LNG - What is it

Compiled by Arthur MacKayBocabec, NB, Canada

September, 2012Joyce Morrell cover graphic

From the campaign to prevent LNG terminals in Passamaquoddy BayDocuments and references used to explain LNG

RESOURCE FILES

About LNG(Liquified Natural Gas)

WHAT ARE RESOURCEFILES?

Resource files are created from the contents of the working reference and publication files of Art MacKay and are made available for reference purposes. They contain documents, drawings, photographs and other resources accumulated over a 50 year period, including public domain materials as well as materials with copyrights held by Arthur MacKay and others.

Since online resources come and go, they have been converted to PDFs and archived to preserve their contents. They can be accessed directly where the links are still active. Live links and copyright requirements are speci-fied for each item if still available. Art MacKay can be contacted at art@bayof fundy.ca to clarify availability for further publication.

Entire files composed of physical documents, books, photos, cds, etc. are available and sold separately.

RESOURCE FILES

LNG (Liquified Natural Gas)

Liquefied natural gas or LNG is natural gas (predominantly methane, CH4) that has been converted to liquidform for ease of storage or transport.

Liquefied natural gas takes up about 1/600th the volume of natural gas in the gaseous state. It is odorless, colorless, non-toxic and non-corrosive. Hazards include flammability, freezing and asphyxia.

The liquefaction process involves removal of certain components, such as dust, acid gases, helium, water, andheavy hydrocarbons, which could cause difficulty downstream. The natural gas is then condensed into a liquidat close to atmospheric pressure (maximum transport pressure set at around 25 kPa/3.6 psi) by cooling it toapproximately −162 °C (−260 °F).

LNG achieves a higher reduction in volume than compressed natural gas (CNG) so that the energy densityof LNG is 2.4 times heavier than that of CNG or 60% of that of diesel fuel.[1] This makes LNG cost efficient to

transport over long distances where pipelines do not exist. Specially designed cryogenic sea vessels (LNG carri-ers) or cryogenic road tankers are used for its transport. LNG is principally used for transporting natural gas to markets, where it is regasified and distributed as pipeline natural gas. It can be used in natural gas vehicles, although it is more common to design vehicles to use compressed natural gas. Its relatively high cost of produc-tion and the need to store it in expensive cryogenic tanks have hindered widespread commercial use. (Wikipedia.com)

LNG FAQs Relating to Passamaquoddy Bay

NOTE: FAQs as originally published on the internet. Many links no longer work.© Art MacKay************************************************

As more and more people become concerned about LNG in Passamaquoddy Bay, we are getting more and more questions. We have begun a FAQs page here to help you get answers. Various members of savepassamaquod-dybay.org have and will contribute to this. If you have information or a question, please send it to [email protected]

WHAT ARE THE ISSUES SURROUNDING THE PROPOSED TERMINALS

1. Other than being unappealing, how will these terminals affect the Bay of Fundy & its communities

This is largely an economic story with an important environmental background. The “Quoddy Region” is one of, if not the most productive areas square kilometer for square kilometer on the east coast. This is created by the huge tides that rush in twice daily through all of the passages between ledges and islands. This condenses plankton and results in “gardens” of bottom-dwelling invertebrates. These creatures in turn spew larvae and gametes into the water resulting in a localized elevation of productivity that feeds all of the fish, birds, whales, etc. on which our enterprises depend.

It’s against this background that we have developed over a billion dollar annual economy based on fisheries, tourism, aquaculture, and other resource-based industries. We’ve calculated this from available data and this does not include income from: the Maine shore; our small ports; research at the Biological Station, Huntsman, ASF,; various US groups in Cobscook Bay, real estate, the Arts community, etc.. We need to do a detailed eco-nomic evaluation of our economy. So... we already have an important economy that supports thousands of residents on the mainland and islands. While there are many concerns about fires, safety, terrorism, displacement of populations, related development of a polluting industrial cluster (which seems to always happen), the exclusion zones create the real and imme-diate loss. Based on FERC (Federal Energy Regulatory Commission) the exclusion zone will be 2 miles ahead, 1 miles behind, and 1000 feet on each side. The zone will be enforced by gunboats (which will be our coast guard - paid for by us?) and all traffic will be excluded. Since there could be anywhere from 2 ships a week to 9 (2 declared developments and 1 rumoured). This could result in the exclusion of all activities along the traffic lane from Grand Manan, through Head Harbour Passage and up to the Terminal across from St. Andrews. The area they are passing through fosters the fish, the birds, the whales, the water, etc. that gives us our wealth, ie this is where there is the most weirs, the most whales to watch, the most scallops to fish,, the most rockweed to harvest, the most aquaculture sites, the most birds to watch, etc. etc. We are being asked to trade a vibrant economy which has great promise in the future for LNG that will employ a handful of Americans and will have only 180 million dollars in benefit over the three years of construction (developer #2), with no benefits flowing to Canada. Those of our neighbours who support these developments do not, apparently, have concerns for those neighbours who will be displaced. We are not alone in our concerns. The entire Maine coast has refused to allow these terminals in. One major concern is the fact that they are usu-ally accompanied by cogeneration plants which draw other heavy industry to the multiple energy sources. Once heavy industry is allowed an opening, other heavy industry rushes in. We have seen that here already with two proposed terminals and talk about a third. For more information go to this slide show at http://www.bayoffundy.ca/LNG/slideshow . 2. Do we have a copy of their proposed site plans We have the plans from Developer # 2 (Robbinston) Downeast LNG. Developer #1, Quoddy Bay LLC has changed their plans so many times, that there is no concrete proposal. However, there are drawings at savepas-samaquoddybay.org.

3. Have the companies submitted zoning, amendment applications and etc to the town?

No. Both developers have leased lands. Developer #1 at the Passamaquoddy Reservation, Pleasant Point, and Robbinston; Developer #2 in Robbinston. Developers have presented plans to Robbinston selectmen who have said there should be a vote. Developers have purchased options on private land in both cases. 4. If so, is it the town policy to hold public meetings regarding application? What’s the appeal process?We have conducted over 40 public meetings around the Bay at all communities. Petitions were collected and tabled in the House of Commons. With the exception of Baileyville and Calais, every community has issued a declaration in opposition to the LNG proposed development.

As of last week, there is no appeal process. A law has been passed to allow FERC to override all local, regional, and state laws. Once they put their stamp of approval on a site, legally it is done!

TRANSPORTATION OF LNG BY TANKER

1. How do these tankers differ from cruise and other transport ships going to the Bayside port?

Substantially. They are slightly smaller than the Queen Mary, must be brought in by large tugs not their own steam (never done before through Head Harbour) Please see the following web page for all of the details (They are between 150,000 and 200,000 tons, 950 to 1000 ft long, 12 stories high and need four 5,000 hp tugs to handle them. They draw 40 feet of water. They carry liquid LNG which is flammable, I should say explosive under the right conditions. They carry the equivalent of 55 hiroshima bombs in energy potential. They take five miles to stop. They are blind for ¼ mile in front of them. They are most difficult to handle when they are mov-ing the most slowly.) http://timrileylaw.com/LNG_TANKERS.htm 2. In 1976 the Canadian government denied oil tankers from using this passage, what is different now? Stephane Dionne, in response to a question from Greg Thompson, stated that this still stands with a rider some-thing like, “based on current information”. Times have changed and the Americans have been testing our sover-eignty will over the last few weeks with forays into Head Harbour Passage and recently as far in as Chamcook Harbour. Very strange. Where’s our Coast Guard? Soverneighty is developing as a major issue not only here but in the Northwest Passage and the West coast. Canada will be tested on this issue) 3. What makes the Bay of Fundy “hazardous” to this type of transportation and product? The Bay of Fundy isn’t hazardous. In fact that is one of the reasons why we do not oppose LNG in Saint John. It is, however, hazardous to pass through Head Harbour Passage between Campobello and Deer Island, not to mention taking a sharp right through the Old Sow Whirlpool. Our group has not opposed LNG per se, we do oppose LNG in Passamaquoddy Bay because it is the wrong place and the trade-offs just aren’t there. The Lake Charles (USA) terminal has a long passage in through marshes. The current is negligable, the winds are kind. Our tidal current is strong, fast, unceasing, with no slack, only shearing. They want an hour or more of slack tide to come in here. They will have no slack tide. There is a rock mount half way across Head Harbour passage that leaves 25 feet at low tide, This cuts the width of the passage in half for these tankers. They have to come in almost against the Campobello shore line, up against the village of Wison’s Beach, the village of North Road and the town of Welshpool. We have very thick fog most of the late spring and early summer. We have strong winds in the fall, winter and early spring.

SECURITYSee Sandia Report

1. If the tankers will be in Canadian waters will our government allow US armed guards into our waterways to escort the ship? We don’t know. See comments about recent incursions above. Greg Thompson feels this is primarily a sover-eignty issue. Who pays for the escorts? If there are two terminals in here we will have a constant stream of tank-ers in and out, and possibly more waiting if the weather is bad or the tide is wrong.

2. Is this done anywhere else in Canada?

Don’t know.

3. How often does the CDN Coast Guards visit the Bay of Fundy? They are stationed in St. John. They visit the Passamaquoddy Bay area infrequently; usually for exercises and to tend navigation buoys.(They used to come on a regular basis to Campobello, but they seldom come now. One Canadian Coast Guard ship was in here a week ago and I was shocked at the poor condition of the ship. Joyce Morrell)

MARINE LIFE

This is a very long and important topic and it’s really too detailed to give a satisfactory answer here. Suffice to say that this is one of the richest areas on the east coast with over 2,000 identified marine species, many listed species, the Passage has a “global significance” designation for marine birds, has a right whale sanctuary, has been designated by Parks Canada with their “national significance” designation, and has been identified by nu-merous professionals as an area in need of protection.

1. Will their habitats be disturbed by the terminals or the tankers and how?

Yes. Please see the slide show: http://www.bayoffundy.ca/LNG/slideshow

2. What species will be most affected? Any considered at extreme risk or close to endangered?

There are many. The key species that is likely to impact the LNG development is the Right Whale. As you know this is the most endangered marine mammal in the world and it summers in a sanctuary that the tankers must pass through. The biggest hazard to these whales is ship strikes.

3. Do we have independent studies relating to the marine life issues?

Many. The area has been intensively studied since 1904.

Disaster Planning

1. It’s stated should there be an explosion it would wipe out a 6 mile radius. How do we know this?

Go to http://www.savepassamaquoddybay.org/documents/safety_reports/ for James Fay Passamaquoddy Study.

2. LNG is not crude oil, please explain the impact of a spill into the Bay of Fundy?

A spill will have virtually no environmental impact. If ignited, however, the fire could be catastrophic with se-vere social and environmental impacts. See http://timrileylaw.com for more than you ever wanted to know. A spill of LNG is much more controllable on land than it is on the water. Industry studies always speak of studies of fire, explosion etc. done on land, they never talk about water. A spill on water is immediately regas-sified because the water acts as a huge heat sink. The gas cloud hangs low over the water and travels extremely fast due to some synergistic effect between the water and the heavy, cold gas cloud. The gas cloud over water is totally uncontrollable. A gas plume can travel, some experts say, 30 miles and still be ignitable if it reaches any heat source or flame. No one knows the exact nature of the catastrophy that could happen because it cannot be studied on any realistic scale. LNG burning is more than 8 times hotter than gasoline. The fire is impossible to extinguish, it has to burn out. The heat radiation is severe. The LNG that arrives here in tankers is not pure

methane, it is a varying mixture of methane and other heavy hydrocarbons like butane and ethane, depending on the source of the gas. When industry says LNG will not explode, they refer to the properties of pure methane. LNG is not pure methane. Also, the impact of a growing industrial corridor in Passamaquoddy Bay would dev-astate the environment here and end our way of life as we know it. This cannot be quantified and the industry counts on that. 3. What type of disaster planning would be required by Bay of Fundy communities? A total revamp and building of systems in this end of the Bay. The only disaster planning we will have is the planning we provide and fund ourselves. If the tanker blows up in the bay the LLC corporation simply walks away, it has no liability for extreme scenarios. The companies are Limited Liability Companies (LLC) and never admits to any risk. TIMING

1. I understand we have 4 months to make an impact on the provincial/federal government, why? Because of the new law giving FERC siting authority. This could happen very fast. Also, the signals we have been getting from Ottawa up to this time are worrisome in the extreme.

2.There is a meeting with the LNG company on Aug 22, what’s the agenda & goal of this meeting?

Originally this was with Developer # 2 (Robbinston). He backed out and wants to reschedule for September Developer #1 wants the slot. Mayor Craig has asked Art MacKay to present for the Town, Brian Smith will present for QuoddyBay LLC. Microphones will be present for questions from the crowd. The Mayor indicated he wished to have the arena packed with people from around the Bay. The purpose will be to give the Develop-ers a message, but more particularly to send a clear signal to Ottawa of the magnitude of the opposition. 3. Construction of the terminals is slated for 2007 with a completion goal of 2010, is this correct?

Target dates keep changing.

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Why is LNG in Passamaquoddy Bay a Concern?© Art MacKay as originally published

LNG supertankers must pass through Canada’s Head Harbour Passage to Maine terminals. Exclusionary zones will damage commercial activity and the dangerous passage may result in catastrophic environmental disaster.

Passamaquoddy Bay

Passamaquoddy Bay is incredibly rich in marine resources due to its unique location at the mouth of the Bay of Fundy and the 25 foot tides that course through the dozens of islands and the bay. The resulting krill and plankton swarms provide abundant food and are the basis of the food chain for huge numbers of fish, birds and whales, including many endangered species.

Exclusionary Zone

The exclusionary zone can be 2 miles ahead of the tanker, 1 mile behind, and up to 1500 feet to each side. This

will be in effect while the tanker passes through, and while the tanker is at layover. Tankers may layover while awaiting the unloading facility to be free, and for appropriate tides and weather conditions. For the 6 summer months, there can be fog at the Passage up to 20 days per month. While tankers at the terminal, at layover or passing through, there can be no vessels in the exclusion zone and all commercial activity must cease and the area evacuated.

Impact

The passage, layover and exclusionary zones traverse ground fishing areas, aquaculture sites, lobster fishing ar-eas, herring weirs, whale and bird watching areas, calving and feeding areas for Right whales, Humpbacks and Minke whales, and Harbour porpoises and seals.

Fisheries and aquaculture - haddock, cod, herring, scallops, lobster and salmon - are worth $400 million annu-ally and provide more than 5,000 jobs.

Tourism is worth $340 million and supports thousands of jobs. Interruptions can result in downtime for com-mercial and tourism operations ranging from 30%-100% depending on number of tankers and weather condi-tions. Interruptions to fishing, processing and transportation of marine products will result in significant failure to meet market and contract commitments. Marine tourism operations, such as whale watching, bird watching, kayaking, will be unable to ensure visitors access to these activities. This lack of assurance will have an in-creasingly negative impact on these operations and all tourism infrastructure around Passamaquoddy Bay. Ferry service to the Fundy Isles is the lifeline for Deer Island, Grand Manan and Campobello Island. Interruptions to the ferry schedule or shutdowns will impact their ability to transport marine products and to access employment, medical services, schools and groceries.

Environment

The same conditions that produce the rich abundance of marine life in the Head Harbour Passage area also result in rips and confused water, upwellings, ebb slicks, shoals and whirlpools. For this reason, the Canadian government refused passage to tankers in 1976, noting that Head Harbour Passage was overwhelmingly the worst site studied, and that the value of the fisheries and aquatic bird resources was so high that no risk could be afforded These conditions have not changed, but these LNG supertankers are now 900 feet long with new ships under contract that will reach 1350 feet. There is a significant likelihood of a tanker having an accident.

Innocent Passage

The right of “innocent passage”, as contained in the UN Convention on the Law of the Sea 1982 (which the United States has not signed), and customary law specifically allow coastal states to designate sea lanes and require tankers carrying inherently dangerous materials to confine their passage to such lanes.It further allows the coastal state to adopt laws and regulations in respect of the safety of navigation, the conser-vation of marine resources, the prevention of infringement on fisheries laws, and the preservation of the envi-ronment of the coastal state.

Escorts

LNG tankers approaching American terminals are escorted by armed Coast Guard cutters, which would con-tinue through Canadian waters, and these warships would presumably take what they considered appropriate action should there be a vessel within or approaching the exclusionary zone.

Economic and Social Consequences

Should the fisheries industry be compromised with operators unable to meet contractual obligations, and should the tourism industry be unable to deliver promised services, or should an environmental disaster render these industries uneconomic or unsustainable, this will result in economic crisis for southwest New Brunswick.This will have long term and major impacts on government economic development and support, training and assistance programs.

Maine

Maine communities around Passamaquoddy Bay will suffer the same economic impacts. There are no plans to distribute this gas in Maine. It will just be added into the MN&P pipe line to Boston Siting decisions are now under the control of FERC (Federal Energy Regulatory Commission), rather than states or local communities, and their priorities differ from communities. Developers appear to be entrepreneurs, attracted to the investment potential of LNG.

Saint John

Saint John’s proposed LNG site is located in an established industrial area and approached from well-estab-lished sea lanes, clear of the navigational hazards of Head Harbour Passage. Irving and Repsol are established energy companies with the expertise to develop value-added industrial and consumer products. Saint John has trained personnel and an infrastructure to ensure safety and emergency conditions are professionally addressed.

REFERENCE ARCHIVE

9/7/12 Liquefied natural gas - Wikipedia, the free encyclopedia

1/16en.wikipedia.org/wiki/Liquefied_natural_gas#Safety_and_accidents

A typical LNG process. The gas is first extracted

and transported to a processing plant where it is

purified by removing any condensates such as

water, oil, mud, as well as other gases such as CO2

and H2S. An LNG process train will also typically

be designed to remove trace amounts of mercury

from the gas stream to prevent mercury

amalgamizing with aluminium in the cryogenic heat

exchangers. The gas is then cooled down in stages

until it is liquefied. LNG is finally stored in storage

tanks and can be loaded and shipped.

Liquefied natural gasFrom Wikipedia, the free encyclopedia

Liquefied natural gas or LNG is natural gas (predominantly methane, CH4) that has been converted to liquid

form for ease of storage or transport.

Liquefied natural gas takes up about 1/600th the volume of natural gas in the gaseous state. It is odorless, colorless,non-toxic and non-corrosive. Hazards include flammability, freezing and asphyxia.

The liquefaction process involves removal of certaincomponents, such as dust, acid gases, helium, water, andheavy hydrocarbons, which could cause difficultydownstream. The natural gas is then condensed into a liquidat close to atmospheric pressure (maximum transportpressure set at around 25 kPa/3.6 psi) by cooling it toapproximately −162 °C (−260 °F).

LNG achieves a higher reduction in volume thancompressed natural gas (CNG) so that the energy densityof LNG is 2.4 times heavier than that of CNG or 60% of

that of diesel fuel.[1] This makes LNG cost efficient totransport over long distances where pipelines do not exist.Specially designed cryogenic sea vessels (LNG carriers) orcryogenic road tankers are used for its transport.

LNG is principally used for transporting natural gas tomarkets, where it is regasified and distributed as pipelinenatural gas. It can be used in natural gas vehicles, although itis more common to design vehicles to use compressednatural gas. Its relatively high cost of production and theneed to store it in expensive cryogenic tanks have hinderedwidespread commercial use.

The Economist Intelligence Unit brought out a report inAugust 2012 entitled "Tankers on the horizon: Australia’scoming LNG boom" on the dominant trends in thedevelopment of Australia's gas resources and details theLNG projects that will unlock these resources for export tomarkets in Asia. Download the complimentary report(http://www.eiu.com/public/topical_report.aspx?campaignid=AusGas2012) .

Contents

1 Energy density and other physical properties2 Production



3 Commercial aspects

4 Trade

4.1 Imports

4.2 Cargo diversion

4.3 Cost of LNG plants

4.3.1 Small-scale liquefaction plants

5 LNG pricing

5.1 Oil parity5.2 S-curve

5.2.1 JCC and ICP

5.2.2 Brent and other energy

carriers

5.3 Price review

6 Quality of LNG

7 Liquefaction technology

7.1 Storage7.2 Transportation

7.2.1 Terminals

7.3 Refrigeration

8 Environmental concerns

8.1 Safety and accidents

9 See also10 References

11 External links

12 Other sources

Energy density and other physical properties

The heating value depends on the source of gas that is used and the process that is used to liquefy the gas. Thehigher heating value of LNG is estimated to be 24 MJ/L. The lower heating value of LNG is 21 MJ/L or 563623

BTU/ft3. For the purpose of comparison of different fuels the heating value is also known as the energy density

expressed in MJ/L or the gasoline gallon equivalent expressed in BTU/ft3. The energy density of LNG is 2.4 timesgreater than that of CNG which makes it economical to transport natural gas by ship in the form of LNG. Theenergy density of LNG is comparable to propane and ethanol but is only 60% that of diesel and 70% that of

gasoline.[2]

The density of LNG is roughly 0.41 kg/L to 0.5 kg/L, depending on temperature, pressure, and composition,compared to water at 1.0 kg/L.

One million BTU is 32.76kg.[3]

Production

The natural gas fed into the LNG plant will be treated to remove water, hydrogen sulfide, carbon dioxide and other



components that will freeze (e.g., benzene) under the low temperatures needed for storage or be destructive to theliquefaction facility. LNG typically contains more than 90% methane. It also contains small amounts of ethane,propane, butane, some heavier alkanes, and Nitrogen. The purification process can be designed to give almost100% methane. One of the risks of LNG is a rapid phase transition explosion (RPT), which occurs when cold

LNG comes into contact with water.[4]

The most important infrastructure needed for LNG production and transportation is an LNG plant consisting of oneor more LNG trains, each of which is an independent unit for gas liquefaction. The largest LNG train now inoperation is in Qatar. Until recently it was the Train 4 of Atlantic LNG in Trinidad and Tobago with a production

capacity of 5.2 million metric ton per annum (mmtpa),[5] followed by the SEGAS LNG plant in Egypt with acapacity of 5 mmtpa. The Qatargas II plant has a production capacity of 7.8 mmtpa for each of its two trains. LNGis loaded onto ships and delivered to a regasification terminal, where the LNG is allowed to expand and reconvertinto gas. Regasification terminals are usually connected to a storage and pipeline distribution network to distributenatural gas to local distribution companies (LDCs) or independent power plants (IPPs).

Information for the following table is derived in part from publication by the U.S. Energy Information

Administration.[6]

Plant Name Location CountryStartup

Date

Capacity

(mmtpa)Corporation

Qatargas II Ras Laffan Qatar 2009 7.8

Arzew GL4Z Algeria 1964 0.90

Arzew GL1Z Algeria 1978

Arzew GL1Z Algeria 1997 7.9

Skikda GL1K Algeria 1972

Skikda GL1K Algeria 1981

Skikda GL1K Algeria 1999 6.0

Lumut 1 Brunei 1972 7.2

Bontang A-B Indonesia 1977

Bontang A-D Indonesia 1986

Bontang A-E Indonesia 1989

Bontang A-F Indonesia 1993

Bontang A-G Indonesia 1998

Bontang A-H Indonesia 1999 22.6

Point FortinTrinidad and

Tobago1999 Atlantic LNG

Point FortinTrinidad and

Tobago 2003 9.9 Atlantic LNG

Damietta Egypt 2004 5.5 Segas LNG



Idku Egypt 2005 7.2

Bintulu MLNG 1 Malaysia 1983 7.6



Nigeria LNG Nigeria 1999 23.5

Northwest Shelf

VentureKarratha Australia 2009 16.3

Withnell Bay Karratha Australia 1989

Withnell Bay Karratha Australia 1995 (7.7)

Sakhalin II Russia 2009 9.6.[7]

Yemen LNG Balhaf Yemen 2008 6.7

Tangguh LNG

Project

Pappua

BaratIndonesia 2009 6.7

Qatargas I Ras Laffan Qatar 1996 (4.0)

Qatargas I Ras Laffan Qatar 2005 10.0

Qatargas III Qatar 2010 7.8

Rasgas I and II Ras Laffan Qatar 1999 6.6

Qalhat Oman 2000 7.3

Das Island IUnited Arab

Emirates1977

Das Island I and IIUnited Arab

Emirates1994 5.7

TOTAL WORLD 1990 50[8]



As most LNG plants are located in "stranded" areas not served by pipelines and the costs of LNG treatment andtransportation are huge, development was slow during the second half of the last century. The construction of anLNG plant costs at least $1.5 billion per 1 mmtpa capacity, a receiving terminal costs $1 billion per 1 bcf/daythroughput capacity, and LNG vessels cost $200-300 million.

In the early 2000s, as more players invested, both in liquefaction and regasification, and with new technologies, theprices for construction of LNG plants, receiving terminals and vessels have fallen, making LNG a more competitivemeans of energy distribution, but increasing material costs and demand for construction contractors have driven upprices in the last few years. The standard price for a 125,000 cubic meter LNG vessel built in European andJapanese shipyards used to be USD 250 million. When Korean and Chinese shipyards entered the race, increasedcompetition reduced profit margins and improved efficiency, costs were reduced by 60%. Costs in US dollar termsalso declined due to the devaluation of the currencies of the world's largest shipbuilders, Japanese yen and Korean



won. Since 2004, ship costs have increased due to a large number of orders which have increased demand forshipyard slots. The per-ton construction cost of an LNG liquefaction plant fell steadily from the 1970s through the1990s. The cost reduced by approximately 35%. However, recently, due to materials costs, lack of skilled labor,shortage of professional engineers, designers, managers and other white-collar professionals, the cost of buildingliquefaction and regasification terminals has doubled.

Due to energy shortage concerns, many new LNG terminals are being contemplated in the United States. Concernsover the safety of such facilities has created extensive controversy in the regions where plans have been created tobuild such facilities. One such location is in the Long Island Sound between Connecticut and Long Island.Broadwater Energy, an effort of TransCanada Corp. and Shell, wishes to build an LNG terminal in the sound onthe New York side. Local politicians including the Suffolk County Executive have raised questions about theterminal. In 2005, New York Senators Chuck Schumer and Hillary Clinton have both announced their opposition

to the project.[10] Several terminal proposals along the coast of Maine have also been met with high levels ofresistance and questions.

The commercial development of LNG is a style called value chain, which means LNG suppliers first confirm salesto the downstream buyers and then sign 20–25 year contracts with strict terms and structures for gas pricing. Onlywhen the customers are confirmed and the development of a greenfield project deemed economically feasible couldthe sponsors of an LNG project invest in their development and operation. Thus, the LNG liquefaction business hasbeen regarded as a game of the rich, where only players with strong financial and political resources could getinvolved. Major international oil companies (IOCs) such as ExxonMobil, Royal Dutch Shell, BP, BG Group;Chevron, and national oil companies (NOCs) such as Pertamina, Petronas are active players.

Reflecting slowdown in the economy, the growth rate of eight infrastructure sectors in India slowed down to 2.2%

in April 2012 because of poor performance of crude oil, natural gas, petroleum refinery products and fertilizers.[11]

Commercial aspects

LNG is shipped around the world in specially constructed seagoing vessels. The trade of LNG is completed bysigning a sale and purchase agreement (SPA) between a supplier and receiving terminal, and by signing a gas saleagreement (GSA) between a receiving terminal and end-users. Most of the contract terms used to be DES or exship, holding the seller responsible for the transport of the gas. With low shipbuilding costs, and the buyerspreferring to ensure reliable and stable supply, however, contract with the term of FOB increased. Under suchterm, the buyer, who often owns a vessel or signs a long-term charter agreement with independent carriers, isresponsible for the transport.

LNG purchasing agreements used to be for a long term with relatively little flexibility both in price and volume. If theannual contract quantity is confirmed, the buyer is obliged to take and pay for the product, or pay for it even if nottaken, in what is referred to as the obligation of take-or-pay contract (TOP).

In the mid 1990s, LNG was a buyer's market. At the request of buyers, the SPAs began to adopt some flexibilitieson volume and price. The buyers had more upward and downward flexibilities in TOP, and short-term SPAs lessthan 16 years came into effect. At the same time, alternative destinations for cargo and arbitrage were also allowed.By the turn of the 21st century, the market was again in favor of sellers. However, sellers have become moresophisticated and are now proposing sharing of arbitrage opportunities and moving away from S-curve pricing.There has been much discussion regarding the creation of an OGEC, the OPEC equivalent of natural gas. Russiaand Qatar, countries with the largest and the third largest natural gas reserves in the world, have finally supported

such move.[citation needed]



Until 2003, LNG prices have closely followed oil prices. Since then, LNG prices in Europe and Japan have beenlower than oil prices, although the link between LNG and oil is still strong. In contrast, prices in the US and the UK

have recently skyrocketed, then fallen as a result of changes in supply and storage.[citation needed]

In late 1990s and in early 2000s, the market shifted for buyers, but since 2003 and 2004, it has been a strong

seller's market, with net-back as the best estimation for prices.[citation needed]

Receiving terminals exist in about 18 countries, including India, Japan, Korea, Taiwan, China, Belgium, Spain, Italy,France, the UK, the US, Chile, and the Dominican Republic, among others. Plans exist for Argentina, Brazil,Uruguay, Canada, Greece, Ukraine and others to also construct new receiving (gasification) terminals.

