2057 and 2059 

require exclusion zones for LNG transfer systems, which are defined to include transfer piping. 

However, NFPA 59A only requires exclusion zones for “transfer areas” which are defined as the 

part of the plant where liquids are introduced or removed from the facility such as truck loading 

or vessel unloading areas. The definition of transfer area in NFPA 59A specifically excludes 

permanent plant piping such as cargo transfer lines. Additionally, NFPA 59A Section 2.2.3.1 

specifically excludes transfer area at the water edge of marine terminals. When the DOT 

originally incorporated NFPA 59A into its regulations, it removed the requirement for 

impounding systems around transfer piping (old Part 193.2149). In the preamble to the final 

rule, the DOT determined that the most likely sources of leaks within an LNG plant are LNG 

storage tanks, cargo transfer areas, and vaporizers and process equipment, which are all 

addressed in NFPA 59A Section 2.2.1.2. The result is that while Part 193 retains exclusion 

zones for LNG transfer systems, neither Part 193 nor NFPA 59A requires the impoundment from 

which to base the calculations. We do not believe that this was the intent, nor do we believe that 

omitting containment for transfer piping is a sound engineering practice. The FERC staff will 

continue to require containment for all LNG transfer piping within a plant site. 

The incorporation of NFPA 59A also changed the way in which design spills and impoundment 

capacities may be determined. Under Section 2.2.2.2, the capacity of impounding areas for 

vaporization, process, or LNG transfer areas must equal the greatest volume during a 10-minute 

period from any single accidental leakage source or during a shorter time period based upon 

demonstrable surveillance and shutdown provisions acceptable to the authority having 

jurisdiction. Similar criteria appear in Section 2.2.3.5 for determining the design spill used in 

thermal and flammable vapor exclusion zone calculations. Prior to the incorporation of NFPA 

59A the design spill in Part 193 assumed the rupture of a single transfer pipe with the greatest 

overall flow capacity, for not less than 10 minutes (old Part 193.2059(d)). As a result, the spill 

rate for vaporization, process, or LNG transfer areas may be assumed to be a "leakage source" 

rather than a full pipe rupture; however, the spill duration must be 10 minutes unless the 

authority having jurisdiction (i.e., DOT’s PHMSA), determines that a shorter time is acceptable. 
4.12-16 4.12 – Reliability and Safety

Again, given the confusion in applying the two requirements, the FERC staff will continue to 

utilize the 10-minute spill criteria at the maximum flow possible for containment sizing. This 

will ensure that impoundments are sized for a catastrophic failure, while recognizing that less 

conservative spill scenarios may be appropriate to calculate exclusion zones. In giving 

recognition to the integrity of all-welded transfer piping, the determination of the single 

accidental leakage source should be based on an evaluation of all small diameter attachments to 

the transfer piping for instrumentation, pressure relief, recirculation, etc., and any flanges that 

may be used at valves or other equipment, in order to determine the largest spill rate. This 

approach is the result of discussion with DOT’s staff concerning the basis for design spills and 

application to exclusion zone determinations for proposals before the Commission. 

We received a comment that the siting requirements of 49 CFR 193 only govern the onshore part 

of the facility, and there are no mandated exclusion zones around the ships that serve the facility. 

The Coast Guard, as the federal agency responsible for matters related to maritime security, 

navigation safety, and vessel engineering and safety standards, has examined the use of 

mandated exclusion zones around LNG marine traffic under docket number USCG-2004-19615. 

The Coast Guard determined that exclusion zone regulations were not necessary as risks to the 

public from transportation systems are managed with “a combination of preventative and 

mitigation measures, including design standards, operational procedures, safety and security 

regulations, etc.” In addition, the Coast Guard referred to NVIC 05-05 which establishes a 

comprehensive review process by which the Coast Guard, in conjunction with stakeholders at the 

port, could ensure all safety and security issues have been addressed relating to the marine 

transportation of LNG for a proposed waterfront LNG facility. In its response to the petitions 

under docket number USCG-2004-19615, the Coast Guard stated that the risk-based approach in 

NVIC 05-05 was more appropriate than the issuance of regulations establishing thermal and 

vapor dispersion exclusion zones for marine spills of LNG. Although NVIC 05-05 was 

cancelled in December 2008, the Coast Guard issued NVIC 05-08, “Guidance Related to 

Waterfront Liquefied Natural Gas (LNG) Facilities” which incorporates the same risk-based 

approach. The Coast Guard’s review process and conclusions are further discussed in section 

4.12.5.5. 

4.12.4.2 Impoundment Systems and Design Spills 

Part 193.2181 specifies that each impounding system serving an LNG storage tank must have a 

minimum volumetric liquid capacity of 110 percent of the LNG tank’s maximum design liquid 

capacity for an impoundment serving a single tank. Jordan Cove proposes two full-containment 

LNG storage tanks in which the outer tank wall serves as the impoundment system. The 

volumetric capacity of the outer concrete wall would be 55,571,711 gallons, which would exceed 

the 110 percent requirement. 

The process area impoundment basin would be located in the tank area, and spills from the LNG 

tanks, process area equipment, and portions of the unloading line would be routed to the process 

area impoundment basin by a series of collection troughs. The marine area impoundment basin 

would be located along the transfer line, and spills from the majority of the unloading line would 

be routed to the marine area impoundment basin. Both impoundment basins would be sized for a 

full-rupture of the 36-inch-diameter unloading line. A spill from this line over a 10-minute 

period would result in a spill volume of 528,400 gallons at the maximum unloading rate of 

52,840 gpm (12,000 m3

/hr). Jordan Cove used this volume in the sizing of the process area 
4.12-17 4.12 – Reliability and Safety

impoundment basin and the marine area impoundment basin. Both impoundment basins’ 

dimensions were designed to be 65 feet long by 65 feet wide, with a depth of 20 feet. This gives 

an available sump capacity of 632,060 gallons. A 10-minute spill from the unloading line would 

be completely contained by either impoundment basin. 

The proposed terminal would also be designed to provide drainage of water to disposal areas in 

accordance with 49 CFR 193.2173. Drainage and disposal of water would be accomplished by a 

series of ditches and swales. Water that is collected within the curbed LNG containment areas 

would be directed by gravity to the LNG impoundment trenches and eventually to the 

impoundment basins. Pumps in the impoundment basins would remove the water at a rate equal 

to or greater than 25 percent of the 10-year frequency, one-hour duration storm. The pumps 

would discharge the water into the firewater pond for disposal. The pumps would be 

automatically operated via level control and would be interlocked using low temperature 

detectors to prevent the pumps from operating if LNG would be present. 

4.12.4.3 Design Spills 

The calculation of thermal and flammable vapor exclusion zones for the proposed LNG facility 

are based on the dimensions of the proposed spill containment systems and the design spills 

according to 49 CFR 193 and NFPA 59A, 2001 edition. In accordance with section 2.2.3.5 of 

NFPA 59A, 2001 edition, the design spill for an LNG storage tank with no penetrations below 

the liquid level is defined as the largest flow from any single line that could be pumped into the 

impounding area with the tank withdrawal pumps considered to be operating at full rated 

capacity over a 10-minute period. For the proposed design, this would be a guillotine rupture of 

the discharge header of the in-tank pumps. Because each pump is rated at 5,325 gpm and there 

are two pumps per tank, the resulting 10-minute design spill would be 106,500 gallons. This 

spill would be completely contained by the process area impoundment basin. 

NFPA 59A, 2001 edition, section 2.2.3.5 also defines design spills for impounding areas serving 

only vaporization, process, or LNG transfer areas as the flow from any single accidental leakage 

source for a 10-minute duration. In its analysis of the process area and marine area 

impoundment basins, Jordan Cove modeled a design spill of a 2-inch hole in the unloading line 

at a rate of 1,653 gpm. This would result in a 10-minute spill volume of 16,530 gallons. This 

spill would be completely contained by either the process area impoundment basin or the marine 

area impoundment basin. The FERC staff reviewed the piping and instrumentation diagrams for 

small diameter attachments to determine a credible LNG spill into the process area and the 

marine area impoundment basins. A break in the 16-inch diameter in-tank pump header was 

determined to be the design spill for the process area impoundment basin. This 10-minute spill 

would generate a volume of 106,500 gallons and would be contained by the process area 

impoundment basin. The FERC staff also determined that a credible LNG spill into the marine 

area impoundment basin would result from a break of the 6-inch LNG recirculation line attached 

to the unloading line. This 10-minute spill would generate a volume of 80,880 gallons and 

would be contained by the marine area impoundment basin. 

Table 4.12.4.3-1 presents the impounding areas and spill size volumes used to determine 

adequate impounding capacity, as well as the design spills used in the thermal radiation and 

flammable gas dispersion modeling. 
4.12-18 4.12 – Reliability and Safety

TABLE 4.12.4.3-1 

Impoundment Areas

Source 

Spill Size 

(gallons) Impoundment System 

Impoundment Size

(gallons) 

Impoundment Sizing Spills: 

LNG Storage Tank 45,421,597 Outer Tank Concrete Wall 55,571,711 

Unloading Line (36-inch diameter) 528,400 Process Area or Marine Area 

Impoundment Basin 

632,060 

Design Spills: 

Hole in unloading line (2-inch diameter) 16,530 Marine Area Impoundment Basin 632,060 

In-tank pump discharge header (16-inch 

diameter) 

106,500 Process Area Impoundment Basin 632,060 

LNG recirculation line (6-inch diameter) 80,880 Marine Area Impoundment Basin 632,060 

4.12.4.4 Thermal Exclusion Zone 

If a large quantity of LNG is spilled in the presence of an ignition source, the resulting LNG pool 

fire could cause high levels of radiant heat in the area surrounding the impoundment. Exclusion 

distances for various flux levels were calculated according to 49 CFR 193.2057 and section 

2.2.3.2 of NFPA 59A, 2001 edition, using the "LNGFIRE III" computer program model 

developed by the Gas Research Institute. NFPA 59A, 2001 edition, establishes certain 

atmospheric conditions (0 mph wind speed, 70°F, and 50 percent relative humidity), which are to 

be used in calculating the distances. However, Part 193.2057 supersedes these requirements and 

stipulates that wind speed, ambient temperature, and relative humidity which produce the 

maximum exclusion distances must be used, except for conditions that occur less than 5 percent 

of the time based on recorded data for the area. For its analysis, Jordan Cove selected the 

following ambient conditions to produce the maximum distances: wind speed of 32 mph, 

ambient temperature of 27°F, and 60 percent relative humidity. The FERC staff agrees with the 

selection of these conditions and these conditions yield longer distances than the 0 mph wind 

speed, 70°F ambient temperature, and 50 percent relative humidity specified in NFPA 59A, 2001 

edition. 

Under 49 CFR 193.2057, the LNG storage tank impoundment must have a thermal exclusion 

zone in accordance with NFPA 59A, 2001 edition. The referenced section 2.2.3.2 of NFPA 59A, 

2001 edition, requires thermal radiation distances ranging from 1,600 to 10,000 British thermal 

units per square foot per hour (Btu/ft2

-hr) to be calculated for a volume of LNG determined in 

accordance with section 2.2.2.1 of NFPA 59A. 

Jordan Cove calculated thermal radiation distances for the 1,600, 3,000, and 10,000 Btu/ft2

-hr 

incident flux levels for an LNG storage tank impoundment fire. These calculations were verified 

by FERC staff. The calculations were based on the outer tank’s concrete wall diameter (275 

feet) as the pool diameter and the flame height equal to the top of the concrete wall (123 feet). 

The target height was set at ground level (0 feet). The resulting distances would be 482 feet for 

the 10,000 Btu/ft2

-hr zone; 776 feet for the 3,000 Btu/ft2-hr zone; and 967 feet for the 1,600 

Btu/ft2

-hr zone (see figure 4.12-1). The 10,000 Btu/ft2-hr zone would not extend off site, but 

portions of the 1,600 and 3,000 Btu/ft2

-hr zones would extend beyond the plant property line to 

the west and the south. 
4.12-19 4.12 – Reliability and Safety

Figure 4.12-1. Thermal Radiation Zones 

In addition, Jordan Cove calculated the thermal radiation distances for the 1,600 Btu/ft2

-hr 

incident flux level centered on the process area impoundment basin and the marine area 

impoundment basin. These calculations were verified by FERC staff. The 1,600 Btu/ft2-hr zone 

would extend 333 feet from the center of the process area impoundment basin and from the 

center of the marine area impoundment basin (see figure 4.12-1). The 1,600 Btu/ft2

/hr zone for 

the process area impoundment basin would not extend past the plant property line and therefore 

would be in compliance with 49 CFR 193.2057. The 1,600 Btu/ft2

-hr zone for the marine area 

impoundment basin would extend beyond the plant property line south over the LNG berth. 

Because portions of the 1,600 and 3,000 Btu/ft2

-hr thermal exclusion zones for the LNG storage 

tanks and the marine area impoundment basin extend beyond the plant property line, Jordan 

Cove entered into an option for an easement with the Oregon International Port of Coos Bay to 

satisfy the thermal exclusion zone requirements of 49 CFR 193.2057. This option for an 
4.12-20 4.12 – Reliability and Safety

easement would give Jordan Cove legal control over the portion of land that is required by DOT 

for siting purposes. Therefore, we recommend that:

• Prior to initial site preparation, Jordan Cove should file with the Secretary, for 

review and approval by the Director of OEP, finalized documentation of the 

easement agreement, which demonstrates that the thermal exclusion zones 

extending beyond the plant property line comply with 49 CFR 193.2007 and 

193.2057. 

Table 4.12.4.4-1 presents the maximum distances for the incident flux levels of 1,600, 3,000, and 

10,000 Btu/ft2

-hr. 

TABLE 4.12.4.4-1 

Thermal Exclusion Zones

Source 

Exclusion Area NFPA 59A, 2001 edition, 

section 2-2.3.2 a/

Incident 

Flux 

(Btu/ft2

/hr) a 

Exclusion Zone 

(feet) 

LNG Storage Tank Impoundment Outdoor assembly area occupied by 50 or more people. 1,600 967 

LNG Storage Tank Impoundment Off-site structures used for occupancies or residences. 3,000 776 

LNG Storage Tank Impoundment Property line that can be built upon. 10,000 482 

Process Area and Marine Area 

Impoundment Basin 

Outdoor assembly area occupied by 50 or more people. 1,600 333 

a/ The 1,600 Btu/ft2

/hr flux level is associated with an exposed person experiencing burns within about 30 seconds. At 

3,000 Btu/ft2

/hr, an exposed person would experience burns within 10 seconds; however, a wooden structure would not be 

expected to burn and affords protection to sheltered persons. At 10,000 Btu/ft2

/hr, clothing and wood can ignite spontaneously. 

4.12.4.5 Vapor Dispersion Zone 

A large quantity of LNG spilled without ignition would form a flammable vapor cloud that 

would travel with the prevailing wind until it either dispersed below the flammable limits or 

encountered an ignition source. Sections 2.2.3.3 and 2.2.3.4 of NFPA 59A, 2001 edition, and 

Part 193.2059 require that provisions be made to minimize the possibility of flammable vapors 

reaching a property line that can be built upon and that would result in a distinct hazard. Part 

193.2059 requires that dispersion distances be calculated for a 2.5 percent average gas 

concentration (one-half the lower flammability limit [LFL] of LNG vapor) under meteorological 

conditions which result in the longest downwind distances at least 90 percent of the time. 

Alternatively, maximum downwind distances may be estimated for stability Class F, a wind 

speed of 4.5 mph, 50 percent relative humidity, and the average regional temperature. The 

section allows the use of the DEGADIS (Dense Gas Dispersion) Model, or the FEM3A model, to 

compute dispersion distances. Design spills into impounding areas serving LNG containers, 

transfer systems, and piping are to be determined in accordance with section 2.2.3.5 of NFPA 

59A, 2001 edition. In accordance with section 2.2.3.3 of NFPA 59A, 2001 edition, an average 

concentration of methane in air of one-half of the LFL cannot cross the property line from a 

design spill into each tank impoundment. In this case, compliance with section 2.2.3.3 would 

also meet the requirements of section 2.2.3.4 of NFPA 59A, 2001 edition. 

In performing the vapor dispersion analysis for the process area and marine area impoundment 

basins as required by 49 CFR 193.2059, Jordan Cove selected a wind speed of 4.5 mph, an 

atmospheric temperature of 52°F, a relative humidity of 50 percent, and atmospheric stability 
4.12-21 4.12 – Reliability and Safety

Class F. Although we agree with the selection of humidity, temperature, and stability, wind 

speeds below 4.5 mph may occur at the site at least 90 percent of the time, based on our review 

of recorded data for the area. In its analysis of both the process area impoundment basin and the 

marine area impoundment basin, Jordan Cove modeled a 10-minute continuous spill of flow 

from a two-inch hole in the unloading line. This spill would result in a distance of 173 feet to the 

2.5 percent average gas concentration isopleths. The FERC staff determined the design spill for 

the process area impoundment basin would be the rupture of the 16-inch diameter in-tank pump 

header. This 10-minute design spill would generate a volume of 106,500 gallons and would 

result in a distance of 257 feet to the 2.5 percent average gas concentration isopleth. The FERC 

staff determined the design spill for the marine area impoundment basin would be a break of the 

6-inch-diameter recirculation line attached to the unloading line. This 10-minute design spill 

would generate a volume of 80,880 gallons and would be contained in the marine area 

impoundment basin. This spill would result in a distance of 217 feet to the 2.5 percent average 

gas concentration isopleths (see figure 4.12-2). 