Trade

In 1970, Global LNG trade was of 3 billion cubic metres.[12] In 2011, it was 331bcm.[13]

In 2004, LNG accounted for 7% of the world’s natural gas demand.[14] The global trade in LNG, which hasincreased at a rate of 7.4 percent per year over the decade from 1995 to 2005, is expected to continue to grow

substantially during the coming years.[15] The projected growth in LNG in the base case is expected to increase at

6.7 percent per year from 2005 to 2020.[15]

Until the mid-1990s, LNG demand was heavily concentrated in Northeast Asia — Japan, Korea and Taiwan. At

the same time, Pacific Basin supplies dominated world LNG trade.[15] The world-wide interest in using natural gas-fired combined cycle generating units for electric power generation, coupled with the inability of North Americanand North Sea natural gas supplies to meet the growing demand, substantially broadened the regional markets for

LNG. It also brought new Atlantic Basin and Middle East suppliers into the trade.[15]

By the end of 2007 there were 15 LNG exporting countries and 17 LNG importing countries. The three biggestLNG exporters in 2007 were Qatar (28 MT), Malaysia (22 MT) and Indonesia (20 MT) and the three biggestLNG importers in 2007 were Japan (65 MT), South Korea (34 MT) and Spain (24 MT). LNG trade volumes

increased from 140 MT in 2005 to 158 MT in 2006, 165 MT in 2007, 172[16] MT in 2008 and it is forecasted tobe increased to about 200 MT in 2009 and about 300 MT in 2012. During next several years there would besignificant increase in volume of LNG Trade and only within next three years; about 82 MTPA of new LNG supplywill come to the market. For example just in 2009, about 59 MTPA of new LNG supply from 6 new plants comesto the market, including:

Northwest Shelf Train 5: 4.4 MTPA

Sakhalin II: 9.6 MTPA

Yemen LNG: 6.7 MTPA

Tangguh: 7.6 MTPA

Qatargas: 15.6 MTPA

Rasgas Qatar: 15.6 MTPA

In 2006, Qatar became the world's biggest exporter of LNG,[17] As at 2012, 25% of the world's LNG exports are

from Qatar.[18]

Imports



In 1964, the UK and France made the first LNG trade, buying gas from Algeria, witnessing a new era of energy.

Today only 19 countries export LNG.[19]

Compared with the crude oil market, the natural gas market is about 60% of the crude oil market (measured on aheat equivalent basis), of which LNG forms a small but rapidly growing part. Much of this growth is driven by theneed for clean fuel and some substitution effect due to the high price of oil (primarily in the heating and electricitygeneration sectors).

Japan, South Korea, Spain, France, Italy and Taiwan import large volumes of LNG due to their shortage of energy.In 2005, Japan imported 58.6 million tons of LNG, representing some 30% of the LNG trade around the worldthat year. Also in 2005, South Korea imported 22.1 million tons and in 2004 Taiwan imported 6.8 million tons.These three major buyers purchase approximately two-thirds of the world's LNG demand. In addition, Spainimported some 8.2 mmtpa in 2006, making it the third largest importer. France also imported similar quantities as

Spain.[citation needed]

Cargo diversion

Based on the LNGSPAs, LNG is destined for pre-agreed destinations, and diversion of that LNG is not allowed.However if Seller and Buyer make a mutual agreement, then the diversion of the cargo is permitted subject tosharing the profits from such a diversion. In some jurisdictions such as in the European Union, it is not permitted toapply the profit-sharing clause in the LNGSPAs.

Cost of LNG plants

For an extended period of time, design improvements in liquefaction plants and tankers had the effect of reducingcosts.

In 1980s the cost of building an LNG liquefaction plant cost $350 per tpa (tonne per year). In 2000s, it was

$200/tpa. In 2012, the costs can go as high as $1000/tpa, partly due to the increase in the price of steel.[20]

As recently as 2003, it was common to assume that this was a “learning curve” effect and would continue into the

future. But this perception of steadily falling costs for LNG has been dashed in the last several years.[15]

The construction cost of green-field LNG projects started to skyrocket from 2004 afterward and has increasedfrom about $400 per ton per year of capacity to $1000 per ton per year of capacity in 2008.

The main reasons for skyrocketed costs in LNG industry can be described as follows:

1. Low availability of EPC contractors as result of extraordinary high level of ongoing petroleum projects world

wide.[7]

2. High raw material prices as result of surge in demand for raw materials.

3. Lack of skilled and experienced workforce in LNG industry.[7]

4. Devaluation of US dollar.

Recent Global Financial Crisis and decline in raw material and equipment prices is expected to cause some declinein construction cost of LNG plants, however the extent of such a decline is still unclear.



Small-scale liquefaction plants

Small-scale liquefaction plants are advantageous because their compact size enables the production of LNG closeto the location where it will be used. This proximity decreases transportation and LNG product costs forconsumers. The small-scale LNG plant also allows localized peakshaving to occur – balancing the availability ofnatural gas during high and low periods of demand. It also makes it possible for communities without access to

natural gas pipelines to install local distribution systems and have them supplied with stored LNG.[21]

LNG pricing

There are three major pricing systems in the current LNG contracts:

Oil indexed contract used primarily in Japan, Korea, Taiwan and China;

Oil, oil products and other energy carriers indexed contracts used primarily in Continental Europe;[22] and

Market indexed contracts used in the US and the UK.;

The formula for an indexed price is as follows:

CP = BP + β X

BP: constant part or base price

β: gradient

X: indexation

The formula has been widely used in Asian LNG SPAs, where base price refers to a term that represents variousnon-oil factors, but usually a constant determined by negotiation at a level which can prevent LNG prices fromfalling below a certain level. It thus varies regardless of oil price fluctuation.

Oil parity

Oil parity is the LNG price that would be equal to that of crude oil on a Barrel of oil equivalent basis. If the LNGprice exceeds the price of crude oil in BOE terms, then the situation is called broken oil parity. A coefficient of0.1724 results in full oil parity. In most cases the price of LNG is less the price of crude oil in BOE terms. In 2009,in several spot cargo deals especially in East Asia, oil parity approached the full oil parity or even exceeds oil

parity.[23]

S-curve

Many formula include an S-curve, where the price formula is different above and below a certain oil price, todampen the impact of high oil prices on the buyer, and low oil prices on the seller.

JCC and ICP

In most of the East Asian LNG contracts, price formula is indexed to a basket of crude imported to Japan calledthe Japan Crude Cocktail (JCC). In Indonesian LNG contracts, price formula is linked to Indonesian Crude Price(ICP).



Brent and other energy carriers

In the continental Europe, the price formula indexation does not follow the same format, and it varies from contractto contract. Brent crude price (B), heavy fuel oil price (HFO), light fuel oil price (LFO), gas oil price (GO), coalprice, electricity price and in some cases, consumer and producer price indexes are the indexation elements of priceformulas.

Price review

Usually there exists a clause allowing parties to trigger the price revision or price reopening in LNGSPAs. In somecontracts there are two options for triggering a price revision. regular and special. Regular ones are the dates thatwill be agreed and defined in the LNGSPAs for the purpose of price review.

Quality of LNG

LNG quality is one of the most important issues in the LNG business. Any gas which does not conform to theagreed specifications in the sale and purchase agreement is regarded as “off-specification” (off-spec) or “off-

quality” gas or LNG. Quality regulations serve three purposes:[24]

1 - to ensure that the gas distributed is non-corrosive and non-toxic, below the upper limits for H2S, total

sulphur, CO2 and Hg content;

2 - to guard against the formation of liquids or hydrates in the networks, through maximum water and

hydrocarbon dewpoints;

3 - to allow interchangeability of the gases distributed, via limits on the variation range for parameters

affecting combustion: content of inert gases, calorific value, Wobbe index, Soot Index, Incomplete

Combustion Factor, Yellow Tip Index, etc.

In the case of off-spec gas or LNG the buyer can refuse to accept the gas or LNG and the seller has to payliquidated damages for the respective off-spec gas volumes.

The quality of gas or LNG is measured at delivery point by using an instrument such as a gas chromatograph.

The most important gas quality concerns involve the sulphur and mercury content and the calorific value. Due to thesensitivity of liquefaction facilities to sulfur and mercury elements, the gas being sent to the liquefaction process shallbe accurately refined and tested in order to assure the minimum possible concentration of these two elementsbefore entering the liquefaction plant, hence there is not much concern about them.

However, the main concern is the heating value of gas. Usually natural gas markets can be divided in three markets

in terms of heating value:[24]

Asia (Japan, Korea, Taiwan) where gas distributed is rich, with an GCV higher than 43 MJ/m3(n), i.e. 1,090

Btu/scf,

the UK and the US, where distributed gas is lean, with an GCV usually lower than 42 MJ/m3(n), i.e. 1,065

Btu/scf,

Continental Europe, where the acceptable GCV range is quite wide: approx. 39 to 46 MJ/m3(n), i.e. 990 to



LNG storage tank at EG LNG

1,160 Btu/scf.

There are some methods to modify the heating value of produced LNG to the desired level. For the purpose ofincreasing the heating value, injecting propane and butane is a solution. For the purpose of decreasing heating value,nitrogen injecting and extracting butane and methane are proved solutions. Blending with gas or LNG can be asolutions; however all of these solutions while theorically viable can be costly and logistically difficult to manage inlarge scale.

Liquefaction technology

Currently there are 4 Liquefaction processes available:

1. C3MR (sometimes referred to as APCI): designed by Air Products & Chemicals, Incorporation.

2. Cascade: designed by ConocoPhillips.

3. Shell DMR

4. Linde

It is expected that by the end of 2012, there will be 100 liquefaction trains on stream with total capacity of 297.2MMTPA.

The majority of these trains use either APCI or Cascade technology for the liquefaction process. The otherprocesses, used in a small minority of some liquefaction plants, include Shell's DMR technology and the Lindetechnology. These processes are less important than the APCI or Cascade processes.

APCI technology is the most used liquefaction process in LNG plants: out of 100 liquefaction trains on-stream orunder-construction, 86 trains, with a total capacity of 243 MMTPA have been designed based on the APCIprocess: the second most used is the Philips Cascade process which is used in 10 trains with a total capacity of36.16 MMTPA. The Shell DMR process has been used in 3 trains with total capacity of 13.9 MMTPA; and,finally, the Linde/Statoil process is used only in the Snohvit 4.2 MMTPA single train.

Floating liquefied natural gas (FLNG) facilities float above an offshore gas field, and produce, liquefy, store andtransfer LNG (and potentially LPG and condensate) at sea before carriers ship it directly to markets. The first

FLNG facility is now in development by Shell,[25] due for completion in around 2017.[26]

Storage

Modern LNG storage tanks are typically full containment type, which hasa prestressed concrete outer wall and a high-nickel steel inner tank, withextremely efficient insulation between the walls. Large tanks are lowaspect ratio (height to width) and cylindrical in design with a domed steelor concrete roof. Storage pressure in these tanks is very low, less than10 kPa (1.45 psig). Sometimes more expensive underground tanks areused for storage. Smaller quantities (say 700 m³ (190,000 US gallons)and less), may be stored in horizontal or vertical, vacuum-jacketed,pressure vessels. These tanks may be at pressures anywhere from lessthan 50 kPa to over 1,700 kPa (7 psig to 250 psig).

LNG must be kept cold to remain a liquid, independent of pressure. Despite efficient insulation, there will inevitably



Tanker LNG Rivers, LNG capacity of

135,000 cubic metres

be some heat leakage into the LNG, resulting in vapourisation of the LNG. This boil-off gas acts to keep the LNGcold. The boil-off gas is typically compressed and exported as natural gas, or is reliquefied and returned to storage.

Transportation

LNG is transported in specially designed ships with double hullsprotecting the cargo systems from damage or leaks. There are severalspecial leak test methods available to test the integrity of an LNG vessel's

membrane cargo tanks.[27]

The tankers cost around $200 million each.[28]

Transportation and supply is an important aspect of the gas business,since natural gas reserves are normally quite distant from consumermarkets. Natural gas has far more volume than oil to transport, and most gas is transported by pipelines. There is anatural gas pipeline network in the former Soviet Union, Europe and North America. Natural gas is less dense,even at higher pressures. Natural gas will travel much faster than oil though a high-pressure pipeline, but cantransmit only about a fifth of the amount of energy per day due to the lower density. Natural gas is usually liquefiedto LNG at the end of the pipeline, prior to shipping.

Short LNG pipelines for use in moving product from LNG vessels to onshore storage are available. Longerpipelines, which allow vessels to offload LNG at a greater distance from port facilities are under development. This

requires pipe in pipe technology due to requirements for keeping the LNG cold.[29]

LNG is transported using both tanker truck, railway tanker, and purpose built ships known as LNG carriers. LNGwill be sometimes taken to cryogenic temperatures to increase the tanker capacity. The first commercial ship-to-

ship transfer (STS) transfers were undertaken in February 2007 at the Flotta facility in Scapa Flow[30] with132,000 m³ of LNG being passed between the vessels Excalibur and Excelsior. Transfers have also been carriedout by Exmar Shipmanagement, the Belgian gas tanker owner in the Gulf of Mexico, which involved the transfer ofLNG from a conventional LNG carrier to an LNG regasification vessel (LNGRV). Prior to this commercialexercise LNG had only ever been transferred between ships on a handful of occasions as a necessity following an

incident.[citation needed]

Terminals

Main article: List of LNG terminals

Liquefied natural gas is used to transport natural gas over long distances, often by sea. In most cases, LNGterminals are purpose-built ports used exclusively to export or import LNG.

Refrigeration

The insulation, as efficient as it is, will not keep LNG cold enough by itself. Inevitably, heat leakage will warm andvapourise the LNG. Industry practice is to store LNG as a boiling cryogen. That is, the liquid is stored at its boilingpoint for the pressure at which it is stored (atmospheric pressure). As the vapour boils off, heat for the phasechange cools the remaining liquid. Because the insulation is very efficient, only a relatively small amount of boil off isnecessary to maintain temperature. This phenomenon is also called auto-refrigeration.



Green bordered white diamond

symbol used on LNG-powered

vehicles in China

Boil off gas from land based LNG storage tanks is usually compressed and fed to natural gas pipeline networks.Some LNG carriers use boil off gas for fuel.

Environmental concerns

Issues commonly referenced include: focus on climate forcing associated with carbon dioxide production inextraction (however, in reality carbon dioxide emissions in the LNG supply chain are lower than in piping natural

gas from remote fields when considering equivalent transport distances), liquefaction, gasification and transport;[31]

Some groups have identified the plants' release of nitrogen oxide and particulate matter, known to aggravate asthmaand respiratory disease as a particular issue. However, combustion emissions from LNG plants are no greater than

from a similar energy-demand industrial plant burning natural gas;[32] environmental justice issues associated with

site placement;[33] and that expensive infrastructure investment will displace cleaner alternatives.[34]

A typical LNG liquefaction and export terminal exporting 4.5 million tonnes of LNG can be expected to produce inthe order of 1.2 million tonnes equivalent carbon dioxide of direct emissions. The greenhouse gas emissionsassociated with the combustion of 4.5 million tonnes of LNG is approximately 12 million tonnes equivalent carbondioxide.

On the West Coast of the United States where up to three new LNG importation terminals have been proposed,environmental groups, such as Pacific Environment, Ratepayers for Affordable Clean Energy (RACE), and Rising

Tide have moved to oppose them.[35] While natural gas power plants emit approximately half the carbon dioxide ofan equivalent coal power plant, the natural gas combustion required to produce and transport LNG to the plants

adds 20 to 40 percent more carbon dioxide than burning natural gas alone.[36] However, this assessment does notconsider the life cycle emissions of natural gas production, which include significant carbon dioxide emissions fromgas compression and transport. On a per kilometer transported basis, LNG carbon dioxide emissions are lowerthan piped natural gas emissions.

Natural gas could be considered the most environmentally friendly fossil fuel, because it has the lowest CO2

emissions per unit of energy and because it is suitable for use in high efficiency combined cycle power stations. On aper kilometre transported basis, emissions from LNG are lower than piped natural gas, which is a particular issue inEurope, where significant amounts of gas are piped several thousand kilometres from Russia. However, emissionsfrom natural gas transported as LNG are higher than for natural gas produced locally to the point of combustion asemissions associated with transport are lower.

Safety and accidents

Natural gas is a fuel and a combustible substance. To ensure safe andreliable operation, particular measures are taken in the design,construction and operation of LNG facilities.

In its liquid state, LNG is not explosive and can not burn. For LNG toburn, it must first vaporize, then mix with air in the proper proportions(the flammable range is 5% to 15%), and then be ignited. In the case of aleak, LNG vaporizes rapidly, turning into a gas (methane plus tracegases), and mixing with air. If this mixture is within the flammable range,there is risk of ignition which would create fire and thermal radiationhazards.



LNG tankers have sailed over 100 million miles without a shipboard death or even a major accident.[37]

Several on-site accidents involving or related to LNG are listed below:

1944, 20 October. The East Ohio Natural Gas Company experienced a failure of an LNG tank in

Cleveland, Ohio.[38] 128 people perished in the explosion and fire. The tank did not have a dike retaining

wall, and it was made during World War II, when metal rationing was very strict. The steel of the tank was

made with an extremely low amount of nickel, which meant the tank was brittle when exposed to the extreme

cold of LNG. The tank ruptured, spilling LNG into the city sewer system. The LNG vaporized and turned

into gas, which exploded and burned.

1979 October, Lusby, Maryland, at the Cove Point LNG facility a pump seal failed, releasing gas vapors

(not LNG), which entered and settled in an electrical conduit.[38] A worker switched off a circuit breaker,

igniting the gas vapors, killing a worker, severely injuring another and causing heavy damage to the building.

National fire codes were changed as a result of the accident.

2004, 19 January, Skikda, Algeria. Explosion at Sonatrach LNG liquefaction facility.[38] 27 killed, 56

injured, three LNG trains destroyed, 2004 production was down 76% for the year. A steam boiler that was

part of a liquefaction train exploded triggering a massive hydrocarbon gas explosion. The explosion occurred

where propane and ethane refrigeration storage were located.

See also

Compressed natural gas

Gasoline gallon equivalent

Industrial gasLiquefied petroleum gas

List of LNG terminals

LNG spill

Natural gas processing

Natural gas storage

Natural gas vehicle

References

1. ^ "Liquefied Petroleum Gas (LPG), Liquefied Natural Gas (LNG) and Compressed Natural Gas (CNG)"(http://www.envocare.co.uk/lpg_lng_cng.htm) . Envocare Ltd.. 2007-03-21.http://www.envocare.co.uk/lpg_lng_cng.htm. Retrieved 2008-09-03.

2. ^ Fuels of the Future for Cars and Trucks, Dr. James J. Eberhardt, U.S. Department of Energy, 2002 DieselEngine Emissions Reduction (DEER) Workshop, August 25–29, 2002

3. ^ [1] (http://www.todayonline.com/World/EDC120625-0000006/Spore-could-get-better-deal-buying-gas-from-US)

4. ^ Understand LNG Rapid Phase Transitions (RPT)(http://www.iomosaic.com/docs/training/Understand_LNG_RPT.pdf)

5. ^ "Atlantic waits on Train 4" (http://www.upstreamonline.com/live/article124283.ece) . Upstream Online (NHSTMedia Group). 2006-12-06. http://www.upstreamonline.com/live/article124283.ece. Retrieved 2008-01-19.

6. ^ The Global Liquefied Natural Gas Market: Status and Outlook, Appendix F, Energy Information Administration,http://www.eia.doe.gov/oiaf/analysispaper/global/pdf/app_f.pdf

7. ̂a b c Hashimoto, Hiroshi (2011). "Evolving Roles of LNG and Asian Economies in the Global Natural Gas



Markets" (http://www.nbr.org/downloads/pdfs/eta/PES_2011_Hashimoto.pdf) . Pacific Energy Summit.http://www.nbr.org/downloads/pdfs/eta/PES_2011_Hashimoto.pdf.

8. ̂a b http://www.lngpedia.com/wp-content/uploads/2009/01/lng-exports-by-country-1982-20072.jpg

9. ^ "The Global Liquefied Natural Gas Market: Status and Outlook"(http://www.eia.doe.gov/oiaf/analysispaper/global/exporters.html) . US Energy Information administration.December 2003. http://www.eia.doe.gov/oiaf/analysispaper/global/exporters.html.

10. ^ Long Island Business News, 2005 (http://www.allbusiness.com/legal/laws-government-regulations-environmental/917040-1.html)

11. ^ "Indian core sector growth slows down in April 2012" (http://www.engineeringfromindia.com/indian-core-sector-growth-slows-down-in-april/) . www.engineeringfromindia.com.http://www.engineeringfromindia.com/indian-core-sector-growth-slows-down-in-april/.

12. ^ [2] (http://www.economist.com/node/21558456)


14. ^ The role of LNG in a global gas market (http://www-static.shell.com/static/media/downloads/speeches/lcook_speech_oilandmoneyconf.pdf)

15. ̂a b c d e The Outlook for Global Trade in Liquefied Natural Gas Projections to the Year 2020, Prepared For:California Energy Commission, August 2007 Energy.ca.gov (http://www.energy.ca.gov/2007publications/CEC-200-2007-017/CEC-200-2007-017.PDF)

16. ^ World Gas Intelligence, May 6, 2009, Page 8





21. ^ https://inlportal.inl.gov/portal/server.pt/document/43128/liquefied_natural_gas_plant_4_pdf_%282%29

22. ^ Hughes, Peter (2011). "Europe's Evolving Gas Market: Future Direction and Implications for Asia"(http://www.nbr.org/downloads/pdfs/eta/PES_2011_Hughes.pdf) . Pacific Energy Summit.http://www.nbr.org/downloads/pdfs/eta/PES_2011_Hughes.pdf.

23. ^ http://www.walterenergy.info/mainframe.php?page=gas&level=9

24. ̂a b LNG Quality and Market Flexibility Challenges and Solutions Com.qa(http://www.lng14.com.qa/lng14.nsf/attach/$file/PS3-1.ppt)

25. ^ http://www.platts.com/weblog/oilblog/2011/03/31/shell_australia.html

26. ^ http://www.ft.com/cms/s/0/9ccaed4a-82ba-11e0-b97c-00144feabdc0.html#axzz1NADgzzOH

27. ^ "LNG Carrier Leak Test Completed Outside Korea" (http://www.oilandgasonline.com/article.mvc/LNG-Carrier-Leak-Test-Completed-Outside-Korea-0001?VNETCOOKIE=NO) . Oil and Gas Online. January 20, 2009.http://www.oilandgasonline.com/article.mvc/LNG-Carrier-Leak-Test-Completed-Outside-Korea-0001?VNETCOOKIE=NO. Retrieved 2009-02-11.


29. ^ Rankin, Richard (11/14/2005). "LNG Pipe-in-Pipe Techology"(http://www.lngplants.com/LNGPipeInPipeTechnology.html) .http://www.lngplants.com/LNGPipeInPipeTechnology.html. Retrieved 6/22/2012.

30. ^ http://www.orkneyharbours.com/ship_to_ship_transfers.asp

31. ^ LNGpollutes.org (http://www.lngpollutes.org/article.php?list=type&type=12) Ratepayers for Affordable CleanEnergy: LNG and Climate Change

32. ^ LNGpollutes.org (http://www.lngpollutes.org/article.php?list=type&type=13) Ratepayers for Affordable CleanEnergy: LNG and Your Health

33. ^ LNGpollutes (http://www.lngpollutes.org/article.php?list=type&type=13) Ratepayers for Affordable CleanEnergy: LNG and Your Health

34. ^ LNGpollutes (http://www.lngpollutes.org/article.php?list=type&type=4) Excerpt from "Collision Course: HowImported Liquefied Natural Gas Will Undermine Energy in California" by Rory Cox and Robert Freehling

35. ^ Pacific Environment : California Energy Program (http://www.pacificenvironment.org/article.php?list=type&type=21)

36. ^ Ratepayers for Affordable Clean Energy : Search (http://www.lngwatch.com/race/truth.htm)



37. ^ MSN.com (http://www.msnbc.msn.com/id/18556688/page/2/) , MSNBC U.S. Thirst for Natural Gas Grows,AP

38. ̂a b c CH-IV (December 2006). Safe History of International LNG Operations (http://www.ch-iv.com) .http://www.ch-iv.com.

External links

New LNG Plant Technology (http://www.inl.gov/research/liquefied-natural-gas-plant-technology/)

What is LNG and how is it becoming a U.S. energy source?

(http://tonto.eia.doe.gov/energy_in_brief/liquefied_natural_gas_lng.cfm)Liquefied Natural Gas in the US: Federal Energy Regulatory Commission (FERC)

(http://www.ferc.gov/industries/lng.asp)

LNG safety (http://www.our-energy.com/liquefied-natural-gas-lng_en.html)

Alternative Fuel Vehicle Training (http://www.naftc.wvu.edu) From the National Alternative Fuels Training

Consortium

LNG Safety (http://ch-iv.com/pdfs/riley_debunk.pdf) "The Risks and Dangers of LNG" is an exhaustive

report prepared by CH·IV International President, Jeff Beale, analyzing the points made in a controversial

Anti-LNG video.LNG Terminal Siting Standards Organization (http://www.lngtss.org) Advocating Government Adoption of

LNG Industry Standards

Prospects for Development of LNG in Russia (http://www.energystate.ru/eng/conferences/42.html)

Konstantin Simonov's speech at LNG 2008. April 23, 2008.

The Terrorist Threat to Liquefied Natural Gas: Fact or Fiction? (http://www.iags.org/hurstlng0208.pdf)

Other sources

The Global Liquefied Natural Gas Market: Status and Outlook

(http://www.eia.doe.gov/oiaf/analysispaper/global/index.html) - (Adobe Acrobat *.PDF document)

California Energy Commission: The Outlook for Global Trade in Liquefied Natural Gas Projections to the

Year 2020 (http://www.energy.ca.gov/2007publications/CEC-200-2007-017/CEC-200-2007-017.PDF) -

(Adobe Acrobat *.PDF document)

Guidance on Risk Analysis and Safety Implications of a Large Liquefied Natural Gas (LNG) Spill Over

Water (http://www.fossil.energy.gov/programs/oilgas/storage/lng/sandia_lng_1204.pdf) - (Adobe Acrobat

*.PDF document)

The International Group of Liquefied Natural Gas Importers (GIIGNL) (http://www.giignl.org/)The LNG Industry 2008 (http://www.giignl.org/fileadmin/user_upload/flipbook2008/pdf/lng_industry.pdf) -

(Adobe Acrobat *.PDF document)Society of International Gas Tanker and Terminal Operators (http://www.sigtto.org) World LNG Industry

Standards

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DRAFT DRAFT DRAFT

Section 1:Characteristics of a Generic LNG Project for the

Passamaquoddy Bay Region(DRAFT)

Table of ContentsSummary of a Generic LNG Facility...................................................................................2Potential Locations of Generic LNG Terminal....................................................................2Footprint...............................................................................................................................3Throughput/Sendout Capacity.............................................................................................3Pipeline................................................................................................................................3Shipping Route.....................................................................................................................5LNG Transport by Truck.....................................................................................................6LNG Vessels........................................................................................................................6Number of Vessel Transits per Year....................................................................................6Employment & Spending.....................................................................................................7

Construction Phase...........................................................................................................7Operation Phase...............................................................................................................7Employment at Sea .........................................................................................................7Tax Revenues...................................................................................................................7

Traffic..................................................................................................................................7

List of FiguresFigure 1: Potential Locations of LNG Facilities (attached)Figure 2: Exclusion Zones for LNG Storage TanksFigure 3: Potential Natural Gas Pipeline Routes (attached)Figure 4: Shipping Lane for LNG Vessels from the SouthFigures 5-9: Navigation Waypoints for LNG Vessel (attached)

List of TablesTable 1: Potential Pipeline Segments Associated with the Proposed LNG Facility (page 4)Table 2: Navigation Waypoints and Associated Time/Distance Waypoints for LNG Vessel (attached)

_____________________________________________________________________Yellow Wood Associates, Inc., 228 North Main St., St. Albans, VT 05478, 802-524-6141

1

LNG facility showing storage tank, pier, and LNG vessel.

DRAFT DRAFT DRAFT

Summary of a Generic LNG FacilityA generic LNG facility would consist of the following:• A parcel of land, approximately 80

acres in size, situated on the waterfront between Red Beach and Pleasant Point.

• A 3,500 foot pier extending from the shoreline, equipped with mechanical arms to off-load the LNG from the tankers (pier includes: jetty, trestle/bridge, breasting and mooring dolphins, and unloading platform).

• 130,000 cubic meter LNG vessels arriving at the terminal one out of every 5 and ½ days.

• Two 200,000 cubic meter LNG storage tanks (approximate outside diameter of 100 ft each).

• A sendout capacity (the total amount of natural gas that is delivered to the grid) of 500,000 million cubic feet per day (182.5 billion cubic feet per year), with the capacity to upgrade to 1,000,000 million cubic feet per day.

• A cryogenic pipe used to convery LNG from the pier to the storage tanks.• Support buildings and an access road.• Boil-off gas (BOG) compressors (used to recapture the heat produced in the

regasification process).• Water bath regasification units used to convert the LNG to a gas for distribution.• Natural gas pipeline connecting the terminal to the Maritimes & Northeast Pipeline.• A permanent right-of-way of 50 feet in width along the length of the pipeline.• A total cost of construction of $500 million.

Potential Locations of Generic LNG TerminalBased on proposals by different companies for an LNG facility on the U.S. side of Passamaquoddy Bay, potential sites extend as far north as Red Beach and as far south as Split Rock (Pleasant Point). See Figure 1 (attached) for a graphical representation of this area.


2

LNG Storage Tanks

100 ft

100 ft

Exclusion Zone (1000 ft radius)

Figure 2: Exclusion Zones for LNG Storage Tanks

DRAFT DRAFT DRAFT

FootprintFederal guidelines require that all LNG facilities have exclusion zones around the LNG storage tanks for public safety purposes. The regulations further require that the LNG facility either own or maintain control (i.e. through easements) of all lands within the exclusion zone. As a result, there is often a minimum parcel size on which a facility can legally exist. We will assume that for this project, there will be two (2) single containment tanks, comprised of a 9% nickel steel inner tank and a reinforced concrete outer tank wall with a capacity of approximately 200,000 m3. Single containment tanks are the most common LNG storage tank in the Americas.i For a tank of this design and capacity, the thermal and vapor exclusion zones would require an area with a radius of approximately 1000 feet from the center of each tank (see figure 2). If the base of each tank was positioned 100 feet from the shore, the exclusion zones would require a parcel of land that was 2150 feet in length and approximately 1250 feet in width, or approximately 62 acres.ii If double containment tanks were used, the exclusion zone would be less. Given additional structures and possible increased setbacks from the coast, for the purposes of this paper, we will assume a land area of 80 acres.

Throughput/Sendout CapacityThe total amount of natural gas that a LNG facility produces and delivers to the natural gas grid is referred to as the throughput capacity (also referred to as sendout capacity). We will assume that the sendout capacity for this project will be approximately 500,000 mmcfd (million cubic feet per day). At this rate, the total annual sendout would equal 182.5 BCF (billion cubic feet). In reality, this figure is lower than many of the existing or planned LNG facilities operating in the United States.iii Consequently, it is conceivable that once the facility is in operation, the total throughput will increase to 1,000,000 mmcfd (an annual total of 365 BCF).

PipelineIn order to deliver the natural gas to the existing grid for eventual distribution, a new pipeline (lateral) must be constructed to connect the LNG facility to the Maritimes and Northeast Pipeline, which stretches from Nova Scotia, Canada to Massachusetts.

The minimum size of the lateral would likely be 24 inches in diameter in order to deliver the anticipated throughput of the facility. Based on the potential location of a LNG terminal, the connector pipeline may be constructed along a number of possible routes (See figure 3).


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A right-of-way will be required to ensure access to the land along which the lateral will be constructed. The typical width of a construction right-of-way for a natural gas lateral will be approximately 75 feet (approximately 37 feet on either side of the centerline of the pipe). The area within the construction right-of-way will be cleared of trees and vegetation during the construction phase. If the pipeline parallels existing utility right-of-way, there may be minimum clearing necessary because the area should already be clear. Once the lateral has been installed, there will be a permanent right-of-way which will likely be 50 feet wide (25 feet on either side of the centerline). In fact, many municipalities are moving towards larger setbacks from natural gas pipelines. The additional setbacks could require an additional 50 feet from all buildings and, in some cases, require a doubling of the initial setback.iv

Landowners whose property is in the path of the permanent right-of-way must enter a legal agreement with the parent company that gives the company access to the right-of-way for maintenance purposes. Within a permanent right-of-way, the following actions are prohibited:

• Construction of buildings or structures• Planting of trees or other vegetation that may obstruct the right-of-way• Excavating, impounding water, or changing the grade of the land.• Moving heavy equipment• Blasting within 1000 feet of pipeline.v

Based on the potential pipeline routes in Figure 3, the minimum distance of a pipeline connecting to the Northeast Maritimes Pipeline would be approximately 5.2 miles (from Red Beach), while the maximum length would be 10 miles (from Pleasant Point, along segments A & C). Assuming a 50-foot permanent right-of-way along the pipeline segments, the total area of land within the right-of-way would range between 31 and 60 acres. The table below summarizes the length and area attributes of the right-of-way for the different pipeline segments shown in figure 3.

Table 1: Potential Pipeline Segments Associated with the Proposed LNG Facility

Segment Segment NameLength

(mi.)Area of Construction right-of-way (acres)

Area of Permanent right-of-way (acres)

A Pleasant Point - Mill Cove 2.8 25.2 16.8B Mill Cove - NMP 7.2 65.3 43.5C Mill Cove - NMP 5.7 51.6 34.4D Mill Cove - NMP 6.7 60.8 40.5E Red Beach - NMP 5.2 46.9 31.3

From Mill Cove, there are 3 possible pipeline routes (B, C, & D), which pass through different types of land use. Segment B & C would pass through the 1.7 and .7 miles (respectively) of the Moosehorn National Wildlife Refuge.


4

Figure 4: Shipping Lane for LNG Vessels from the South

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Shipping RouteThe transit route from sea to a potential location at the southernmost end of the LNG zone consists of passage through the Bay of Fundy to Head Harbour Passage and then on to Western Passage. LNG vessels approaching from the south will likely be directed to the traffic lane East of Grand Manan Island (see Figure 4). If an LNG facility were to be sited at the far north of the LNG zone near Red Beach, the vessel would also pass through Passamaquoddy Bay and a portion of the St. Croix River. See Figures 5-9 (attached) for detailed maps of the transit route.

TRC Companies, Inc.’s Preliminary Navigations/Waterways Analysis and LNG Safety Review for LNG Receiving Terminal at Port Pleasant, Maine indicates that the transit time between the initial waypoint northeast of Quoddy Head to near Pleasant Point (waypoint 9) is approximately 2 – 2 ½ hours. Based on the distance covered, the average speed is approximately 6 knots. Given this figure, the total transit time by transit leg for all waypoints (1-16) can be seen in column 11 in table 2 (Appendix B). The total transit time to the northernmost point (near Red Beach) in the LNG zone is approximately, 4 hours and 14 minutes.

During transit, the LNG vessel would likely be assisted by two tug boats and at least one U.S. Coast Guard Vessel. Due to the flammable nature of liquefied natural gas and the potential impact of a resulting fire or explosion, safety and security zones are enforced to safeguard the LNG vessels from sabotage and other terrorist activities. Federal regulations require a moving safety zone around any LNG vessel; however, the size of the safety zone varies from facility to facilityvi. In Cove Point, Maryland, there is a 500-yard safety zone (nearly 1/3 of a mile), while the Everett, Massachusetts (Boston Harbor) facility requires a safety zone that is 2 miles ahead, 1 mile astern, and 500 yards on either side while the LNG vessel is in transit. For the purposes of this report, we will assume the safety zone to be 1 mile ahead, ½ mile astern (880 yards) and 500 yards on each side. See figure X (TO BE COMPLETED)for a graphical representation of the safety zone as applied to a LNG vessel in Head Harbor Passage.

Vessels bound for U.S. port traveling through Canadian waters are piloted by U.S. pilots. Canadian regulations governing LNG transport in Canadian waters are less stringent those in the United States (LNG vessels are not required to have a Canadian Coast Guard escort). Transport Canada is the Canadian agency responsible for regulating vessel


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traffic. Upon entering the Bay of Fundy Vessel Transit Services (VTS) Zone, all vessels over twenty meters in length are required to notify the Canadian Coast Guard Personnel in Saint John, New Brunswick and maintain radio contact with controllers throughout the voyage. In addition, 24 hour advance notice is required for all vessels approaching this zone.

Once the LNG vessel has arrived at the terminal, federal regulations stipulate a safety zone around the docked vessel. As with the LNG vessels in transit, the extent of the safety zone around the docked vessel varies from one site to the next. For the purposes of this report, we will assume a 500 yard radius safety zone, which is indicated by figure Y (TO BE COMPLETED).

LNG Transport by TruckShould there be a perceived or real problem with the lateral or the Maritimes and Northeast Pipeline, distribution of LNG may need to occur by truck. LNG trailers typically carry around 11,000 gallons each. If a LNG vessel were to arrive when the storage tanks were full, one way to handle the situation would be to offload to trucks. It would take over 3,000 truckloads of LNG to transport the volume of a 130,000 cubic meters. LNG tankers must offload their cargo within a certain period of time, since a percentage of the extremely cold liquid burns off each day, making long hauls at sea unprofitable.vii In addition, if the parent company of this project decided to expand into the growing market for LNG as a vehicular fuel, LNG transport by truck would likely increase.viii

LNG VesselsThe typical LNG carrier can transport about 125,000 to 140,000 cubic meters of LNG, which, when gasified is equivalent to about 70 – 80 million m3 of natural gas.ix The dimensions of a vessel with a capacity of approximately 130,000 m3 are approximately 300 m in length, 43 m wide, and have a 12 m draft. Although, the largest vessel built to date is 145,000 m3, there are plans for a class of super tankers that would hold 200,000 m3 of LNG.x

Number of Vessel Transits per YearIf standard-sized ships carrying 125,000-138,000 cubic meters of LNG are used, each ship would provide about 2.6 – 2.8 BCF of natural gas, and it would take 65- 70 ships to deliver the anticipated throughput of 182.5 BCF per year (182.5/2.6 or 182.5/2.8). Assuming it takes each ship 12-24 hours to unload, there would be a tanker at the dock one day out of every 5 and a half days on average year round. If the capacity of the LNG Terminal is expanded to a throughput of 1 BCF per day as is likely, it would require 131-141 ships to deliver 365 BCF per year (365/2.6 or 365/2.8). This would mean that there


6

A typical LNG Vessel

A typical LNG Vessel

DRAFT DRAFT DRAFT

would be a tanker at dock one out of every approximately two and a half days on average year round.

Depending on the size of the LNG tankers used, there would be tankers in the shipping lanes from a minimum of 135 days to a maximum of 272 days per year, entering or exiting Passamoquoddy Bay.

Employment & Spending

Construction PhaseThe cost of construction of the LNG facility is estimated to be $500 million. The construction of a LNG facility is likely to span 36 months and employ and average of 250-300 workers (approximately 80 of which will be working on the pipeline). Of these workers, approximately 17-20 will be management/staff positions and the rest will be supervisors and crew. The total estimated payroll for these workers is between $15.8 (250 workers) and $19 million (300 workers). The total amount of sales of goods or services related to the project is likely to be $50 million or more.

Operation PhaseOnce the construction of the LNG facility is completed, approximately 40 permanent staff will be employed at the project site, including supervisors, operators, technicians, and mechanics. The annual payroll for these workers would likely be $2.6 million.

Employment at Sea TO BE DETERMINED.

Tax RevenuesThe annual tax revenue resulting from this project could be as much as $X.

TrafficFor the pier construction, approximately 30 barge loads of materials will be delivered to the site during the construction phase.xi Traffic directly related to construction of the facility and the pipeline is likely to consist of 118 heavy truck trips/month and 8 light truck trips/monthxii. The total volume of passenger trips may vary greatly, depending on the average occupancy per vehicle and the passengers point of origin, but may be as many as 18,000 trips/month.xiii


7

i Jacques Whitford Environment Limited. Environmental Impact Statement: Liquefied Natural Gas Marine Terminal and Multi-Purpose Pier. New Brunswick: Jacques Whitford Environment Limited, 2004. (prepared for Irving Oil), p. 41.ii http://www.weaverscove.com/files/ResourceReport10.pdfiii The annual sendout capacities of existing U.S. LNG terminals, including expansions, are as follows: Everett, MA Terminal – 360 BCF (billion cubic feet); Lake Charles, LA – 438 BCF; Cove Point, MD – 365 BCF; Elba Island, GA – 292 BCF (including planned improvements). Source:www.eia.doe.gov/oiaf/servicerpt/natgas/chapter3 iv Doherty, Jim. Setbacks and Zoning for Natural Gas and Hazardous Liquid Transmission Pipelines. Municipal Resarch & Services Center. Seattle, WA: 2004. p. 21v http://www.dom.com/about/gas-transmission/covepoint/expansion/pdf/pipeline_safety.pdfvi 33 CFR 3.05-10.vii Powers, Bill, P.E., Assessment of Potential Risk Associated with Location of LNG Receiving Terminal Adjacent to Bajamar and Feasible Alternative Locations, Prepared for Bajamar Real Estate Services, June 30, 2002, p.6.viii Energy Information Administration, Office of Oil and Gas, U.S. LNG Markets and Uses, January 2003.ix 1 cubic meter of natural gas = .00164 cubic meters of LNGx http://www.gsenet.org/host/lng-logan/PDF/MAY%203%202004%20COMMENT%20LETTER%20TO%20FERC.pdfxi Jacques Whitford Environment Limited, p. 90.xii Delivery and Departure are considered to be 2 trips. Jacques Whitford Environment Limited, p. 106.xiii 1 worker per car X 2 trips/day X 30 days/month X 300 workers

9/25/12 FERC: Help - Frequently Asked Questions (FAQs) - LNG

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Frequently Asked Questions (FAQs)

LNG

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1. What is LNG and what are some of its properties?

LNG properties are:

LNG (liquefied natural gas) is natural gas, primarily methane, which has been cooled to itsliquid state at -260°F (162.2°C)Liquefying natural gas reduces the volume it occupies by more than 600 times, making ita practical size for storage and transportationLNG (the liquid itself) is not flammable or explosiveLNG vapor (methane) is colorless, odorless and non-toxic. Methane can become anasphyxiant when it displaces the amount of oxygen that humans need for breathingLNG vapor (methane) typically appears as a visible white cloud since its cold temperaturecauses humidity in the air to condenseCold LNG vapor (methane) is flammable when it occurs in a 5%-to-15% concentration air.Less air does not provide enough oxygen to sustain a flame, while more air causes thefuel to become too dilute for ignitionvLNG vapor (methane) is not explosive in an unconfined environmentAfter LNG vapors (methane) become warmer than -160°F (-106.7°C), they becomelighter than air and will rise and disperse rather than collect near the ground

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2. Where does LNG come from?

Indonesia, Algeria, Malaysia, Trinidad and Qatar are currently the leading exporters of LNG.Russia and Iran also have the greatest potential.

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3. How is LNG shipped?

LNG is shipped via:

Specially designed ships are used to transport LNG to U.S. import terminals. The shipscan carry LNG over long distances and are constructed of specialized materials andequipped with systems designed to safely store LNG at temperatures of -260 °F(-162.2°C)All LNG ships are constructed with double hulls. This construction method increases theintegrity of the hull system, provides insulation for the LNG and provides protection forthe cargo tanks in case of an accidentThree basic tank designs have been developed for LNG ship containment and transport:prismatic free-standing, spherical, membrane

The "International Code for the Construction and Equipment of Ships Carrying LiquefiedGases in Bulk" (Gas Tanker Code) and Coast Guard regulations require that LNG shipsmeet a Type IIG standard of subdivision, damage stability, and cargo tank locationLNG is also transported via truck. LNG tanker trucks typically carry between 10,000 and12,000 gallons (38-to-45 m3) of LNG. LNG trucks are used to deliver LNG from its sourceto remote or satellite peak sharing facilities. LNG trucks are also used with portablevaporizers as a temporary supply of natural gas if normal supplies are interrupted or forpeak sharing during abnormal winter conditions

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4. Where do ships unload LNG?

Ships unload LNG at specially designed terminals where the LNG is pumped from the ship toinsulated storage tanks at the terminal. LNG is also converted back to gas at the terminal, whichis connected to natural gas pipelines that transport the gas to where it is needed. Speciallydesigned trucks may also be used to deliver LNG to other storage facilities in different locations.

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5. How is LNG stored?

LNG is stored:

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LNG is stored:

At more than 100 US facilities, either for use during periods of peak natural gas demandor as a real-time source of natural gas (from marine imports). Most facilities wereconstructed between 1965 and 1975.In double-walled, insulated tanks, at pressures only slightly higher than atmosphericpressure. The inner tank contains the LNG, while the outer tank contains the insulationand prevents any vapor (methane) from escapingIn facilities are required to have a dike or impounding wall capable of containing 110% ofthe maximum LNG storage capacity. In the unlikely event of a spill, this feature willprevent any LNG from flowing off of the siteStorage facilities also use advanced monitoring systems to immediately detect anynatural gas leaks or fires at the plantAll LNG storage facilities must comply with DOT (Department of Transportation) Title 49CFR Part 193 - Liquefied Natural Gas Facilities: Federal Safety Standards and NFPA(National Fire Protection Association) 59A - Standard for the Production, Storage andHandling of Liquefied Natural Gas.

Please visit our For Citizens LNG Overview page for similar LNG information and photographs.

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6. Why make LNG?

Cooling natural gas to -260°F (-162.2°C) changes it from a vapor into a liquid. This reduces thespace natural gas occupies by more than 600 times, making it a practical size for storage andtransportation.

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7. Is LNG explosive?

No, in its liquid state, LNG is not explosive. When LNG is heated and becomes a gas, the gas isnot explosive if it is unconfined. Natural gas is only flammable within a narrow range ofconcentrations in the air (5%-to-15%). Less air does not contain enough oxygen to sustain aflame, while more air dilutes the gas too much for it to ignite.

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8. What are the public safety issues related to LNG?

Safety issues are:Flammable Vapor Clouds

If LNG is spilled, the resulting LNG vapors (methane) will warm, become lighter than air,and disperse with the prevailing wind. Cold LNG vapor will appear as a white cloudIf a source of ignition is present where LNG vapors (methane) exist at 5%-to-15%concentration in the air, the vapor cloud will burn along a flame front toward the source ofthe fuelTo keep the public safe, vapor dispersion exclusion zones are calculated and plotted todetermine how far LNG vapors (methane) could possibly travel from a storage facility andstill be flammable. These zones must not reach beyond a property line that can be builtupon

Fires

If LNG is spilled in the presence of an ignition source, a fire will result from the continuousevaporation of the LNG contained within the impoundmentSince this fire would burn with intense heat, thermal exclusion zones are also calculatedand plotted to keep the public at a safe distance from possible heat exposure"Liquefied Natural Gas Facilities: Federal Safety Standards" are found in Title 49 CFR Part193 (You will be leaving FERC's website)

Dispelling the explosion myth

LNG is not explosive. Although a large amount of energy is stored in LNG, it cannot bereleased rapidly enough to cause the overpressures associated with an explosionLNG vapors (methane) mixed with air are not explosive in an unconfinedenvironment

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Updated: May 30, 2012

9/25/12 NEB - Energy Reports - Liquefied Natural Gas - A Canadian Perspective - Energy Market Asssessment

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Liquefied Natural Gas - A Canadian Perspective - Energy Market Asssessment - February 2009

[PDF 2787 KB]

An Energy Market Assessment

February 2009

Copyright/Permission to Reproduce

Table of Contents

List of Figures

List of Acronyms

List of Units and Conversion Factors

Units

Conversion Factors

Foreword

Executive Summary

Chapter 1 - Introduction

Chapter 2 - Backgroud

Liquefied Natural Gas - A Canadian Perspective - Energy

Market Asssessment

National Energy Board



2.1 Global Natural Gas Supply and Consumption

2.2 Inter-regional Natural Gas and LNG Trade

2.2.1 East-Asia

2.2.2 Europe

2.2.3 North America

2.3 Outlook on Global LNG Liquefaction and Regasification

2.4 Historical Pricing and Competition for Supply

2.5 Global Influences and Uncertainty

Chapter 3 - North American Natural Gas and LNG Development

3.1 Inter-relationship with Global Markets

3.1.1 Gas Interchangeability

3.1.2 Competition for LNG Supply

3.2 Snapshot of Proposed North American Regasification Development

3.3 North American Influences and Uncertainty

Chapter 4 - Canadian LNG Development

4.1 Current Status of Canadian Projects

4.2 East Coast

4.3 West Coast

4.4 Canadian Issues and Uncertainty

Chapter 5 - Conclusions and Observations

Glossary

Appendices

Appendix 1 Global Region Definitions

Appendix 2 Existing Global LNG Liquefaction Capacity

Appendix 3 Current Global LNG Regasification Capacity

Appendix 4 Illustrative Heat Content of Global LNG Supply

Appendix 5 The LNG Value Chain

List of Figures

Figure 1.1 LNG Share of World Natural Gas Market

Figure 1.2 Global Natural Gas Consumption and Outlook

Figure 1.3 Natural Gas Balance in Major Consuming Markets

Figure 2.1 Estimated Natural Gas Reserves (2007)

Figure 2.2 World Production and Consumption of Natural Gas (2007)

Figure 2.3 Growing Reliance on Natural Gas Imports

Figure 2.4 World LNG Production

Figure 2.5 Major LNG Producing and Consuming Regions (2007)

Figure 2.6 World LNG Markets

Figure 2.7 East-Asia Natural Gas Balance

Figure 2.8 East-Asia Seasonal LNG Requirement



Figure 2.9 LNG Supply to Japan

Figure 2.10 Natural Gas Production and Consumption in Major East-Asian Countries

Figure 2.11 European Natural Gas Production

Figure 2.12 European Natural Gas Balance

Figure 2.13 North American Natural Gas Balance

Figure 2.14 World Market Influence on U.S. LNG Imports

Figure 2.15 Global LNG Liquefaction and Regasification Outlook

Figure 2.16 Global LNG Liquefaction Under Construction

Figure 2.17 LNG Shipping Fleet

Figure 2.18 Atlantic Basin LNG Development

Figure 2.19 Asia-Pacific Basin LNG Development

Figure 2.20 Middle East LNG Liquefaction

Figure 3.1 North American Natural Gas Consumption and LNG Imports

Figure 3.2 U.S. LNG Imports

Figure 3.3 Natural Gas Production and Consumption in North America

Figure 3.4 Natural Gas Production and Consumption in Europe

Figure 3.5 U.S. LNG Imports and Atlantic Basin Competition

Figure 3.6 Atlantic Basin LNG Supply and North American Imports

Figure 4.1 Canadian LNG Projects

Figure 4.2 Illustrative Transportation Costs to Atlantic Basin Markets

Figure 4.3 Outlook for Canadian Gas Deliverability - Reference Case

Figure 4.4 Outlook for Canadian Gas Deliverability - Comparison of Cases

List of Acronyms

EIA U.S. Energy Information Administration

EMA Energy Market Assessment

GHG greenhouse gas

IEA International Energy Agency

LNG liquefied natural gas

NEB, the Board National Energy Board

Russia/FSU Russia and countries of the Former Soviet Union

U.K. United Kingdom

USA or U.S. United States of America

List of Units and Conversion Factors

Units



106m3 = million cubic metres

106m3/d = million cubic metres per day

109m3 = billion cubic metres

109m3/d = billion cubic metres per day

1012m3 = trillion cubic metres

Bcf = billion cubic feet

Bcf/d = billion cubic feet per day

Btu = British thermal unit

GJ = gigajoule

m3 = cubic metre

mtpa = million tonnes LNG per year

MMBtu = million British thermal units

$ or C$ = Canadian dollars

US$ = U.S. dollars

Tcf = trillion cubic feet

Conversion Factors

1 m3 gas = 35.3 cubic feet of natural gas

1 m3 LNG = 21,824 cubic feet of natural gas

1 Tonne LNG = 47,257 cubic feet of natural gas

Foreword

The National Energy Board (the NEB or the Board) is an independent federal agency whose

purpose is to promote safety and security, environmental protection, and efficient energy

infrastructure and markets in the Canadian public interest[*] within the mandate set by Parliament

in the regulation of pipelines, energy development and trade.

[*] NOTE: View our most recent Strategic Plan to see our Purpose, Vision, Goals, Values and Strategies.

The Board's main responsibilities include regulating the construction and operation of

interprovincial and international oil and gas pipelines, international power lines, and designated

interprovincial power lines. Furthermore, the Board regulates the tolls and tariffs for the pipelines

under its jurisdiction. With respect to the specific energy commodities, the Board regulates the

export of natural gas, oil, natural gas liquids and electricity, and the import of natural gas.

Additionally, the Board regulates oil and gas exploration and development on frontier lands and

offshore areas not covered by provincial or federal management agreements.

In an advisory function, the Board also keeps under review and analyzes matters related to its

jurisdiction and provides information and advice on aspects of energy supply, transmission and

disposition in and outside Canada. In this role, the NEB publishes periodic assessments to inform

Canadians on trends, events and issues which may affect Canadian energy markets.



The Board indicated in its 2007 Energy Market Assessment (EMA), Canada's Energy Future:

References Case and Scenarios to 2030 , that the import of liquefied natural gas (LNG) may play

an important role in the future energy supply available to Canadians. Through its scenarios on

energy supply and demand for the period 2005 to 2030, the Board provided projections on

possible LNG imports into Canada. Although the report indicated that LNG imports could

commence in 2009, the scenarios also suggested that there is significant uncertainty with

respect to the number of LNG terminals that will be built in Canada, as well as on the amount of

LNG that may be imported.

Given that Canada is a relative newcomer in the global LNG market[2], some Canadian natural gas

consumers have sought additional information from the NEB that would assist them to better

understand the dynamics in the global natural gas and LNG markets. In particular, these parties

believe that an independent and objective assessment of global LNG trade would provide valuable

insight regarding the likelihood and availability of future LNG imports to North America and on the

potential implications to Canadian natural gas markets and LNG development.

[2] Although a number of facilities have existed for many years in Quebec, Ontario, and British Columbia that

liquefy pipeline natural gas and store the LNG for later regasification and use during peak demand periods.

This report provides context on the historical global trade of natural gas and LNG and provides an

assessment of LNG supply and demand for the period 2008 to 2015. From this analysis, the Board

seeks to provide a high-level perspective on the potential implications to LNG development in

North America and on the potential effects that imported LNG may have on Canadian gas markets

and energy infrastructure.

The scope of this report does not include discussion of the safety and environmental regulations

associated with LNG development in Canada which would be subject to the purview of various

federal, provincial and municipal agencies depending on the location of the project. For more

information, a summary of the regulatory requirements for LNG development in Canada

[PDF 147 KB] may be found via the following link on the Board's website.

Any comments on this report or suggestions for further analysis can be directed to:

Margaret Skwara

Market Analyst

Strategy and Analysis

National Energy Board

E-mail: [email protected]

Telephone: 403-292-8617

Telephone (toll free): 1-800-899-1265

Telecopier: 403-292-5503

Telecopier (toll free): 1-877-288-8803

TTY (Teletype): 1-800-632-1663

If a party wishes to rely on material from this report in any regulatory proceeding, it can submit

the material as can be done with any public document. In such a case, the material is in effect

adopted by the party submitting it and that party could be required to answer questions on it.

Information about the NEB, including its publications, can be found by accessing the Board's



website at www.neb-one.gc.ca.

Executive Summary

Canada is a relative newcomer in the global market for liquefied natural gas (LNG). This Energy

Market Assessment provides an overview of global LNG supply and demand, trade, and a high-

level perspective on LNG development and the potential effects that imported LNG may have on

Canadian gas markets and energy infrastructure.

Despite current economic uncertainty, the world requirement for energy and natural gas is

projected to grow in the long-term. To meet this increasing requirement, consuming regions are

pursuing options to increase gas supply. Options include LNG and pipeline imports, connecting

new sources of conventional supply, and developing unconventional resources such as shale gas

and coalbed methane.

Global LNG trade enables the development and movement of significant natural gas resources

around the world to supplement domestic production and to diversify sources of natural gas in

consuming regions. The global LNG market continues to evolve with current prospects for the LNG

market quite different than anticipated only a couple of years ago when North American natural

gas prices were high relative to the rest of the world and LNG was viewed as a critical

incremental source of fuel to parts of North America, including Canada. In 2009, the demand

outlook for LNG has been significantly reduced as a result of weak financial and credit markets,

slower economic growth, volatile energy prices and the potential for development of other supply

options such as pipeline gas imports to Europe and increasing unconventional gas production in

North America.

The large amount of regasification capacity currently under construction and proposed to be in-

service by 2015 is projected to almost double the world's existing LNG receiving capacity.

Availability of supply, full globalization and price convergence in the LNG market is not however

expected to keep pace largely because of differences in how LNG prices are determined and the

fact that LNG liquefaction facilities require significant lead time for construction.

LNG pricing in major global markets is closely indexed to the price of crude oil or oil products. This

is in contrast with North American natural gas prices, which are determined by price competition

between various sources of natural gas. LNG price differences affect trading opportunities and

the flow of LNG between regions. Europe represents the primary competition to North America

regasification terminals for LNG supply.

Despite being the world's largest producer of natural gas, North America has historically required

LNG imports to supplement its indigenous production. North America generally acts as a swing

market for global LNG largely because of significant capacity for underground natural gas storage.

The extent to which North American LNG facilities are used and whether long-term supply is

available is determined by a number of additional competitive factors including local, national and

global market conditions and demand as well as specific contractual arrangements for supply and

markets.

The number of LNG projects to be developed in Canada in the near and long term remains unclear.