Figure 4.12-2. Vapor Dispersion Zones 

We received a comment that using low wind speeds and stable atmospheric conditions in 

modeling an LNG release may not result in the maximum downwind dispersion distance. While 

higher wind speeds would tend to decrease the downwind dispersion distance, the associated 

“wind scooping” would tend to increase dispersion distances by increasing the source strength. 

The extent to which these effects would offset each other is not known. In addition, higher wind 

speeds generally correspond to more atmospheric instability, which will further reduce the 

downwind dispersion distance. To investigate the possible effects to the calculations, FERC 

staff adjusted the vapor production model to eliminate all vapor retention and used the resulting 
4.12-22 4.12 – Reliability and Safety

source production curve as input to DEGADIS. In addition, a range of low wind speeds 

occurring at least 90% of the time were modeled to determine the maximum downwind 

dispersion distance. 

Using this methodology for the source term for the process area impoundment, the maximum 

downwind dispersion distance was found to be at 4.7 mph (2.1 m/s) and would generate a 

distance of 600 feet to the 2.5 percent average gas concentration isopleth. Using the revised 

source term for the marine area impoundment basin, the maximum downwind dispersion 

distance was found to be at 4.7 mph (2.1 m/s) and would generate a distance of 600 feet to the 

2.5 percent average gas concentration isopleth. Due to the conservatism of this approach, we 

believe the dispersion distance would actually be shorter. While DEGADIS cannot depict terrain 

and actual geometries, calculations that take into account the obstruction of flow, such as from 

storage tanks and the earthen berm, would result in shorter dispersion distances due to enhanced 

turbulent mixing in the wake of such structures. In addition, the source term would be reduced 

by some vapor holdup. The use of low wind speeds in conjunction with a maximum source term 

also lengthens the dispersion distance calculated by the model. As a result, we believe that this 

method does not under-predict the downwind dispersion distances.

Because portions of the vapor dispersion exclusion zones calculated by Jordan Cove extended 

beyond the plant property line, Jordan Cove entered into an option for an easement with the Port 

to satisfy the vapor exclusion zone requirements of 49 CFR 193.2059. This option for an 

easement would give Jordan Cove legal control over the portion of land that is required by DOT 

for siting purposes. According to our conservative calculations, the flammable vapor dispersion 

exclusion zone for the process area impoundment basin associated with a 4.7 mph wind and no 

vapor hold-up would also extend beyond the plant property line. However, this zone would 

remain substantially within the areas for which Jordan Cove has the option for an easement from 

the Port. The flammable vapor dispersion exclusion zone we calculated for the marine 

impoundment basin associated with a 4.7 mph wind and no vapor holdup would also extend 

beyond the plant property line, but would also remain substantially within the option easement 

area. It is not clear that the easement areas would completely cover the maximum downwind 

dispersion distances of 600 feet which we calculated for the facility impoundments. Therefore, 

we recommend that:

• Prior to initial site preparation, Jordan Cove should file finalized documentation of 

the easement agreement, which demonstrates that the vapor dispersion exclusion 

zones extending beyond the plant property line comply with 49 CFR 193.2007 and 

193.2059 or provide revised modeling which demonstrates the vapor dispersion 

exclusion zones stay within areas under the legal control of Jordan Cove. 

We received a comment that using low wind speeds and stable atmospheric conditions in 

modeling an LNG release may not result in the maximum downwind dispersion distance. While 

higher wind speeds would tend to decrease the downwind dispersion distance, the associated 

“wind scooping” would tend to increase dispersion distances by increasing the source strength. 

The extent to which these effects would offset each other is not known. As stated before, in 

order to account for higher initial source strengths associated with “wind scooping,” the vapor 

production model was adjusted to eliminate all vapor retention. This higher source strength was 

dispersed using the DEGADIS model, which has been shown to give longer downwind vapor 
4.12-23 4.12 – Reliability and Safety

dispersion distances at lower wind speeds and stable atmospheric conditions. In addition, higher 

wind speeds generally correspond to more atmospheric instability, which will further reduce the 

downwind dispersion distance. We believe this results in a conservative result which does not 

under-predict the downwind dispersion distances. 

We received a comment that the source calculations used in determining vapor dispersion 

exclusion zones do not address either flashing of the LNG released from a single accidental 

leakage source or for jetting effects resulting from a release from pressurized piping. In 

accordance with §193.2059, an exclusion zone for each LNG container and LNG transfer system 

must be determined for the design spills defined in Section 2.2.3.5 of NFPA 59A. Neither Part 

193 nor NFPA 59A specifically requires consideration of flashing or jetting in the determination 

of exclusion zones. The analyses provided by Jordan Cove assumed complete capture and 

conveyance of the design spill through trenches/troughs to impoundments which may be distant 

from the spill source. This is consistent with the typical approach used in demonstrating 

compliance with the exclusion zones requirements of Part 193. Accordingly, we believe that the 

impoundment system technically complies with 49 CFR 193.2059 based on our understanding of 

the regulations. However, we recognize that either flashing or jetting of any leaks could increase 

the downwind distance required for dispersion of flammable vapors. Therefore, we recommend 

that: 

• Jordan Cove should examine provisions to minimize any effects from flashing or 

jetting on the downwind dispersion distance of vapor from a release from 

pressurized piping. Measures to be considered may include, but are not limited to: 

vapor fencing; installation of spray shielding; or increasing the distance between 

leak sources and the plant property line. Jordan Cove should file final drawings 

and specifications for these measures with the Secretary prior to initial site 

preparation for review and written approval by the Director of OEP. 

In addition, the issue of the lengthy distance from potential spill locations to the sumps needs to 

be addressed. Potential LNG spills would be directed to either the process area impoundment 

basin or the marine area impoundment basin through a series of impoundment trenches. Long 

trenches increase the surface area available for heat transfer and, correspondingly, increase vapor 

generation. As a result, the control of vapors produced in these trenches should be considered. 

On January 17, 2008, FERC issued a data request to Jordan Cove requesting detailed vapor 

production rate (source strength) calculations and vapor dispersion calculations for the trenches. 

On March 28, 2008, Jordan Cove responded to the data request with a report entitled, “Vapor 

Generation and Flammable Dispersion Modeling of LNG Releases in the Jordan Cove Energy 

Project.” This report, prepared by Quest Consultants Inc., provided vapor production rates and 

dispersion results for wind blowing from west to east and from north to south for the following 

LNG spill scenarios: 

1. an LNG spill from a 2-inch-diameter hole in the LNG unloading line located near the 

unloading platform at a volumetric flow rate of 1,654 gpm into a 3-ft wide by maximum 

3-ft deep trench, having a floor sloped to the center of the trench and also sloped to direct 

flow into the marine area impoundment basin; and 

2. an LNG spill from a 2-inch-diameter hole in the LNG unloading line located near the 

process area at a volumetric flow rate of 1,654 gpm into a 3-ft wide by maximum 3-ft 
4.12-24 4.12 – Reliability and Safety

deep trench, having a floor sloped to the center of the trench and also sloped to direct 

flow into the process area impoundment basin. 

However, as mentioned in section 4.12.4, after a review of the piping and instrumentation 

diagrams for all small diameter attachments to the unloading line, FERC staff determined that a 

credible LNG spill could result from a break of the 6-inch-diameter recirculation line from the 

unloading line. 

In addition, the report submitted by Jordan Cove did not provide the method or assumptions that 

were used to calculate the LNG height or LNG flow velocity in the trenches. The report also 

referenced the 1974 Arthur D. Little report, “Evaluation of LNG Vapor Control Methods,” but 

did not provide calculations for the vapor production rates from the chosen spill scenarios. As a 

result, in the draft EIS we recommended that Jordan Cove provide revised vapor production rate 

calculations, including step-by-step calculations for LNG flow velocity and LNG liquid height 

for a break of the 6-inch-diameter recirculation line from the LNG unloading line.

On December 19, 2008, Jordan Cove provided revised vapor production calculations using a 6-

inch-diameter recirculation break during unloading and during recirculation. However, the 

subsequent release from the 6-inch-diameter recirculation break accounted for depressurization 

effects, spill detection and instrumentation response times, and subsequent valve closure and 

pump shutdown that limited the spill release rate. In addition, the vapor production rate used in 

the dispersion analysis was based on an average of the first 120 seconds of the calculated LNG 

release rate. Using an average release rate artificially reduces the release rate and subsequent 

vapor production, resulting in a shorter flammable vapor downwind dispersion distance. As a 

result, we recommend that: 

• Prior to initial site preparation, Jordan Cove should file with the Secretary, for 

review and approval by the Director of OEP, revised vapor production rate and 

vapor dispersion calculations based on the transient LNG release rate calculated for 

10 minutes, including technical justification and calculations supporting the release 

rate curve. At a minimum, the technical justification should include the 

methodology and calculations for: 

a. the determination of depressurization effects; 

b. the determination of spill detection times and associated reliabilities; 

c. the determination of instrumentation response times and associated reliabilities; 

d. the determination of valve closure times and associated reliabilities; 

e. the determination of pump shutdown times and associated reliabilities; and 

f. quantification of the potential for manual overrides and other human factors 

and errors that may interfere with the timely closure of valves and shutdown of 

the pumps. 

Alternatively, Jordan Cove may submit revised vapor production rate and vapor 

dispersion calculations based on a steady-state LNG release rate equal to the initial 

release rate (at t=0) for the 6-inch-diameter LNG recirculation line during 

unloading for 10 minutes which demonstrate the one-half LFL isopleth stays onsite. 
4.12-25 4.12 – Reliability and Safety

The December 19, 2008, report also provided the methodology used to determine LNG flow 

velocity, LNG liquid height in the trenches, and vapor production calculations, but the 

information pertaining to the methodologies still did not provide sufficient detail for FERC staff 

to be able to reproduce the vapor production rate. Furthermore, the information contained some 

discrepancies from previous filings, including a change in temperature and a change in trench 

physical properties. In addition, the calculation of the wetted perimeter in determining the vapor 

production rate seemed to only include one of the two sloped trench walls. As a result, we 

recommend that: 

• Prior to initial site preparation, Jordan Cove should file with the Secretary, for 

review and approval by the Director of OEP, step-by-step calculations showing how 

the vapor production rate from a single trench elemental area over a 10- minute 

period was determined. These calculations should include the following 

information: 

a. justification for the change in air temperature from the previous filing of 52°F to 

59°F, and clarification on the discrepancy between the trench wall and floor 

surface temperature of 52°F with the air temperature of 59°F; 

b. justification for the change in trench physical properties from the previous 

filing; 

c. justification for the longitudinal slope of the trench used to calculate the LNG 

velocity within the trench; 

d. an elevation drawing of the trench illustrating the slope along the entire trench 

path; 

e. the roughness coefficient used to calculate the LNG velocity within the trench (if 

the roughness coefficient is less than 0.012, provide justification for the selected 

value and include a sensitivity analysis using a roughness coefficient of 0.012; 

f. verification that both trench walls are included in calculating the wetted 

perimeter; and 

g. revised vapor production rate calculations based on an appropriate LNG 

velocity within the trench. 

In addition to concerns on the calculation of the source strength, the draft EIS noted our 

questions on the dispersion methodology used in the March 28, 2008 report. Quest Consultants, 

Inc. employed the Fire Dynamics Simulator (FDS) Version 5.0 to simulate the vapor dispersion 

distances. The Jordan Cove facility was modeled as a uniformly flat surface with the exception 

of a 2-meter high fence just east of the trench. The report indicated that the one-half LFL 

concentration of LNG vapor would remain within the facility property, however justification for 

the vapor fence dimensions and material properties (i.e., permeability) were not provided. 

Moreover, the videos provided of the simulations showed that this concentration extended past 

the property line at approximately 420 to 470 seconds into the simulation for Spill Scenario 1 

with wind blowing from west to east. The videos also showed the one-half LFL concentration 

extending past the domain of the simulation during the majority of the time period for Spill 

Scenario 1 with wind blowing from north to south. 

In addition, Jordan Cove’s March 28, 2008 report did not provide justification or adequate 

information for the parameters selected in the vapor dispersion modeling, including temperature, 
4.12-26 4.12 – Reliability and Safety

wind speed, relative humidity, wind profile and lapse rate reflecting atmospheric stability, 

ground surface material, grid size, domain, boundary conditions, slip factor, or obstruction 

dimensions. Jordan Cove also did not provide input or output files for FERC staff review. In 

addition, the report submitted by Jordan Cove did not demonstrate that the downwind dispersion 

distance converges to a grid-independent solution. 

In the draft EIS, we also noted that FDS simulation submittals containing a greater amount of 

information had been provided for other projects in other dockets at the Commission. In those 

other submittals, several concerns were noted by FERC staff. The input files indicated the use of 

“open” boundaries along the direction of flow/wind (sides and top) in the simulations. It has 

been shown that “open” boundaries will cause artificial mixing and subsequent dilution near 

those boundaries. Since the boundaries of the domain are typically specified at locations 

representative of the facility property line, this may essentially prevent vapors from ever 

extending past the property line. To reduce this artificial mixing near the boundary condition, 

“mirror” boundaries may be used. This recommendation is consistent with recommendations 

made by Sandia National Laboratories in the report, “Review of the Independent Risk 

Assessment of the Proposed Cabrillo Liquefied Natural Gas Deepwater Port Project,”(Cabrillo 

Report), which evaluated the use of the same model, FDS, for determining dispersion distances 

in the Cabrillo Deepwater Port Project. The Cabrillo report was also referenced in Jordan Cove’s 

March 28, 2008 report. 

Additionally, we noted in the draft EIS that FDS submittals in other dockets have shown that the 

ingress of LNG vapors into the domain initiated before the wind profile reached a quasi-steady 

state, which could cause excess mixing and dilution. Jordan Cove’s March 28, 2008 report 

stated that the release of LNG vapors was delayed until 200 seconds into the simulation. 

However, this delay may not suffice for all scenarios considered, and therefore the wind profile 

should be allowed to reach a steady or quasi-steady state throughout the entire domain of the 

simulation before injecting LNG vapor into the domain. This recommendation is also consistent 

with the recommendations made in the Cabrillo report. 

Another concern we noted in the draft EIS concerned the effect of the slip factor on the “ground” 

or “bottom” boundary condition. Values other than 1 (a free-slip condition) affect the wind 

profile. Consequently, the slip factor may also affect the spreading and dispersion of the LNG 

vapors. Therefore, a technical justification for the selection of the slip factor or a sensitivity 

analysis supporting the use of the selected slip factor should be provided. Other submittals have 

pointed to the FDS manual for its technical justification, which states that it is not recommended 

that the default velocity boundary condition be changed unless the effect on the overall flow is of 

interest. As noted in the draft EIS, we believe that the slip factor may have a significant impact 

on the overall flow and flammable vapor downwind dispersion distance, and therefore we felt the 

selection of the slip factor value warranted further study. 

As a result, in the draft EIS we recommended that Jordan Cove provide the following 

information: 

• a demonstration that the ambient temperature, relative humidity, and wind speed selected 

are a combination of those which result in longer predicted downwind dispersion 

distances than other weather conditions at the site at least 90 percent of the time, based on 

recorded data for the area; 
4.12-27 4.12 – Reliability and Safety

• technical justification for the lapse rate, ground surface material properties, and wind 

profile used to determine the downwind dispersion distances; 

• a grid sensitivity analysis that supported the selection of grid size and demonstrates the 

convergence of the downwind dispersion distances; 

• a sensitivity analysis and/or technical justification that supported the slip factor value 

used to determine the downwind dispersion distances; 

• technical justification for the vapor fence dimensions and material properties used to 

determine the downwind dispersion distances; 

• revised vapor dispersion calculations if the analyses from a-f did not support the values 

used in the March 28, 2008 submittal; and 

• input files (*.fds) and output files (*.out) used to determine the downwind dispersion 

distances. 

On December 19, 2008, Jordan Cove provided information pertaining to their selected 

parameters and revised vapor dispersion simulations and related input and output files used to 

determine the downwind dispersion distances. However, we did not agree with the justification 

provided for many of the parameters. Specifically, Jordan Cove’s December 19, 2008 report 

stated that the weather data collected by NOAA does not include readings of relative humidity 

and air temperature in the data sets reporting wind speed, direction, and stability. Therefore, 

Jordan Cove could not demonstrate that the ambient temperature, relative humidity, and wind 

speed selected were a combination of those which resulted in longer predicted downwind 

dispersion distances than other weather conditions at the site at least 90 percent of the time, 

based on recorded data for the area. Jordan Cove stated that 2.01 m/s wind speed, 50 percent 

humidity, and average temperature was selected in accordance with 49 CFR 193.2059(b)(2). 

Although we agree that the triplet of data may not be easily calculated, based on our review of 

recorded data for the area, wind speeds below 2.01 m/s may occur at the site at least 90 percent 

of the time, which may extend the downwind dispersion distance. In addition, relative humidity 

below 50% may occur at the site at least 90 percent of the time, which may also extend the 

downwind dispersion distance. However, since the relative humidity was specified only on the 

miscellaneous line in the FDS input file, the humidity specified only affected the ambient air in 

the initial domain and not the air from the incoming wind boundary. As a result, the air entering 

the domain defaulted to 0% humidity, which would result in less heat transfer and therefore 

longer dispersion distances. 

Jordan Cove’s December 19, 2008 report also stated that since ambient air temperature has little 

effect on these simulations, the default lapse rate of 6.5°C/1000 meters would have little effect 

on the simulations. Although we agree that the ambient temperature may have little effect on the 

downwind dispersion distance, it has not been satisfactory demonstrated that the lapse rate and 

associated density differences in air related to F stability are negligible. 