LNG development in Canada and North America is largely dependent on the outlook for continental

natural gas supply and demand. Current economic decline combined with recent increases in U.S.

natural gas production from shale and other unconventional gas resources has reduced

requirements for near-term LNG imports. The potential size and extent of shale gas resources

could significantly displace long-term North American and global LNG requirements.

In general, proposed and existing Canadian LNG projects are located competitively with other

North American and global terminals. The first Canadian LNG import terminal (Canaport LNG in

Saint John, New Brunswick) is expected to become operational in the first part of 2009. Eastern

Canadian import terminal projects are suitably located to serve the important New England market

where LNG has historically provided up to 25 per cent of the total natural gas requirement. LNG

import terminals on Canada's west coast are not anticipated in the near term because of

preference by suppliers to meet Asian demand.

Chapter 1 - Introduction

When natural gas is cooled to a temperature of approximately -160°C (-260°F) at atmospheric

pressure, it condenses into a liquid and is reduced to about 1/600th of its volume. This allows

large quantities of natural gas to be stored and transported in a more efficient and economic

manner[3]. Liquefied natural gas (LNG) has been used as a safe, convenient and effective means

to store and transport natural gas around the world for many decades[4].

[3] The LNG value chain is described in Appendix 5.

[4] LNG Safety and Security, Center for Energy Economics (2003).

In North America, commercial operations to liquefy and store natural gas were initiated in the

1940s and the first transatlantic LNG shipment by tanker took place in 1959. The LNG industry

was proven in earnest during the 1960s with the United Kingdom (U.K.) importing natural gas from

Algeria, after which additional marine liquefaction plants and import terminals were constructed

around the world. Operation of the first North American facility to liquefy and export LNG began in

Kenai, Alaska in 1969 and the first North American terminal to receive and regasify LNG opened in

Everett, Massachusetts in 1971. Since then, numerous LNG receiving terminals have been

constructed across North America including the first in Mexico in 2006 and the first in Canada

in 2009, located at Saint John, New Brunswick.

Historically, LNG was developed and used primarily as a means to commercialize stranded natural

gas resources around the world[5] and the natural gas used as an alternative to crude oil in

countries with little or no indigenous oil and gas production. Today, LNG provides an increasingly

important source of natural gas to satisfy a growing world demand for energy. In 2007, LNG

accounted for over 200 109m3 annually (almost 21 Bcf/d), or about 7.4 per cent of the global

natural gas production (Figure 1.1). In comparison, Canada's natural gas production and

consumption in 2007 was about 175 109m3 (17 Bcf/d) and 77 109m3 (8 Bcf/d), respectively.

[5] Natural gas resources considered too far from market to be accessed economically by pipeline.

Figure 1.1 - LNG Share of World Natural Gas Market



Source: BP Statistical Review of World Energy

As illustrated in Figure 1.2, worldwide natural gas consumption has increased by over 40 per cent

since 1990. In the same time, LNG production has approximately tripled. The growth in LNG

development has been fueled by the increasing consumption of natural gas, particularly for

electricity power generation. Demand for electricity remains strong worldwide and is expected by

the U.S. Energy Information Administration (EIA) to account for nearly one-half of the

incremental worldwide energy consumption over the period 2005 to 2030[6]. The EIA expects that

by 2030, over one-third of worldwide natural gas consumption will be used for electricity

generation and that total global natural gas consumption will increase by about 25 per cent, from

about 2 940 109m3 (104 Tcf) in 2005, to 3 660 109m3 (129 Tcf) by 2015.

[6] EIA International Energy Outlook, September 2008.

Figure 1.2 - Global Natural Gas Consumption and Outlook



Source: EIA International Energy Outlook 2008

Although the use of natural gas for electricity generation can vary across regions, consumption is

generally increasing as countries strive to meet growing energy demand, reduce carbon and other

greenhouse gas emissions (GHGs), and phase out the use of older generation facilities.

Meanwhile, natural gas production in the major consuming regions of North America, Europe and

Asia has not kept pace with the growth in demand for natural gas (Figure 1.3). In this

environment, the inter-regional trade of natural gas by either pipeline or LNG has become the

principle means to ensure that reliable and secure energy supplies are available to meet

requirements in these regions.

Figure 1.3 - Natural Gas Balance in Major Consuming Markets




The growing dependence on natural gas and competition for LNG in international markets has

stimulated growth in LNG projects worldwide.

Potential markets for additional LNG supply are continuing to evolve. Only a few years ago, North

American natural gas prices were the highest in the world as indigenous gas production struggled

to keep pace with the expected growth in regional demand. This growing reliance on natural gas

helped to spawn a number of projects to import LNG into North America. Today, new prospects

for indigenous natural gas production from shale and other unconventional sources appear very

promising and consumption has waned with a slowdown in the North American economy.

Moreover, Asian and European consumption and prices have increased, drawing away LNG supply

once available for North America. Facilities in North America which once contemplated LNG

imports are now also considering regulatory authorizations to re-export the imported LNG.

Scope of this Report

As Canada is a potential market for global LNG and a significant consumer of natural gas, this EMA

examines ongoing developments in global LNG. Chapter 2 examines the historical development of

LNG around the world and provides a high-level perspective and outlook on potential

developments in LNG supply and imports.

Next, Chapter 3 examines the recent LNG developments in North America, describes the possible

future role of LNG in North America, and provides a perspective on future LNG supply availability.

Chapter 4 provides further discussion on Canadian markets and LNG development. Note that this

report does not provide any detailed analysis or opinion on any specific project. Finally, Chapter 5

examines the potential uncertainties and issues with respect to Canadian LNG development and



includes a discussion of the possible implications for Canadian gas markets, LNG development, and

related NEB regulatory activities.

Chapter 2 - Global LNG and Natural Gas

2.1 Global Natural Gas Supply and Consumption

In simple terms, the increasing development of LNG is viewed as a key means to access

worldwide natural gas resources and supply the world's growing requirement for energy and

natural gas. Proven reserves of natural gas worldwide are about 20 times larger than the proven

reserves in North America and about 10 times larger than the combined proven reserves found in

the world's three largest LNG consuming regions (North America, Europe and East-Asia[7]).

In 2007, Canada's natural gas reserves were estimated to be about 1.6 1012m3 (58 Tcf), or less

than one per cent of worldwide reserves. Estimates for total worldwide natural gas reserves are

as high as 178 1012m3 (6 300 Tcf), of which over 70 per cent is located in Russia, the former

Soviet Union (FSU), and the Middle East (Figure 2.1).

[7] Includes major consuming countries of Japan, South Korea, China and Taiwan.

Figure 2.1 - Estimated Natural Gas Reserves (2007)

Source: IEA 2008

Figure 2.2 illustrates the relative levels of natural gas production and consumption in various

global regions and indicates that the regions which rely heaviest on inter-regional gas imports are

Asia and Europe. In North America, the United States and Mexico are also net importers, but as

one of the world's largest natural gas producing regions, historical North American LNG imports

have been relatively small compared to Asia and Europe.

Figure 2.2 - World Production and Consumption of Natural Gas (2007)




In 2007, East-Asia, Europe and North America consumed about 1.6 1012m3 (57 Tcf) of natural

gas, or more than half of the world's total natural gas production. In its recent reference case

outlook, the EIA has suggested that the combined annual imports into these three regions would

increase from about 440 109m3 (16 Tcf) in 2005, to over 600 109m3 (21 Tcf) by 2015, or an

increase of about 37 per cent[8]. The outlook also suggested that annual North American natural

gas demand will increase by over 60 109m3 (1.8 Tcf) or ten per cent during this period, up to

about 840 109m3 (30 Tcf) by 2015. Over the same period, annual natural gas consumption in

Europe and East-Asia are projected to increase by about 150 109m3 (5 Tcf) and 88 109m3

(3 Tcf), respectively.

[8] EIA International Energy Outlook, September 2008

The projected increase in natural gas production in the three regions is more moderate, increasing

by only about 130 109m3 (3.7 Tcf) or ten per cent over the period 2005 to 2015. As a result, the

overall gap between production and consumption within these regions is widening, which suggests

an increasing reliance by these regions on external sources of natural gas (Figure 2.3). Although

there is a corresponding increase in natural gas production worldwide, the widening gap between

natural gas produced and consumed within these regions has been the primary driver in the

development of incremental LNG supply and in the growth of inter-regional natural gas trade.

Figure 2.3 - Growing Reliance on Natural Gas Imports




Historically, LNG supply has been developed in countries where natural gas resources far

exceeded local requirements and shipping distances to major consuming markets were

economically feasible. Continued advances in LNG production[9] and transportation technology are

now extending LNG development into other more distant regions as cost-competitive sources of

gas supply. The Middle East has emerged in recent years as a major LNG supply region,

augmenting traditional supply from the Asia-Pacific region and Africa (Figure 2.4). In addition to

the Middle East, significant new LNG liquefaction or production facilities are also being developed

in Russia and are expected to begin LNG deliveries by early 2009.

[9] The production of LNG from natural gas is also referred to as liquefaction.

Figure 2.4 - World LNG Production




The number of new liquefaction facilities currently under construction highlights the growing

importance of these new supply sources in the global LNG market. Based on capacity that

currently exists or is under construction, the Middle East and Russia are projected to account for

up to about 150 109m3 (5 Tcf) of annual LNG output by 2015, or up to 38 per cent of total world

LNG production. In 2007, total world LNG production was about 225 109m3 (8 Tcf), about one-

quarter of which was produced in the Middle East. By 2015, the Middle East may supply over one-

third of world LNG with another three per cent coming from Russia/FSU. For comparison, in 1990

only four per cent of world LNG was produced in the Middle East and almost 95 per cent of global

LNG was produced in Africa and the Asia-Pacific region encompassed by Oceania.

2.2 Inter-regional Natural Gas and LNG Trade

The global LNG trade amongst regions in 2007 is shown in Figure 2.5, which illustrates the

production, consumption, LNG exports and flows of natural gas by pipeline and LNG into the

consuming regions. The figure provides a perspective on the relative scale of operation within the

different regions and the dependency of various regions on domestic production, pipeline imports

and LNG. The historical LNG volumes imported into the various global regions are shown in

Figure 2.6 and provides a perspective on the relative size of the various LNG consuming markets.

The key characteristics of the major LNG consuming markets are reviewed in the following

sections.

Figure 2.5 - Major LNG Producing and Consuming Regions (2007) - 109m3




Figure 2.6 - World LNG Markets


2.2.1 East-Asia

Although the East-Asia region accounts for less than ten per cent of world natural gas

consumption, the region is by far the largest market for LNG, accounting for almost two-thirds of

global LNG consumption and includes the world's two largest consumers of LNG, Japan and South

Korea. Combined with India, the general region consumed almost 70 per cent of the world LNG



supply in 2007. Without significant oil and gas production and having no access to natural gas via

pipeline, consuming countries in East-Asia have relied on LNG from nearby Pacific Rim countries

for the majority of their natural gas supply (Figure 2.7).

Figure 2.7 - East-Asia Natural Gas Balance

* Predominately From China


In East-Asia, electricity generation accounts for the largest portion of natural gas consumption,

at almost 45 per cent of the region's total natural gas usage. In Japan, the share used for

electricity generation is even greater and has been as high as 65 per cent in recent years. After

electricity generation, much of the remaining gas is consumed in the residential, commercial and

industrial sectors, in roughly equal proportions.

Given the weather-sensitive nature of natural gas consumption in this region for electricity

generation and for residential and commercial heating demand, the quantity of LNG imports is

largely seasonal and is very dependent on the amount of electricity that can be generated from

alternative fuels (e.g., nuclear, oil, coal). With minimal gas production or pipeline options in this

region, the main competing fuel source to natural gas is crude oil or oil products. For this reason,

the purchase price of LNG in Asian markets is commonly linked to the average price of crude oil or

sometimes to oil products. The region also has little capacity for underground natural gas

storage. Consequently, the region relies mainly on LNG storage in aboveground tanks and variable

LNG import levels to manage and balance significant fluctuations in demand (Figure 2.8).

Figure 2.8 - East-Asia Seasonal LNG Requirement



Source: Various data sources

In 2007, Japan imported close to 90 109m3 (3.1 Tcf) of LNG, and South Korea imported almost

35 109m3 (1.1 Tcf) of LNG. Although there has been significant growth during the last decade in

other Asian markets such as Taiwan, China and India, Japan alone still represents over

40 per cent of global LNG consumption and about 60 per cent of the Asian LNG market. South

Korea accounts for another 16 per cent of global LNG consumption and over 23 per cent of the

Asian LNG market. The historical LNG imports into Japan are shown in Figure 2.9, which illustrates

Japan's growing LNG requirement and its outreach to non-traditional supply sources in the

Atlantic Basin.

Figure 2.9 - LNG Supply to Japan



Source: Japan Ministry of Finance

The chart also illustrates the impact of the July 2007 closure of Japan's largest nuclear electricity

generation plant on its overall LNG requirement[10]. Following closure of the nuclear plant, Japan's

LNG imports increased by more than six per cent. During the winter months when demand is

typically greatest, Japan's monthly LNG imports were up by more than one 109m3 (30 Bcf) over

the previous winter. To meet this requirement, the higher-priced Japanese market attracted

incremental LNG supply from the Atlantic Basin, including sources from as far away as Trinidad

and Tobago.

[10] Japan's largest nuclear reactor, the 8.2-Megawatt Kashiwazaki Kariwa nuclear reactor was closed for repairs

following a major earthquake on July 16, 2007. Current plans expect the plant to return to service in mid-2009.

LNG demand in the East-Asia region is expected to increase as electricity demand continues to

grow and as countries seek to replace generation from other energy sources. New LNG consuming

countries are also emerging as countries like Thailand and Indonesia look to LNG imports to meet

their own growing requirements for natural gas and electricity (Figure 2.10).

Figure 2.10 - Natural Gas Production and Consumption in Major East-Asian Countries*



* Includes Japan, South Korea and China

Source: EIA International Energy Outlook 2008, September 2008

2.2.2 Europe

After East-Asia, Europe is the second-largest market for LNG. In Europe, about one-third of total

natural gas consumption is used for the generation of electricity and LNG provides an alternative

energy source to imported crude oil and pipeline imports of natural gas.

In 2007, about one-half of Europe's natural gas requirements were met by regional production,

with the majority obtained from only a few countries (Figure 2.11). Incremental supply from new

sources in Northern Europe, such as the North Sea sectors of Norway and Denmark, has helped

to increase regional production and serve a growing demand for natural gas. However, in recent

years those additions have not been able to offset an overall decline in European production. As

a result, a growing share of the European requirement for natural gas is now being met through

imports of LNG or by pipeline from Russia, countries of the FSU, and Africa (Figure 2.12).

Figure 2.11 - European Natural Gas Production




Figure 2.12 - European Natural Gas Balance


European LNG imports have historically attracted supplies from Africa and other Atlantic Basin

suppliers. Although on average LNG accounts for less than ten per cent of Europe's total gas

supply today, the International Energy Agency (IEA) projects that by 2015 LNG may provide up

to 140 109m3 (5 Tcf), or 15 per cent of the annual European gas requirement[11].



[10] IEA Natural Gas Market Review 2008

The increased use of LNG may also help some European countries to diversify sources for natural

gas supply and reduce reliance on any particular supplier. However, LNG import terminals are

currently concentrated in only a few countries. With declining regional production, other European

countries without LNG are faced with a growing reliance on pipeline supplies from Russia and the

FSU. LNG development is seen as an option by European countries to increase security of natural

gas supply and avoid over-dependence on any single source of natural gas.

While natural gas production and pipeline imports are readily accessible in many parts of Europe,

in some countries such as Spain, the natural gas infrastructure is not well-integrated with the

continental pipeline grid and imported LNG accounts for a much larger portion of supply. Similarly,

the availability of natural gas storage is not evenly distributed, further limiting the volume of LNG

imports in many regions to only the volume that may be readily consumed.

In Spain, LNG provides over two-thirds of annual natural gas requirements. While Spain's natural

gas requirement (35 109m3 or 1.2 Tcf in 2007) represents less than 10 per cent of Europe's total

gas consumption, Spain's LNG imports (24 109m3 or 0.9 Tcf in 2007) account for over half of total

European LNG imports. This highlights the major role and influence that Spain has in the European

and Atlantic Basin LNG markets.

Although some parts of Europe such as the U.K. may enjoy a diverse supply of natural gas and

have evolved toward competitive market prices that are determined based on competing sources

of gas supply, natural gas prices are still largely influenced by other markets in continental Europe

that compete for the same gas supply. Consequently, European natural gas prices are influenced

by the long-term contracts for natural gas imports into the region by pipeline and LNG. In these

contracts, prices are often determined based on the cost to obtain an equivalent value of energy

from an alternate fuel available in each country and are typically linked to the price of oil

products or sometimes to crude oil.

The demand for natural gas and LNG in Europe is also largely dependent on weather, particularly

with limited gas storage in consuming regions and about two-thirds of natural gas consumption

being used for electricity generation or heating in the residential and commercial sectors.

Future LNG demand in Europe is expected to increase as electricity demand continues to grow.

Demand for LNG will also extend into eastern Europe, as new countries pursue LNG as a means to

meet their own growing requirements and improve energy security by reducing dependence on

pipeline imports from Russia and the FSU. In addition to development of LNG import projects,

there are also several pipeline projects from Africa and Russia and the FSU being developed or

proposed to supply Europe's growing natural gas requirements.

2.2.3 North America

Although LNG import facilities have existed in North America since 1971, North America has not

been a major importer of LNG. Until about 2003, LNG import volumes typically provided less than

one per cent of total North American natural gas requirements. The bulk of those total

requirements are met through growth in natural gas production and the associated expansion of

pipeline infrastructure (Figure 2.13). LNG in this environment was primarily used to supplement



domestic production and as a means to ensure security during peak demand periods, most

notably in the U.S. northeast where natural gas production and pipeline infrastructure are more

limited.

Figure 2.13 - North American Natural Gas Balance


Being a relatively small player in the global LNG market and having an abundance of regional

production, North American LNG imports have typically been limited to the nearest suppliers in the

Atlantic Basin, (i.e., from Trinidad and Tobago and North Africa). Historically, North American LNG

receiving terminals were located only in the U.S. In 2006, Mexico brought its first LNG receiving

terminal into service on the east coast and added a second terminal in Baja California in 2008.

Moreover, other terminals are currently being constructed in Atlantic Canada and on Mexico's

west coast.

In 2007, North American LNG imports totaled about 24 109m3 (850 Bcf), with over 90 per cent of

that volume delivered into the U.S. and the remainder into Mexico. The U.S. also exports an

average of 1.6 109m3 (60 Bcf) of LNG each year to Japan from its liquefaction facility in Kenai,

Alaska.

Given prospects for growing natural gas demand amidst a backdrop of a less than certain outlook

for future natural gas production, North America had experienced renewed interest in LNG imports

in recent years. Concerns about environmental consequences from combustion of fossil fuels and

a projected decline in natural gas production from some traditional sources (e.g., conventional

natural gas production in Canada) have fueled expectations of an increasing requirement for LNG

imports. This has led to the construction of numerous new facilities to import LNG into North

America and a diversification of LNG suppliers in recent years. At the end of 2008, North American

LNG regasification capacity is estimated to be over 400 106m3/d (14.5 Bcf/d), over half of which

is located in the Gulf of Mexico region.



With over one-half of total North American gas consumption used for space heating and cooling,

demand is very weather-dependent and can vary substantially on a seasonal basis. While

weather may influence the amount of LNG consumed in North America, an increasingly and

perhaps greater influence on the level of North American LNG imports is the availability of LNG

after accounting for requirements in other global markets. This is particularly the case as other

global markets may have more limited indigenous gas production and natural gas storage options.

Figure 2.14 illustrates the dynamics and relationship of other global markets to North American

LNG imports and the swing market characteristic of the North American LNG market. This was

particularly evident during the summer of 2007, when mild weather and low demand resulted in

low LNG prices in Europe, while gas demand and prices were high in North America. As a result,

suppliers made significantly larger deliveries of LNG to North America and were able to obtain

relatively higher prices and earn greater returns after deduction of transportation costs.

Consequently, North America imported LNG at record-high levels during the first half of 2007, with

much of the gas used to replenish storage inventory levels that were drawn down because of

cold weather during the previous winter.

Figure 2.14 - World Market Influence on U.S. LNG Imports

* Converted to US$/MMBtu from data derived from the InterContinental Exchange (ICE) and the Japan Ministry of

Finance

Since mid-2007, LNG demand and prices in Asia and Europe have been higher than in North

America which has reduced the amount of LNG supply directed to North America. The regional

allocation of LNG deliveries intensified with the unplanned outage of Japan's largest nuclear

electricity generation facility following a major earthquake in July 2007. Since then, Japan's LNG

requirements have increased, drawing up to one 109m3 per month (one Bcf/d) of LNG supply from

the Atlantic Basin. Crude oil and related product prices have also increased strongly during this

period, which resulted in much higher LNG prices in Asia and Europe. The strong demand and

prices in Asia and Europe have persisted into 2008, as the Japanese nuclear plant remained offline

and European natural gas consumption was high because of lower electricity generation from coal



and dry weather reduced the availability of hydro-electricity.

Consequently, North American LNG imports in 2008 remain lower than historical levels despite the

recent construction of several new import terminals. In recent months, there has been significant

growth in U.S. natural gas production, particularly from tight sand and shale gas resources which

has offset much of the immediate requirement for LNG imports. Although the full extent of new

gas supply from these unconventional sources is not definitive, the recent optimistic outlook on

incremental production and the decline in natural gas demand have created uncertainty for LNG

imports.

With the waning need for immediate LNG imports, two of the recently constructed receiving

terminals have applied for U.S. regulatory approval to re-export imported LNG[12]. With relatively

minor facility modifications, imported LNG could be received and stored at the terminal until a

market develops either in the U.S. or abroad. Re-export would enable facilities to be kept

operational[13] amidst a competitive LNG market, while most of the LNG may be re-shipped to

other markets. Also, given the potential for further growth in U.S. production and the prospective

development of shale and tight gas resources in Canada, there is now a proposal to construct an

LNG liquefaction and export terminal in northwest British Columbia.

[12] Freeport LNG and Sabine Pass LNG

[13] Once operational, it is generally desirable to maintain the LNG-handling facilities at a constant low temperature.

2.3 Outlook on Global LNG Liquefaction and Regasification[14]

Although there has been development of additional LNG supply around the world, the pace of

development for new liquefaction capacity has varied across regions and is significantly less than

additions to regasification capacity (Figure 2.15 and Figure 2.16). Major LNG markets in Asia and

Europe are seasonal in nature, often have only limited storage, and consequently require

regasification capacity that is designed to meet peak market requirements. For that reason,

those facilities may not always operate at high utilization levels. On the other hand, the longer

lead time and higher costs associated with upstream development and liquefaction facilities

generally require larger projects for economy of scale with high and stable utilization rates.

Having access to regasification capacity to service different markets in excess of liquefaction

capacity facilitates a high utilization of the more expensive liquefaction assets. This also allows

suppliers to capitalize on arbitrage opportunities to optimize returns.

[14] See Appendix 2 and Appendix 3 for a summary of global liquefaction and regasification capacity.

Figure 2.15 - Global LNG Liquefaction and Regasification Outlook



Figure 2.16 - Global LNG Liquefaction Under Construction

Historically, liquefaction and regasification projects have been developed in close alignment, often

with some common stakeholders, rigid long-term contracts, and dedicated shipping vessels that

linked the supply to specific markets. Spare shipping capacity was limited and diversion of LNG

supply to alternate markets would usually occur only during periods of low demand in the primary

market, as the re-routing of tankers would temporarily reduce the ability to serve the primary

market.



Associated with the significant growth in worldwide LNG development during the past decade, the

LNG industry has also increased its capacity to serve multiple markets and engage in shorter-term

trade. In recent years, particularly with strong demand and higher prices during peak demand

periods, new LNG developers now commonly hold a certain portion of liquefaction output for

short-term trading opportunities. Often these developers use their own trading affiliates to

manage a portfolio of LNG supply to serve a number of potential markets through more flexible

contracts. Short-term LNG trade has provided suppliers with greater opportunity to capture

higher prices among multiple competing markets, thereby maximizing returns and use of

infrastructure.

The LNG shipping fleet has also grown substantially, almost tripling the number of ships and

capacity in the last decade (Figure 2.17). The size of new LNG tankers is also larger than ever.

With greater shipping distances, the use of larger cargoes provides an economy of scale which

reduces the per unit transportation costs of LNG. The expansion of the LNG shipping fleet has

also provided suppliers with greater flexibility to serve multiple markets, which has supported the

growth of inter-basin trading and enabled greater liquidity within the LNG market.

Figure 2.17 - LNG Shipping Fleet

Source: Argus and NEB estimates

LNG markets have developed regionally in two basins: the Atlantic Basin, which includes Europe

and eastern North America; and the Asia-Pacific Basin, which consists of East-Asia, Oceania, and

western North America. While traditional sales agreements consisted mostly of intra-basin trade

arrangements, as the LNG market has grown, the increased competition for LNG supply has

resulted in higher prices and greater globalization of LNG trade. This has improved the economics

and provided the impetus for large-scale upstream development in new regions such as Qatar.

Figures 2.18 and 2.19 provide a snapshot of the projected liquefaction and regasification

development in the Atlantic and Asia-Pacific Basins over the next decade. Regasification capacity

that is currently under construction and expected to be in-service by 2015 will more than double



the total existing LNG receiving capacity in world markets. The majority of new regasification

capacity is expected to be added in the Atlantic Basin. World liquefaction, however, takes much

longer to develop and is expected to increase by about 110 106m3/d (5 Bcf/d) during this period.

Although many more liquefaction projects have been proposed, it is unlikely that all will proceed

and those that do may take longer to develop.

Figure 2.18 - Atlantic Basin LNG Development

Figure 2.19 - Asia-Pacific Basin LNG Development



Consequently, the LNG market is expected to remain fairly competitive until after 2015.

Figure 2.20 indicates that it is around that time, that the proposed development of significant

additional LNG liquefaction in the Middle East could be brought into service.

Figure 2.20 - Middle East LNG Liquefaction

2.4 Historical Pricing and Competition for Supply



Incremental supply development from new regions, such as those in the Middle East and Russia,

are more distant from market than historical suppliers. However, aided by advances in LNG

shipping technology and economy of scale savings through the use of much larger tankers,

economic development of these supplies is being made possible. Moreover, these regions are also

situated centrally to the major LNG consuming markets in both the Atlantic and Asia-Pacific

Basins, thereby providing multiple market options and arbitrage opportunities to achieve the

highest return.

Hence, a growing portion of LNG supply is able to cost-effectively serve both Atlantic and Asia-

Pacific Basin markets on a routine basis. This will mean greater inter-basin trade and may also

help to connect LNG prices in Atlantic and Asia-Pacific markets. In the Natural Gas Market Review

(2008) , the IEA suggests that inter-regional trade will increase from about 13 per cent in 2005 to

about 17 per cent by 2015 and will aid further globalization of the natural gas market. Even so,

price convergence with the North American natural gas market, if the proper conditions are

achieved, will likely take additional time given the low quantities of LNG being consumed in North

America. Unlike other global markets, North American prices are not directly linked in sales

contracts to the price of crude oil or oil products. The abundance of indigenous natural gas

production allows North American natural gas prices to be determined based primarily on the

supply and demand of natural gas within the continent. The use of extensive underground natural

gas storage capacity also allows North America to act as a swing market that can import larger

quantities of LNG during periods when demand and prices are lower in Asia and Europe.

2.5 Global Influences and Uncertainty

The large amount of new regasification capacity being added in North America, Europe and East-

Asia is likely to maintain competition for global LNG supply. However, the amount of LNG required

in each specific market is uncertain given the potential for further development of other supply

options such as pipeline gas imports into Europe and unconventional gas production in North

America. Moreover, the outlook for gas demand is uncertain, given the weather-sensitive loads

being served and the difficulties in the global credit and financial markets experienced in 2008.

Economic slowdown in key consuming markets will likely reduce overall natural gas demand in the

near term. The related drop in global crude oil prices will also impact LNG supply development,

given the oil-indexed pricing structure in long-term supply contracts. However, in the longer term,

economic recovery and environmental initiatives to reduce the combustion of other fossil fuels

and GHG emissions are likely to result in significant demand for natural gas and LNG.

Growth in LNG liquefaction and supply, particularly with the significant addition of supply from the

Middle East, will increase the prevalence of shorter-term contracts with flexible market

arrangements. These in turn, will enable greater international trade of LNG and are likely to

increase the availability of supply to swing markets such as North America, particularly during

periods when demand is lower in Europe or East-Asia.

The large investments and long lead time associated with LNG development limits participation in

projects to relatively few larger, multi-national or government-sponsored corporations capable of

funding these endeavours. Due to limited number of participants in a highly competitive market,

there will be reluctance by parties to reveal specific information on markets and pricing in order to

make a swap or other trade arrangement with other suppliers. The physical compatibility of the



LNG vessel or of the LNG composition (gas quality) to a specific market destination may limit

international trade.

The uncertainty in financial markets and tighter credit requirements experienced in 2008 may

impose additional requirements on new LNG development and limit the participation of new

entrants. In general, new project financing may require a greater equity contribution from

developers than in the past, in addition to having solid financial backing and commercial

arrangements. It is not clear whether there may be additional requirements for liquefaction plant

developers to tie a greater portion of project output to long-term contracts, particularly as

participants can significantly benefit from short-term arbitrage opportunities.

Chapter 3 - North American Natural Gas and LNG

Development

Despite being one of the world's largest producers of natural gas, in the last decade imports of

LNG to North America have increased to supplement indigenous production. Recent projections by

the EIA suggest there will be a growing gap between natural gas production and consumption in

North America, despite an expected gain in U.S. natural gas production.

The EIA estimates that the deficit between North American natural gas consumption and natural

gas supply will continue to increase in the period to 2020 (Figure 3.1)[15]. Although U.S. natural

gas production is projected to increase by over 123 106m3/d (4 Bcf/d) from 2005 levels, Canadian

natural gas production is expected to decrease and overall North American natural gas

consumption is projected to increase by about 250 106m3/d (9 Bcf/d)[16].

[15] EIA International Energy Outlook 2008

[16] Most recent projections for the U.S. natural gas production from the EIA Annual Energy Outlook (early release,

December 2008) expects U.S. natural gas production in 2020 to be 228 106m3/d (8 Bcf/d), higher than 2005 levels.

Figure 3.1 - North American Natural Gas Consumption and LNG Imports



Sources: Historical from BP, Projection from EIA International Outlook 2008 with adjustment from 2009 Annual

Energy Outlook

Although these projections may not incorporate the full effects of the 2008 economic slowdown

and uncertainty in financial markets, it is likely that the projections for both demand growth and

supply addition may be less than originally expected. The projections also do not account for any

possible environmental policies that may promote natural gas use in favour of other fossil fuels in

electricity generation as some have suggested.

A large part of the popularity of gas-fired generation particularly in the near term is driven by the

reduced environmental impact of using natural gas relative to other fossil fuels and the increased

efficiency, relatively shorter lead time to build, and low capital costs associated with the use of

gas-fired power generation plants.

Continental Natural Gas Supply and Demand

Despite recent progress and significant additions from production of unconventional natural gas

resources such as shale and coalbed methane, projections for future natural gas consumption

suggest that there will be a need for additional sources of gas supply, including a requirement for

LNG imports. The EIA projections suggest that LNG imports could increase from about 65 106m3/d

(2.3 Bcf/d) in 2007 to over 150 106m3/d (5 Bcf/d) by 2020 and provide over five per cent of

North America's total natural gas requirement.

In this environment, LNG provides an important source of gas to balance supply and demand. This

is true particularly during the winter months in the New England region, where LNG has historically

provided up to 25 per cent of the total natural gas requirement. Having little gas production

within the region and limited pipeline access to other North American supply, the New England

market is the market in North America that is most dependent on LNG.

Natural Gas Production

The extent to which other sources of natural gas can be developed and connected to markets

will influence the future requirement for LNG in North America.

Most recently, gas production from shale resources in the U.S. have been significant and have

helped to offset declines from other conventional sources. Although shale resources have

historically not been significant prospects for gas production, recent advances in horizontal

drilling and the use of induced hydraulic fractures have now enabled economic development. Most

significantly, the Barnett Shale in Texas is now being extensively developed after having only

limited success in previous decades.

With the prevalence of other shale deposits across North America, there has been much optimism

and an increase in recent industry activity to pursue potential development of these resources.

In Canada, efforts are ongoing to assess shale prospects in northeast B.C. (Horn River Basin and

the Montney formation), southern Alberta and Saskatchewan (Colorado shale), Quebec (Utica

shale), and Atlantic Canada (Windsor Group shales).

While having significant potential, the full extent of commercial development of shale resources is



yet uncertain. The near-term contribution of Canadian shale development may also be

constrained by the need to assess viability, optimize operations, and build the necessary

connecting infrastructure to access major pipelines.

3.1 Inter-relationship with Global Markets

Increasing LNG imports are likely to further connect North American natural gas markets to the

world market. However, the relatively small volumes and the seasonal nature of North American

imports may not be sufficient to create price convergence and result in common LNG pricing in a

single global market. In the current market environment, North American LNG imports are likely to

occur under flexible destination and shorter-term contracts. This would particularly apply to off-

season LNG imports.

Relative to other major gas consuming regions (i.e. East-Asia and Europe), an abundance of

natural gas storage capacity and substantial LNG receiving and regasification capacity provides

North America with the ability to import large quantities of LNG during the off-season

(i.e. summer) when LNG demand is typically lower in other northern hemisphere markets.

Figure 3.2 illustrates the historical sources of LNG imports into the U.S. While LNG from Algeria

has been the longest-serving supplier, Trinidad and Tobago is the closest to east coast terminals

and has provided almost two-thirds of recent North American LNG imports. In recent years,

difficulty in further expanding LNG production from Trinidad and Tobago has resulted in a larger

share of North American imports coming from new and more distant sources in Africa and the

Middle East.

Figure 3.2 - U.S. LNG Imports

Source: U.S. Department of Energy

To these new LNG suppliers, the North American market may not be the most proximate and may



entail longer shipping times and higher transportation costs. However, having the flexibility to

serve North American markets is an important option, either to:

obtain higher returns when demand and prices are higher in North America (such as in 2005

after hurricane-induced production disruptions); or,

secure a ready market that can absorb LNG deliveries when demand is lower and the LNG is

not required in other markets. As an alternate market, North American natural gas prices can

be an important lower benchmark for global LNG prices.

3.1.1 Gas Interchangeability

The projected growth in LNG imports and the greater diversification of LNG supply are likely to

entail additional challenges for LNG importers and connecting pipelines to ensure the compatibility

or interchangeability of regasified LNG with traditional gas supply. Historically, the majority of

North American LNG imports have originated from Trinidad and Tobago or Algeria as regasified LNG

from these suppliers have composition and burning qualities similar to traditional pipeline gas. For

LNG with significantly different qualities, imports may be more limited because of a need to blend

these volumes with other gas supplies to facilitate the seamless use of LNG in the regional

market.

This issue is particularly important where LNG is imported directly into consuming regions. Such

imports can provide significant benefits by increasing the availability of gas, diversifying sources

of supply, easing pipeline bottlenecks and reducing transportation costs. However, there may be

additional challenges and costs associated with enabling end-use equipment to use natural gas

with more variable composition. For markets with newer power generation facilities and other

specialized equipment designed to use a narrow range of gas composition, further blending or

processing may also be required to make the combustion characteristics of the regasified LNG

similar to that of traditional gas supply.

Although potential differences in gas composition may exist across all sources of gas supply,

including domestic production, the opportunity to blend or process a particular gas stream can be

much greater in a producing region, such as the Gulf of Mexico, which has an abundance of

pipelines and processing infrastructure. Consequently, gas interchangeability is an important

consideration for LNG terminal developers with respect to site selection, process design, and the

source and quantity of LNG contemplated for import.

Appendix 4 illustrates the heat content of LNG from various supply regions of the world. Although

heat content is only one indicator of gas quality and interchangeability, it serves to provide a

perspective of the wide variability of LNG. In general, LNG markets in East-Asia are able to accept

LNG with heavier hydrocarbons and much higher heat content than markets in Europe and North

America. Consequently, LNG from sources in the Asia-Pacific Basin generally will have higher heat

content than most supply from the Atlantic Basin.

3.1.2 Competition for LNG Supply

For terminals in eastern North America, Europe represents the main competition for Atlantic Basin



LNG supply. As illustrated by Figure 3.3 and Figure 3.4, both Europe and North America are large

consumers of natural gas and both markets are projected to require significant imports in order to

meet future gas requirements.

Figure 3.3 - Natural Gas Production and Consumption in North America

Sources: EIA International Energy Outlook 2008 and Annual Energy Outlook 2009

Figure 3.4 - Natural Gas Production and Consumption in Europe


The competitive relationship between North America and Europe for Atlantic Basin natural gas



supplies in recent years is illustrated in Figure 3.5. In general, North American LNG imports are

highest during the summer periods when European natural gas demand and prices are lower. In

winter, when prices and demand are usually higher in Europe, North American import volumes can

be significantly lower.

Figure 3.5 - U.S. LNG Imports and Atlantic Basin Competition

Sources: Intercontinental Exchange, U.S. Department of Energy

The recent development of new LNG markets in the southern hemisphere could potentially offer

significant competition to summer LNG imports into North America. In 2008, Argentina and Brazil

inaugurated South America's first LNG import terminals and there are proposals for a number of

other projects in countries such as Argentina, Brazil, El Salvador and Uruguay that are in various

stages of development. If developed, these projects could reduce the amount of LNG that may

be available to North America.

3.2 Snapshot of Proposed North American Regasification

Development

Since 2005, in addition to reactivation and expansion of existing regasification facilities, more

than two dozen new LNG receiving and regasification terminals have been approved for

construction in North America. Of these, four new terminals have been built and another six

terminals are currently under construction. The magnitude of this additional capacity in eastern

North America compared to the total projected liquefaction capacity or supply available in the

Atlantic Basin is illustrated in Figure 3.6.

Figure 3.6 - Atlantic Basin LNG Supply and North American Imports



Source: NEB estimates

This comparison suggests that even without any additional regasification projects beyond those

already existing or under construction (from a volumetric perspective), the capacity for North

American terminals to receive LNG already exceeds the total capacity to produce LNG in the

Atlantic Basin. Combined with similar trends in European regasification capacity, and for East-

Asian markets in the Asia-Pacific Basin, a highly competitive environment for LNG supply is

expected to continue, at least until significant new supplies from production or imports can be

developed.

The comparison also suggests that available LNG supply in the immediate market area may not be

sufficient to satisfy potential market growth or that much of the regasification capacity may not

be fully utilized. Moreover, there is likely to be significant competition between markets in both

the Atlantic and Asia-Pacific Basins for additional supply from more distant sources such as the

Middle East, which are suitably located to engage in inter-basin trade.

The extent to which long-term LNG supply will be available to North American LNG facilities on a

regular basis will largely be determined by market conditions and by the stakeholders involved and

their ability to develop and contract LNG worldwide. LNG suppliers have the flexibility to serve

various markets and may select markets to maximize return on investment and optimize utilization

of their existing assets. An important consideration in a supplier's decision on the market to serve

is the relative cost associated with transporting the LNG supply to its destination. Higher-priced

markets can help to attract more distant supply and may provide better returns to a supplier

after deduction of transportation costs.

3.3 North American Influences and Uncertainty

Currently, the North American market utilizes its significant capacity for underground natural gas

storage in order to import LNG during periods when natural gas demand (and price) is low in other



major markets. This swing market characteristic is unlikely to be significantly altered in the near-

term, although the development of various projects to increase storage capacity in parts of

Europe, additions to LNG storage in East-Asian markets, and LNG imports into the southern

hemisphere may eventually diminish this role.

Perhaps the greatest uncertainty for LNG development in North America is in the outlook for

continental supply and demand of natural gas. Given the substantial size and extent of potential

shale gas resources, it is conceivable that significant development could displace some, or even

all, of the requirement for LNG. With respect to gas demand, the pursuit of environmental

initiatives to manage GHG emissions and to reduce usage of other fossil fuels has the potential to

significantly increase the future requirement for natural gas and LNG. However, the overall

demand for natural gas in North America remains a significant uncertainty.

The volatile energy prices, economic slowdown, and uncertain financial markets experienced

in 2008 may also have consequences for near-term natural gas requirements and future LNG

development and financing. Historically, the existence of rigid long-term contracts often, with

state-backed organizations, have helped to reduce the amount of equity requirement in new

project funding. In a climate of tighter credit, the greater equity obligations required from

sponsors to finance new projects will likely limit the participation of newer, less-established

developers that have been instrumental in a number of recent LNG projects in North America.

Chapter 4 - Canadian LNG Development

The Board indicated in its 2007 EMA, Canada's Energy Future: Reference Case and Scenarios

to 2030 , that additional sources of gas supply, including LNG, would be required to supplement

declining supply from conventional sources in Western Canada and from Atlantic Canada to meet

growing demand. The scenarios presented in that report assessed some possibilities of the extent

of potential LNG development in Canada.

This chapter provides a more qualitative discussion of Canadian LNG development and a high level

assessment of the relative position of Canadian projects from a global perspective.

4.1 Current Status of Canadian Projects

In anticipation of growing natural gas requirements in North America, there are numerous

proposals to expand existing terminals in the U.S. and Mexico and construct new LNG receiving

facilities, including several proposed projects in Canada (Figure 4.1)[17]. Given the integrated

nature of the North American natural gas market and infrastructure, Canadian LNG terminals will

likely serve markets in both Canada and the U.S.

[17] In addition, there has been other activity related to the examination of the potential development of gas

supplies in the Canadian Arctic and the transportation of that gas to market as LNG.

Figure 4.1 - Canadian LNG Projects



Location Terminal Proponents Capacity

Proponents'

Estimated

On-Stream

Date

Existing LNG Terminals

1. Saint John,

New Brunswick

Canaport LNG[1] Repsol YPF and Irving Oil 7.6 mtpa

1.0 Bcf/d

2008

Proposed LNG Receiving and Regasification Projects

2. Bish Cove, British

Columbia

Kitimat LNG Galveston Energy 3-4 mtpa

0.5 Bcf/d

na

3. Goldboro, Nova Scotia MapleLNG 4 Gas BV & Suntera Canada Ltd. 7.6 mtpa

1.0 Bcf/d

2012

4. Québec City, Quebec Rabaska Gaz Métro, Enbridge and Gaz de France 3.8 mtpa

0.5 Bcf/d

2014

5. Rivière-du-Loup, Québec Gros Cacouna

LNG

Petro-Canada and TransCanada Pipelines 3.8 mtpa

0.5 Bcf/d

Suspended

6. Saguenay, Quebec Énergie Grande-

Anse

Saguenay Port Authority and Énergie

Grande-Anse Inc.

7.6 mtpa

1.0 Bcf/d

2013

7. Texada Island, British

Columbia

WestPac LNG WestPac Terminals Inc. 3.8 mtpa

0.5 Bcf/d

2014

Proposed LNG Storage and Transshipment Projects

8. Placentia Bay,

Newfoundland

Grassy Point LNG Newfoundland LNG Ltd. na 2011

Proposed Liquefaction and LNG Export Projects

9. Bish Cove, British

Columbia

Kitimat LNG[2] Galveston Energy 5 mtpa

0.6 Bcf/d

2013

na not available

[1] At time of writing, construction of the Canaport LNG terminal is nearing completion and is expected to be in-

service in early 2009.

[2] Kitimat LNG is now proposing to construct an LNG liquefaction and export terminal at the previously approved

site for an LNG receiving and regasification terminal.

The Canaport LNG facility in Saint John, New Brunswick is the only LNG receiving terminal in

Canada at this time[18], which is currently under construction and expected to be available for

service in early 2009. The eventual number of LNG terminals that may be built in Canada and the

potential effects that imported LNG will have on gas markets and the pattern of natural gas flow

are uncertain at this time.



[18] Although a number of facilities have existed for many years in Quebec, Ontario and British Columbia that

liquefy pipeline natural gas and store the LNG for later regasification and use during peak demand periods.

Though there may be some localized benefits from a general increase in gas supply received from

LNG imports, the scale of economical LNG developments generally require connection with large

existing markets. For example, a typical LNG regasification terminal in North America would

generally have an output capacity in excess of 14 106m3/d (0.5 Bcf/d), which may be higher than

the volume of local natural gas consumption. Generally, additional infrastructure may be required

to connect LNG receiving terminals to existing natural gas transmission pipelines and natural gas

markets. LNG terminals also present potential changes for Canada's natural gas supply and

demand balance and could have important implications for the future development and utilization

of Canadian pipeline systems. These changes may, in turn, impact the investments, tolls and

associated costs of using those pipelines.

The expected introduction of LNG into Canadian markets has also heightened the awareness of

potential issues related to gas composition and interchangeability. Consequently, pipelines will

need to work closely with their suppliers and customers to establish gas quality standards and

monitoring processes to ensure compatibility with existing equipment and end-use operation.

4.2 East Coast

The relative transportation costs to major market regions in the Atlantic Basin from various LNG

supply regions are illustrated in Figure 4.2. These estimates are derived assuming an average LNG

carrier size and typical marine diesel costs in 2008[19].

[19] Assumptions include: LNG vessel capacity of 138 000 m3 and marine diesel cost of US$400/tonne.

Transportation costs may be substantially reduced through the use of newer 'super-sized' tankers in long-haul

transportation. In the case of transportation of LNG from Qatar, the use of larger Q-Flex or Q-Max LNG vessels can

almost double the size of tankers and provide economy of scale savings and enable Qatari supply to be cost

competitive with conventional transport of LNG from other regions.

Figure 4.2 - Illustrative Transportation Costs to Atlantic Basin Markets



Source: NEB

These illustrative transportation costs suggest that for North American markets, the

transportation cost is lowest to receive LNG supply from Trinidad and Tobago and that LNG import

terminals on Canada's east coast may hold a slight transportation cost advantage over many of

the other terminals in the U.S. and Mexico. LNG terminals on the east coast are also likely to

serve natural gas markets in the northeast U.S. and eastern Canada, which historically have

higher prices than in other market regions of North America.

In particular, LNG import terminals on Canada's east coast have targeted the New England

market, which has historically relied on imports from LNG and pipeline volumes from Canada for a

significant part of its gas supply. On an annual basis, New England consumes about 22 109m3

(800 Bcf) of natural gas, of which up to about 25 per cent is provided from LNG (Figure 4.3). The

region also experiences pipeline constraints during peak demand periods, and additional supply

from LNG, Canadian imports, or U.S. domestic production may be needed to support further

environmental initiatives to reduce consumption of coal and oil products in the region.

Figure 4.3 - New England Natural Gas Consumption and LNG Imports



Source: EIA

Figure 4.2 also indicates that European markets would have a transportation cost advantage over

Canadian terminals for LNG supply from regions other than Trinidad and Tobago. As a

consequence, Canadian imports from other supply regions would typically only occur when prices

in North America are sufficiently high to offset this difference, or, when European markets do not

require all available LNG cargoes. In general, the transportation difference or hurdle to attract

LNG supply is lower for terminals in the U.S. northeast and eastern Canada, particularly from

northern supply sources. Canadian LNG terminals on the east coast have a transportation

advantage for LNG supply from the Europe's North Sea, Russia and North Africa over other

terminals in North America.

LNG receiving terminals in eastern Canada may face additional challenges associated with

ensuring the interchangeability of regasified LNG and traditional gas supply without adversely

impacting combustion and equipment operation. Traditionally, U.S. terminals in the northeast have

predominately imported LNG supplies from Trinidad and Tobago which have composition and

burning qualities similar to traditional pipeline gas in the region. LNG imports from other supply

regions may also be accepted, but in some cases may have much different composition and

characteristics and may require further processing to remove hydrocarbon liquids or conditioning

to achieve similar burning qualities as typical pipeline gas. Appendix 4 illustrates the heat content

of LNG from various supply regions of the world. Although heat content is only one indicator of

gas quality and interchangeability, it serves to provide a perspective of the wide variability of

LNG.

4.3 West Coast

Figure 4.4 illustrates the relative transportation costs to major market regions in the Asia-Pacific

Basin from various supply regions. These estimates assume transportation using an average LNG

carrier size and typical marine diesel costs observed in 2008.



Figure 4.4 - Illustrative Transportation Costs to Asia-Pacific Basin Markets

Source: NEB

As a potential market, LNG transportation costs to other Asia-Pacific Basin markets would usually

be lower than to deliver to Canada's west coast and would not require the use of extensive

additional pipelines to access major markets. While LNG transportation costs to Canadian

terminals are generally lower than for other receiving terminals on the west coast of North

America, most of the LNG supply in the Asia-Pacific region is much closer to the large LNG

markets in East-Asia. Similarly, the cost to transport LNG from Peru to western Canada is second

to other markets in Mexico. For these reasons, an LNG import terminal on Canada's west coast

would likely serve as an alternative market when contracted supplies are not required elsewhere.

Otherwise North American prices would need to be sufficiently high to offset the difference in

transportation costs.

As a potential LNG supplier, an export terminal on Canada's west coast would benefit from having

a relatively short distance and low shipping cost to markets in East-Asia and on the west coast

of the U.S. and Mexico. From a transportation cost perspective, shipping costs from the west

coast of Canada to Asian markets would be competitive with that from most other Asia-Pacific

supply regions, with the exception of Russia. In addition, transportation costs from western

Canada to terminals in Mexico would be competitive with those from other Asia-Pacific region

supply.

A liquefaction and LNG export project on the west coast could provide natural gas producers in

western Canada with access to incremental markets in Asia, with the potential to obtain much

higher prices and returns than in North America in today's market. Although such a project may

appeal to suppliers, there is significant uncertainty associated with the relative competitiveness

with other LNG suppliers and the availability and cost of sufficient natural gas resources



necessary to underpin a large long-term investment.

A recent increase in unconventional gas production in the U.S. may have created a more

optimistic outlook for North American gas supply, but increases to date have mostly offset

declines in conventional production and LNG imports. At this time, the full extent of shale gas

development is unclear, particularly in western Canada where development is still in an early

stage.

4.4 Canadian Issues and Uncertainty

The extent of incremental supply development in Canada and even in the U.S. is not certain. At

this time, new natural gas development in Canada has not kept pace with the overall decline from

traditional sources. In two of the three cases examined in the Board's recent report Short-term

Canadian Natural Gas Deliverability 2008-2010 , the Board suggested that Canadian production will

continue on a downward trend as the result of lower gas-directed drilling and ongoing declines in

initial well productivity.

To date, all of the proposed Canadian LNG import and regasification projects have included the

ability to serve U.S. markets in addition to markets in Canada. For these projects, the larger U.S.

market is an important anchor market to support development. Accordingly, Canadian LNG

projects will also be subject to changes in supply and demand developments in the integrated

North American natural gas market.

In general, Canadian projects are well located and should be competitive with other North

American and global terminals. Eastern Canadian import terminals are located closer to a number

of Atlantic Basin supply regions than most other Atlantic-based terminals in North America and

are suitably located to serve the significant U.S. northeast market. However, LNG terminals

serving this market may require additional processing or blending of LNG or may need to limit

quantities from supply regions with significantly different gas composition from traditional gas

supply to ensure seamless compatibility of LNG in end-use applications.

Potential Canadian import terminals on the west coast may be closer to some sources of Asia-

Pacific LNG supply than other North American import terminals. However, west coast terminals in

Canada may face additional hurdles and require greater use of connecting pipelines to access

major markets.

The proposed LNG export terminal in western Canada is closer to Asian and other North American

markets than many of the competing supply regions that serve the Asia-Pacific region. However,

at this time, there is significant uncertainty on the extent of North American supply development

and the ability to support both growing North American requirements and a long-term export

market. Such a project, if approved and built, would enable further integration of North American

and world natural gas markets.

Chapter 5 - Conclusions and Observations

The large amount of new regasification capacity being added in North America, Europe and East-

Asia is likely to maintain a competitive market for global LNG supply. However, the amount of LNG



required in each region is uncertain given the potential for greater development of other supply

options such as natural gas pipeline imports to Europe and unconventional gas production in North

America. Recent volatile energy prices and financial markets may have profound consequences for

future LNG development and financing. Greater financial obligations on proponents could limit the

participation of newer, less established developers who have been instrumental in a number of

recent LNG projects in North America.

Although greater international trade of LNG may increase the availability of supply to North

America, full globalization and price convergence in the LNG market by 2015 is not expected. LNG

pricing in other major global markets are more closely indexed to the price of crude oil or oil

products, whereas natural gas prices in North America are determined more by price competition

between various sources of natural gas. The differences in pricing provide trading opportunities

between regions and will affect the flow of LNG.

The North American market will continue to operate as a swing market for global LNG, utilizing its

significant capacity for underground natural gas storage in order to import LNG during periods

when natural gas demand is lower in other major markets. The extent to which North American

LNG facilities are used and whether long-term supply is available will be determined largely by

market conditions, by the stakeholders involved, their respective contractual arrangements for

supply and markets, and the requirement for LNG in other global regions.

In the near term, lower economic growth in key consuming markets and lower and volatile energy

prices will likely reduce the demand for natural gas and slow the rate of LNG development. In

North America, growing production from shale and other unconventional gas resources have

helped to offset the ongoing decline in conventional production and may reduce or set back the

immediate requirement for LNG imports into North America. However, in the longer term, economic

recovery and environmental initiatives to reduce the combustion of other fossil fuels and GHG

emissions may result in significant demand for natural gas and LNG. The extent to which North

America pursues the various alternate energy sources to natural gas will greatly influence the

overall need for LNG.

Canadian LNG projects are well located and should be competitive with other North American

projects for global markets and supply. As with other North American terminals, the utilization of

Canadian facilities will be greatly dependent on market conditions and contracted LNG supply

arrangements. Without dedicated long-term supply contracts, Canadian facilities are likely to

serve as the alternate or swing market to other major LNG markets in Europe and Asia.

Glossary

Coalbed

methane

An unconventional form of natural gas that is trapped within the matrix of coal

seams.

Henry Hub A major natural gas hub and trading point in Louisiana and a common benchmark

pricing point for North America.

Hydraulic

fracture

A technique in which fluids are injected underground to create or expand existing

fractures in the rock, allowing oil or gas to flow out of the formation or to flow at

a faster rate.



Liquefaction The process of cooling natural gas to a temperature of about -160 degrees

Celsius, at which point it becomes a liquid or LNG.

National

Balancing Point

A major natural gas trading point in the United Kingdom, used in this report to

represent natural gas prices in continental Europe.

New England A sub-region of the northeastern United States as defined by the U.S. Census

Division. Consists of Connecticut, Maine, Massachusetts, New Hampshire, Rhode

Island, and Vermont.

Regasification The process of warming the LNG in order to return it to a gaseous state or natural

gas.

Reserves Reserves are estimated remaining marketable quantities of oil and natural gas and

related substances anticipated to be recoverable from known accumulations, as of

a given date, based on analysis of drilling, geological, geophysical and engineering

data; the use of established technology; and specified economic conditions, which

are generally accepted as being reasonable, and where applicable shall be

disclosed.

Resources The total volume of oil or natural gas that is thought to be found in an area, or

that portion of the total resources that is not penetrated by a well bore to date,

or the volume that could be found as a result of appreciation.

Shale gas A form of unconventional gas where the gas molecules are mainly trapped on the

organic material in a host rock of fine-grained shale.

Unconventional

gas

Natural gas that is contained in a non-traditional reservoir rock that requires

significant additional stimulus to allow gas flow. It may be that the gas is held by

the matrix material such as coal, ice, or shale or where the reservoir has an

unusually low amount of porosity and permeability.

Appendix 1 - Global Region Definitions

Geographical regions used to characterize the various global natural gas markets in this report are

defined purely for statistical purposes and convenience and do not intend to imply any political or

economic standing. While the report attempts to stay consistent with regional definitions made

by the United Nations Statistics Division, in many cases finer divisions or other commonly used

country and geographical groupings are necessarily used to reflect the LNG industry and the data

and analysis used in the production of this report.

Asia-Pacific: A general region encompassing East-Asia, South Asia, and Oceania and Southeast

Asia as defined in this report.

Central Asia: Kazakhstan, Kyrgyzstan, Tajikistan, Turkmenistan and Uzbekistan.

Central & South America: Includes countries in Central America, South America and the

Caribbean.

East-Asia: People's Republic of China (China), Hong Kong*, Macao*, Democratic People's

Republic of Korea, Japan, Mongolia, Republic of China (Taiwan) and the Republic of Korea (South



Korea).

Eurasia: Includes countries of continental Europe, Central Asia and the Republic of Turkey.

Middle East: Refers to countries in a region which includes the Arabian Peninsula, Mesopotamia,

Persian Plateau, Anatolia and The Levant (Eastern Mediterranean).

North Africa: Considered as part of Africa in this report and would include LNG exporting

countries Algeria, Egypt and Libya.

Oceania and Southeast Asia: Australia, New Zealand, Norfolk Island, Brunei Darussalam

(Brunei), Cambodia, Indonesia, Lao People's Democratic Republic, Malaysia, Myanmar, Philippines,

Singapore, Thailand, Timor-Leste and Vietnam.

North America: Canada, United States and Mexico.

Russia and the Former Soviet Union (Russia/FSU): Includes Russia and other independent

nations that once formed the Union of Soviet Socialists Republic. Includes: Armenia, Azerbaijan,

Belarus, Estonia, Georgia, Kazakhstan, Kyrgyzstan, Latvia, Lithuania, Moldova, Russia, Tajikistan,

Turkmenistan, Ukraine and Uzbekistan.