In addition, the December 19, 2008 report stated that since the ground in the facility is a nonreacting boundary and assumed to be at or near ambient air temperature, the choice of the default 

INERT surface specification is appropriate. We disagree that the choice of the default INERT 

surface specification is appropriate since heat transfer between the ground and vapor cloud 

would occur. 

The December 19, 2008 report also stated that the wind profile was selected with an exponent of 

0.253, typically representative of F stability class. We agree with the wind profile selection. 
4.12-28 4.12 – Reliability and Safety

However, the report stated that the simulation was allowed to run for 200 seconds before the 

LNG was released to allow the ambient flow field to become established throughout the domain. 

As previously stated in the draft EIS, a 200 second delay may not suffice for all scenarios 

considered, and therefore the wind profile should be allowed to reach a steady or quasi-steady 

state throughout the entire domain of the simulation before injecting LNG vapor into the domain. 

The December 19, 2008 report also provided simulations using three different grid combinations: 

a) 1-meter by 1-meter by 1-meter; b) 1-meter by 1-meter by 2-meters, and c) 1⁄2-meter by 1⁄2-

meter by 2-meters. However, the analysis showed that there was an increase in downwind 

dispersion distance with a decrease in the grid size in the z dimension (a to b) and in the x and y 

direction (c to b). As a result, the grid dimensions selected did not indicate a convergence in 

downwind dispersion distance and are not satisfactory in demonstrating a grid-independent 

solution. 

The December 19, 2008 report stated that the default slip factor value was used since the FDS 

manual states that changing the default velocity boundary condition is not recommended unless 

its effect on the overall flow is of interest. The FDS manual also stated that a change in slip 

factor should be done carefully using experimental data or empirical correlation as guidance. As 

previously stated in the draft EIS, slip factors values other than 1 (a free-slip condition) affect the 

wind profile. As the slip factor may also affect the spreading and dispersion of the LNG vapors, 

we believe the selection of the slip factor value warrants further study. 

The December 19, 2008 report removed the specification of the vapor fence and therefore did not 

provide information on the dimensions or properties. However, the dispersion analysis did add 

certain terrain features. 

Although none of the flammable vapor downwind dispersion distances submitted in the 

December 19, 2008 report extended offsite, the recommended modifications to the dispersion 

calculations may cause the LNG vapors to go offsite. However, this is largely because the 

dispersion modeling has not accounted for all the variation in terrain or obstacles that would 

actually be present. Other dispersion modeling submittals have shown that the turbulent kinetic 

energy near obstacles in the flow field may be more than an order of magnitude larger than the 

turbulent kinetic energy associated with the atmospheric wind profile of F stability. We believe 

the inclusion of obstacles in the flow field would greatly reduce the vapor dispersion distances 

due to increased turbulence. In addition, mitigation measures (i.e. vapor fences) may be 

implemented to reduce the downwind dispersion distance. We believe if these measures are 

taken into consideration the vapors would remain on-site. As a result, we recommend that:

• Prior to initial site preparation, Jordan Cove should file with the Secretary, for 

review and approval by the Director of OEP, revised vapor dispersion simulations 

which include: 

a. Revised design spill and vapor production rates reflective of any changes 

resulting from the previous two recommendations; 

b. a lapse rate reflective of F atmospheric stability; 

c. a water vapor concentration at the inlet of the wind boundary reflective of the 

modeled relative humidity; 
4.12-29 4.12 – Reliability and Safety

d. properties reflective of the trench wall and floors and surrounding ground for all 

modeled surfaces and obstructions; 

e. a quantitative grid sensitivity analysis, including at least three grid resolutions 

with uniformly decreasing dimensions in all three dimensions (x, y, and z) that 

supports the selection of grid size and demonstrates the convergence of the 

downwind dispersion distances; 

f. simulations that allow the wind profile to reach a steady or quasi-steady state 

before injecting LNG vapor into the domain; 

g. a sensitivity analysis and technical justification that supports the slip factor 

value used to determine the downwind dispersion distances; 

h. technical justification and/or sensitivity analyses that support the selection of the 

lapse rate, ground surface material properties, temperature, humidity, and wind 

profile used to determine the downwind dispersion distances; and 

i. all pertinent input files (*.fds) and output files (*.out) used to determine the 

downwind dispersion distances. 

We received a comment that Jordan Cove’s use of the FDS model in examining the control of 

vapors produced in trenches is in violation of the requirements of 49 CFR 193 related to the 

determination of exclusion zones. As noted in all publicly issued environmental review 

documents issues for LNG project since 2000, the adoption of NFPA 59A into Part 193 resulted 

in the removal of the requirement for impounding systems around transfer piping. While Part 

193 retains exclusion zones for LNG transfer systems, neither Part 193 nor NFPA 59A requires 

the impoundment from which to base the calculations. According to discussion with DOT staff 

regarding previous projects, exclusion zones are considered to be centered on impoundments, but 

not on trenches. In order to account for the vapor produced along trenches leading to these 

impoundments, FERC staff has been requiring applicants to include vapor retention measures 

around the trenches to enhance the safety of the facility. Although not intended to be used in 

establishing exclusion zones, applicants, such as Jordan Cove, have begun providing modeling to 

indicate these measures would be effective. Jordan Cove has used the publicly available Fire 

Dynamic Simulator (FDS) Computational Fluid Dynamics (CFD) model to demonstrate that 

vapors from trenches would not extend off-site. Although FDS was developed for thermally 

driven flow associated with fires, it can be used for other Low Mach number fluid flow 

simulations that do not necessarily include fire or thermal effects. FDS has been evaluated for 

such use and has previously been used to evaluate LNG facilities proposed to the Coast Guard 

(Chang and Meroney 2003) (Clement 2000) (Mouilleau and Champassith 2008).

We also received a comment regarding the influence of heavier hydrocarbons on the propensity 

for a detonation or deflagration with damaging overpressures. As mentioned in section 4.12.1, 

less processed product with greater amounts of heavier hydrocarbons is more sensitive to 

detonation. LNG facilities have typically imported LNG with methane concentrations ranging 

from 89-96 percent with occasional imports as low as 86 percent. These compositions are not in 

the range shown to exhibit overpressures and flame speeds associated with high-order explosions 

and detonations. However, the Coast Guard studies reference in section 4.12.1, and by the 

commentor, indicated overpressures of 4 bar and flame speeds of 35 m/s were produced from 

vapor clouds of 86-96 percent methane near stoichiometric proportions using exploding charges 

as the ignition source. The 4 bar overpressure was the same overpressure produced during the 
4.12-30 4.12 – Reliability and Safety

calibration test involving exploding the charge ignition source alone, so it remains unclear that 

the overpressure was attributable to the vapor deflagration. 

The ignition energy required to initiate an unconfined LNG vapor cloud detonation with a typical 

import composition near stoichiometric proportions is not reflective of credible release scenarios 

due to the safety and security measures which would be employed at the facility. Unconfined 

methane vapor clouds ignited with low energy ignition sources have been shown to produce 

flame speeds ranging from 5.2 to 7.3 m/s, which is much less than the flame speeds associated 

with high order explosions or detonations. 

As noted by the commentor, the propensity of a vapor cloud to detonate or produce damaging 

overpressures may also be influenced by the level of confinement and congestion surrounding 

the vapor cloud. It is possible that the prevailing wind direction may cause the vapor cloud to 

travel into a partially confined or congested area. The commentor referenced a Coast Guard 

study which tested the influence of obstacles on creating a partially confined and turbulent 

scenario. The flame speeds were not significantly higher than the unconfined case and were not 

in the range associated with detonations. LNG vapors that are ignited in a confined space, such 

as a building or structure, can result in large overpressures. In order to prevent such an 

occurrence, buildings are located away from process areas containing flammable materials. 

Furthermore, as required by our recommendation in section 4.12.2, Jordan Cove would be 

required to demonstrate that all areas are adequately covered by hazard detection devices. 

Jordan Cove proposes to install an NGL extraction unit where there would be a potential for 

vapors with higher concentrations of heavier hydrocarbons to exist. It should be noted that most 

areas of confinement and congestion would be within the process areas of the plant and would be 

unlikely to ignite a vapor cloud due to required safety measures (such as the electrical area 

classification for Class 1, Division 1 or 2). Nonetheless, we used the Baker-Strehlow-Tang 

(BST) methodology, recently updated based on the work of Pierorazio, Thomas, Baker, and 

Ketchum in 2005, in order to investigate the effects of such a vapor cloud migrating into a 

congested area. 

Based on our analysis of the proposed layout and pipe rack cross-sections, the NGL area would 

have volume and area blockage ratios consistent with a low congestion area and would allow for 

expansion consistent with 2.5D confinement (i.e. pipe rack where pipes are almost touching). 

The primary flammable substances in the NGL extraction area would be methane, ethane, and 

propane. Using the revised BST methodology, we analyzed the distance to a threshold value of 1 

psi, a value used in consequence analyses required under federal regulations such as Title 40 

CFR Part 68.22. 

Methane, which has a laminar flame speed of approximately 0.37 m/s to 0.40 m/s would be 

classified as low reactivity. Methane was used in near stoichiometric proportions with air by the 

Explosion Research Cooperative for the tests that form the BST blast wave curves for low 

reactivity substances. Based on FERC staff analysis of the Jordan Cove facility, low reactivity 

substances, such as methane, will not produce overpressures greater than 1 psi in areas of low 

congestion, even with partial confinement, and therefore is not of great concern. This is 

consistent with the tests of the USCG referenced in Section 4.12.1 and above. 

Ethane and propane, which have laminar flame speeds of approximately 0.43 m/s to 0.46 m/s and 

0.41 m/s to 0.44 m/s, respectively, would be classified as medium reactivity. Propane was used 
4.12-31 4.12 – Reliability and Safety

in near stoichiometric proportions with air by the Explosion Research Cooperative for the tests 

that form the BST blast wave curves for medium reactivity substances. For medium reactivity 

substances such as ethane and propane, the maximum distance to a 1 psi overpressure would be 

approximately 300 feet from the edge of the NGL extraction unit area and would remain within 

plant property. However, our review is based on the preliminary information contained in the 

FEED submitted by Jordan Cove. Volume and area blockage ratios may be altered during final 

design, resulting in increased congestion in the NGL extraction unit area and an increase in the 

distance to a 1 psi overpressure endpoint. Therefore, we recommend that: 

• Prior to initial site preparation, Jordan Cove should file with the Secretary, for 

review and approval by the Director of OEP, models or drawings that would 

indicate a low level of confinement and congestion (i.e. volume blockage ratio) in the 

NGL extraction unit area or submit calculations indicating that a 1 psi overpressure 

would not extend offsite. 

4.12.5 LNG Carrier Safety 

Since 1959, LNG has been transported by ship without a major release of cargo or a major 

accident involving an LNG carrier. Over the last 45 years, LNG carriers have made over 44,000 

voyages worldwide. Starting in 1971, LNG began arriving at the Distrigas facility in Everett, 

Massachusetts. To date, more than 680 cargoes, with volumes ranging from 60,000 to 138,000 

m3

, have been delivered into the Port of Boston without incident. Recently, LNG imports to 

other U.S. terminals, such as Elba Island, have steadily increased. During 2005, a total of 241 

cargoes of LNG were imported into the United States. During 2006, 226 cargoes of LNG were 

imported into the United States. For 36 years, LNG carrier operations have been safely 

conducted in the United States. 

4.12.5.1 History 

During the 44,000 voyages that have been completed since the inception of LNG maritime 

transportation, there has not been a serious accident at sea or in a port which resulted in a spill 

due to rupturing of the cargo tanks. However, insurance records, industry sources, and public 

Web sites identify a number of incidents involving LNG carriers, including minor collisions with 

other carriers of all sizes, groundings, minor LNG releases during cargo unloading operations, 

and mechanical/equipment failures typical of large carriers. Some of the more significant LNG 

carrier incidents are described below: 

• Pollenger had an LNG spill onto the steel cover of cargo tank number one during 

unloading at Everett, Massachusetts in April 1979. The spill caused cracking of the steel 

plate. 

• El Paso Paul Kayser grounded on a rock in June 1979 in the Straits of Gibraltar during a 

loaded voyage from Algeria to the United States. Extensive bottom damage to the ballast 

tanks resulted; however, the cargo tanks were not damaged, and no cargo was released. 

The complete cargo of LNG was subsequently transferred to another LNG carrier and 

delivered to its United States destination. 

• LNG Taurus grounded in December 1980 near the entrance to Taboata Harbor, Japan. 

The grounding resulted in extensive bottom damage, but the cargo tanks were not 

affected. The carrier was refloated and the cargo unloaded. 
4.12-32 4.12 – Reliability and Safety

• Isabella had LNG spill onto its deck due to a cargo tank overflow in June 1985, causing 

severe cracking of the steelwork. The spill had been attributed to a cargo valve failure 

during discharging of cargo. 

• Tellier was blown by severe winds from its docking berth at Skikda, Algeria in February 

1989 causing damage to the loading arms and the ship and shore piping. The cargo 

loading had been secured just before the wind struck, but the loading arms had not been 

drained. Consequently, the LNG remaining in the loading arms spilled onto the deck 

causing fracture of some plating. 

• Mostefa Ben Boulaid had LNG spill onto its deck during loading operations in Algeria 

in 2002. The spill, which is believed to have been caused by overflow rather than a 

mechanical failure, caused significant brittle fracturing of the steelwork. The carrier was 

required to discharge its cargo, after which it proceeded to dock for repair. 

• Khannur had a cargo tank overfill into the ship’s vapor handling system on September 

10, 2001, during unloading at Everett, Massachusetts. Approximately 100 gallons of 

LNG were vented and sprayed onto the protective decking over the cargo tank dome, 

resulting in several cracks. After re-inspection by the Coast Guard, the Khannur was 

allowed to discharge its LNG cargo. 

• Norman Lady was struck by the USS Oklahoma City nuclear submarine while the 

submarine was rising to periscope depth near the Strait of Gibraltar in November 2002. 

The 87,000-m3

 LNG carrier, which had just unloaded its cargo at Barcelona, Spain, 

sustained only minor damage to the outer layer of its double hull but no damage to its 

cargo tanks. 

• Tenaga Lima grounded on rocks while proceeding to open sea east of Mopko, South 

Korea due to strong current in November 2004. The shell plating was torn open and 

fractured over an approximate area of 20 feet by 80 feet, and internal breaches allowed 

water to enter the insulation space between the primary and secondary membranes. The 

carrier was refloated, repaired, and returned to service. 

• Golar Freeze moved away from its docking berth during unloading on March 14, 2006, 

in Savannah, Georgia. The powered emergency release couplings on the unloading arms 

activated as designed, and transfer operations were shut down. 

• Catalunya Spirit lost propulsion and became adrift 35 miles east of Chatham, 

Massachusetts, on February 11, 2008. Four tugs towed the carrier to a safe anchorage for 

repairs. The carrier was repaired and taken to port to discharge its cargo. 

4.12.5.2 LNG Carrier Construction 

In 1980, at the initial peak of LNG import activity in the United States, the Coast Guard 

published the report Liquefied Natural Gas and Liquefied Petroleum Gas – Views and Practices 

– Policy and Safety. The report summarized the Coast Guard’s extensive research into the safety 

hazards of LNG and its view that “...the nature of both LNG and LPG presents an acceptable risk 

for transportation in maritime commerce.” This is due to the fact that LNG carriers are well 

constructed, robust carriers designed to withstand low-energy-type incidents that are prevalent in 

harbors and during docking operations. Moreover, safety measures, both equipment and training, 

are planned and designed into these LNG carriers to prevent or control all types of potential 

incidents. Sandia National Laboratories reached a similar conclusion in 2005 in its report. 
4.12-33 4.12 – Reliability and Safety

The world’s LNG carrier fleet currently exceeds 250 carrier (LNG Express 2008). Currently, all 

of the carriers in the LNG fleet operate under a foreign flag with foreign crews. The LNG 

carriers used to import LNG to the United States would be constructed and operated in 

accordance with the International Maritime Organization’s (IMO) Code for the Construction and 

Equipment of Ships Carrying Liquefied Gases in Bulk, the SOLAS, and 46 CFR Part 154, which 

contain the U.S. safety standards for carriers carrying bulk liquefied natural gas. Foreign flag 

LNG carriers are required to possess a valid IMO Certificate of Fitness and a Coast Guard 

Certificate of Compliance. 

As required by the IMO conventions and design standards, hold spaces and insulation areas on 

an LNG carrier are equipped with gas detection and low temperature alarms. These devices 

monitor for leaks of LNG into the insulation between primary and secondary LNG cargo tank 

barriers. In addition, hazard detection systems are also provided to monitor the hull structure 

adjacent to the cargo tank, compressor rooms, motor rooms, cargo control rooms, enclosed 

spaces in the cargo area, specific ventilation hoods and gas ducts, and air locks. 

LNG carriers are equipped with a firewater system with the ability to supply at least two jets of 

water to any part of the deck in the cargo area and parts of the cargo containment and tank covers 

above-deck. A water spray system is also available for cooling, fire prevention, and crew 

protection in specific areas. Furthermore, certain areas of LNG carriers are fitted with dry 

chemical powder-type extinguishing systems and CO2 smothering systems for fighting fires. 