South Asia: India, Pakistan and Bangladesh

* Special Administration Regions of China

Appendix 2 - Existing Global LNG Liquefaction Capacity

Basin RegionCapacity

109m3 per year

Capacity

mtpa

Capacity

Bcf/d

Existing LNG Liquefaction Terminals

Atlantic Americas 20.6 15.1 2.0

Europe 5.6 4.1 0.5

Africa 72.3 53.1 6.9

Middle East Middle East 64.3 47.2 6.1

Asia-Pacific Americas 2.0 1.5 0.2

Oceania 106.3 78.1 10.1

Total 23.8

LNG Liquefaction Terminals Under Construction

Atlantic Africa 13.2 9.7 1.3

Middle East Middle East 72.8 53.6 6.9

Asia-Pacific Americas 6.0 4.4 0.6

Russia 13.1 9.6 1.2

Oceania 21.3 15.7 2.0

Total 12.0

Source: IEA



Appendix 3 - Current Global LNG Regasification Capacity

RegionCapacity

109m3 per year

Capacity

Bcf/d

LNG Storage

m3

Underground

Natural Gas

Storage

109m3

Existing Re-gasification Terminals

North America 109.8 10.5 2 973 720 117

South & Central America 7.9 0.8 320 000

Europe 120.2 11.4 4 003 000 76

Asia 375.2 35.6 21 863 200 1.3

Total 58.2

Re-gasification Terminals Under Construction

North America 71.4 6.8 2 240 000

South & Central America 12.0 1.1 320 000

Europe 75.6 7.2 3 008 500

Asia 50.9 4.8 3 835 000

Total 20.0

Source: IEA

Appendix 4 - Illustrative Heat Content of Global LNG Supply

CountryHeat Content

(Btu per cubic foot)Supply Region

Libya 1160 - 1190 Atlantic

Brunei 1133 - 1150 Asia-Pacific

United Arab Emirates 1127 - 1160 Middle East

Oman 1100 - 1160 Middle East

Nigeria 1110 - 1145 Atlantic

Malaysia 1120 - 1133 Asia-Pacific

Indonesia 1107 - 1118 Asia-Pacific

Australia 1065 - 1143 Asia-Pacific

Qatar 1024 - 1124 Middle East

Algeria 1041 - 1121 Atlantic

Trinidad & Tobago 1050 - 1082 Atlantic

Equatorial Guinea 1050 Atlantic

USA (Alaska) 1000 - 1030 Asia-Pacific

Egypt 1000 - 1041 Atlantic

Norway 1000 - 1075 Atlantic

Appendix 5 - The LNG Value Chain

The essence of the LNG value chain is not unlike that for conventional natural gas. It is based



upon the monetization of natural gas assets with the main difference being that, because of the

location of the assets, a more elaborate system is required to bring the commodity to end

market. The basic elements of the LNG value chain are described below:

1. Exploration and Production

The exploration and production of natural gas used for LNG is essentially the same around the

world, except that the gas exists in areas of the world with little or no domestic demand for the

product. In general, it is produced by the same companies that produce natural gas in North

America, using the same technology. Producing natural gas fields are connected by pipeline to

liquefaction plants which then convert the natural gas to LNG.

2. Liquefaction

Natural gas becomes LNG when it is cooled to about -160°C (-260°F) at atmospheric pressure,

through the use of refrigeration processes at the liquefaction plants. Liquefaction is the most

unique portion of the LNG value chain when compared to the traditional natural gas value chain

and requires the greatest amount of investment and use of sophisticated equipment and

processes.

The large investment for liquefaction also requires large natural gas reserves to ensure the

commercial viability of the project. In many countries, participation of government-owned

companies is also common because of difficulties in receiving approvals and financing. Present

day financing and supply contracts may also entail rigid requirements for guaranteed takes and

payment.

3. Shipping

LNG is transported to various markets around the world via specialized shipping vessels that have

onboard liquefaction units to keep the LNG cold and in its liquid form. LNG shipping costs can vary

greatly depending on fuel costs, ship capacity and distance of haul. In general, LNG shipping

becomes favourable compared to natural gas transportation via pipeline for transportation over

large distances. LNG transportation can also provide suppliers with additional flexibility to serve a

number of competing markets and facilitate arbitrage opportunities.

Market players may own their own ships or can charter or lease LNG vessels in order to avoid the

large capital costs and specialized skills associated with building, owning and operating the ships.

Historically, the LNG shipping fleet was owned by a few LNG players. As a result, transportation

capacity was very limited and charter rates could make up the majority of the LNG transportation

cost. In recent years, shipping costs have declined with the substantial growth in the LNG

shipping fleet and advances in shipping technology.

4. Regasification

Upon reaching its destination, LNG is unloaded from the ship into the regasification terminal where

the liquid commodity can be stored in tanks or transferred back into its gaseous state. Once



Date Modified: 2012-02-03

regasified, LNG is natural gas and is handled the same as for any conventional natural gas. This

includes any processing that may be required in order to achieve the gas quality standards of the

regional pipelines and markets.

Regasification terminals are much less capital intensive relative to the investment required for

liquefaction terminals and can be built easily without necessarily securing dedicated supply to

ensure utilization at full capacity. In fact, having excess regasification capacity relative to supply

will enable an LNG supplier to ensure high utilization of its liquefaction assets and may help to

ensure the viability of that significant investment. Having regasification capacity to service

different markets will also enable the LNG supplier to capitalize on arbitrage opportunities and

obtain the highest return.

5. Markets

At this point, the natural gas can be delivered from the regasification terminal into the natural

gas pipeline infrastructure of the region and used in the same way as conventional natural gas.

9/25/12 About LNG

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Liquefaction offers a unique solution for transporting natural gaslocated in areas far from a pipeline infrastructure.

LNG stands for liquefied natural gas, and is produced by cooling down natural gas

below its dew point.

Methane usually accounts for about 85-95% of LNG, which may also contain other

hydrocarbons such as ethane, a little propane and butane (natural gas liquids) and

traces of nitrogen.

LNG shares many of the properties of methane, being odourless, colourless, non-

corrosive and non-toxic.

LNG – a unique transport solution

Liquefaction offers a unique solution for transporting natural gas located in areas

far from a pipeline infrastructure.

The volume occupied by liquefied natural gas at atmospheric pressure is about

614 times smaller than its gaseous state. This reduces the space needed to

freight a given amount of energy.

LNG is shipped in specially-built carriers from liquefaction plants to large tank

farms in buyer countries. These vessels can load from 145,000 to more than

200,000 cubic metres.

The energy volume of such a consignment corresponds to 1-1.4 terawatt-hours

About LNG

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(TWh). A TWh equals one billion kilowatt-hours. Since a Norwegian family

consumes some 20,000 kWh of electricity per year, one LNG cargo represents the

annual power consumption of roughly 50,000 households in Norway.

Useful conversion units relating to LNG:

1 standard cubic metre (scm) LNG = 11 kilowatt-hours (kWh)

Statoil’s LNG involvement and future plans

Research and development relating to liquefied natural gas (LNG) have been

pursued by Statoil for more than 20 years.

The companyhas focused on three approaches to LNG R&D:

joint industry projects

contract research and purchase of services

those aspects of greatest strategic significance for Statoil, which have

been tackled in-house.

Together w ith Linde Statoil developed spirally-wound heat exchangers (SWHE).

These can be used for gas liquefaction both on land and in future offshore

facilities.

The LNG technology alliance w ith Linde, which ended in 2007, has also yielded a

patented cooling solution, liquefaction process currently used in the Snøhvit LNG

plant, which is operated by Statoil. This represents Europe’s first and only large-

scale base load gas liquefaction facility plant.

Over two decades, Statoil has supported and built up leading-edge expertise at a

number of national and international academic institutions. The results of this

commitment include 15 doctoral theses and several industry-financed professorial

chairs.

Statoil w ill continue to play a leading role in LNG-related R&D in Norway. Its

ambition is to be the technological leader in such areas as production

optimisation, gas liquefaction, (utfrysning) and carbon dioxide management in the

gas chain.

—

Description ofLNG Technology

and Import System

Volumetric Conversion Table

VOLUME RELATIONSHIPSLNG Gas/Liquid Ratio 619.8 to 1

1086 Btu/Cu. Ft. Spec. Grav. 0.465

LNGConversion

Factors

1 MCF

1 Gallon

1 Imp, Gal

1 Cubic Foot

1 Barrel

1 Cubic Meter

1 Metric Ton

1 Therm

Gas

CubicFeet MCF

1000.0 -

8 2 8 5 0 0 . 0 8 2 8 5 0

9 9 5 0 3 0 . 0 9 9 5 0 3

619.80 061980

348008 3.48008

21,886 21,886

4 7 , 1 0 3 4 7 1 0 3

9 2 0 8 1 0 , 0 9 2 0 8

Liquid

Imp. Cubic Cubic MetricPounds Gallons Gal. Feet Barrels Meters Tons

46758 1 2 0 7 0 1 0 . 0 5 1 1,6134 0.28735 0.045692 .02123

3.87390 - 0.8327 0.13367 0,02380 0,003785 0001759

4.6526 1,201 - 016054 0.02858 0,004546 000211

28.981 7.4811 6.229 - 0.17810 0.02832 0.01316

162,72 42,005 34,97 5,6148 - 0,15901 0.07388

1023,3 264.16 220,0 35314 6.2888 - 0.46463

2202,4 568,53 473,4 75.996 13.535 2.1522 -

4,3055 1.1114 0,92546 0,14856 0.02646 0,00421 0.00195

10.860

0.89975

1,08059

6.7311

37,794

32768

511 54

Chapter I

S U P P L Y A N D D E M A N D

Description of LNG Technologyand Import System

Natural gas is a major source of energy forthe United States, supplying 20 trillion cubicfeet, more than one-quarter of the total energyconsumed in this country, during 1976.1

Although U.S. production of natural gashas been declining since 1971 (figure 1), thereare significant supplies of natural gas inseveral regions of the world where there is lit-

Figure 1. U.S. Natural Gas Consumption 1971-1976

YearlyTotal 25ConsumptionTrillionCubicFeet 20

15

10

5

1971 1972 1973 1974 1975 1976

U S Production

Source Federal Energy Administration Monthly Energy Review, March 1977

1Federa] Ener~ Administration, Monthly EnergyReuzew, March 1977.

Figure 2. World Proportional Natural Gas ReservesBy Major Supplier Country

Country Percentage

USSR. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33Iran’ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14United States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Algeria*. . . . . . . . . . . . . . . . . . . . . . . . . . . 10Abu Dhabi* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Total 75

● Countries with little or no gas demand.

Source Department of the lnterior World Natural Gas Annual – 1975

tle or no gas demand (figure 2). To date, muchof this natural gas has been wasted—in 1975,6.5 trillion cubic feet were vented or flaredworldwide. z

To use the natural gas which would other-wise be untapped or wasted, importation ofnatural gas is one of several supplementalsupply schemes used by those areas of theworld with large energy demand, primarilythe Uni ted S ta tes , Europe , and Japan .Natural gas has been carried overland by con-ventional pipelines, and about 1 trillion cubicfeet of natural gas is imported in that mannerfrom Canada to the United States each year.However, in order to import natural gas in aform practical for water transportation fromEastern Hemisphere nations, a system hasbeen developed to convert the gas to liquidform at about l/600th the volume. The lique-

U.S. Department of the Interior, Bureau of Mines,World Natural Gas Annual (Washington, D. C.: U.S.Department of the Interior, Bureau of Mines, 1975).

3

—

4 CH. I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM

fied natural gas (LNG) is then shipped inspecially constructed tankers, introducing amarine link in the supply and demand ofnatural gas. This marine link is a large com-ponent, consisting of the liquefaction facility

Figure 3. Existing International LNG Trade

Amount per DayDate Started Supplier to Importer (million cubic feet)

19721977196419691969196919641971

Brunei to JapanIndonesia to JapanAlgeria to FranceLibya to ItalyLibya and Algeria to SpainAlaska to JapanAlgeria to United KingdomAlgeria to Boston, Mass.

73755040023516013510044

Source Pipeline and Gas Journal, June 1977

Figure 4. U.S. LNG Import Projection

at the source of the gas, the LNG tanker, andthe receiving terminal and regasif icat ionfacility at a location near a gas distributionnetwork. It is a very capital-intensive system,which can cost more than $1 billion to con-struct. A large 500 million cubic feet per dayproject with four ships could require a $2bil l ion capital expenditure for l iquefac-tion/export facilities ($1 billion), ships ($150mill ion each), and import /regasif icat ionfacilities ($300 million to $400 million). Im-plementation of all announced LNG projectscould require capital expenditures in excess of$35 billion worldwide. In the United Statesalone, construction of facilities and ships forthe import of LNG could require $20 billion. a

:1’’LNG Rep&rt,” Pipeline and Gas Journal 204 (June1977).

— —

S u c h h u g e c a p i t a l e x p e n d i t u r e s a r egenerally financed by a multinational mix ofgovernments and private firms. The U.S.Government has already provided about $716million in subsidies, loans, and loan guaran-tees in connection with LNG projects. Morethan two-thirds of that support has been givento the foreign portions of the projects. A

Europe became the first steady market forLNG in 1964 (figure 3). Japan took over as thekey market about 1972, receiving about 49percent of the LNG moving in internationaltrade. However, the United States—which hasused very limited imports of LNG only since1971–is projected to become a major LNGcustomer if ventures now planned go for-ward. b

The United States is presently a net ex-porter of LNG. More than 32 billion cubic feetof natural gas in the form of LNG has beensent to Japan from southern Alaska each yearfor the past 5 years, while only about 15billion cubic feet per year is imported fromAlgeria to Everett, Mass. The LNG importedto Everett is a very small amount, less thanone-twentieth of 1 percent of the U.S. con-sumption of natural gas in 1976.6 According toindustry representatives, however, LNG couldbe 5 to 15 percent of the total U.S. gas con-sumption by 1985 (figure 4).7 Projects are nowproposed which could bring as much as 3.5trillion cubic feet of LNG per year to theUnited States from foreign sources within thenext 10 to 15 years (figure 5).

41nterview with Officials of Export-Import Bank ofthe United States, Washington, D. C., June 16, 1977.

JDavid Hawdon, World Transport of Energy 1975 to1985 (London: Stanil and Hall Associates Limited,April 1977), p. 39.

6Federa1 power commission, “Table of LNG Importsand Exports for 1976,” News Release, June 3, 1977, andFederal Energy Administration, Monthly EnergyReview, March 1977.

TOffice of Technology Assessment LNG panel meet-ing, Washington, D. C., June 23, 1977.

Figure 5. Status of U.S. LNG Import Projects

Project Start-up Date Supply Source Status (AGA/FPC) Quantity(billion cubic feet/y r.)

Existing & Firm Foreign Imports

Distrigas I 1972 Algeria Existing/Operational 1,6Distrigas IV 1978 Algeria Firm/Pending 42*El Paso I 1978 Algeria Firm/Approved 365Note -- Eascogas project IS deleted here because of 407recent questions regarding approvals and project viability

Probable Foreign Imports

Panhandle EasternPacific Lighting IntEl Paso II

Possible Foreign Imports

Tenneco-N B. CanadaOccidental-El PasoBrown/Root-TennecoKalingasEl Paso-IranShell-BP

198019801980-82

19851985 +/-

1985 +/-1985 +/-1985 +/-1985 +/-

AlgeriaIndonesiaAlgeria

AlgeriaUSSRUSSRIranIranNigeria

Probable/ApprovedProbable/ApprovedProbable/Pending

Possible/Filed

Possible/Not FiledPossible/Not FiledPossible/Not FiledPossible/Not FiledPossible/Not Filed

179197365741

397365547285547237

2,378

Grand Total 3,526

● Replaces Distrigas 1. Sources American Gas Association and the Institute of Gas Technology,

9 6 - 5 9 7 0 - 7 7 - 2

— .—

Note Other possible future sources of LNG include Iran, Russia, and NIgerIaBcf/y = billion cubic feet per year

Source OTA.

Ultimately, the supply of natural gas islimited, But since it is currently an under-utilized resource in many foreign countries,importing it as LNG could satisfy a significantportion of the U.S. energy demand for at leastthe next 20 years.

Imports of LNG could be part icularlyuseful in alleviating near-term fuel shortagesin certain sectors of the economy or parts ofthe country. In California, which accounts for11 percent of U.S. natural gas consumption, sLNG could help to alleviate projected energyshortfalls and air quality problems.

If presently planned and approved projectsmove forward, Algeria would be the majorsource of the increased imports (figure 6). Asmaller amount of LNG would come from In-donesia, and there is a possibility of suppliesfrom the U.S.S.R, Iran, and Nigeria after1985.9 The stability of these foreign suppliesand likely results of possible curtailment ofLNG shipments to the United States has beenidentified by this study as one of the potentialproblems of the LNG system. Foreign supplyis discussed further in the critical review sec-tion which follows this chapter.

~Douglas M . Considive, cd., Energy TechnologyHandbook (New York: McGraw-Hill, 1977).

gAmerican Gas Association, Gas Supply Review, 5(February 1977).

CH. I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM 7

In addition to foreign natural gas, new gasdiscoveries in Alaska could be transported tothe west coast as LNG. This possible supply ofgas from the North Slope and southernAlaska could be more than 1 trillion cubic feeta yea r a s ea r ly a s 1984 .10

The North Slope is by far the largest of thetwo Alaskan supplies of natural gas. Themethod of transportation to be used to bringthe North Slope gas to the west coast was to bedetermined by the President in September? Aproposal to transport this gas by pipelinethrough Canada was being weighed against aproposal to use an LNG system.

D E S C R I P T I O N O F L N G

Liquefied natural gas is not the only haz-ardous cargo transported in the United Statestoday, or is it necessarily the most dangerous.Other cargoes which pose unique hazardswhen transported in large volumes includeliquefied petroleum gas (LPG), chlorine,acids, and gasoline.

Liquefied natural gas and LPG are similarin many ways and are treated together as “liq-uefied gases’ by most regulators. Liquefiedpetroleum gas, however, appears to be betterknown and accepted by the public. In 1976, 10million tons of LPG were moving in worldtrade, most of it going to Japan from the Mid-dle East countries. It is estimated that by1980, LPG trade will more than double, andthat U.S. demand will be as much as 12

*NOTE: On September 8, 1977, the Presidentannounced that an agreement had beenreached with Canada for a pipeline to carrynatural gas across that country from Alaskato the west coast of the United States. TheCongress has 60 days after formally receivingthe President’s plan in which to disapprovethe choice if it so desires.

IOFedera] power ~o~missio~, Recomme~da~~on to

the President Alaskan Natural Gas TransportationSystems (Washington, D. C.: Federal Power Commis-sion, May 1, 1977) p. I-44.

million tons.11 In 1977, there were 441 LPGtankers operating worldwide with a capacityof 3.5 million cubic meters. In comparison, 30LNG tankers were operating worldwide at thesame time with a capacity of 2.2 million cubicmeters.

Some unique properties of LNG whichaffect the design of tankers or terminals are:

●

●

●

●

●

●

●

it has an extremely low temperature of–259° F;

it weighs about 28 pounds/cubic foot,slightly less than half the weight ofwater, and would therefore float;

a t normal ambien t t empera tu res , i tevaporates very rapidly and expands toabout 600 times its liquid volume;

in the vapor state, and when still verycold, the gas is heavier than air and, inthe event of a spill, would hug to theearth’s surface for a period of time untilsubstantially dissipated;

when the vapor warms up, reaching tem-peratures of about –100° F, it is lighterthan air and would rise and dissipate inthe air;

in the vapor state, it is not poisonous, butcould cause asphyxiation due to the ab-sence of oxygen;

in the vapor state, concentrations of 5 to15 percent natural gas are flammable.

Liquefied natural gas is odorless and color-less. It looks much like water. Except for itsextremely cold temperature, which requiresspecial handling techniques and materials,the liquid is relatively safe. In bulk form itwill not burn or explode. Momentary contacton the skin is harmless although extendedcontact will cause severe freeze burns, On con-tact with certain metals such as carbon steelship decks, LNG can cause immediate crack-ing.

1 IH. Magelssen, “LPG-Transportation Cost, MarketPotential and Future Charterers,” Gastech 76 Proceed-ings LNG and LPG Conference, New York, Oct. 5-8,1976, (Herts, England: Gastech Exhibitions, 1977).


The behavioral patterns of LNG vapor inthe atmosphere, however, are not so well un-derstood and may create hazards. If spilled onthe ground, LNG would “boil,” (vaporize)very rapidly for 2 or 3 minutes unt i l theground was frozen and no longer emittingheat to the LNG on top of it. This would slowthe rate of vaporization and minimize cloudformation dangers.

If spilled on water in a large-scale accident,it is unlikely the water would freeze. Insteadthe water would continue to warm the floatingLNG, vaporizing it and forming a spreadingcloud. Researchers currently disagree on theshape, size, movement, and composition of thevapor cloud and the factors which will affectit. It is believed that the concentration of LNGvapor within the cloud is not homogeneous. Atthe edge of the cloud, where the greatest mix-ing with ambient air occurs, the concentrationof gas is lowest. At the core of the cloud, theconcentration is highest. Where the concentra-tion falls within the flammable limits of 5 to15 percent, the cloud may be ignited and burnback toward the source of the spill. It isgenerally agreed that, if the vapor from alarge LNG spill ignites, it would be beyond thecapability of existing firefighting methods toextinguish it. 12 Therefore, the key to reducingthe hazard of an LNG fire is a strong preven-tion program.

The hazards of transporting LNG are some-what similar to those of LPG, if the two areconsidered in equal volumes. However, LPG issomewhat more dense than LNG vapor atcomparable temperatures. In the event of aspill of either liquid on water, the liquidwould rapidly spread by gravity until a largevapor cloud would form. LNG would vaporizeconsiderably faster than LPG because LNG ismore volatile. Thus, the LPG vapor cloudwould evolve over a longer period of time, andwould be more cohesive than the LNG cloud.LPG has the greatest potential for detonationboth in open air and confined. LPG stored in

1 ~Society of Naval Architects and Marine Engineers,Proceedings of Second Ship Technology and Research(STAR) Symposium (San Francisco, Calif.: May 25-27,1977), p. 396.

tanks continually heated by a surroundingflame causes a rise in pressure which leads todetonation. Open-air detonations of LPG 13

have been demons t ra t ed by exper imen twhereas the same is not true of LNG. 14

Research into the behavior of spilled LNGand an LNG cloud is another critical area dis-cussed in the next chapter.

SAFETY RECORD OF EARLYUSE OF LNG

Liquefaction of natural gas is achieved bycooling the gas to –259° F. The process wasdeveloped on a large scale during the firstquarter of the 20th century to simplify thetransportation and storage of natural gas,since the liquid state is l/600th the volume ofthe gaseous state.

Until recently, LNG was utilized primarilyin operations which produced the liquid andstored it for use only during peak demand, forexample, in cold winter weather. There are 89of these facilities operating in the UnitedStates today to produce and/or store domesticLNG. Known as “peak shaving plants,” theyhave a combined storage capacity of 2 millioncub ic mete r s .15 In addit ion, one plant inBoston imports and stores foreign LNG. Itscapacity is 146,000 cubic meters. The peakshaving plants have existed safely for years,without much public attention to either theirlocation in heavily populated areas or theiroperations. Only one major incident has mar-red the safety record of these plants.

That accident occurred at the first LNG in-stallation in 1944. At that time, a storage tankowned by East Ohio Gas Company in Cleve-land ruptured, spilling 6,200 cubic meters ofLNG into adjacent streets and sewers. The liq-uid evaporated, the gas ignited and, whereconfined, exploded, The disaster remains the

l~elephone interview with staff of the Bureau ofMines, Pittsburgh, Pa., Sept. 7, 1977.

ld’l_’elephone interview with staff of Naval WeaponsLaboratory, China Lake, Calif,, Aug. 25, 1977,

15A~erican Gas Association, LNG Information Book1973 (Arlington, Va.: American Gas Association, 1973).

. —


most serious LNG accident anywhere in theworld. It resulted in 128 deaths, 300 injuries,and approximately $7 million in propertydamage . l6

Based on investigations made by the U.S.Bureau of Mines after the accident, it wasgenerally agreed that the tank failed becauseit was constructed of 3.5 percent nickel steel,which becomes brittle on contact with the ex-treme cold of LNG. Since the Cleveland dis-aster, it has become standard practice in theLNG industry to use 9 percent nickel steel,aluminum, or concrete and to surroundstorage facilities with dikes capable of con-taining the contents of the tank if a ruptureoccurs.

The only other significant accident relatedto LNG to date occurred at a Staten Islandimport facility in 1973; where 40 workmenrepairing an empty LNG tank were killedwhen the roof of the tank collapsed as a resultof a fire.

While the Staten Island tank disaster pre-cipitated active local opposition to LNG, thegas industry has repeatedly argued that theaccident was not due to any characteristic orhandling of LNG17, but was an industrial ac-cident involving an insulation fire. However, aBureau of Mines study of the accident indi-cated that there was enough LNG in the in-sulation that it could have been released veryquickly into the tank once igni t ion hadstarted. 18

The only other accident in the UnitedStates mentioned in connection with LNG

IGU.S. Department of the Interior, Bureau of Mines,Report on the Investigation of the Fire at the Liquefac-tion, Storage and Regasification Plant of the East OhioGas Company, Cleveland, Ohio, Oct. 20, 1944.(Washington, D. C.: U.S. Department of the Interior,Bureau of Mines, February 1946).

[email protected] Systems, Inc., Environmental Im-pact Report for the Proposed Oxnard LNG Facilities,Safety, Appendix B (Los Angeles, Ca.: Socio-EconomicSystems, 1976), p. 10.

18U.S, ConWess, House, Staten Island Explosion:Safety Issues Concerning LNG Storage Facilities. Hear-ings before the Special Subcommittee on Investigationsof the Committee on Interstate and Foreign Commerce.93rd Cong., first sess., July 10, 11, 12, 1973, pp. 143, 145.

took four lives in Oregon. This accident,however, took place during construction of thestorage tank before LNG had ever been in-troduced into the facility.l9

Over the past 10 to 20 years, the peak shav-ing facilities have been engaged in all phasesof LNG handlings: liquefaction, regasifica-tion, loading and unloading, storage, andshipment by pipeline, truck, rail, and barge.However, new LNG projects involve muchlarger scale facilities entirely dependent onmarine shipment, and these are the focus ofthis study.

R E G U L A T I O N O F I M P O R TP R O J E C T S

Before any LNG import or export projectcan begin operation, more than 130 permitsmust be obtained from Federal, State, andlocal agencies (see appendix A), and 12different Federal agencies are involved in ap-provals and controls. The Federal PowerCommission (FPC), the Coast Guard, and theOffice of Pipeline Safety Operations (OPSO),are the agencies most involved in LNG andare discussed in appropriate sections of thischapter. The others are explained in appendixB.

The most crucial agency in this milieu is theFederal Power Commission, which under theNatural Gas Act of 1938, has power to ap-prove or reject any proposed project in threeways: 20

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●

●

it must determine whether of not thepublic interest will be served by LNG im-portation;

it must authorize construction or exten-sion of any facilities to be used in thet r anspor t a t ion o r sa l e o f in t e r s t a t enatural gas;

it has the authority to establish the priceat which the gas is sold.

lg’’LNG Scorecard,” I%”peline and Gas Journal 204(June 1977): 22.

2015 U.S.CO ~ 717 f (c) (1970).


The Federal Power Commission has broaddiscretionary powers in determining what isand what is not in the public interest and instipulating conditions which must be met inorder to meet the public interest.

To date, the FPC has been asked to rule onone LNG export project and 10 LNG importprojects (see figure 5). The export project, withliquefaction facilities in Kenai, Alaska, hasbeen approved and is operating. Of the importprojects, three have received final approval;one has received initial approval, subject toreview. One import project with its terminaland regasification plant in Everett, Mass., isin operation. Another, with import facilities ‘inCove Point, Md., and Savannah, Ga., isscheduled to begin operation later this year.Facilities for the approved project at LakeCharles, La., have not yet been constructed,nor have facilities for the Oxnard, Calif., ter-minal which has received only initial ap-proval.

The FPC approves the import projects bymeans of an express order authorizing impor-tation and certificates of public convenienceand necessity (authorization and stipulationsfor construction and operation of facilities).The approvals are obtained by means of acomplicated quasi-judicial procedure whichroutinely takes several years from the time anapplication is filed until it is approved. First,an evidentiary hearing is held before an ad-ministrative law judge, in which the appli-cant, staff, and interveners each present theirviews of the nature of the project, cost esti-mates, the need for additional supply of gas,and environmental consequences of the proj-ect. The evidence presented also includes anenvironmental impact statement prepared bythe FPC, an engineering and safety review bythe cryogenics division of the National Bureauof Standards, and a risk analysis by the FPCstaff. On the basis of this evidence, the FPCadministrative law judge makes an initialdecision.

“ Second, there is a period of review duringwhich any of the parties may file exceptions tothe decision. At the end of the review period,the commissioners make a final decision

which may uphold the initial decision orchange it completely. The final decision is sub-ject to an appeal in one of the U.S. Courts ofAppeal.

Since the historic role of FPC has been toregulate the entry of suppliers into the inter-state natural gas market and to ensure thatinterstate sales of gas take place at prices thatare “just and reasonable,” 21 the agency haslimited its activities to licensing and ratemak-ing. There is little onsite inspection to assurecompliance with stipulations contained in thelicenses. The exception to this general rule oc-curs when a company wishes to expand exist-ing facilities and submits a new application.In that context, FPC engineers inspect thefacility to judge its operating performance.22 Acritical analysis of the decisionmaking processwhich leads to certification of LNG projectsand the difficulties of pricing policies are dis-cussed in the next chapter.

LNG TANKER TECHNOLOGY

Liquefied natural gas import projects in-volve a complex consortia of energy andtransportation companies. The gas supplier isusually represented by a foreign governmentor State-owned subsidiary company. Therecipient of the gas at the import terminal isgenerally a consortia of gas utilities and/orpipeline companies, which use the gas in theirown systems and sell to other distribution orutility companies. The supplier and receiverare connected by a transportation company,the subsidiary of an oil, gas, or pipeline com-pany, which owns and operates the LNGtankers.

Liquefied natural gas tanker technologyhas been developed over the past 20 years tothe point where, currently, about a dozenworldwide trade routes are either in opera-tion, planned, or proposed for LNG shipping(figure 7). Growth in the world LNG fleet has

2115 UOS.C, $ 717 ~ (a) (1970).221n~rvi~w~ with Federal Power commission s t a f f ,

Washington, D. C., May 31 and June 24, 1977.


o

& i Q

a

0


Figure 8. Total Capacity of World LNG and LPG Tanker Fleet

26 51 39 28 32 44 34 22 30 67 66 60145 172 209 242 274 307 339 352 379 404 418 441

vessels 4 6 9 13 23 24 28 45 49 42 435 5 5 5 8 11 14 17 20 27 35 39

Total 176 232 259 284 327 385 411 419 475 547 561 583

8,000

been rapid (figure 8). Seventy-two ships willbe operational by 1980, with a possibility that33 more would be required if all planned LNGprojects go through. 23

Source Liquid Gas Carrier Register 1977

Currently, only one LNG tanker is engagedin regular import t rade with the UnitedStates, that is the French ship, the Descartes,which has brought 25 shipments from Algeria

23Edward Faridany, LNG: 1974-1990 Marine Opera-tions and Market Prospects for Liquefied Natural Gas,(London: Economist Intelligence Unit Limited, June1974), p. 69,


Figure 9. LNG Tankers On Order or Under ConstructionIn U.S. Shipyards

No. of ContainmentShipyard Vessels System Design

Avondale 3 Conch

General Dynamics 10 Kvaerner-Moss

Newport News 3 Technigaz

Sun Shipbuilding 2 MacDonaldDouglas/GasTransport

Self-supportingaluminum alloyprismatlc tanks,British design

Spherical aluminumalloy tank,Norwegian design

Stainless steelalloy membraneFrench design

Invar ( nickel-steel),American/Frenchdesign

to the Distrigas peak shaving plant in Bostonsince July 1975.24 Nine more LNG tankers willjoin the U.S. trade early next year when im-port terminals under construction at CovePoint, Md., and Savannah, Ga., begin opera-tion, and five more when an import terminalat Lake Charles, La., is online about 1980(figure 9). If other projects now proposed areapproved, it is possible that 12 additionalLNG tankers will be required for imports tothe United States and 14 for shipments fromAlaska to the continental United States. By1985, a total of 41 tankers could be calling atcontinental U.S. ports. (In addition, twotankers are involved in export of LNG fromAlaska to Japan through 1985).25

ziInterviews with Officials of Distrigas Inc., Boston,Mass.,

2 5 a ,

b.

c.

d,

.June 15, 1977.“LNG Scorecard,’ Pipeline and Gas Journal 203(June 1976): 20.American Gas Association, “Update of Status ofLNG Projects,” Gas Supply Review 5 (February1977): 8.U.S. Department of Commerce, Maritime Ad-m i n i t r a t i o n , Sta tus o f LNG V e s s e l s(Washington, D. C.: U.S. Department of Com-merce, Maritime Administration, March 15,1977).U.S. Department of Commerce, Maritime Ad-m i n i s t r a t i o n , Status of LNG Pro j e c t s(Washington, D. C.: U.S. Department of Com-merce, Maritime Administration, September1976).

Liquefied natural gas tankers are bulkcargo ships which require unique design andmaterials to handle the very low-temperaturegas.

Most LNG tankers range in size from about40,000 cubic meters to planned ships of165,000 cubic meters (figure 10). The industrystandard has become the 125,000- to 130,000 -cubic meter ship. Each ship this size carriesenough LNG to heat a city of 100,000 popula-tion for 1 month.26

Figure 10. Profiles of Typical LNG Ships

METHANE PRINCESS27,400 cubic meters

DESCARTES50,000 cubic meters

Source National Maritime Research Center

zGInterview with official of General Dynamics Com-pany, Boston, Mass., June 15, 1977.


By comparison to the better known crudeoil tankers, the largest LNG ships are one-halfto one-fourth the total size of the very largecrude carriers (VLCC or “supertanker’ )(figure 11), some of which are more than400,000 deadweight tons. A 130,000 cubicmeter LNG tanker with a 143-foot beam and a900- to 1,000-foot length is roughly equivalentto a 100,000-deadweight ton oil tanker.

The LNG tanker is a shallow draft vessel,about 36 feet, on which the cargo-carryingcapacity is increased by adding to the lengthinstead of the depth. It has an unusually largeamount of freeboard, rising about 50 feet outof the water. Because of its visible length andheight, the LNG tanker appears larger thansome VLCCs.

The LNG tanker is a high-powered, high-speed ship, with an optimum service speed inthe 20-knot range, about 5 knots faster thanmost oil tankers.

New LNG tankers are fueled by their owncargoes. Immediately upon being loaded inthe tanker, LNG begins to evaporate and con-tinues to do so throughout the entire voyage.In a typical design, the vapor produced duringthe voyage is used as the ship’s fuel and maybe sufficient to meet 100 percent of the fuel re-quirements. However, safety regulations re-quire that the ship carry, and be equipped touse, fuel oil as well. After the ship is unloaded,

a small percentage of the LNG cargo is re-tained in the tanks for cooling purposes andthis supplies part of the fuel requirements forthe return trip.

The tankers are equipped with specializedsystems for handling LNG and for combatingpotential hazards associated with l iquidspillage and fire. These include high-expan-sion foam and dry powder fire protectionsystems, water-spray systems for floodingdeck piping, and pressure-, temperature-, andleak-monitoring systems. Cargo handlingsystems are provided for loading and dis-charging LNG, for cooling down and warmingup tanks, for transmittal of boiloff gas to theship boilers and, most importantly, to provideinert atmospheres in the spaces surroundingthe cargo tanks and in the tanks themselvesprior to and after aeration at the time of dry-docking.

Each LNG tanker is a complicated vessel,representing approximately a $100- to $150-mil l ion investment .27 Most U.S. flag LNGtankers are financed with a variety of aidsfrom the Maritime Administration, includingconstruction differential subsidies, operatingdifferential subsidies, and ship mortgageguarantees.

zT’’General Dynamics Gets Tanker Job for $310million, ’ Wall Street Journal, July 28, 1977.

Figure 11, Comparison of LNG Tanker and Crude Oil Tankers

A comparison of the Principal Dimensionsa, Cargo Deadweightb, and Full-Load Dlsplacementc of a 125,000 Cubic Meter LNG Ship and a Variety of CrudeOil Tankers

80,000 dwt 100,000 dwt 137,000 dwt 125,000 cu/m 476,000 dwt 554,000 dwtOil Tanker Oil Tanker Oil Tanker LNG Ship Oil Tanker Oil Tanker

Length 811 848 974 936 1,243 1,359

Breadth 125 128 134 144 203 207

Depth 57 65 85 82 118 118

Draft 44 50 54 36 93 94

Dwt 80,459 100,300 137,010 63,100 476,025 553,700Full-Load Displacement 105,000 128,500 172,500 94,500 509.000 631,000

‘IN FEETblN LONG TONSCIN LONG TONS Source Engineering Computer Opteconomics Inc

—


To date, the Maritime Administration hasauthorized approximately $270.3 million forsubsidy of all LNG tankers.28 (Federal finan-cial aids are also provided by the Export-Im-port Bank, although that aid is made availa-ble to foreign governments in order to promotethe use of U.S. goods and services in their proj-ects. To date, the Export-Import Bank hasprovided approximately $483 million in loansand loan guarantees to Algeria to support

28’’$ubsidized Shipbuilding Contract Awards’Statistical Quarterly (First quarter 1977),

construction of liquefaction plants and re-lated facilities.)29

The construction cost of an LNG tanker isroughly twice that of an oil tanker of similarsize. Most of the increased cost for LNGtankers is due to special design features of thecontainment system which holds the low-tem-perature, low-density cargo.

The standard 125,000 cubic meter LNGtanker usually has five cargo tanks, each witha capacity of about 25,000 cubic meters (figure12). An eight-story building could fit inside

zgInterview with officials of Export-Import Bank ofthe United States, Washington, D. C., June 16, 1977.

Figure 12. Inboard Profile of LNG Tanker

Liquefied natural gas tankers con-structed by General Dynamics use fivespherical tanks of about 25,000 cubic meterseach Tanks for the ships are constructed inSouth Carolina and towed by barge to theshipyard at Ouincy, Mass , where they aremounted into the ship hull

—


each of these large cargo tanks, which func- ters which are welded to the ship structure.tion in the same way as the common Thermosbottle. A cold product—LNG—is introduced With the membrane design (figure 15), theinto the container and the insulation sur- ship’s hull, in effect, becomes the outer tank.

I n s u l a t i o n i s i n s t a l l e d t h e r e o n , a n d arounding the tank (comparable to the vacuumjacket in the Thermos bottle) is the sole means membrane placed on the inside to retain theby which the cargo is kept cold. No refrigera- liquid. The inner surface of this “double hull’tion is employed on the LNG carrier. is either high nickel steel or stainless steel.

From the 15 or more cargo tank system The unique design problems associateddesigns, two basic types have become most with LNG tankers stem primarily from the

common: the freestanding tank and the need to contain and insulate the extremelymembrane tank. cold LNG cargo and from the fact that many

materials such as mild steel will become brit-The freestandin g tanks are self-contained, tle and fail at very low temperatures. Special

usually spherical or prismatic in shape, made materials used for the interior of cargo tanksof aluminum alloy or 9 percent nickel steel must be able to withstand both the very lowwith layers of insulat ion on the outside temperatures when filled with LNG and the(figures 13 and 14). The tanks are welded to normal temperatures when empty. Whencylindrical skirts or otherwise tied to suppor- metals are subject to these temperature

Figure 13. Free-Standing Spherical LNG Tank

Source U S Maritime Administration

18 CI-I. I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM

changes of as much as 300 degrees, they ex-pand and contract and, in the case of free-standing tanks, the whole structure of thetank interior must be able to move within theship. In addition, up to 2 feet of very efficientinsulation is necessary around each tank inorder to minimize heat leak into the tank dur-ing the voyage from liquefaction plant toreceiving terminal and back.

So far, none of the containment systems inuse has been established as clearly superior tothe others (figure 16), and it is too early in thehistory of LNG carriers to have determinedmeaningful l i fe-cycle cost comparisons.However, each of the present systems is basedon many years of design and testing, andresearch is continuing into new containmentsystems using materials such as concrete andglass-reinforced plastic.

Safety analyses conducted for LNG projectshave constantly identified a ship accident asthe most likely event that could trigger themost serious type of LNG accident. A ship col-lision could result in the rupture of one or

Figure 16. Comparative Characteristics of Some LNG Tank

more cargo tanks and spill a large amount ofLNG onto the water. A water spill wouldspread much farther and evaporate muchmore quickly than a land spill. While it ismost likely that a collision would producesome source of ignition which could fire theLNG vapor around the ship, a huge vaporcloud could be generated if no ignition oc-curred.

A critique of LNG tanker design and con-struction is included in the next chapter.

LNG TANKER CERTIFICATION ANDR E G U L A T I O N

The Coast Guard has primary responsiblityfor the safe construction and operation of theLNG tankers and activities in ports where thetankers call.

Under the Ports and Waterways Safety Actof 1972 and the Dangerous Cargo Act of 1970,the Coast Guard is required to establish andenforce design and construction standards for

Systems

Safety in event of vesselgrounding/collision orother emergency.

Reliability of ContainmentSystem. -

Most ship years operatingexperience and most experiencewithout primary barrier failure.Structure can be analyzed andrisk of fatigue failures minimized.Tanks can be constructed and100% inspected prior to instal-lation in vessel.

Safest system in event of groundingor collision — tank structureindependent of hull and most voidspace between vessel hull and cargotanks. Spherical tanks can bepressurized for emergency dischargein case of cargo pump failure.

Tank system easiest to analyzestructurally: therefore can be mademost reliable,

Source National Maritime Research Center

CH. I – DESCRIPTION OF LNGT ECHNOLOGY AND IMPORT SYSTEM 19

U.S. flag LNG tankers and foreign flag LNGtankers entering the 3-mile territorial watersof this country. It does so by letters of com-pliance for foreign vessels and certificates ofinspection for U.S. vessels.

The criteria used for both are essentiallythe same, however, Federal regulations whichare specifically applied to U.S. flag ships aresimply used as guidelines for foreign ships.

The Letter of Compliance program which isnow in operation requires that the CoastGuard review the vessel with respect to cargocontainment, cargo safety, and the safety oflife and property in U.S. ports. Featurescovered by the review include:30

●

●

●

●

●

●

design and arrangement of cargo tanksand cargo piping and vent systems;

arrangement and adequacy of installedfire extinguishing system and equipment;

safety devices and related systems whichcheck the cargo and surrounding spacesto give warning of leaks or other disor-ders which could result in a casualty;

isolation of toxic cargoes;

compatibility of one cargo with anotherand with the materials of the contain-ment system; and

suitability of electrical equipment in-stalled in hazardous areas.

The review is accomplished by inspection ofdetailed plans and specifications submitted inwriting by the vessel owner, inspection ofdocumentation that the vessel is accepted by arecognized foreign classification society whosestandards provide the same degree of safety ascomparable U.S. standards, and inspection ofthe ship itself on its first visit to a U.S. port.Coast Guard boarding parties examine thevessel’s arrangement and cargo systems,tanks, piping, machinery, and alarms. Theyalso observe the condition of the vessel, vesseloperation, cargo handling operations, fire-

tollepartxnent of Transportation, U.S. Coast Guard,Liquefied Natural Gas, Views and Practices Policy andSafety (Washington, D. C.: Department of Transporta-tion, U.S. Coast Guard, Feb. 1, 1976), p. III-B (2).

fighting capability, and personnel perform-ance. Serious problems, such as any involvinginoperative safety equipment, leaking cargopiping, or nonexplosion-proof electrical in-stallations, may require immediate correction.Minor problems may require correction priorto a return trip to the United States.

If the vessel meets all applicable require-ments, a Letter of Compliance will be issuedand the vessel must continue to meet thestandards of the first visit on all subsequentcalls at U.S. ports. To assure continued com-pliance, the Coast Guard makes a less exten-sive examination of the vessel each time it en-ters U.S. ports.

The Coast Guard requirements for thedesign, construction, and testing of U.S. flagvessels are contained in 46 CFR 38. Newregulations are being drawn up but are not yetcomplete. The Coast Guard has also proposedregulations which would set minimum stand-ards for persons employed on U.S. flag LNGships and is working with internationalgroups to develop standards for foreign crews.The regulations now in effect cover ships t a b i l i t y a n d s u r v i v a b i l i t y , s h i p h u l lmaterials, gas dangerous areas, electrical ar-rangements, firefighting arrangements, ven-tilation, cargo containment systems, tem-perature and pressure control, and instrumen-tation of the ship. They also cover systemsrelating to the transfer of LNG, such as themeans of loading and offloading the cargo,piping materials, piping insulation, valving,’instrumentation, construction, and testing ofthe systems.

Inspections for compliance with thesestandards are carried out during constructionof the vessels. In general, requirements resultin the design of ships which the Coast Guardbelieves to meet a consistent and reasonablelevel of safety and provide for means of deal-ing with casualties such as tank overfilling,overpressuring, and emergency shutdowns. Ingeneral, the vessels are designed tO Survivetwo-compartment flooding from collision orstranding with reserve stability. They are notdesigned to withstand a major collision orstranding without cargo release, but the

—


design does limit the release to the tanksdirectly involved in an incident.

In addition to minimizing the possibility ofcollisions, strandings, or other incidents, theCoast Guard has specified operational con-trols on the vessels while entering, moored, orleaving a U.S. port. By regulations promul-

gated under 50 USC 191, Executive Order10173, and the Ports and Waterways SafetyAct of 1972, the Coast Guard Captain of thePort has control over any vessel within theterritorial sea and may prescribe conditionsa n d r e s t r i c t i o n s f o r t h e o p e r a t i o n o fwaterfront facilities.31 Under the regulations,the Captain of the Port in Boston has drawnup an Operations/Emergency Plan 32 for LNGshipments coming into the Everett, Mass.,LNG facility. Similar plans will be drawn upfor all LNG import terminals. The plan takesin to accoun t t he ind iv idua l geograph icfeatures and environmental characteristics ofeach import terminal and surrounding water-way as well as the unique nature of the LNGcargo. The result is a set of operational con-straints on LNG vessels in order to enhanceport safety. These constraints may includesuch things as the requirement for a CoastGuard escort; enforcement of a “sliding safetyzone,’ which is an area around the LNG shipfrom which all other vessels are excluded asthe LNG tanker proceeds to its berth; restric-tion of operations to certain times of day;prohibitions against certain other types ofwork, such as welding, or the transfer of othertypes of cargo, such as LPG, during dischargeof LNG; and others.33

The regulation of LNG tanker constructionand operations is discussed in the followingchapter.

3133 C-FOR. $$6.04.8, 6.14.1 (1976),qz~partment of Transportation, U.S. Coast Guard,

The Port of Boston, LNG-LPG Operation/EmergencyPlan (Boston, Mass.: Department of Transportation,U.S. Coast Guard, Mar. 29, 1977).

qqwpartment of Transportation, U.S. Coast Guard,Liquefied Natural Gas, Views and Practices Policy andSafety, p. IV-3.

The Coast Guard claims jurisdiction overthe entire portion of the LNG system that con-nects the tanker to the distribution system.Existing regulations give the Captain of thePort authority to control and monitor LNGwaterfront operations. However, there cur-rently are no Coast Guard regulations whichspecifically apply to the terminal facilities.Development of these regulations is under-ways 34 and publication is expected in the fall of1977.

LNG TERMINAL TECHNOLOGY

The proposed LNG import projects andprojects to receive LNG which may come fromAlaska require the construction of large ter-minals to receive and store the product andgasification plants to return the liquid to itsvapor form. A large terminal capable of sup-plying 500 million cubic feet of gas per day canrepresent an investment of more than $350million by the sponsoring companies.

The technology for these terminals is an ex-trapolation of many small LNG peak shavingplants which have been operating for years.This technology has been proved opera-tionally satisfactory for the small plants.Even so, baseload LNG import terminals,which are intended to provide a continuousflow of gas into commercial pipelines, aredesigned to meet much more stringent re-quirements than smaller peak shaving units.35

Offloading of the LNG tankers is ac-complished at a specially constructed pierwhere the tanker is connected to pipelines byarticulated unloading arms and the cargo ispumped ashore (figure 17).

The LNG is stored in large insulated tankson shore and later pumped to regasificationfacilities before it enters the distribution

Wbid., p. IV-4.ssConversation with officials of Columbia LNG Cor-

poration, Cove Point, Md., June 8, 1977.

CH. I – DESCRIPTION OF LNG Technology AND IMPORT SYSTEM 21


Figure 18. Aboveground LNG Storage Tank

Source Scientific American.

system (figure 18). The storage capacity of thetanks is roughly equivalent to twice thecapacity of a single LNG ship, but—unlikepeak shaving storage tanks—the import ter-minal tanks are intended to hold LNG onlybriefly.

In either type of facility, the storage tanksrepresent a significant portion of the costs,and the gas industry has spent much time andmoney in research to develop effective storagesystems.

Currently, there are four storage concepts:double-wall metal tanks, prestressed concretetanks,’ frozen holes, and mined caverns. Tech-niques for storing liquids in abovegroundtanks are well established and the LNG in-dustry has drawn on these techniques. In ad-dition, the tanks are surrounded by earthendikes. These dikes are a safety measure, inthat they could contain the entire contents of atank in the event of a spill. However, they in-crease the land requirements for abovegroundstorage several times over. Much research hasfocused on the idea of underground storagetanks because little or no insulation otherthan the earth appears to be needed and thereis no need for diking to contain spills.

Underground storage tanks have been builtfor LNG in the United States, Algeria, Eng-

land, and Japan. The U.S. tanks were built forpeak shaving operations in New Jersey andMassachusetts, but have since been aban-doned in favor of other types of storagebecause the units failed to perform satisfac-torily.

In any type of tank, the one hazard mostoften mentioned in connection with thestorage of LNG is a phenomena known as“roll over.’

Peak shaving plants have a greater poten-tial for rollover due to weathering of the LNGand/or introduction of new LNG into a par-tially filled tank.

Rollover refers to the convection or motionof fluid which occurs when liquids of differentdensities exist in a storage tank. If differentdensities or stratification do occur within atank such that a denser and warmer liquid isat the bottom of the tank and subject to heatleak, that l iquid can ul t imately becomeheated to the point that it is less dense thanthe liquid above it, and it will be rapidlymoved by buoyant forces up the tank sidewalls to the surface. At this point, it ex-periences a sudden decrease in pressure andbeing above its normal boiling point vaporizesvery rapidly in large quantities causing a sig-nificant pressure rise in the tank. As a resultof this rapid expansion, cracks or even tankrupture can occur.

However, industry research on rollover hasbeen extensive, resulting in deliberate con-trolled mixing of the tank contents, selectedtop, side, or bottom filling, careful monitoringof the temperature of the LNG contentsthroughout the tank, higher design tankpressures combined with low normal operat-ing pressures, and improved venting. In addi-tion, the potential of the phenomena occurringat a baseload plant is further reduced by anoperational practice of unloading tankers intoempty tanks, not partially filled tanks as canoccur at peak-shaving plants.

From the storage tanks, LNG is pumped tothe regasification plant where it is vaporizedby heating it. Frequently, the LNG is heated insystems using the naturally occurring heat innearby seawater. Other systems use process


heat from other equipment or have heat ex- LNG TERMINAL SITINGchangers fueled with oil, electricity, gas, orambient air. None of the vaporizer systems is There are several factors related to pro-obviously the most economical or technically posed LNG import terminals that set themsuperior. The choice depends primarily on the apart from the existing peak shaving plants.location and design of a specific terminal and The proposed terminals are large-scale opera-environmental regulations. tions located in the coastal zone and major

The regasification facility is one of the leastshipping channels, some in major harbors-or

costly sections of the terminal, but is con-near large population centers (figures 19 and20). They require large

sidered important because if it should fail tooperate, the entire purpose of the plant—to

capital, and represent a

provide natural gas—will have been defeated. energy at a single site.

amounts of land andlarge concentration of

Figure 19. Layout of Cove Point, Md., LNG Receiving Terminal

Source Columbia LNG Corp


The location of a terminal can be a majorfactor in its safety. The magnitude and extentof any damage from an LNG spill can dependon the proximity of the terminal and storagesites to other industrial and residential areas.

The site selection process is currently con-ducted by the company or consortium propos-ing the project. Gas industry officials considersuch factors as accessibility by large tankers,the availability of the market, which is largelydetermined by the proximity of an existingpipeline network; costs of land acquisition;avai labi l i ty of ski l led labor supply; andavailability of public facilities such as roads,electricity, sewers, etc. Some companies alsoconsider area land-use characteristics and en-vironmental sensitivities important aspects ofsite selection. The FPC position is that, unlessotherwise stipulated, FPC approval of thefacility allows Federal preemption of Stateand local laws relating to siting. Therefore,local and State land-use regulations could beoverruled. A company makes application tothe FPC only after it has done as muchpreliminary work as possible, which includesat least gaining control over, if not outrightownership of, the proposed site. Thus, neitherthe general public nor the Federal Govern-ment become involved in the site selectiondecision until it has already been made by thecompany. There are, at present, no Federalsiting criteria, and those projects which arenow proposed have a variety of sites, rangingfrom remote coastal and riverine areas with1,000-acre buffer zones to as little as a 90-acresite on Staten Island.

L N G T E R M I N A L R E G U L A T I O N

The construction and operation of LNG ter-minals are primari ly regulated by threeFederal agencies; the Federal Power Commis-sion (FPC), and the Office of Pipeline SafetyOperations (OPSO), and the Coast Guard.

Federal Power Commission jurisdictionover the terminals is included in the process oflicensing import projects. The FPC considersapproval of any LNG import project to be “amajor Federal action significantly affectingthe quality of the human environment” sub-ject to the National Environmental Policy Act

requirement that an environmental impactstatement (E IS) be prepared.

As a part of the EIS, the National Bureauof Standards’ cryogenics division in Boulder,Colo., under con t rac t to FPC, rev iewsengineering and safety aspects of the proposedterminal. Also as part of the EIS, the FPCstaff prepare a quantitative risk analysis,which is its principal method for determiningwhether a project can be considered safe. Therisk analysis considers the major events whichmight cause an LNG spill, such as ship colli-sion, grounding, or ramming; failure of theunloading arms or other major pieces ofequipment; and damage to the facility fromnatural phenomena or unusual accidents. Therisk analysis determines the extent of damageand the number of deaths and injuries whichmay result from a disaster and the probabilitythat certain types of disasters would occur.The death probabilities from natural dis-asters are typically about 1 in 10 million. Insome recent applications, the FPC rejected asite because it posed a public risk to life with aprobability of greater than 1 in 10 million.Therefore, that figure has become the infor-mal criteria which projects must meet for FPCapproval .36

The FPC exerts i ts influence over thefacilities by attaching stipulations to the cer-tification of public convenience and necessitywhich it issues if the project is approved.These stipulations are designed to minimizeenvironmental consequences and to promotethe safety of the facility. The applicant is re-quired to comply with these stipulations if heaccepts the certificate. Statements of com-pliance and operating reports are requiredregularly, but there is little or no post-cer-tification oversight by the FPC. Onsite FPCinspection generally occurs only when a com-pany wishes to expand its facilities and sub-mits a new application.37

aG1nterV& with staff of Woodward-Clyde Consul-tants, Washington, D. C., June 28, 1977, and FederalPower Commission, Alaska Natural Gas Transporta-tion System, R“nal Environmental Impact Statement,Vol. 111, p. 425d and 4253. (Washington, D. C.: FederalPower Commission, 1976).

371nt,erview with staff of Federal Power Commission,Washington, D, C., May 31, and June 24, 1977.


Figure 21. Storage and Diking at Onshore LNG Plant

Source El Paso LNG Terminal Co

The safety of the terminal facilities islargely an OPSO responsibility. Under theNatural Gas Pipeline Safety Act of 1968,O P S O i s r e s p o n s i b l e f o r e s t a b l i s h i n gminimum Federal safety standards for allpipeline facilities in or affecting interstate orforeign commerce. Pipeline facilities havebeen given an extremely broad interpretationto include all components of an LNG importterminal, including the offloading facilities,storage tanks, regasification facilities and allassociated pipelines.

Permits are not required by OPSO, whichexercises its authority solely by inspectingfacilities for compliance with Federal stand-

a rds . The s t andards a re cu r ren t ly bu i l taround the safety code of the National FireProtection Association, known as 59(A). Inaddition to setting minimum standards formaterials, equipment, and systems the coderelies upon two basic concepts to protect thepublic from LNG hazards: the requirement fora diking and containment system and the re-quirement that specific distances be main-tained between certain components and be-tween components and the property line.

Dikes are the primary device used to pre-vent the uncontrolled spreading of an LNGspill on land (figure 21). The dikes make it

— —-— —


possible to use either of two methods of con-trol:

● In the event of an LNG spill, the liquidcan be contained within the dike and therate of evaporation slowed by the use ofhigh expansion foam. All sources of igni-tion can be eliminated. In this way, theLNG can dissipate in harmless con-centrations into the atmosphere.

● Or, in the event of an LNG spill, the liq-uid can be contained within the dike andits evaporation controlled or even ignitedso that it immediately burns in the con-fined space where the fire can be con-trolled by known firefighting methods.

The NFPA 59(A) regulations currentlyadopted by OPSO specify the size and con-struction of the dike and the design of relatedequipment necessary for the diking system.

The other technique used to enhance safetyis to establish the distance which must lie be-tween the dikes around the storage tanks andthe property line. The distance required is onewhich would assure that heat from an LNGfire inside the dikes would not be severeenough at the property line to cause death orthird degree burns.

Current regulations require that this dis-tance be 0.8 times the square root of the areainside the dikes.

Regulations also require that the facility bedesigned to meet the maximum earthquakespecifications of the Uniform Building Code.

New LNG terminal standards have beenproposed by OPSO and are being circulatedfor public comment. Generally, the proposedstandards are more strict and cover moreaspects of terminal design than do currentstandards, but in many cases they are lessdefinitive. The standards increase the dis-tance between dikes and property line, requirea vapor dispersion zone or a redundantautomatic ignit ion system, and set morestringent seismic design criteria. 38 It is ex-

pected that the proposed standards wil lseriously limit the choice of sites for LNG ter-minals.