In 1993, amendments to the IMO’s Code for the Construction and Equipment of Ships Carrying 

Dangerous Chemicals in Bulk require all tankers to have monitoring equipment with an alarm 

facility which is activated by detection of over-pressure or under-pressure conditions within a 

cargo tank. In addition, the cargo tanks are heavily instrumented, with gas detection equipment 

in the hold and inter-barrier spaces, temperature sensors, and pressure gauges. Fire protection 

must include the following systems: 

• a water spray (deluge) system that covers the accommodation house control room and all 

main cargo valves; 

• a traditional firewater system that provides water to fire monitors on deck and to fire 

stations found throughout the ship; 

• a dry chemical fire extinguishing system for hydrocarbon fires; and 

• a CO2 system for protecting machinery including the ballast pump room, emergency 

generators, and compressors. 

As a result of the terrorist attacks that occurred on September 11, 2001, the IMO agreed to new 

amendments to the 1974 SOLAS addressing port facility and ship security. The International 

Ship and Port Facility Security (ISPS) Code was adopted in 2003 by the IMO. This code 

requires both vessels and ports to conduct vulnerability assessments and to develop security 

plans. The purpose of the code is to prevent and suppress terrorism against ships; improve 

security aboard vessels and ashore; and reduce the risk of passengers, crew, and port personnel 

on board vessels and in port areas. All LNG carriers as well as other cargo vessels 300 gross 

tons and larger, and ports servicing those regulated vessels, must adhere to these IMO and 

SOLAS standards. Some of the IMO requirements are as follows: 
4.12-34 4.12 – Reliability and Safety

For vessels: 

• vessels must develop security plans and have a Carrier Security Officer (VSO); 

• vessels must be provided with a vessel security alert system. These alarms transmit shipto-shore security alerts to a competent authority designated by the Administration, 

identifying the vessel, its location, and indication that the security of the ship is under 

threat or has been compromised; 

• vessels must have a comprehensive security plan for international port facilities, focusing 

on areas having direct contact with vessel; and 

• vessels may have certain equipment onboard to help maintain or enhance the physical 

security of the ship. 

For port facilities: 

• ports must develop a port facility security plan and have a Facility Security Officer 

(FSO); and 

• certain security equipment may be required to maintain or enhance the physical security 

of the facility. 

For both vessels and ports: 

• access must be monitored and controlled; 

• activities of people and cargo must be monitored; 

• secure communications must be readily available; and 

• a Declaration of Security must be completed and signed by the FSO and VSO.

4.12.5.3 Hazards 

The history of LNG marine traffic has been free of major incidents, and none have resulted in 

significant quantities of cargo being released (see section 4.12.5.1). No incidents have occurred 

at existing LNG terminals during the 50 years of operation that resulted in any significant 

quantities of cargoes being released. However, the possibility of an LNG spill from a carrier 

over the duration of the proposed project must be considered. If an LNG spill were to occur, the 

primary hazard to the public would be the impact of radiant heat from a pool fire. If an LNG 

release were to occur without ignition, an ignitable gas cloud could form and present a hazard. 

This section presents the results of analyses specific to LNG carriers to determine the distances 

for these hazards, and describes how the hazard distances would be managed if the project is 

approved. 

Historically, the events most likely to cause a significant release of LNG were a ship casualty 

such as: 

• a grounding sufficiently severe to puncture an LNG cargo tank; 

• a vessel colliding with an LNG carrier in transit; 

• an LNG carrier alliding2

 with the terminal or a structure in the waterway; or 

• a vessel alliding with an LNG carrier while moored at the terminal. 

 

2

 “Alliding” is the action of dashing against or striking upon a stationary object (for example, the running of one ship upon 

another ship that is docked) – distinguished from “colliding,” which is used to refer to two moving ships striking one another.
4.12-35 4.12 – Reliability and Safety

However, the attacks on September 11, 2001, have made the public keenly aware of an 

additional risk that must be considered in the evaluation of marine safety and security: 

• a deliberate attack on an LNG carrier by a terrorist group. 

To result in a spill of LNG, any of the above events would need to occur with sufficient impact 

to breach an LNG carrier’s double hull and cargo tanks. All LNG carriers used to deliver LNG 

to the proposed project would have double-hull construction, with the inner and outer hulls 

separated by about 10 feet. Furthermore, the cargo tanks are normally separated from the inner 

hull by a layer of insulation approximately 1-foot thick. 

As a result, many grounding incidents severe enough to cause a cargo spill on a single-bottom oil 

tanker would be unable to penetrate both inner and outer hulls of an LNG carrier. An earlier 

Federal Power Commission (predecessor to the FERC) study estimated that the double-bottom of 

an LNG carrier would be sufficient to prevent cargo tank penetration in about 85 percent of the 

cases that penetrated a single-bottom oil tanker. Previous incidents with LNG carriers have 

primarily involved grounding, and none of these have resulted in the breach of the double hull 

and subsequent release of LNG cargo. 

The likelihood of an LNG carrier sustaining cargo tank damage in a collision would depend on 

several factors – the displacement and construction of both the struck and striking ships, the 

velocity of the striking ship and its angle of impact with the struck ship, and the location of the 

point of impact. The previous Federal Power Commission study estimated that the additional 

protection afforded by the double hull would be effective in low-energy collisions; overall, it 

would prevent cargo tank penetration in about 25 percent of the cases that penetrated a singlehull oil tanker. 

In 1995, to assist the Coast Guard in San Juan, Puerto Rico, EcoEléctrica L.P. prepared an 

analysis of the damage that could result from an oil tanker striking an LNG carrier at berth 

(FERC 1996). The analysis assumed a 125,000 m3 LNG carrier and an 82,000-dead-weight-ton 

ship carrying number 6 fuel oil without tug assistance. The analysis determined the minimum 

striking speed to penetrate the cargo tanks of an LNG carrier for a range of potential collision 

angles. The resulting minimum striking speeds are presented in table 4.12.5.3-1 for the two 

principal cargo systems.

TABLE 4.12.5.3-1 

Minimum Striking Speed to Penetrate LNG Cargo Tanks

Minimum Striking Speed (knots) 

Angle of Impact Spherical Tanks Membrane Tanks 

Greater than 60 degrees 4.5 3.0 

45 degrees 6.3 4.0 

30 degrees 9.0 6.0 

15 degrees 18.0 12.0 

For membrane tanks, the critical beam-on striking speed is 3.0 knots; for spherical tanks, the 

critical beam-on speed is 4.5 knots. For both containment types, lower angles of impact result in 

much greater minimum striking speeds to penetrate LNG cargo tanks. In the July/August 2002 

issue of “LNG Journal,” the SIGTTO General Manager provides a table that indicates the critical 
4.12-36 4.12 – Reliability and Safety

speed necessary for a 20,000-ton carrier to puncture the outer hull of an LNG carrier is 7.3 knots. 

For a 93,000-ton ship, the impact speed is 3.2 knots. In neither case does such an impact result 

in damage to the LNG cargo containment system, nor does it result in release of LNG. 

The 2004 Sandia Report included an LNG cargo tank breach analysis using modern finite 

element modeling and explosive shock physics modeling to estimate a range of breach sizes for 

both credible accidental and intentional LNG spill events. The analysis of accidental events 

found that groundings, collisions with small carriers, and low-speed (less than 7 knots) collisions 

with large carriers striking at 90 degrees could cause minor ship damage but would not result in a 

cargo spill. This is due to the protection provided by the double-hull structure, the insulation 

layer, and the primary cargo tank of an LNG carrier. High-speed (12 knots) collisions with large 

carriers striking at 90 degrees were found to potentially cause cargo tank breach areas of 0.5 to 

1.5 m2

. 

In the event of a collision or allision of sufficient magnitude to rupture an LNG cargo tank, it is 

likely that sparks or flames would ignite the flammable vapors at the spill site. In a grounding of 

sufficient magnitude to rupture an LNG cargo tank, the damage would occur underwater, and the 

potential for ignition would be less than for collisions or allisions. In this case, an LNG spill 

would rapidly vaporize on water and form a potentially flammable cloud. If not ignited, the 

flammable vapor cloud would drift downwind until the effects of dispersion would dilute the 

vapors below the LFL for methane. The maximum range of potentially flammable vapors, or the 

distance to the LFL, is a function of the volume of LNG spilled, the rate of the spill, and the 

prevailing meteorological conditions. If the flammable vapor cloud encountered an ignition 

source, the cloud would burn back to the spill site. 

The final EIS for the Calcasieu LNG Project (FERC 1976) analyzed the maximum range of a 

flammable vapor cloud and hazardous radiation levels from an instantaneous one-tank spill. As 

was consistent with risk analyses at that time and for nearly 25 years thereafter, the instantaneous 

spillage of one cargo tank was considered to be the “worst-case” scenario. Physical constraints 

on maximum carrier speeds and maximum depths of penetration required to rupture one LNG 

cargo tank render the possibility of an instantaneous release of more than one cargo tank to be 

implausible. This is not to imply that the loss of multiple cargo tanks could never occur, but that 

the extent of the hazard would not exceed that of the instantaneous spillage of one tank. 

For an instantaneous one-tank spill with ignition, the final EIS for the Calcasieu LNG Project 

estimated that a hazardous thermal radiation level of 5,300 Btu/ft2

-hr would extend 3,595 feet 

from the center of the spill. For an instantaneous one-tank spill without ignition, the final EIS 

for the Yukon Pacific LNG Project (FERC 1995) estimated that potentially flammable vapors 

could travel up to 3.3 miles, with a 10-mph wind and typical atmospheric stability. 

In October 2001, the use of a one-tank instantaneous release as the worst-case scenario was 

reexamined by Quest Consultants, Inc (Quest) as part of an effort by the DOE to determine the 

hazards associated with reopening the Distrigas LNG import terminal following the terrorist 

attacks of September 11, 2001. It was determined that time-release spills through 1-meter and 5-

meter diameter holes would more accurately simulate credible worst-case damage scenarios. 

The maximum flammable vapor cloud and radiation hazards were calculated for the two spill 

scenarios. For a spill on water with ignition, the maximum distance to a radiant flux level of 

1,500 Btu/ft2

-hr was estimated to be 1,770 feet. For a spill on water without ignition, a 
4.12-37 4.12 – Reliability and Safety

flammable vapor cloud of 2.5 miles was estimated. In November 2003, in response to comments 

concerning its October 2001 study, Quest clarified that its study applied only to LNG spills 

resulting from a collision with a large ship in Boston’s Outer Harbor, where waves would restrict 

the spreading of LNG on water. 

Since the Quest study, there has been an emergence of studies by various parties to define the 

worst-case scenario that would result from a deliberate terrorist attack on an LNG carrier and the 

subsequent release of cargo. Distances have been estimated to range from 1,770 to 4,200 feet for 

a thermal radiation level of 1,500 Btu/ft2

-hr. Part of the reason for the apparent discrepancies is 

the lack of large-scale historical incidents, and the need to extrapolate small-scale field test data 

to a worst-case event. This inevitably leads to differing conservative assumptions used by the 

various parties performing the modeling. For example, some models calculate a time-release 

cargo discharge through 1-meter or 5-meter diameter holes, while others assume that the cargo 

tank empties instantaneously. 

As a result, the FERC commissioned a study by ABSG Consulting Inc. (ABSG) to search and 

review the literature on experimental LNG spills and on consequence methodologies that are 

applicable to modeling incidents of LNG spills on water. Further, the goal of the study was to 

identify appropriate methods for estimating flammable vapor and thermal radiation hazard 

distances for potential LNG carrier cargo releases during transit and while at berth. The resulting 

study, Consequence Assessment Methods for Incidents Involving Releases from Liquefied 

Natural Gas Carriers, was released for public comment on May 14, 2004. On June 18, 2004, the 

FERC staff’s responses to comments on the consequence assessment methods were issued. In 

addition, the model was updated to include a lower limit on the characteristic wind speed. As 

discussed in greater detail in the staff’s responses, various components of the consequence 

assessment methodologies were revised based on comments received. The revised methodology 

provides procedures for calculating: (1) the rate of release of LNG from a cargo tank penetration 

for various-sized holes; (2) the spreading of an unconfined LNG pool on water for both 

continuous spills and rapid (nearly instantaneous) releases; (3) the rate of vapor generation from 

an unconfined spill on water; (4) thermal radiation distances for LNG pool fires on water; and (5) 

flammable vapor dispersion distances. 

A detailed evaluation of the consequences of a terrorist attack on a modern membrane LNG 

carrier was prepared by Lloyds Register North America for the Weaver’s Cove LNG Project. 

The study evaluated the consequences of attacks on an LNG carrier by missiles and explosives. 

Finite element analysis was used to evaluate the effect of various-sized charges on both the outer 

and inner hulls. A 1-meter diameter hole of the inner hull at the waterline was found to be the 

worst-case scenario for hazard consequence assessments. This finding is consistent with the 

attack on the double-hull oil tanker Limberg which caused greater than a 5-meter diameter hole 

on the outer hull, but only minor damage to the inner hull. A failure modes and effects analysis 

was used to understand internal LNG release characteristics, and a residual strength analysis was 

used to investigate damage scenarios for a loaded LNG carrier. 

As discussed above, the 2004 Sandia Report included an LNG cargo tank breach analysis, using 

modern finite element modeling and explosive shock physics modeling to estimate a range of 

breach sizes for credible accidental and intentional LNG spill events. For intentional scenarios, 

the size of the cargo tank hole depends on the location of the ship and source of threat. 

Intentional breach areas were estimated to range from 2 to 12 m2

. In most cases, an intentional 
4.12-38 4.12 – Reliability and Safety

breaching scenario would not result in a nominal hole of more than 5 to 7 m2

, which is a more 

appropriate range to use in calculating potential hazards from spills. These hole sizes are 

equivalent to circular hole diameters of 2.5 and 3 meters. 

The 2004 Sandia Report also included guidance on risk management for intentional spills, based 

on the findings that the most significant impacts to public safety and property exist within 

approximately 500 meters (1,640 feet) of a spill due to thermal hazards from a fire, with lower 

public health and safety impacts beyond 1,600 meters (approximately 1 mile). Large unignited 

LNG vapor releases were found to be unlikely, but could extend from nominally 2,500 meters 

(8,200 feet) to a conservative maximum distance of 3,500 meters (2.2 miles) for an intentional 

spill. 

In 2008, the DOE released another study by Sandia National Laboratories, entitled Breach and 

Safety Analysis of Spills Over Water from Large Liquefied Natural Gas Carriers, May 2008

(2008 Sandia Report). The 2008 Sandia Report assesses the scale of possible hazards for newer 

LNG carriers with capacities up to 265,000 m3

. Using the same methodology as the 2004 Sandia 

Report, it concludes that thermal hazard distances are only 7-8% greater than current ships 

carrying 145,000 m3 of LNG, due primarily to the slightly greater height of LNG above the 

waterline. The 2008 Sandia Report also notes that the general design of the larger vessels are 

similar to current designs and hence for near-shore facilities the calculated breach size for 

intentional scenarios remains the same. Overall, the 2008 Sandia Report maintains the same 

impact zones as with the smaller carriers as analyzed in the 2004 Sandia Report. 

Cascading damage due to brittle fracture from exposure to cryogenic liquid or fire-induced 

damage to foam insulation was evaluated and, while possible under certain conditions, is not 

likely to involve more than two or three cargo tanks. Cascading events are not expected to 

increase the overall fire hazard by more than 20 to 30 percent (1,920 to 2,080 meters [6,300 to 

6,825 feet]) but would increase the expected fire duration. RPTs are possible for large spills, but 

the effects would be localized near the spill source and should not cause extensive structural 

damage. 

In February 2007, the U.S. Government Accountability Office (GAO) published a report (GAO 

2007) that assessed recent studies, including the Sandia Report, that have been conducted on the 

consequences of an LNG spill resulting from a terrorist attack on an LNG carrier. The GAO’s 

panel of experts agreed that the most likely public safety impact of an LNG spill would be the 

radiant heat from a pool fire. Although the GAO report characterizes disagreements among the 

panel of experts, the majority felt the Sandia calculations were either accurate or overly 

conservative. The Sandia Report concluded that damage due to brittle fracture from exposure to 

cryogenic liquid or fire-induced damage was possible under certain conditions and would 

increase the duration of the event. The majority of the GAO expert panel agreed with Sandia 

National Laboratories that cascading events are not expected to significantly increase the overall 

fire hazards. The disagreement citied in the GAO report concerned the need for future research 

and clarifying uncertainties, rather than on Sandia National Laboratories’ conclusions on 

cascading failures. 

As part of the waterway suitability review process, the Coast Guard used the criteria developed 

by Sandia National Laboratories to define the outer limits of the hazard zones for assessing 

potential risks associated with the proposal. These hazard zones were based on the capacity of 
4.12-39 4.12 – Reliability and Safety

LNG carriers in operation in 2004 which had a cargo carrying capacity up to 148,000 m3

. The 

Zones of Concern used in the waterway review were: 

• Zone 1 – impacts on structures and organisms are expected to be significant within 500 

meters (1,640 feet). The outer perimeter of Zone 1 is the distance to thermal hazards of 

37.5 kW/m2 (12,000 Btu/ft2-hr) from a pool fire. 

• Zone 2 – impacts would be significant but reduced, and damage from radiant heat levels 

are expected to transition from severe to minimal between 500 and 1,600 meters (1,640 

and 5,250 feet). The outer perimeter of Zone 2 is the distance to thermal hazards of 5 

kW/m2

 (1,600 Btu/ft2-hr) from a pool fire. 

• Zone 3 – impacts on people and property from a pool fire or an unignited LNG spill that 

does not ignite are expected to be minimal between 1,600 meters (5,250 feet) and a 

conservative maximum distance of 3,500 meters (2.2 miles). The outer perimeter of 

Zone 3 should be considered the vapor cloud dispersion distance to the LFL from a worst 

case unignited release. Impacts to people and property could be significant if the vapor 

cloud reaches an ignition source and burns back to the source. 

The severity of impacts within Zones 1 through 3 would depend on the location of the incident 

relative to a specific area, the scope of the incident, and whether the released LNG ignited or 

dispersed. This could be a significant impact, being most severe in Zone 1 and decreasing 

outward through Zones 2 and 3. However, because of the implementation of safety and security 

measures during marine transit, the likelihood of a marine LNG spill would be remote. 

The methodology described in the ABSG study and revised in staff’s responses to comments was 

also used by FERC staff to calculate the thermal radiation and flammable vapor dispersion 

distances for several holes ranging in diameter from 1 meter to 3.9 meters. Based on the 

penetration of the largest cargo tank of a 140,000 m3

 LNG carrier, a potential spill of 23,000 m3

is estimated for the volume of LNG above the waterline. The estimated pool spread results and 

thermal radiation hazard distances are identified in table 4.12.5.3-2. Thermal radiation 

calculations are based on an ambient temperature of 46°F, a relative humidity of 50 percent, and 

a 16.8-mph wind speed obtained from National Oceanic and Atmospheric Administration’s 

National Data Buoy Center. 

TABLE 4.12.5.3-2 

LNG Spills on Water from a 140,000 m3

 LNG Carrier (using ABSG Methodology)

LNG Release and Spread 

Hole Area 0.8 m2 1.5 m2 5 m2 7 m2 12 m2

Hole Diameter 1.0 m 1.4 m 2.5 m 3.0 m 3.9 m 

Spill Time 94.0 minutes 48.0 minutes 15.0 minutes 10.4 minutes 6.2 minutes 

Pool Fire Calculations 

Maximum Pool Radius 340 feet 477 feet 816 feet 939 feet 1,102 feet 

Fire Duration 94.1 minutes 48.1 minutes 15.2 minutes 10.7 minutes 6.5 minutes 

Distance to: 

1,600 Btu/ft2/hr 2,151 feet 2,777 feet 4,151 feet 4,616 feet 5,209 feet 

3,000 Btu/ft2/hr 1,668 feet 2,141 feet 3,189 feet 3,542 feet 3,992 feet 

10,000 Btu/ft2/hr 1,000 feet 1,273 feet 1,879 feet 2,084 feet 2,344 feet 

12,000 Btu/ft2-hr 916 feet 1,166 feet 1,721 feet 1,908 feet 2,146 feet 

Flammable vapor dispersion calculations were based on an atmospheric temperature of 46oF, 

50 percent relative humidity, a 4.5-mile per hour wind speed and atmospheric stability Class F. 
4.12-40 4.12 – Reliability and Safety

Based on a 1-meter diameter cargo tank breach in a 140,000 m3

 LNG carrier, an unignited 

release would result in an estimated pool radius of 425 feet. The unignited vapor cloud would 

extend to 8,985 feet to the LFL and 14,901 feet to one-half the LFL. It is important to identify 

certain key assumptions of conditions that must exist in order to achieve these vapor cloud 

distances. First it would be necessary for an event to create a 1-meter diameter hole by 

penetrating the outer hull, the inner hull, and cargo containment without ignition. Far more 

credible is that the event creating a 1-meter diameter hole would also result in a number of 

ignition sources which would lead to an LNG pool fire and subsequent thermal radiation hazards. 

It is also unlikely that a flammable vapor cloud could achieve these distances over land surfaces 

without encountering an ignition source, and subsequently burning back to the source. 

The results of these calculations are in agreement with the Zones of Concern used by the Coast 

Guard in assessing the waterway suitability and are in agreement with the 2004 Sandia Report. 

For the project, Jordan Cove proposes to receive LNG carriers with a capacity of up to 160,000 

m3

. In its Waterway Suitability Report (WSR), the Coast Guard has placed a restriction on the 

size of LNG carriers transiting the Coos Bay navigational channel to a capacity of 148,000 m3

and a restriction on the physical dimensions of the carrier to a length of 950 feet, a beam of 150 

feet, and a loaded draft of 40 feet. These restrictions would be in place until Jordan Cove 

conducts additional simulator studies to assure the sufficiency of the channel. 

By focusing on the “worst-case” scenario for LNG transportation, there is a tendency to dismiss 

the potential hazards for other fuels and products commonly transported on our waterways. 

Some of the previously identified studies that calculate long hazard distances for LNG cargo 

fires also estimate similarly long distances for gasoline, propane, and jet fuel cargo fires. Also, it 

should not be assumed that the hazard distances identified are the assured outcome of an LNG 

carrier accident or attack, given the conservatisms in the models and the level of damage 

required to yield such large scale releases. Further, these “worst-case” intentional breach 

scenarios should not be misconstrued as defining an exclusionary zone. Rather the average most 

probable “worst-case” scenarios provide guidance in developing the operating restrictions for 

LNG marine traffic transiting the waterway to the proposed terminal, as well as in establishing 

potential impact areas for emergency response and evacuation planning. 

4.12.5.4 LNG Carrier Transit to the Jordan Cove Terminal 

Imported LNG could be obtained from exporting terminals throughout the world and delivered 

by LNG carriers to the proposed project. Exporting countries include Algeria, Australia, Brunei, 

Indonesia, Malaysia, Nigeria, Oman, Qatar, Trinidad, and United Arab Emirates. In 2007, LNG 

imports to the United States included: 59 percent from Trinidad, 15 percent from Egypt, 12 

percent from Nigeria, 10 percent from Algeria, 2 percent from Qatar, and 2 percent from 

Equatorial Guinea. Jordan Cove expects to source LNG supplies from various countries. 

Carrier Routes 

Moffatt & Nichol International (MNI) conducted an LNG carrier maneuvering simulation study 

to evaluate the transit of an LNG carrier through the Coos Bay navigational channel (CBNC) to 

the terminal, evaluate the feasibility of the berthing configuration at the terminal, and evaluate 

the tractor tug requirements for the proposed project. MNI contracted Marine Safety 

International in Rhode Island to develop the transit model and perform the simulations under 

direction from marine consultants. The study included the transit of a 71,500 m3

, 87,600 m3, 
4.12-41 4.12 – Reliability and Safety

137,000 m3

, and a 165,000 m3 LNG carrier. The study indicated that LNG carriers could safely 

maneuver the approach to the LNG terminal and ship berth with the assistance of three tugs. The 

transit of the 137,000 m3

 and 165,000 m3 LNG carriers would be possible with the benefit of the 

Port of Coos Bay’s plan to widen and deepen the channel. Based on the simulation study, MNI 

made several recommendations including: adding buoys at different points to define the turning 

basin originally contemplated in the design; the arrival time of LNG carriers to coincide with 

high slack water; and support for a series of simulations to familiarize Coos Bay pilots, tractor 

tug operators, and vessel masters with the transit of an LNG carrier. 

In March 2008, MNI conducted another LNG carrier maneuvering simulation study that 

evaluated the transit of the CBNC by an LNG carrier with a capacity of 148,000 m3 without a 

turning basin. Jordan Cove contracted a pilot from the Coos Bay Pilots Association to provide 

local waterway expertise. Jordan Cove also contracted a pilot from Lake Charles Pilots, Inc. 

(who routinely operate LNG carriers in the Calcasieu ship channel) to provide insight on LNG 

carrier behavior to the Coos Bay pilot and perform as the helmsman during the simulations. The 

simulations confirmed that LNG carriers with a capacity of 148,000 m3

 could safely navigate to 

and from the proposed terminal in the current CBNC in high water conditions and without a 

turning basin. 

A pilot would board the incoming LNG carrier at least five nautical miles outside of the sea 

buoy. From the territorial sea, LNG carriers would be under the pilot’s control and would enter 

the navigational channel and go past the sea buoy. Two 80 metric ton bollard pull tractor tugs 

would be secured to the LNG carrier at the direction of the pilot at a point either offshore or 

entering the breakwater. The last point to turn the ship around if conditions are deemed not 

appropriate to enter the port is Buoy #1. For most deep draft ships that enter Coos Bay Harbor, a 

speed of 6 to 8 knots is maintained while the carrier passes Buoy #2 and the ends of the jetties. 

At this point the channel depth decreases from 55 feet to 42 feet and the channel narrows from 

approximately 1,000 feet wide to 300 feet. The total distance an LNG carrier would travel from 

the entrance of the ship channel to the end of the jetties is approximately 1.7 nautical miles. 

The community of Charleston is directly to the south of the water inside the entrance of the bay. 

The Charleston Marina is the only marina in the area and any ship leaving the marina enters the 

main channel at this point. Only during high water slack would an LNG carrier transit the waters 

inside the jetties to minimize the impacts of currents. After passing the jetties and the southern 

tip of the North Spit, the LNG carrier would travel approximately 1.8 nautical miles and begin its 

turn to the north at a speed of approximately 6 knots. There are no underwater or overhead 

channel crossings in this area. 

Transiting a distance of 1.6 nautical miles up the Coos Bay Range, Barview, a rural housing area 

traversing the entire channel, is located to the east. Barview includes several small businesses 

along Highway 240 (Cape Arago Highway). On the west bank of the channel there are no 

residences. The speed of an LNG carrier in this area would be determined by steerage and wind 

conditions, but would be about 6 knots. 

The LNG carrier would travel in a northerly direction a distance of 2.1 nautical miles when 

traversing the Empire Range and the Lower Jarvis Range. The neighborhood of Empire is 

located to the east of the channel at this point. There are two docks located in the Empire Range. 

One is used for barges and the other is not in use. The eastern shoreline has a small boat ramp 
4.12-42 4.12 – Reliability and Safety

that is exposed to channel conditions and wakes from passing vessels. On the west side of the 

channel there are two industrial facilities that are new to the area. There is no housing on the 

west side of the channel, but this area can experience visitors to the Coos Bay Shorelands 

SRMA. The speed of an LNG carrier in this area would be 4 to 6 knots. 

At this point an LNG carrier traversing the channel would cross Southwest Oregon Regional 

Airport’s main runway designed for instrument landings. The issue of an LNG carrier passing 

through the flight path of the airport’s main runway was discussed between Jordan Cove and the 

FAA airport authority during the development of the WSA. The current height limitation 

imposed on marine traffic in the CBNC by the FAA is 140 feet from the surface of the main 

runway. This equates to a height of 157 feet from sea level. The FAA indicated that as long as 

vessels did not exceed the maximum height of 140 feet above the main runway, they would not 

have any objections to carriers passing through the flight path of the main runway. In its 

development of the WSA, Jordan Cove verified the highest height to the mast of existing LNG 

carriers with a capacity of 148,000 m3

 is 139 feet above msl. This would be in agreement with 

the FAA’s height limitation of 157 feet above msl. In the draft EIS we recommended that Jordan 

Cove submit a request for a FAA feasibility study under IAW FAA Order 7400.2G, 6-1-6 and 

consult with the FAA to ensure proper aspects of Project alternatives are studied. Jordan Cove 

submitted a Request for Hazard Determination and a Notice of Proposed Construction or 

Alteration to the FAA on October 22, 2008. In section 4.9.2.4 of the final EIS, we recommend 

that Jordan Cove should file documentation of consultations with the FAA, and a copy of the 

feasibility study upon receipt, and if the LNG terminal meets the notification standards outlined 

in 14 CFR Subchapter E, Jordan Cove should submit the appropriate notice to the FAA under 

FAR 77, with a copy filed with the Secretary with its Implementation Plan. 

After the Lower Jarvis Range, the LNG carrier would travel a distance of 0.8 nautical miles to 

reach the northernmost point in its transit. The LNG carrier would stop and begin a turn to the 

right and back into the berthing dock at the proposed facility with tug assistance. This area is 

known locally as the North Bay area and is beyond the city limits of North Bend, which ends at 

the center point of the channel. Beyond the proposed terminal there is a wood chip facility and 

two bridges with height restrictions. LNG carriers would not transit to the wood chip facility or 

under the two bridges. 

Three tractor tugs would be utilized to maneuver the LNG carrier into the berth stern first. As 

mentioned before, two tractor tugs would meet the LNG carrier at a point either offshore or 

entering the breakwater. The third tractor tug would meet the LNG carrier at the turn into the 

access channel. The LNG carrier would be berthed stern first so it can more easily leave the 

facility when it is finished unloading its cargo. While maneuvering the LNG carrier, the pilot 

would have the use of the three tractor tugs to assist in the docking of the carrier. As the LNG 

carrier arrives at the berth, a tractor tug would slow the LNG carrier down with help from the 

main propulsion of the carrier. During this period, the other two tugs would either push or pull 

the carrier to a complete stop at the direction of the pilot. Once the LNG carrier is perpendicular 

to the berth and its propulsion stopped, two tugs would push the carrier into the berth. 

Hazard Zones Associated with the Proposed Route 

The only area of land that would be overlapped by Zone 1 in the LNG carrier’s transit to the 

proposed terminal would be a small portion of western side of Empire and a small portion of the 

eastern side of the uninhabited North Spit. During transit, Zone 2 would overlap portions of the 
4.12-43 4.12 – Reliability and Safety

neighborhoods of Charleston, Barview, and Empire to the east and most of the North Spit to the 

west. Near the proposed terminal, Zone 2 would overlap the Roseburg facility and a portion of 

the Southwest Oregon Regional Airport’s main runway. During transit, Zone 3 would overlap 

portions of the cities of Coos Bay and North Bend. 

4.12.5.5 Requirements for LNG Carrier Operations in the Coos Bay Navigational 

Channel 

The Coast Guard exercises regulatory authority over LNG facilities that affect the safety and 

security of port areas and navigable waterways under EO 10173; the Magnuson Act (50 USC 

Section 191); the Ports and Waterways Safety Act of 1972, as amended (33 USC Section 1221, 

et seq.); and the Maritime Transportation Security Act of 2002 (46 USC Section 701). The Coast 

Guard is responsible for matters related to navigation safety, carrier engineering and safety 

standards, and all matters pertaining to the safety of facilities or equipment located in or adjacent 

to navigable waters up to the last valve immediately before the receiving tanks. The Coast 

Guard also has authority for LNG facility security plan review, approval, and compliance 

verification as provided in Title 33 CFR Part 105, and siting as it pertains to the management of 

carrier traffic in and around the LNG facility. 

The Coast Guard regulations in 33 CFR 127 apply to the marine transfer area of waterfront 

facilities between the LNG carrier and the last manifold or valve located immediately before a 

storage tank. Title 33 CFR 127 regulates the design, construction, equipment, operations, 

inspections, maintenance, testing, personnel training, firefighting, and security of LNG 

waterfront facilities. The safety systems, including communications, emergency shutdown, gas 

detection, and fire protection, must comply with the regulations in 33 CFR 127. Under 127.019, 

Jordan Cove would be required to submit two copies of its Operations and Emergency Manuals 

to the COTP for examination. 

In accordance with 33 CFR 127, an applicant who intends to build an LNG import facility must 

submit a Letter of Intent (LOI) to the COTP at least 60 days prior to construction. However, 

FERC regulations under 18 CFR 157.21 require an applicant to submit an LOI to the Coast 

Guard at the same time the pre-filing process is initiated with the Commission. Consequently, 

Jordan Cove notified the Coast Guard that it proposed to construct an LNG import terminal in 

Coos County, Oregon and submitted an LOI to the COTP Portland on April 10, 2006. 

As required by its regulations (section 127.009), the Coast Guard is responsible for issuing a 

LOR as to the suitability of the waterway for LNG marine traffic with respect to the following 

items: 

• physical location and description of the facility; 

• the LNG carrier’s characteristics and the frequency of LNG shipments to or from the 

facility; 

• waterway channels and commercial, industrial, environmentally sensitive, and residential 

areas in and adjacent to the waterway used by LNG carriers en route to the facility, 

within 25 kilometers (15.5 miles) of the facility; 

• density and character of marine traffic in the waterway; 

• locks, bridges, or other manmade obstructions in the waterway; 

• depth of water; 
4.12-44 4.12 – Reliability and Safety

• tidal range; 

• protection from high seas; 

• natural hazards, including reefs, rocks, and sandbars; 

• underwater pipes and cables; and 

• distance of berthed carriers from the channel and the width of the channel. 

On June 14, 2005, the Coast Guard published a Navigation and Carrier Inspection Circular – 

Guidance on Assessing the Suitability of a Waterway for Liquefied Natural Gas (LNG) Marine 

Traffic (NVIC 05-05). The purpose of the NVIC 05-05 was to provide Coast Guard 

COTPs/Federal Maritime Security Coordinators (FMSC), members of the LNG industry, and 

port stakeholders with guidance on assessing the suitability of a waterway for LNG marine 

traffic. On December 22, 2008, the Coast Guard published a second Navigation and Carrier 

Inspection Circular – Guidance Related to Waterfront Liquefied Natural Gas (LNG) Facilities 

(NVIC 05-08). The purpose of NVIC 05-08 is to revise the format of the LOR to conform to its 

intended effect of being a recommendation of the waterway suitability to the FERC. The NVIC 

05-08 is further discussed in the Coast Guard Waterway Suitability Report section. In 

accordance with this guidance, each LNG project applicant is to submit a WSA to the cognizant 

COTP. The assessment is to address the transportation of LNG from entrance into U.S. 

territorial waters through transit to and from the LNG receiving facility, including operations at 

the LNG carrier/facility interface. Issues related to navigational safety issues and port security 

introduced by the proposed LNG operation should be considered and addressed in the WSA. 

Jordan Cove’s Waterway Suitability Assessment 

NVIC 05–05 describes two phases in the applicant’s development of the WSA. The first is the 

submittal of the Preliminary WSA, which begins the Coast Guard review process for determining 

the suitability of the waterway for LNG marine traffic. The second is the submittal of the 

Follow-On WSA. This document is reviewed and validated by the Coast Guard and forms the 

basis for the WSR to the FERC. 

The Preliminary WSA provides an outline which characterizes the port community and the 

proposed facility and transit routes. It provides an overview of the expected major impacts LNG 

operations may have on the port, but does not contain detailed studies or conclusions. This 

document is used to start the scoping process for evaluating the suitability of the waterway for 

LNG marine traffic. On April 10, 2006, Jordan Cove submitted the Preliminary WSA to the 

COTP Portland for review. 

The Follow-On WSA must provide a detailed and accurate characterization of the LNG facility, 

the LNG carrier route, and the port area. The assessment is to identify appropriate risk 

management measures for credible security threats and safety hazards. The purpose of the 

Follow-On WSA is to identify: 

• federal, state, local, and private sector resources needed to carry out risk management 

measures; 

• currently available resources; and 

• ways in which the applicant can address any resource gaps. 

In the development of the Follow-On WSA, the applicant typically consults with the Coast 

Guard, the Area Maritime Security Committee, and other port stakeholders. Jordan Cove 
4.12-45 4.12 – Reliability and Safety

consulted with members of the Area Maritime Security Committees representing: law 

enforcement, emergency management, environmental, and transportation agencies within the 

State of Oregon; Coast Guard Sector Portland; the Coos County Sheriffs; the Cities of Coos Bay 

and North Bend Police Departments; the Cities of Coos Bay and Charleston Fire Districts; Coos 

Bay Pilots; and local towing, maritime industry, and medical personnel. 

Once the applicant submits a complete Follow-On WSA, the Coast Guard reviews the document 

to determine if it presents a realistic and credible analysis of the public safety and security 

implications from LNG marine traffic in the port. Jordan Cove submitted the Follow-On WSA 

to the Coast Guard on March 1, 2007. The NVIC 05-05 directs the use of the 2004 Sandia 

Report as the best available information on LNG spills. Accordingly, the Follow-On WSA used 

three concentric Zones of Concern, based on LNG carriers with a cargo carrying capacity up to 

148,000 m3

, to assess the maritime safety and security risks of LNG marine traffic in Coos Bay. 

The Zones of Concern are discussed in greater detail in section 4.12.5.3. 

We recognize that the port’s overall concerns picture may change over time. New port activities 

may commence, infrastructure may be added, or population density may change. Improvements 

in technology to detect, deter, and defend against intentional acts may also develop. Therefore, 

we recommend that: 

• Until commencement of service, Jordan Cove should annually review its WSA 

relating to LNG marine traffic for the project; update the assessment to reflect 

changing conditions which may impact the suitability of the waterway for LNG 

marine traffic; provide the updated assessment to the cognizant COTP/FMSC for 

review and validation and if appropriate, further action by the COPT/FMSC 

relating to LNG marine traffic; and provide a copy to the FERC staff. 

Coast Guard Waterway Suitability Report 

As described in NVIC 05-05, the COTP submits a WSR to the FERC after review of the FollowOn WSA. The WSR contains the Coast Guard’s preliminary determination on the suitability of 

the waterway for LNG marine traffic. Based on Coast Guard policy, the COTP can generally 

make one of three conclusions regarding the suitability of the waterway to support LNG marine 

traffic. The first is that the waterway is suitable without the implementation of additional 

measures. The second is that the waterway is unsuitable. The third is that to make the waterway 

suitable, additional measures are necessary to responsibly manage risks to navigation safety or 

maritime security associated with LNG marine traffic. 

On July 1, 2008, the COTP Sector Portland provided the FERC with a WSR which summarized 

the required safety and security measures, as well as the port community’s capabilities to 

implement these measures. Based on its review of the WSA and its own independent risk 

assessment, the Coast Guard stated that the Coos Bay navigational channel is not currently 

suitable, but can be made suitable, for the type and frequency of LNG marine traffic associated 

with the proposed Jordan Cove LNG facility. This preliminary determination was contingent 

upon the availability of additional measures necessary to responsibly manage the maritime safety 
4.12-46 4.12 – Reliability and Safety

and security risks. These measures are further detailed in the WSR and include, among others, 

the following requirements: 

• development of a TMP in consultation with the Coast Guard and participating agencies 

that would define the roles, responsibilities, and specific procedures for the LNG carrier, 

the LNG terminal, and the various agencies that would be responsible for managing the 

risks of LNG marine traffic; 

• establishment of a moving safety/security zone around the LNG carrier extending 500 

yards around the carrier but ending at the shoreline; 

• establishment of a fixed safety/security zone of 150 yards around the LNG carrier while 

moored at the terminal to include the entire terminal slip. While there is no LNG carrier 

moored, the security zone would cover the entire terminal slip and extend 25 yards into 

the waterway; 

• restriction on the size of LNG carriers transiting to the proposed terminal to a capacity of 

148,000 m3

 and restriction on the physical dimensions of a carrier to a length of 950 feet, 

beam of 150 feet, and a loaded draft of 40 feet until additional simulator studies are 

conducted to assure the sufficiency of the channel; 

• restrict LNG carriers to daylight transit for at least the first six months, unless approved 

in advance by the COTP Portland; 

• boarding of pilots onto an LNG carrier would occur at least five miles outside the sea 

buoy; 

• coordinate inbound and outbound transit details at least 24 hours prior to an LNG 

carrier’s arrival with the Coast Guard, FBI, Coos Bay Pilot Association, Escort Tug 

Masters, and other escort assets; 

• establishment of automatic identification system signals and have the capability to be 

used by appropriate agencies, port authorities, and vessel companies; 

• presence of two tractor tugs with at least 80-ton bollard pull to assist in the transit of 

LNG marine traffic to the proposed terminal; 

• presence of one tractor tug with at least 80-ton bollard pull to assist with turning and 

mooring of LNG carriers at the proposed terminal; 

• addition of four aids to navigation and the relocation of eight current aids to navigation in 

the Coos Bay navigational channel; 

• provide a PORTS contracted with NOAA to supply real time river levels, currents, and 

wind data; 

• provide simulator training for pilots and tug operators identified as having responsibility 

for LNG marine traffic prior to the arrival of the first LNG carrier; 

• augment emergency response planning resources to develop procedures and protocols as 

well as continuously update the plans as conditions change; 

• pre-arrival inspection and transfer monitoring of the LNG carriers and facility; 

• annual Coast Guard inspections of the LNG carriers and the facility; 

• augment firefighting capabilities at the facility and along the transit route; 

• adequate means to notify the public along the transit route, including on-going public 

education, emergency notification systems, and drills and training. Education programs 

should meet the needs of all users of the waterway, including commercial and 

recreational boaters, local businesses, local residents, and tourists. 

• adequate means of gas detection along the transit route and at the facility; and 
4.12-47 4.12 – Reliability and Safety

• restriction on the size of LNG vessels transiting to the Project site to a capacity of 

148,000 m3

 until a completed site-specific risk analysis for larger vessels is approved by 

the COTP Portland.; 

As the Coast Guard has determined that additional measures beyond those proposed by Jordan 

Cove in the WSA would be required to responsibly manage the maritime safety and security 

risks associated with the LNG marine traffic, we recommend that: 

• Throughout the life of the facility, Jordan Cove should ensure that the facility and 

any LNG carrier transiting to and from the facility comply with all requirements set 

forth by the Coast Guard COTP Sector Portland, including all risk mitigation 

measures recommended in the WSR. 

In addition, section 4.12.6 includes a recommendation that Jordan Cove develop an Emergency 

Response Plan and a Cost-Sharing Plan that identifies the mechanisms for funding all projectspecific security/emergency management costs. 

Pursuant to 33 CFR § 127.009, the Coast Guard would complete its review and issue an LOR to 

address the suitability of the waterway for LNG transport. If the Coast Guard issues an LOR 

finding the waterway suitable for additional LNG marine traffic with conditions, the necessary 

security measures would further be incorporated into the Coast Guard required TMP, which 

would become the basis for appropriate security measures for each maritime security threat level. 

This plan would clearly spell out roles, responsibilities, and specific procedures for LNG marine 

traffic transiting Coos Bay up to the terminal, as well as for all agencies involved in 

implementing security and safety during the operation. It would be required that, prior to the 

LNG carrier being granted permission to enter the shipping channels, both the carrier and facility 

must be in full compliance with the appropriate requirements of the Maritime Transportation 

Security Act and International Ship and Port Facility Security Code, and the security protocols to 

be established by the COTP in the TMP. In future EISs, NVIC 05-08 would replace the WSR 

with an LOR analysis document that would provide the FERC with information needed for the 

NEPA analysis. The LOR analysis document would be issued by the Coast Guard before the 

draft EIS is issued by FERC. NVIC 05-08 would clarify the timing and scope of the process, 

pursuant to FERC regulations, to ensure consideration is given to the safety and security of the 

port, the facility, and the LNG carriers. 

In addition, Jordan Cove would provide security for the terminal according to a Facility Security 

Plan that must be prepared under 33 CFR 105. This plan and any modifications to this plan 

would need to be approved by the Coast Guard COTP. The requirements of this plan may 

include: 

• a Facility Security Assessment to identify site vulnerabilities, possible security threats, 

consequences of an attack, and facility protective measures; 

• procedures for responding to security incidents; 

• a designated FSO responsible for implementing and periodically updating the Facility 

Security Plan and Assessment; 

• scalable security measures to provide increasing levels of security at increasing 

MARSEC levels; 

• security exercises at least once each calendar year and drills at least every 3 months; and 
4.12-48 4.12 – Reliability and Safety

• mandatory reporting of all breaches of security and security incidents. 

Security at the facility would be provided by both active and passive systems. The entire site 

would be surrounded by a protective enclosure (i.e., a fence) with sufficient strength to deter 

unauthorized access. The enclosure would be illuminated with not less than 2.2 lux between 

sunset and sunrise. Intrusion detection systems and day/night camera coverage would identify 

unauthorized access. A separate security staff would conduct periodic patrols of the plant, and 

screen visitors and contractors. The security staff may also assist in maintaining security of the 

marine terminal during cargo unloading. Jordan Cove would be required to submit any revisions 

to their Facility Security Plan to the COTP Portland for approval 60 days before commencement 

of operations. 

4.12.6 Emergency Response and Evacuation Planning 

Prior to commencing service, Jordan Cove would be required to prepare final emergency 

procedure manuals, as required by 49 CFR 193.2509, that provide for: a) responding to 

controllable emergencies and recognizing an uncontrollable emergency; b) taking action to 

minimize harm to the public including the possible need to evacuate the public; and c) 

coordination and cooperation with appropriate local officials. Specifically, section 

193.2509(b)(3) requires, “Coordinating with appropriate local officials in preparation of an 

emergency evacuation plan...” 

While the worst-case scenarios evaluated for the onshore facility in section 4.12.4 and for marine 

spills in section 4.12.5.3 provide guidance on the maximum extent of potential hazards, they 

should not be assumed to represent the evacuation zone for every potential incident. As with any 

other fuel or hazardous material, the actual severity of the incident would determine what area 

needs to be evacuated, if any, rather than a worst-case maximum zone. It is anticipated that the 

emergency evacuation plans would identify evacuation distances based upon increasing severity 

of events. The Emergency Response Plan would include provisions for a tsunami event. 

Section 3A(e) of the NGA, added by section 311 of the EPAct of 2005, stipulated that in any 

Order authorizing an LNG terminal, the Commission shall require the LNG terminal operator to 

develop an ERP in consultation with the Coast Guard and state and local agencies. The FERC 

must approve the ERP prior to any final approval to begin construction. Therefore, we 

recommend that: 

• Jordan Cove should develop an ERP (including evacuation) and coordinate 

procedures with the Coast Guard; state, county, and local emergency planning 

groups; fire departments; state and local law enforcement; and appropriate federal 

agencies. This plan should include at a minimum: 

a. designated contacts with state and local emergency response agencies; 

b. scalable procedures for the prompt notification of appropriate local officials 

and emergency response agencies based on the level and severity of potential 

incidents; 

c. procedures for notifying residents and recreational users within areas of 

potential hazard; 
4.12-49 4.12 – Reliability and Safety

d. evacuation routes/methods for residents and other public use areas that are 

within any transient hazard areas along the route of the LNG marine traffic; 

e. locations of permanent sirens and other warning devices; and 

f. an “emergency coordinator” on each LNG carrier to activate sirens and other 

warning devices. 

The ERP should be filed with the Secretary for review and written approval by the 

Director of OEP prior to initial site preparation. Jordan Cove should notify the 

FERC staff of all planning meetings in advance and should report progress on the 

development of its ERP at 3-month intervals. 

On several LNG import terminal proposals, a number of organizations and individuals have 

expressed concern that the local community would have to bear some of the cost of ensuring the 

security and emergency management of the LNG facility and the LNG carriers while in transit 

and unloading at the facility. In addition, section 3A(e) of the NGA (as amended by EPAct) 

specifies that the ERP shall include a Cost-Sharing Plan that contains a description of any direct 

cost reimbursements the applicants agree to provide to any state and local agencies with 

responsibility for security and safety at the LNG terminal and in proximity to LNG carriers that 

serve the facility. Therefore, we recommend that: 

• The ERP should include a Cost-Sharing Plan identifying the mechanisms for 

funding all project-specific security/emergency management costs that would be 

imposed on state and local agencies. In addition to the funding of direct transitrelated security/emergency management costs, this comprehensive plan should 

include funding mechanisms for the capital costs associated with any necessary 

security/emergency management equipment and personnel base. The Cost-Sharing 

Plan should be filed with the Secretary for review and written approval by the 

Director of OEP prior to initial site preparation. 

The Cost-Sharing plan must specify what the LNG terminal operator would provide to cover the 

cost of the state and local resources required to manage the security of the LNG terminal and 

LNG carrier, and the state and local resources required for safety and emergency management, 

including: 

• direct reimbursement for any per-transit security and/or emergency management costs 

(for example overtime for police or fire department personnel); 

• capital costs associated with security/emergency management equipment and personnel 

base (for example patrol boats, fire fighting equipment); and 

• annual costs for providing specialized training for local fire departments, mutual aid 

departments, and emergency response personnel; and for conducting exercises. 

The Cost-Sharing Plan must include the LNG terminal operator’s letter of commitment with 

agency acknowledgement for each state and local agency designated to receive resources. On 

March 31, 2009, Jordan Cove filed with FERC an MOU between Jordan Cove and the State of 

Oregon. The MOU establishes a framework for cooperation between the State of Oregon and 

Jordan Cove, as well as collaboration with the ODE, the Coast Guard, the Coos County Sheriff’s 

Department, the Coos Bay and North Bend Police and Fire Departments, and the North Bay and 
4.12-50 4.12 – Reliability and Safety

Charleston Fire Departments. The document outlines the responsibilities of Jordan Cove and the 

State of Oregon with respect to the safety and security of the terminal, including the resources 

and financing that Jordan Cove would provide to other entities for safety and security services. 

In the MOU, Jordan Cove has agreed to provide personnel, training, and money to ensure that 

the necessary safety and security resources would be available and operational prior to operation 

of the LNG terminal. 

4.12.7 Conclusions on LNG Carrier Safety 

Based on review of the WSA and an independent risk assessment, the Coast Guard has 

preliminarily determined that the Coos Bay navigational channel can be made suitable for the 

type and frequency of LNG marine traffic associated with the proposed Jordan Cove LNG 

facility. This preliminary determination is contingent upon the availability of additional 

measures necessary to responsibly manage the maritime safety and security risks. The Coast 

Guard would only allow LNG marine traffic to transit the Coos Bay navigational channel upon 

review and approval of Jordan Cove's TMP, as specified in the WSR. The TMP would become 

the basis for appropriate security measures for each maritime security threat level. 

The operational safety of LNG carriers is under the jurisdiction of the Coast Guard. LNG marine 

traffic transiting the Coos Bay navigational channel would be subject to Coast Guard inspections 

and enforcement practices. It would be required that, prior to the LNG carrier being granted 

permission to enter the shipping channels, both the carrier and facility must be in full compliance 

with the appropriate requirements of the Maritime Transportation Security Act and International 

Vessel and Port Facility Security Code, and the security protocols to be established by the COTP 

Sector Portland in the TMP. 

Since 1959, LNG has been transported by ship without a major release of cargo or a major 

accident involving an LNG carrier. Over the last 45 years, LNG carriers have made over 44,000 

voyages worldwide. Based on the extensive operational experience of LNG shipping and the 

structural design of an LNG carrier, the likelihood of a cargo containment failure and subsequent 

LNG spill from a vessel casualty - collision, grounding, or allision - is highly unlikely. For 

intentional spills, the impacts to public safety and property could exist within the Zones of 

Concern. The severity of impacts within the zones would depend on the location of the incident 

relative to a specific area, the scope of the incident, and whether the released LNG is ignited or 

dispersed. However, if the Coast Guard issues a LOR finding the waterway suitable for LNG 

marine traffic with the conditions referenced in the Waterway Suitability Report, the Coast 

Guard would control the transit of the LNG carrier through the harbor and while unloading 

cargo. The security provisions and operational controls that would be imposed by the Coast 

Guard, and the local pilots, to direct movement of LNG carriers would maintain the risk of a 

marine LNG spill, either with or without ignition, at acceptable levels. Therefore, the Jordan 

Cove Energy Project would be unlikely to result in a significant impact within the Zones of 

Concern because it is unlikely that a substantial cargo release would occur. 

4.12.8 Terrorism and Security Issues 

The security requirements for the onshore component of the proposed LNG project are governed 

by 49 CFR 193, Subpart J - Security. This subpart includes requirements for conducting security 

inspections and patrols, liaison with local law enforcement officials, design and construction of 

protective enclosures, lighting, monitoring, alternative power sources, and warning signs. 
4.12-51 4.12 – Reliability and Safety

Requirements for maintaining safety of the marine terminal are in the Coast Guard’s regulations 

in 33 CFR 127. Requirements for maintaining security of the marine terminal are in 33 CFR 

105. 

In the aftermath of the terrorist attacks that occurred on September 11, 2001, terrorism has 

become a very real concern for the facilities under the Commission's jurisdiction. The FERC, 

like other federal agencies, is faced with a dilemma in how much information can be offered to 

the public while still providing a significant level of protection to the facility. Consequently, the 

FERC has removed energy facility design plans and location information from its website to 

ensure that sensitive information filed under CEII is not readily available (RM02-4-000 and 

PL02-1-000 issued February 20, 2003). 

Since September 11, 2001, the FERC has been involved with other federal agencies in 

developing a coordinated approach to protecting the energy facilities of the United States. The 

FERC continues to coordinate with these agencies, specifically with the Coast Guard, to address 

this issue. The Coast Guard now requires arriving ships to provide it with a 96-hour advance 

notice of arrival that includes key information about the carrier and its crew, which allows the 

Coast Guard to conduct a terrorism risk assessment and put in place appropriate mitigation 

before the ship reaches the navigation channel. In addition, interstate natural gas companies are 

actively involved with several industry groups to chart how best to address security measures in 

the current environment. A Security Task Force has been created and is addressing ways to 

improve pipeline security practices, strengthen communications within the industry and the 

interface with government, and extend public outreach efforts. 

On October 22, 2003, the Coast Guard issued a series of six final rules, which promulgated the 

maritime security requirements of the Marine Transportation Security Act of 2002: 

Implementation of National Maritime Security Initiatives; Area Maritime Security; Carrier 

Security; Facility Security; Outer Continental Shelf Facility Security; and the Automatic 

Identification System. The entire series of rulemakings establishes a new subchapter H in 33 

CFR. In support of the rulemakings, the Coast Guard applied a risk-based decision-making 

process to comprehensively evaluate the relative risks of various target and attack mode 

combinations and scenarios for those carrier types and port facilities that pose a risk of a security 

incident. This approach provides a more realistic estimation of risk than a simple worst-case 

outcome assessment. Risk management principles acknowledge that while risk generally cannot 

be eliminated, it can be reduced by adjusting operations to lower consequences, threats, or 

vulnerability - recognizing that it is easier to reduce vulnerabilities by adding security measures. 

On December 29, 2003, all terminal owners or operators subject to 33 CFR 105 were required to 

submit a Facility Security Assessment and Facility Security Plan to the Coast Guard COTP for 

review and approval. The Facility Security Plans were required to be implemented no later than 

July 1, 2004, or for facilities constructed after July 1, 2004, 60 days prior to operations. Some of 

the principal owner or operator responsibilities include: 

• designating a FSO with a general knowledge of current security threats and patterns, risk 

assessment methodology, and the responsibility for implementing the Facility Security 

Plan and Assessment and performing an annual audit for the life of the LNG project; 

• conducting a Facility Security Assessment to identify site vulnerabilities, possible 

security threats and consequences of an attack, and facility protective measures; 
4.12-52 4.12 – Reliability and Safety

• developing a Facility Security Plan based on the Facility Security Assessment, with 

procedures for responding to transportation security incidents; notification and 

coordination with local, state, and federal authorities; prevention of unauthorized access; 

measures and equipment to prevent or deter dangerous substances and devices; training; 

and evacuation; 

• implementing scalable security measures to provide increasing levels of security at 

increasing MARSEC levels for facility access control, restricted areas, cargo handling, 

carrier stores and bunkers, and monitoring; 

• conducting security exercises at least once each calendar year and drills at least every 3 

months; and 

• reporting of all breaches of security and security incidents. 

Increased security awareness has occurred throughout the industry and the nation. President 

Bush established the Department of Homeland Security with the mission of coordinating the 

efforts of all executive departments and agencies to detect, prepare for, prevent, protect against, 

respond to, and recover from terrorist attacks within the United States. The Commission, in 

cooperation with other federal agencies and industry trade groups, has joined in the efforts to 

protect the energy infrastructure, including the more than 300,000 miles of interstate natural gas 

transmission pipeline and associated LNG facilities. 

Safety and security are important considerations in any Commission action. The attacks of 

September 11, 2001 have changed the way pipeline operators as well as regulators must consider 

terrorism, both in approving new projects and in operating existing facilities. However, the 

likelihood of future acts of terrorism or sabotage occurring at the proposed terminal expansion, 

or at any of the myriad of natural gas pipeline or energy facilities throughout the United States is 

unpredictable given the disparate motives and abilities of terrorist groups. However, existing 

and proposed security measures discussed in this section make significant impacts to human life 

and property from a terrorist attack unlikely. The continuing need to construct facilities to 

support the future natural gas pipeline infrastructure is not diminished from the threat of any 

such unpredictable acts. 

4.12.9 ODE Safety Advisory Report 

The NGA, as modified by the EPAct, requires that the FERC consult with the state in which an 

LNG terminal is proposed to be located regarding state and local safety matters. The governor of 

Oregon designated the ODE as the state agency that the FERC should consult with on safety and 

siting matters for the Jordan Cove terminal. On October 4, 2007, the ODE submitted its Safety 

Advisory Report to the FERC. In the report, ODE addressed state and local considerations. The 

EPAct also stipulates that before the FERC may issue an order authorizing an LNG terminal, it 

must “review and respond specifically” to the safety matters raised by the state agency 

designated as the lead for the state and local safety matters. Appendix C provides the FERC’s 

response to the ODE Safety Advisory Report for the Jordan Cove terminal. 

4.12.10 Pipeline Facilities 

The transportation of natural gas by pipeline involves some risk to the public in the event of an 

accident and subsequent release of gas. The greatest hazard is a fire or explosion following a 

major pipeline rupture. 
4.12-53 4.12 – Reliability and Safety

Methane, the primary component of natural gas, is colorless, odorless, and tasteless. It is not 

toxic, but is classified as a simple asphyxiate, possessing a slight inhalation hazard. If breathed 

in high concentration, oxygen deficiency can result in serious injury or death. 

Methane has an ignition temperature of 1,000 oF and is flammable at concentrations between 5 

and 15 percent in air. Unconfined mixtures of methane in air are not explosive. However, a 

flammable concentration within an enclosed space in the presence of an ignition source can 

explode. Methane is buoyant at atmospheric temperatures and disperses rapidly in air. 

4.12.10.1 Safety Standards 

The DOT is mandated to provide pipeline safety under 49 USC § 601. The PHMSA Office of 

Pipeline Safety (OPS) administers the national regulatory program to ensure the safe 

transportation of natural gas and other hazardous materials by pipeline. It develops safety 

regulations and other approaches to risk management that ensure safety in the design, 

construction, testing, operation, maintenance, and emergency response of pipeline facilities. 

Many of the regulations are written as performance standards which set the level of safety to be 

attained and allow the pipeline operator to use various technologies to achieve safety. The 

PHMSA ensures that people and the environment are protected from the risk of pipeline 

incidents. This work is shared with state agency partners and others at the federal, state, and 

local level. Section 5(a) of the Natural Gas Pipeline Safety Act provides for a state agency to 

assume all aspects of the safety program for intrastate facilities by adopting and enforcing the 

federal standards, while section 5(b) permits a state agency that does not qualify under section 

5(a) to perform certain inspection and monitoring functions. A state may also act as the DOT's 

agent to inspect interstate facilities within its boundaries; however, the DOT is responsible for 

enforcement action. The majority of the states have either 5(a) certifications or 5(b) agreements, 

while nine states act as interstate agents. 

The DOT pipeline standards are published in 49 CFR Parts 190-199. Part 192 of 49 CFR 

specifically addresses natural gas pipeline safety issues. 

Under a Memorandum of Understanding on Natural Gas Transportation Facilities (MOU) dated 

January 15, 1993, between the DOT and the FERC, the DOT has the exclusive authority to 

promulgate federal safety standards used in the transportation of natural gas. Section 

157.14(a)(9)(vi) of the FERC's regulations require that an applicant certify that it will design, 

install, inspect, test, construct, operate, replace, and maintain the facility for which a certificate is 

requested in accordance with federal safety standards and plans for maintenance and inspection, 

or shall certify that it has been granted a waiver of the requirements of the safety standards by the 

DOT in accordance with section 3(e) of the Natural Gas Pipeline Safety Act. The FERC accepts 

this certification and does not impose additional safety standards other than the DOT standards. 

If the Commission becomes aware of an existing or potential safety problem, there is a provision 

in the MOU to promptly alert the DOT. The MOU also provides for referring complaints and 

inquiries made by state and local governments and the general public involving safety matters 

related to pipeline under the Commission's jurisdiction. 

The FERC also participates as a member of the DOT's Technical Pipeline Safety Standards 

Committee, which determines if proposed safety regulations are reasonable, feasible, and 

practicable. 
4.12-54 4.12 – Reliability and Safety

The Pacific Connector pipeline and aboveground facilities must be designed, constructed, 

operated, and maintained in accordance with the DOT Minimum Federal Safety Standards in 49 

CFR Part 192. The regulations are intended to ensure adequate protection for the public and to 

prevent natural gas facility accidents and failures. Part 192 specifies material selection and 

qualification, minimum design requirements, and protection from internal, external, and 

atmospheric corrosion. 

Part 192 also defines area classifications, based on population density in the vicinity of the 

pipeline, and specifies more rigorous safety requirements for populated areas. The class location 

unit is an area that extends 220 yards on either side of the centerline of any continuous 1-mile 

length of pipeline. The four area classifications are defined as follows: 

• Class 1 – Location with 10 or fewer buildings intended for human occupancy. 

• Class 2 – Location with more than 10 but less than 46 buildings intended for human 

occupancy. 

• Class 3 – Location with 46 or more buildings intended for human occupancy or where the 

pipeline lies within 100 yards of any building, or small well-defined outside area 

occupied by 20 or more people on at least 5 days per week for 10 weeks in any 12-month 

period. 

• Class 4 – Location where buildings with four or more stories aboveground are prevalent. 

Class locations representing more populated areas require higher safety factors in pipeline 

design, testing, and operation. Pipelines constructed on land in Class 1 locations must be 

installed with a minimum depth of cover of 30 inches in normal soil and 18 inches in 

consolidated (solid) rock. Class 2, 3, and 4 locations, as well as drainage ditches of public roads 

and railroad crossings, require a minimum cover of 36 inches in normal soil and 24 inches in 

consolidated rock. 

Class locations also specify the maximum distance to a sectionalizing block valve. Pipe wall 

thickness and pipeline design pressures, hydrostatic test pressures, maximum allowable operating 

pressure, inspection and testing of welds and frequency of pipeline patrols and leak surveys must 

also conform to higher standards in more populated areas. Approximately 2.8 miles of the 

proposed Pacific Connector pipeline would be within Class 3 locations, 15.4 miles would be 

within Class 2 locations, and the remaining 211.9 would be within Class 1 locations. Class 

locations by MP are listed in table 4.12.10.1-1. Of the federally managed lands that would be 

crossed by the pipeline, all would be within Class 1 locations except about 0.49 mile of Class 2 

location within the BLM Medford District (MPs 120.27-120.46 and MPs 121.25-121.55). 

TABLE 4.12.10.1-1 

DOT Class Locations for the Proposed Pacific Connector Pipeline

Beginning MP Ending MP Class Location 

0.00 0.45 3 

0.45 9.95 1 

9.95 11.18 2 

11.18 11.9 1 

11.9 12.7 2 

12.7 22.4 1 

22.4 23.2 2 
4.12-55 4.12 – Reliability and Safety

TABLE 4.12.10.1-1 

DOT Class Locations for the Proposed Pacific Connector Pipeline

Beginning MP Ending MP Class Location 

23.2 49.5 1 

49.5 52.0 2 

52.0 55.6 1 

55.6 57.7 2 

57.7 65.5 1 

65.5 65.95 2 

65.95 66.5 2 

66.5 69.1 1 

69.1 70.8 2 

70.8 94.5 1 

94.5 95.0 2 

95.0 120.1 1 

120.1 121.6 2 

121.6 122.1 1 

122.1 123.2 2 

123.2 188.9 1 

188.9 190.0 2 

190.0 197.5 1 

197.5 199.3 3 

199.3 203.8 1 

203.8 204.9 2 

204.9 223.6 1 

223.6 223.9 3 

223.9 228.2 1 

228.2 228.4 3 

If a subsequent increase in population density adjacent to the right-of-way indicates a change in 

class location for the pipeline, Pacific Connector would be required to reduce the MAOP or 

replace the segment with pipe of sufficient grade and wall thickness, if applicable, to comply 

with the DOT code of regulations for the new class location. 

In 2002, Congress passed an act to strengthen the nation's pipeline safety laws. The Pipeline 

Safety Improvement Act of 2002 (HR 3609) was passed by Congress on November 15, 2002, 

and signed into law by the President in December 2002. As of December 17, 2004, gas 

transmission operators must develop and follow a written integrity management program that 

contains all the elements described in §192.911 and addresses the risks on each covered 

transmission pipeline segment. Specifically, the law establishes an integrity management 

program which applies to all high consequence areas (HCAs). The DOT (68 Federal Register 

69778, 69 Federal Register 18228, and 69 Federal Register 29903) defines HCAs as they relate 

to the different class zones, potential impact circles, or areas containing an identified site as 

defined in §192.903 of the DOT regulations. 

The OPS published a series of rules from August 6, 2002 to May 26, 2004 (69 Federal Register 

29903), that defines HCAs where a gas pipeline accident could do considerable harm to people 

and their property and requires an integrity management program to minimize the potential for 

an accident. This definition satisfies, in part, the Congressional mandate in 49 USC 60109 for 
4.12-56 4.12 – Reliability and Safety

the OPS to prescribe standards that establish criteria for identifying each gas pipeline facility in a 

high-density population area. 

The HCAs may be defined in one of two ways. In the first method an HCA includes: 

• current Class 3 and 4 locations, 

• any area in Class 1 or 2 where the potential impact radius3

 is greater than 660 feet and 

there are 20 or more buildings intended for human occupancy within the potential impact 

circle,4

 or 

• any area in Class 1 or 2 where the potential impact circle includes an identified site.5 

In the second method an HCA includes any area within a potential impact circle which contains: 

• 20 or more buildings intended for human occupancy, or 

• an identified site. 

Once a pipeline operator has determined the HCAs on its pipeline, it must apply the elements of 

its integrity management program to those segments of the pipeline within HCAs. The DOT 

regulations specify the requirements for the integrity management plan at § 192.911. Pacific 

Connector has identified 16 HCAs that are crossed by or adjacent to the proposed pipeline route 

(see table 4.12.10.1-2). None of the HCAs would be on federally managed lands. The pipeline 

integrity management rule for HCAs requires inspection of the entire pipeline in HCAs every 7 

years. 

TABLE 4.12.10.1-2 

High Consequence Areas Crossed by and Adjacent to the Proposed Pacific Connector Pipeline a/, b/

Beginning MP Ending MP Criteria Approximate Distance to Pipeline (feet) 

0.00 0.40 Class 3 

3.9 4.1 Identified Site 851 

8.20 Identified Site 330 

55.8 56.1 Identified Site 955 

57.0 57.5 Identified Site 955 

65.5 66.1 Class 3 

69.9 70.3 Identified Site 955 

94.6 95.1 Identified Site 335 – 955 

122.5 123.0 Identified Site 955 

189.8 189.9 Identified Site 955 

197.5 199.5 Class 3 

204.0 204.4 Identified Site 410 

206.3 206.4 Identified Site 270 – 955 

207.8 208.2 Identified Site 185 

223.45 224.05 Class 3 

 

3

 The potential impact radius is calculated as the product of 0.69 and the square root of the MAOP of the pipeline in psi 

multiplied by the pipeline diameter in inches. 

4

 The potential impact circle is a circle of radius equal to the potential impact radius. 

5

 An identified site is an outside area or open structure that is occupied by 20 or more persons on at least 50 days in any 12-month 

period; a building that is occupied by 20 or more persons on at least 5 days per week for any 10 weeks in any 12-month period; or 

a facility that is occupied by persons who are confined, are of impaired mobility, or would be difficult to evacuate. 
4.12-57 4.12 – Reliability and Safety

TABLE 4.12.10.1-2 

High Consequence Areas Crossed by and Adjacent to the Proposed Pacific Connector Pipeline a/, b/

Beginning MP Ending MP Criteria Approximate Distance to Pipeline (feet) 

227.7 228.6 Class 3 

a/ For 36-inch diameter pipeline with MAOP of 1,440 psi, the radius for the potential impact is 943 feet. 

b/ A High Consequence Area (HCA) is a requirement of part of 192 CFR. An HCA is determined on pipelines that are in service 

given a particular pressure, size, and diameter of the pipeline. An HCA becomes part of a comprehensive integrity maintenance 

plan based on collected data on the in service pipeline, the population density and type of population (for example limited 

mobility or schools). Since a “proposed” pipeline cannot correctly identify all of the input requirements imposed by the 

regulations, an HCA cannot be completely defined. However, areas of potential impact based on population density, proposed 

location, pipeline size, pressure, and diameter can be tentatively determined and are shown in the table above. 

Part 192 prescribes the minimum standards for operating and maintaining pipeline facilities, 

including the requirement to establish a written plan governing these activities. Under section 

192.615, each pipeline operator must also establish an ERP that includes procedures to minimize 

the hazards in a natural gas pipeline emergency. Key elements of the plan include procedures 

for: 

• receiving, identifying, and classifying emergency events, gas leakage, fires, explosions, 

and natural disasters; 

• establishing and maintaining communications with local fire, police, and public officials, 

and coordinating emergency response; 

• emergency shutdown of system and safe restoration of service; 

• making personnel, equipment, tools, and materials available at the scene of an 

emergency; and 

• protecting people first and then property, and making them safe from actual or potential 

hazards. 

Part 192 requires that each operator must establish and maintain liaison with appropriate fire, 

police, and public officials to learn the resources and responsibilities of each organization that 

may respond to a natural gas pipeline emergency, and to coordinate mutual assistance. The 

operator must also establish a continuing education program to enable customers, the public, 

government officials, and those engaged in excavation activities to recognize a gas pipeline 

emergency and report it to appropriate public officials. Pacific Connector would provide the 

appropriate training to local emergency service personnel before the pipeline is placed in service. 

No additional specialized local fire protection equipment would be required to handle pipeline 

emergencies. 

Pipeline system emergencies can include gas leaks, fire or explosion, and/or damage to the 

pipeline and aboveground facilities. Pacific Connector would maintain 24-hour emergency 

response capabilities, including an emergency-only phone number, which accepts collect 

charges. The number would be included in informational mail-outs, posted on all pipeline 

markers (installed at public road crossings), and provided to local emergency agencies in the 

vicinity of the pipeline and compressor station. 

As part of Pacific Connector’s ERP, operations personnel would attend training for emergency 

response procedures and plans prior to commencing pipeline operations. Pacific Connector 

would meet with local emergency responder groups (fire departments, police departments, landmanaging agencies including the BLM, USFS, and BOR, and other public officials) to review 
4.12-58 4.12 – Reliability and Safety

plans and would work with these groups to communicate the specifics about the pipeline 

facilities in the area and the need for emergency response. Pacific Connector would also meet 

periodically with the groups to review the plans and revise them when necessary. If requested by 

local public emergency response personnel, Pacific Connector would participate in any operatorsimulated emergency exercises and post-exercise critiques. Pacific Connector would use 

adequate local or contract resources to support the pipeline and facilities if an emergency occurs. 

All of the information that Pacific Connector gathers about its system would be used to tailor its 

safety and integrity management activities, so that parts of the system in the greatest need of 

attention receive greater scrutiny, such as residential areas or areas subject to growth and 

development. For example, Pacific Connector would decide where and when to internally 

inspect the pipeline based on this information. Risk assessment of the pipeline system 

determines what inspection criteria are required. This may include many different types of 

assessment tools that provide specific types of information about the condition of the pipeline. 

The Butte Falls Compressor Station would also be equipped with automatic emergency detection 

and shut down systems. For example, the station would have hazardous gas and fire detection 

systems, and an emergency shut down system. The emergency shutdown system would be 

designed to shut down and isolate elements of the compressor station in the event of a fire, 

before the development of a flammable mixture of gas could occur. The system would include 

sensors for detecting natural gas concentrations as well as ultraviolet sensors for detecting 

flames. Additionally, the compressor station equipment would be designed to shut down 

automatically if a mechanical failure poses risk to the equipment or otherwise constitutes a 

hazard. The compressor station would be equipped with relief valves to protect the piping from 

over-pressurization. 

Personnel would be able to respond to a compressor station emergency in 60 minutes or less 

during non-scheduled work hours and within a few minutes if they are at the compressor station. 

Personnel would be on call at all times, 24 hours a day, 365 days a year to respond to 

emergencies. Emergencies while the compressor station is unattended would be monitored 

remotely via the Gas Control Facility in Salt Lake City, Utah. Personnel living within a 30-

minute travel time of the compressor station would be dispatched by Gas Control in the event of 

an emergency at the compressor station. 

Personnel would be Operator Qualified per DOT PHMSA requirements for operational and 

emergency situations at the station. Fire protection, first aid, and safety equipment would be 

maintained at the compressor station and Pacific Connector personnel would be trained in first 

aid and proper equipment use. 

We received comments during scoping asking about the potential impact of a forest fire on 

pipeline integrity. Commenters questioned if additional pipeline burial depth would be 

necessary as protection against forest fires. Pacific Connector proposes to meet or exceed DOT 

pipeline burial depth requirements (found in 49 CFR Part 192), and would install the Pacific 

Connector pipeline with at least 36 inches of cover in Class I locations with normal soils and at 

least 24 inches of cover in consolidated rock areas. Soil is a poor conductor of heat with thermal 

conductivity values ranging from 0.44 to 1.44 BTU/FT-hr-deg F. The heat capacity of most soils 

is 0.20 to 0.25 BTU/LB-deg F. Based on the proposed burial depth of 24 to 36 inches, and the 

insulating effects of soil cover over the pipeline, we do not believe that forest fires would affect 
4.12-59 4.12 – Reliability and Safety

pipeline integrity. In addition, we do not believe that additional burial depth beyond what is 

proposed by Pacific Connector would be necessary to protect against damage by forest fires. 

The BLM and USFS have expressed concern about pipeline safety and reliability as it would 

relate to ongoing and future management activities on BLM- and USFS-managed lands. Pacific 

Connector would be required to prepare a POD for activities on BLM and NFS lands, and the 

ERP, as well as other safety and reliability measures requested by the BLM and USFS for 

federally managed lands, would be incorporated into the POD. The BLM and USFS would 

review draft plans to ensure all safety concerns associated with construction and operation of the 

proposed Pacific Connector pipeline on federally managed lands are addressed. 

4.12.10.2 Pipeline Accident Data 

Since February 9, 1970, 49 CFR Part 191 has required all operators of transmission and 

gathering systems to notify the DOT of any reportable incident and to submit a report on form 

F7100.2 within 20 days. Reportable incidents are defined as any leaks that: 

• caused a death or personal injury requiring hospitalization; 

• required taking any segment of transmission line out of service; 

• resulted in gas ignition; 

• caused estimated damage to the property of the operator, or others, or both, of a total of 

$5,000 or more; 

• required immediate repair on a transmission line; 

• occurred while testing with gas or another medium; or 

• in the judgment of the operator was significant, even though it did not meet the above 

criteria. 

The DOT changed reporting requirements after June 1984 to reduce the amount of data 

collected. Since that date, operators must only report incidents that involve property damage of 

more than $50,000, injury, death, release of gas, or that are otherwise considered significant by 

the operator. Table 4.12.10.2-1 presents a summary of incident data for the 1970 to 1984 period, 

as well as more recent incident data for 1986 through 2007, recognizing the difference in 

reporting requirements. The 14.5-year period from 1970 through June 1984, which provides a 

larger universe of data and more basic report information than subsequent years, has been subject 

to detailed analysis, as discussed in the following sections (Jones et al. 1986). 

TABLE 4.12.10.2-1 

Natural Gas Service Incidents by Cause

Incidents per 1,000 miles of Pipeline (percentage) 

Cause 1970-1984 1986-2007 

Outside force 0.70 (53.8) 0.09 (36.0) 

Corrosion 0.22 (16.9) 0.06 (23.1) 

Construction or material defect 0.27 (20.8) 0.04 (15.4) 

Other 0.11 ( 8.5) 0.06 (23.1) 

Total 1.30 0.25 
4.12-60 4.12 – Reliability and Safety

During the 14.5-year period, 5,862 service incidents were reported over the more than 300,000 

total miles of natural gas transmission and gathering systems nationwide. Service incidents, 

defined as failures that occur during pipeline operation, have remained fairly constant over this 

period with no clear upward or downward trend in annual totals. In addition, 2,013 test failures 

were reported. Correction of test failures removed defects from the pipeline before operation. 

Additional insight into the nature of service incidents may be found by examining the primary 

factors that caused the failures. Table 4.12.10.2-1 provides a percentage distribution of the 

causal factors as well as the annual frequency of each factor per 1,000 miles of pipeline in 

service. 

The dominant incident cause is outside forces, constituting 53.8 percent of all service incidents. 

Outside forces incidents result from the encroachment of mechanical equipment such as 

bulldozers and backhoes; earth movements due to soil settlement, washouts, or geologic hazards; 

weather effects such as winds, storms, and thermal strains; and willful damage. Table 4.12.10.2-

2 shows that human error in equipment usage was responsible for approximately 75 percent of 

outside forces incidents. Since April 1982, operators have been required to participate in "One 

Call" public utility programs in populated areas to minimize unauthorized excavation activities 

in the vicinity of pipelines. The "One Call" program is a service used by public utilities and 

some private sector companies (e.g., oil pipelines and cable television) to provide 

preconstruction information to contractors or other maintenance workers on the underground 

location of pipes, cables, and culverts. The 1986 through 2007 data show that the portion of 

incidents caused by outside forces has decreased to 36.0 percent. 

The pipelines included in the data set in table 4.12.10.2-1 vary widely in terms of age, pipe 

diameter, and level of corrosion control. Each variable influences the incident frequency that 

may be expected for a specific segment of pipeline. 

The frequency of service incidents is strongly dependent on pipeline age. While pipelines 

installed since 1950 exhibit a fairly constant level of service incident frequency, pipelines 

installed before that time have a significantly higher rate, partially due to corrosion. Older 

pipelines have a higher frequency of corrosion incidents, since corrosion is a time-dependent 

process. Further, new pipe generally uses more advanced coatings and cathodic protection to 

reduce corrosion potential. 

TABLE 4.12.10.2-2 

Outside Forces Incidents by Cause (1970-1984) 

Cause Percent 

Equipment operated by outside party 

Equipment operated by or for operator 

Earth movement 

Weather 

Other 

67.1 

7.3 

3.3 

10.8 

1.5 

Older pipelines have a higher frequency of outside forces incidents partly because their location 

may be less well known and less well marked than newer lines. In addition, the older pipelines 

contain a disproportionate number of smaller diameter pipelines, which have a greater rate of 

outside forces incidents. Small diameter pipelines are more easily crushed or broken by 

mechanical equipment or earth movements. 
4.12-61 4.12 – Reliability and Safety

Table 4.12.10.2-3 clearly demonstrates the effectiveness of corrosion control in reducing the 

incidence of failures caused by external corrosion. The use of both an external protective coating 

and a cathodic protection system, required on all pipelines installed after July 1971, significantly 

reduces the rate of failure compared to unprotected or partially protected pipe. The data shows 

that bare, cathodically protected pipe actually has a higher corrosion rate than unprotected pipe. 

This anomaly reflects the retrofitting of cathodic protection to actively corroding spots on pipes. 

TABLE 4.12.10.2-3 

External Corrosion by Level of Control (1970-1984) 

Corrosion Control Incidents per 1,000 miles per Year 

None-bare pipe 

Cathodic protection only 

Coated only 

Coated and cathodic protection 

0.42 

0.97 

0.40 

0.11 

4.12.10.3 Impact on Public Safety 

Pipeline Construction 

The USFS has expressed concern about public safety during construction of the Pacific 

Connector pipeline. Active pipeline construction can increase safety risks to the public generally 

in two ways, from an increase of traffic on roadways in the vicinity of the pipeline, and from 

potential exposure to construction activity itself within the construction right-of-way. 

During periods of active construction, roadways in the vicinity of the pipeline project would 

experience an increase in small vehicle traffic from the construction work force, as well as large 

vehicle traffic transporting construction equipment and materials. Where the pipeline would 

cross roadways, access to and from the right-of-way by construction vehicles and construction 

activity itself at the roadway crossing could disrupt traffic and create potential safety hazards to 

the public. Pacific Connector has developed draft Transportation Plans for both private and 

federal lands that describe measures that it would implement to minimize public access and 

safety concerns as a result of construction vehicle traffic and construction activity at roadway 

crossings (see addition discussion in sections 4.9.4.3 and 4.9.5). In addition, Pacific Connector 

would obtain all necessary permits for public roadway crossings and roadway use, and would 

comply with traffic control and public safety mitigation measures that are conditions of these 

permits. 

During pipeline construction, the general public could be exposed to safety hazards within the 

pipeline construction right-of-way itself. Hazards would be typical of a construction site 

involving clearing, grading, and excavation, and could include timber felling, heavy equipment 

operation including on steep slopes, open trench, falling or rolling rock on steep slopes, and fly 

rock from blasting. During active construction the contractor and company personnel present on 

the job would limit access to the public to potentially hazardous situations such as operation of 

heavy equipment, or blasting for trench excavation. During construction off hours, the public 

could be exposed to hazards such open trench or loose rock. Locating the pipeline in nonpopulated areas helps to minimize the chance for unauthorized public access to the right-of-way. 

Where the pipeline would be placed within residential areas, Pacific Connector would minimize 

impacts and potential safety hazards by ensuring that the construction proceeds quickly through 
4.12-62 4.12 – Reliability and Safety

such areas. Where the construction work area would be within 50 feet of a residence, Pacific 

Connector would install safety fence along the edge of the work area for a distance of 100 feet on 

either side of the residence. Fencing would be maintained, at a minimum, throughout the open 

trench phases of pipeline installation. Where feasible, Pacific Connector has reduced the width 

of the construction right-of-way near residences and placed TEWAs as far as practicable from 

the residences. In residential areas Pacific Connector would also limit the period of time the 

trench remains open prior to backfilling. For the residences within 50 feet of the proposed rightof-way, Pacific Connector has developed site-specific plans showing the temporary and 

permanent rights-of-way and noting special construction techniques and mitigation measures. 

The BLM and USFS can require Pacific Connector to incorporate additional specific public 

safety measures into the Plan of Development as a condition of a Right-of-Way Grant for use of 

federal lands. 

Pipeline Operation 

The service incident data summarized in table 4.12.10.2-1 include pipeline failures of all 

magnitudes with widely varying consequences. Approximately two-thirds of the incidents were 

classified as leaks, and the remaining third classified as ruptures, implying a more serious failure. 

Table 4.12.10.3-1 presents the average annual fatalities that occurred on natural gas transmission 

and gathering lines from 1970 to 2007. Fatalities between 1970 and June 1984 have been 

separated into employees and non-employees, to better identify a fatality rate experienced by the 

general public. Of the total 5.0 nationwide average, fatalities among the public averaged 2.6 per 

year over this period. The simplified reporting requirements in effect after June 1984 do not 

differentiate between employees and non-employees. However, the data show that the total 

annual average for the period 1984 through 2007 decreased to 3.5 fatalities per year. Subtracting 

two major offshore incidents in 1989, which do not reflect the risk to the onshore public, yields a 

total annual rate of 2.8 fatalities per year for this period. 

TABLE 4.12.10.3-1 

Annual Average Fatalities - Natural Gas Transmission and Gathering Systems a/, b/

Year Employees Non-employees Total 

1970-June 1984 2.4 2.6 5.0 

1984-2007 c/ - - 3.5 

1984-2007 c/ - - 2.8 d/

a/ 1970 through June 1984 – American Gas Association 1986. 

b/ DOT Hazardous Materials Information System. 

c/ Employee/non-employee breakdown not available after June 1984. 

d/ Without 18 offshore fatalities occurring in 1989 -- 11 fatalities resulted from a fishing carrier striking an offshore pipeline and 7 

fatalities resulted from explosion on an offshore production platform. 

The nationwide totals of accidental fatalities from various manmade and natural hazards are listed 

in table 4.12.10.3-2 in order to provide a relative measure of the industry-wide safety of natural gas 

pipelines. Direct comparisons between accident categories should be made cautiously, however, 

because individual exposures to hazards are not uniform among all categories. Nevertheless, the 

average of 2.6 public fatalities per year is relatively small considering the more than 320,000 miles 

of transmission and gathering lines in service nationwide. Furthermore, the fatality rate is 
4.12-63 4.12 – Reliability and Safety

approximately two orders of magnitude (100 times) lower than the fatalities from natural hazards 

such as lightning, tornados, floods, earthquakes, etc. 

TABLE 4.12.10.3-2 

Nationwide Accidental Deaths a/

Type of Accident Fatalities 

All accidents 

Motor vehicles 

Falls 

Drowning 

Poisoning 

Fires and burns 

Suffocation by ingested object 

Tornado, flood, earthquake, etc. (1984-93 average) 

All liquid and gas pipelines (1978-87 average) b/

Gas transmission and gathering lines non-employees only (1970-84 average) c/

90,523 

43,649 

14,985 

3,488 

9,510 

3,791 

3,206 

181 

27 

2.6 

a/ All data, unless otherwise noted, reflects 1996 statistics from the U.S. Department of Commerce, Bureau of the Census, 

"Statistical Abstract of the U.S. 118th Edition." 

b/ DOT 1987. 

c/ American Gas Association 1986. 

The available data show that natural gas pipelines continue to be a safe, reliable means of energy 

transportation. Based on approximately 320,000 miles in service, the rate of public fatalities for 

the nationwide mix of transmission and gathering lines in service is 0.01 per year per 1,000 miles 

of pipeline. Using this rate, the Pacific Connector pipeline and associated facilities might result 

in a public fatality every 435 years. This would represent a slight increase in risk to the nearby 

public.