The Coast Guard’s responsibility for ter-minal facilities is an extension of the Captainof the Port’s jurisdiction over waterfrontfacilities. The Coast Guard maintains that itsjurisdiction, with regard to LNG vessel move-ments and waterfront facilities, is sufficient topromulgate and enforce safety requirementsfor the LNG transfer operations at the receiv-ing terminal and, in that light, considers thepipel ines between tanks and loading oro f f load ing equ ipmen t , t he load ing andoffloading equipment, storage tanks, and theentire portion of the LNG system which con-nects the tanker to the distribution system tobe under its jurisdiction. The inland distribu-tion system is not the responsibility of theCoast Guard.

The Coast Guard currently has no regula-tions specific to LNG terminals but has under-taken development of such regulations to im-plement appropriate sections of the Ports andWaterways Safety Act of 1972. In the mean-time, the Captain of the Port in each areawhere LNG is handled exercises authority bydeveloping contingency plans for operations.

A critique of the Government role in theregulation of LNG terminal siting and opera-tions is included in the following chapter.

TRENDS IN LNG USE ANDF A C I L I T I E S

Liquefied natural gas could be an impor-tant short-term energy supply for the UnitedStates over the next few decades and couldhelp alleviate some near-term fuel shortagesin selected sectors of the economy. Ultimately,however, the supply of natural gas which maybe sold to the United States as LNG is limited.LNG is not a major new source of energywhich will allow unrestrained use of naturalgas, and it is unlikely that many import proj-ects will be forthcoming beyond those alreadyproposed.

SNU.S. llepartrnent of Transportation, Office ofPipeline Safety Operations, “Liquefied Natural GasFacilities (LNG); Federal Safety Standards,” FederalRegister 42, no. 77, April 21, 1977, 20776-20800.

— —

CH. I – DESCRIPTION OF LNGT ECHNOLOGY AND IMPORT SYSTEM 27

In the future, it can probably be expectedthat U.S. consumption of natural gas will con-tinue to decline slightly and it is possible asmuch as 15 percent of the total natural gasconsumed could be transported as LNG by1985-95 (figure 22). This figure may be lowerif a pipeline is used to transport Alaskan gasto the continental United States.

Imports of LNG to the United States cur-rently come from Algeria, and there is someconcern about the wisdom of becoming de-pendent upon any one country as the majorsource of supply. However, several other coun-tries also control major portions of the world’snatural gas reserves. For example, liquefac-tion and export facilities are being developed

Figure 22. Projected Future LNG Imports (Based onProposed Projects and Reasonable ApprovalTime)

Trillions Percent of 1976of cubic feet U.S. Natural Gasper year Consumption

4 20%

15%

1977-80 1980-85 1985-90Projects Planned PossibleConstructed Projects Newor Operating Approved Projects

or PendingBefore FPC

El Paso IDistrigas

El Paso IIPanhandlePac/lndonesia

Possible Future Supplies FromUSSR, Iran, and Nigeria

10%O

5 %

in Chile, Nigeria, and Colombia and there is apossibility of additional export projects iftechnology and reserves are proven in Russia,Iran, China, and Australia. 39 It is likely thatsponsors of some U.S. import projects willturn to these exporters for additional suppliesof LNG, thus reducing the dependency onAlgeria.

Changes are also likely to occur in the siteschosen for U.S. import terminal facilities, insome types of equipment which may be used,and in the onshore distribution of LNG.

Currently, public pressure exists for, andthe industry trend is toward, “remote” sitingof LNG terminals and storage facilities. Con-troversy over the meaning of remote and thecharacteristics which make a site acceptablefor an LNG facility, coupled with the difficultyfirms may have in finding acceptable sites,have led to the suggestion that LNG facilitiescould be located offshore, away from popu-lated areas and congested harbors and water-ways.

Several designs have been proposed foroffshore platforms to house LNG facilities, butno detailed design has been developed for anyspecific site. At the present t ime, thesepreliminary designs limit site selection tolocations with water depths of 600 feet. Mostof the design concepts are self-containedfacilities which look like large floating bargesinstalled to a mooring system (figure 23).Other concepts propose that the platforms befloated to a site, then grounded to the beach orseabed. There are also two other, more elabor-ate concepts: One would make use of subseastorage structures, similar to those used in theNorth Sea to store oil, with a semisubmersibleor tension-leg concrete platform mooredabove for the liquefaction or regasificationplant. The other features separate moored orjack-up platforms for the process plant andthe storage structures.

According to industry figures, offshorefacilities will require 3 to 4 years constructiontime. Crude estimates range from $175 million

Source OTA

39JJLNG Report, ’ ~“peline and Gas Journal 204(June 1977).


Figure 23. Artist’s Rendering of Offshore LNG Terminal

to $220 million for a receiving terminal with a limited operating experience now available,500 million cubic feet per day regasification no particular designs for either ship cargoplant and storage for 200,000 cubic meters systems or onshore storage facilities have yetand from $350 million to $425 million for a emerged as obviously superior. Therefore, it is500 million cubic feet per day 40 liquefaction likely that a variety of equipment will comeplant. into use as more projects are approved.

There are many designs for LNG tankers It is also possible that increased use of LNGand onshore facilities. However, with the will result in increased onshore transporta-

tion of LNG to secondary markets by means4{)1bid. other than pipeline. Although the proposed


,

baseload import terminals have no specificprovisions for truck and rail shipment ofLNG, such shipments appear to be possibleand permissible in the future. Shipment bytruck is already a reality at most peak shavingoperations and from the import terminal atEverett, Mass.

Prior to 1969, only a few LNG truckingoperations had been attempted in this coun-try, using equipment originally designed forliquid nitrogen service. Based on the successof the operations, equipment was designedand fabricated especially for LNG. It is esti-mated that there are 75 LNG trucks currentlyin operation in the United States.41 Typical ofthe trucking which has taken place was theshipment of nearly 4.5 million gallons of LNGfrom Philadelphia, Pa., to Lowell, Mass., dur-ing the winter of 1969. Since then largevolumes have been transported all over theUnited States to help supply outlying com-munities, to provide temporary supplies whenservice is interrupted, and to provide smallquantities for experimental work.

Liquefied natural gas could also be movedfrom import terminals or liquefaction plantsby barges or railway tank cars.

The use of barges was first proposed totransport LNG up the Mississippi River to theChicago Union Stockyards, and one barge wasconstructed and tested for this purpose in the1950’s. It was never used commercially.Another barge, the 297-foot Massachusetts,was constructed by Distrigas for distributingLNG from a Staten Island import terminal.However, that barge has been taken out ofservice because of opposition.

Railway tank cars have been proposed as ameans of carrying LNG to isolated areaswhich do not justify construction of pipelines.Tank cars now in use hauling liquid oxygen,nitrogen, and hydrogen would be suitable forLNG service, but the economics are such thatit is unlikely there would be much emphasison rail movement of LNG.

~ I Interviews with officials of Distrigas Inc., Boston,Mass., June 15, 1977.

EXISTING AND PROPOSEDPROJECTS, IN BRIEF

There are two operating LNG marinetransport projects in the United States today,the “Distrigas” project importing gas fromAlger ia in to E v e r e t t , M a s s . , a n d t h e“Phillips/Marathon’ project exporting gasfrom Alaska to Japan. Construction of thefirst large baseload import project to be ap-proved by FPC, “El Paso I,” is nearing com-pletion, and the facility is expected to becomeoperational early in 1978 importing gas fromAlgeria to both Cove Point, Md., and Elba Is-land, Ga., (near Savannah).42

One additional large import project has re-cently been given final approval by FPC, butno construct ion has begun. This is the“Trunkline’ project to import LNG fromAlgeria to Lake Charles, La.43 The “Pacific-Indonesia’ project to import LNG from In-donesia to Oxnard, Calif.,44 has received onlyinitial FPC approval and no construction hasbegun.

Three additional projects have been filedwith the FPC for some time and decisions orapprovals are expected soon. These are: the“El Paso II*’ project to import LNG fromAlgeria to Port O’Connor, Tex., the “Pacific-Alaska” project to transport LNG from CookInlet in southern Alaska to California; andthe “El Paso-Alaska” project to transport thehuge North Slope Alaska gas reserves fromGravina Point, Alaska (after pipelining fromthe North Slope) to California.45

Since these eight projects have a reasonableprobability of being operational in the future(the early 1980’s), a brief description of each isincluded in this section. Other planned or pro-

q~Dean Hale, “Cold Winter Spurs LNG Activity,”Pipeline and Gas Journal 204 (June 1977): 30.

q:~Federal Power Commission, TrunkZine LNG Corn-pany et al., Opinion No. 796-A, Docket Nos .CP74-138-140 (Washington, D. C.: Federal Power Com-mission, June 30, 1977).

~~Federal Power Commission, “FPC Judge ApprovesImportation of Indonesia LNG,” News Release, No.23292, July 22, 1977.

~~Dean Hale, “Cold Winter Spurs LNG Activity,”:31.


posed projects have not been included forvarious reasons. For example: the “Eascogas’project which was planned for Staten Island,N. Y., and Providence, R. I., terminals has beendelayed so many times that its viability is inquestion. A project planned by Tenneco to im-port gas from Algeria to St. John’s, N. B., inCanada, and then pipe the gas to the UnitedState is now in the early review stages byFPC.46 Another recently announced project isone by the Peoples Natural Gas Company ofChicago to import LNG from either Iran orChile to a terminal near Corpus Christi,T e x .47

This report reflects the situation as of thesummer of 1977. Many other projects are inthe early planning states. Many factors affectthese plans, however, and changes are com-mon prior to actual construction of facilities.

1. The Distrigas Project (figure 24)

This project has been in operation since1971. The 50,000 cubic meter LNG tankerDescartes is now on a regular deliveryschedule on approximately a 20-day cycle.48

The ship, which was built in France in 1971and operates under the French flag, 49 h a s

AGIbid., p. 31.ATFederal Power Commission, “NGP-LNG Inc., Ap-

plication and Request for Phased Proceeding,” FederalRegister 42, No. 131, July 8, 1977.

A~Interviews with officials of Distrigas Inc., Boston,Mass, June 15, 1977.

AgU.S. Department of Commerce, Maritime Ad-ministration, Status of LZVG Vessels (Washington, D, C.:U.S. Department of Commerce, March 1977).

Figure 24.Project Data Sheet: DistrigasImport Source: Skikda, AlgeriaImport Terminal: Everett, Mass.

ContractLocation Expected volume

Companies revolved of u s Project operational Bcf/yrterminal designation date (M Mcfd)

Supplier. Sonatrach(Algerian NationalGas Co ).

Shipper. Alocean Everett, Distrigas I Operational 16(Sonatrach subsidiary). Ma,

U S. Importer: DistrigasCorp

Distributors: Various Everett, Distrigasgas companies in New Ma, IllEngland, New York, andNew Jersey

Supplier. Sonatrach. Everett, Distrigas

Importer Distrigas Ma, Iv 2

(Project pending),

since 1971 (43 6)

1977 (1,5 16 totalyr. supple- (43.6)mental con-tract)

1978 42(115)

FPC Number Ships/ Estimated investment ($106) Estimatedstatus S h i p y a r d / price ($)(as of Capacity m3/ Receiving delivered into

9/1/77) Tank design Tankers terminal pipeline/MMBtu— —

Approved 1 / C h a n t i e r - — 33 1.901972, Atlantique l

Reopened (France)/1974, 50,000 m3/Approved membrane1977

—Pending

2.80

Filed 1/Chantiers- — 9 – l o 2.91Feb. Ciotat (added1977 (France)/ investment)

125,000 m3/Sphericalfree-standing

CURRENT IMPORT TERMINAL CHARACTERISTICS 1 The 50,000 cubic meter ship “Descartes’ wiII be taken out of

Storage capacity Regasification Type of storage Number of Terminal service upon arrival of the latest contract (Distrigas IV).

(MMcf) capacity (MMcfd) containers storage tanks acreage2 The Distrigas I and Ill projects will be phased into the Distrigas IV

3250 — 135 A b o v e g r o u n d – -2 37project when the latter commences

9% nickel steel Source OTA


been delivering LNG from Skikda, Algeria, tothe terminal at Everett, Mass., at the rate ofabout 15 trips each year. The terminal is lo-cated on the Mystic River, up from the mainBoston harbor and less than one-half milefrom the Boston city limits, in a highly in-dus t r i a l i zed reg ion wi th bo th LPG andgasoline terminals adjacent to the property. so

The Everett facility has operated withoutmajor incident for 6 years.

The principal market for this LNG is theNortheastern States with distribution madeby both truck and pipeline. At present 40 per-cent of the LNG is distributed by trucks andmore than 60 trucks operate out of the facilityto other satellite storage tanks in the North-east .51 The Distrigas project has contractedfor a supply of 16 billion cubic feet of gas peryear, and in 1976 actual imports totaledslightly over 10 billion cubic feet.52

While this project has received FPC ap-proval, a modification to expand the terminal

~t}Interviews with officials of Distrigas Inc., Boston,Mass., June 15, 1977.

,5 I Ibid.

~~Federal power Commission, United States 1772pOr~S

and Exports of Natural Gas 1976 (Washington, D. C.:Federal Power Commission, May 1977).

and total import volume has been filed and ispending approval by FPC. Under the terms ofa new 20-year contract with the Algerian Na-tional Gas Company, Distrigas would import42 billion cubic feet of gas per year beginningin 1978.53 This contract would replace the ex-isting one and a new 125,000 cubic meter ship,the Mostefa Ben Boulaid, would be used inplace of the Descartes. Additional unloadingfacil i t ies , but no new storage tanks, areplanned for this expansion.54

2. The Phillips/Marathon Project(figure 25)

The oldest operating marine LNG project inthe United States is the project now exportinggas from fields in Cook Inlet in southernAlaska, through a terminal at Kenai , toNeigishi, Japan. This project has been oper-ated by the Phillips Petroleum Company andMarathon Oil Company since 1969.

Two 71,500 cubic meter LNG tankers, the

~:~Dean Hale, “Cold Winter Spurs LNG Activity,”:30.

~qlnterViews with officials of Distrigas Inc., Boston,Mass, June 1

Figure 25.Project Data Sheet: Phillips/MarathonLNG Export Source: Kenai, Alaska (Plant at Nikiski)LNG Export Terminal: Neigishi, Japan

Kenai to Neigishi – 3,280 nmi I— —-

Contract FPC Number Ships/ Estimated Investment ($10°)Location Expected volume status Shipyard/

Companies Involved of u s Project operational— — —

Bcf/yrfacility

(as of Capacity m3/ Receivingdesignation date (MMcfd)

Exported price9/1/77) Tank design Tankers terminal ($)-1976 /MMBtu—

Gas Supplier: Phillips.

and Marathon Plant.Operator: Phillips

Petroleum Kenai. Phillips/ Operational 49,3 Approved 2/K, M, –Shipper: Marathon Oil. Alaska Marathon

—since 1969 (135) Verkstads 1 66Importers Tokyo Electric, 1 5-year (Sweden)/

Tokyo Gas. contract) 7 1 , 5 0 0 m3/ –membrane— —

CURRENT EXPORT SOURCE CHARACTERISTICS

Storage capacity Liquefaction Type of storage Number of Facility(MMcf) capacity (M Mcfd) containers storage tanks acreage—

2300 185 Aboveground 3aluminum

Source OTA

32 CH. 1 – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM

Arctic Tokyo and the Polar Alaska, were builtin Sweden and operate under the Liberianflag with Italian crews.55

The contract to supply Tokyo Electric andTokyo Gas companies is for 135 billion cubicfeet of gas per year, and in 1976 about 50billion cubic feet were actually delivered. 56

This project has operated without a majorproblem since initiation.

During the extreme winter of 1977 a specialdelivery of one shipload of LNG was made toEverett, Mass., from Alaska, after a waiver of

MU.S. Ilepartrnent of Commerce, Maritime Ad-ministration, Status of LNG Vessels.

sGFederal Power Commission, United States Importsand Exports of Natural Gas 1976.

Figure 26.Project Data Sheet: El Paso IImport Source: Arzew, AlgeriaImport Terminal: Cove Point, Md. and Elba Island, Ga.

Companies involved

—Suppliers: Sonatrach

(Algerian NationalGas Co. )

Shipper: El Paso AlgeriaCorp.

Cove Point purchasers:Consolidated SystemLNG Co and ColumbiaLNG Co. (also operators)

Elba Island purchasers:Southern Energy Co(also operators)

Drstributors Columbia GasTransmission Corp.,Consolidated GasSupply Co., SouthernNatural Gas Co

the Jones Act prohibiting the use of foreignflag tankers in U.S. trade. A French-built3,5,000 cubic meter tanker, the Kenai Multina,flying the Liberian flag was used. 57 This proj-ect contract expires in 1985. Beyond that, ap-plication may be made to bring the gas tosouthern California.

3. The El Paso I Project (figure 26)

The agreement between El Paso NaturalGas Company and Sonatrach (Algeria) willlead to the ini t ial t ransport of the LNG

s~ean Hale, “Cold Winter Spurs LNG Activity ”,:21.

Arzew to Cove Point– 3,570 n miArzew to Savannah – 3,77o n mi I

Locationof u s Project

terminals designation— —

Cove Point,Md

El Paso I

Elba Island,Ga.

Contract FPC Number Ships/ Estimated Investment ($106) EstimatedExpected volume status S h i o y a r d / . - — — — — — – — price ($)

operational Bcf/yr (as of Capacity m3/dale (MMcfd) 9/1/77) Tank design Tankers

3/Chantiers- Dunkirk

3651 Approved (France)/(1000) 1972, 125,000 m3/

1973: membraneReopened1974

1978 Approved 3/Avondale 11001-1977 (U.S.A.)/ for all

125,000 m 3/ 9 shipsFree-standingPrismatic

3/Newport(U.S.A.)/125,000 m3/Technigazmembrane

Receiving delivered iintoterminal pipeline/MMBtu

350 1.66-181(CovePoint)

127 1.70(Elba Is, )

CURRENT IMPORT TERMINAL CHARACTERISTICSStorage capacity Regasification Type of storage Number of Terminal —

Location (MMcf) capacity (MMcfd) containers storage tanks acreage

Cove Point, Md. 5000 1000 Aboveground, 4 60 (plant, structures)aluminum 300 acres allocated

1100 acre tractElba Island, Ga. 4000 325 — 3 150 acres allocated

800 acre tract

1 Of this amount. Cove Point shall

Ireceive about two-thirds,Elba Island one-third

Source OTA


equivalent of 1 billion cubic feet per day (365billion cubic feet per year) of natural gas tothe United States.

The Columbia Gas System, along with theConsolidated Gas System, has entered intocontract for some two-thirds of this gas. TheLNG will be delivered to a terminal locatedon the Chesapeake Bay at Cove Point, Md.The terminal will be jointly owned by Colum-bia and Consolidated and will become opera-tional early in 1978. The remainder of LNGwill be delivered to Southern Natural Gas at anew terminal under construction on Elba Is-land, Ga.58

The Cove Point terminal has two tankerberths, four storage tanks and several processareas. The two tanker berths are locatedabout 1 mile offshore along a 2,500-foot pierwhich is connected to shore by an under-ground tunnel containing both LNG pipes andvapor return lines. The initial operating planscall for about 140 ship arrivals per year. TheCove Point facility is located on a 1,100-acretract of land along the Chesapeake Bay inCalvert County, Md.59

The gas will be piped from Cove Point to anexisting pipeline in Loudoun County, Va., andthen to markets in middle Atlantic Statesse rved by Co lumbia and Conso l ida tedNatural Gas Companies.

The Elba Island terminal is on an 800-acresite of undeveloped land, wholly owned bySouthern Natural Gas. It is located 5 milesdownriver from Savannah, Ga., and will sup-ply gas to southeastern U.S. markets. ThisLNG is expected to represent about 15 percentof Southern Natural Gas sales when the ter-minal is operational. It is planned that 50LNG tankers will call at the Elba Island ter-minal each year, substantially increasing theship traffic at the Savannah port entrance. GO

Wbid., p. 30.~gMax Levy, “The Cove Point, Maryland LNG Ter-

minal,” Conference on LNG Importation and TerminalSafety, Boston, Mass., June 13-14, 1972.

GoSouthern Natural Gas Company, Facts on Elba Is-land, Savannah, Georgia LNG Terminal, (n. p.:Southern Natural Gas Company, n.d. ).

Nine 125,000 cubic meter LNG tankers areto be used to serve both El Paso I terminals.Three tankers were built in France, are nowcompleted and laid-up, and are planned to beoperated by El Paso under the Liberian flag.Six others are under construction at two U.S.shipyards (Avondale and Newport News), andare planned to be operated by El Paso underU.S. flag.6l

The entire project is about 2 years behindschedule. The principal technical problemwas completion of the large liquefactionfacilities in Algeria. After one U.S. contractorfailed to perform, the Algerian National GasCompany canceled the contract and hired anew contractor. The U.S. terminals and theU.S.-built tankers are now almost completed,after a slow-down to await completion of theAlgerian terminal. The present schedule is forLNG shipments to begin in January 1978.62

The FPC approved the El Paso I project inJune 1972.

4. The “Trunkline’’Project (figure 27)

The Trunkline project was approved byFPC on June 30, 1977, after an appeal of aninitial opinion in April.63

The proposed LNG facility would be nearthe Lake Charles Harbor in Louisiana andwithin the Terminal District Industrial Park.It would be located on a 139-acre site andwould be used to unload, store, and ship LNGimported from Algeria. The LNG terminalwould consist of a berthing dock for LNGunloading, an onshore facility consisting ofthree 600,000-barrel LNG storage tanks sur-rounded by a dike, two 25,000-gallon liquidnitrogen storage tanks, one 250,000 Bunker Cfuel-oil tank for servicing the LNG tankers,and a process area which would containequipment for all LNG transfer operations.

GIU.S. Department of Commerce, Maritime Ad-ministration, Status of LNG Vessels.

621bid.

63Federal Power commission, Trunk/ine LN(j corn.

pany et al., Opinion No. 796-A, Docket N O S.CP74-138-140 (Washington, D. C.: Federal Power Com-mission, June 30, 1977).

——

34 CH. I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORTS SYSTEM

Figure 27.Project Data Sheet: TrunklineImport Source: Arzew, AlgeriaImport Terminal: Lake Charles, La.

Contract FPC Number Ships/ Estimated investment ($106) EstimatedLocation Expected

Companies Involved of u s Project operationalterminal designation date

Supplier Sonatrach - - ‘ - “ –

(Algerian NationalGas Co. )

Terminal builder & Lake “Panhandle’ 1980-81operator Trunkline Charles, ‘‘Trunkline”LNG Co La ‘‘Calcasleu’

Buyer & distributorTrunkline Gas Co(Subsidiary of PanhandleEastern Pipeline Co)

Market Illinois. Indiana,Michigan, Ohio (primarily)

CURRENT IMPORT TERMINAL CHARACTERISTICS. .Storage capacity Regasification Type of storage Number of Terminal

(MMcf) capacity (MMcfd) containers storage tanks acreage

6000 540 Above-ground, 75 (plant,aluminum 3 structures)

(139 acre site)

Ancillary facilities would include offices,equipment for wastewater treatment, fire con-trol and detection, fire protection equipment,water supply, electrical power, and com-m u n i c a t i o n s . 6 4

The project is planned for importing 179billion cubic feet of gas per year using five125,000 cubic meter LNG tankers. Thetankers would reach the facility at the arrivalrate of 65 per year through a 24-mile channelfrom the Gulf of Mexico.65

Subsidiaries of Panhandle Eastern PipeLine Company, Genera l Dynamics , andMoore-McCormack Bulk Transport , Inc. ,have formed a partnership, Lachmar, to build,own, and operate two of the ships. These two

3/125,000 m3/shipyard &design notknown

Source OTA

ships are to be built at General Dynamics’,Quincy, Mass., shipyard. The three othervessels for this project are expected to be pro-vided by the Algeria National Shipping Com-pany .66

5. The “Pacific Indonesia” Project(figure 28)

In an initial decision on July 22, 1977, anFPC Administrative Law Judge approved aproposal to import 200 billion cubic feet of gasper year from Indonesia to a terminal in Ox-nard, Calif. The decision is subject to Commis-sion review. 67 There is considerable contro-versy in California over the site, and someState legislation on siting is pending.

6 4 Federa] power commission, Flnaz ~nuironmentalImpact Statement Calcasieu LNG Project TrunklineLNG Company Docket No. CP74- 138 et al.,(Washington, D.C.: Federal Power Commission, Sep-tember 1976).

b51bid.

GGDean Hale, “Cold Winter Spurs LNG Activity,”:30.

~TFederal Power Commission, “FPC Judge ApprovesImportation of Indonesia LNG.”


Figure 28.Project Data Sheet: Pacific-Indonesia

Indonesia

Projectdesignatlon

Pacific-IndonesiaProject

PROPOSED IMPORT TERMINAL CHARACTERISTICS.

Oxnard, Ca

Sumatra,

Sumatra 10 Oxnard – 8,300 n ml

Contract FPC Number Ships/ Estimated investment ($106 EstimatedExpected volume status S h i p y a r d / — price ($)

operational Bcf/yr (as of Capacity m3/ ‘Receiving delivered intodate (MMcfd) 9/1/77) Tank design Tankers terminal pipeline/MMBtu

61U.S.A. ) / 155 per1 2 5 , 0 0 0 m 3 / U S Tankershipyard &

48 months 200 Initial tank design

after approv- (550) approval not known

al (Liquefac-tion facilitiesm Indonesiaunder con-struction)

Storage capacity Regasification Type of storage Number of Terminal(MMcfi) capacity (MMcfd) containers storage tanks acreage

7700 4600 Above-ground, 4 Plant, -90/0 nickel steel structures

38 (ulti-mately 55)21 O-acresite—

The proposed Oxnard facility would beowned and operated by Western LNG Ter-minals. It would be located on a 210-acre sitein the City of Oxnard, on the coast of Califor-nia. This plant would import LNG at a rate of546 million cubic feet of gas per day formarkets within the State of California. TheLNG storage and vaporization facilities wouldoccupy 38 acres of the site containing two tofour 550,000-barrel , double-wall , above--ground tanks, 240-feet in diameter with anoverall height of 129 feet. The plant facilitieswould require 55 acres of the site, and themarine terminal would occupy 34 acres ofleased subtidal land extending approximately6,000 feet offshore at Ormand Beach. Unload-ing arms at the marine terminal would

6-77, sub-ject to review

2/ Chandlers-Atlantique(France)/125,000 m3/membrane1/Chantiers-Ciotat/125,000 m3/Free standingspherical

270 3 0 6 - 3 6 0

Source OTA

transfer the LNG from the ship to the storagefacilities through 42-inch cryogenic pipes.68

Liquefaction facilities in Indonesia are nowunder construction.

Conditional agreements have been reachedwith shipping companies for nine 125)000cubic meter LNG tankers. Pacific Indonesiawill charter the ships, three of which will beFrench buil t and the remaining six U.S.built. 69 No U.S. ship construction contract hasbeen announced.

68 Federa] power commission, Final EnvironmentalImpa et Sta tern en t Pacific Indonesia Project(Washington, D. C.: Federal Power Commission, Decem-ber 1976).

fi~u.s. Department of Commerce, Maritime Ad-ministration, Status of LNG Vessels.


6. The El Paso II Project (figure 29)

The El Paso II project is pending before theFPC. The proposal is to transport 365 billioncubic feet of gas per year from Algeria to anew facility at Port O’Connor, Tex. TO A fleetof twelve 125,000 cubic meter LNG tankerswould be required. It is planned that six ofthese would be U.S. flag and U.S. built, but noc o n s t r u c t i o n c o n t r a c t s h a v e b e e n a n -nounced.71 Safety reports have been submit-ted and FPC hearings were held during thesummer of 1977. Draft and final environmen-tal impact statements have been issued.72

~[~Federa] Power Commission, Algeria 11 Proj”ect Out-line of Contracts, El Paso Eastern Company, et al.,Docket No. CP77-330, et al. (Washington, D. C.: FederalPower Commission, n.d. )

~IU.S. Department of Commerce, Maritime Ad-ministrate ion, Status of LNG Vessels.

~~Federal Power Commission, Joint LNG SafetyReport of El Paso Atlantic Company et al., Respectingthe Proposed Algeria II Project, Docket No. CP73-258,et al. (Washington, D. C.: Federal Power Commission,Apr. 1, 19’77).

Figure 29.Project Data Sheet: El Paso IIImport Source: AlgeriaImport Terminal: Port O’Connor,

Companies Involved(project status)

Supplier Sonatrach(Algerian NationalGas Co. )

Shipper El Paso Atlanticco

Receiver El PasoEastern Co

Distributors El Paso,LNG Terminal,United Gas Pipeline.

Locationof u s

terminals

PortO’Connor,Tx.MatagordaBay

Tex.

Projectdesignation

El Paso II

CURRENT IMPORT TERMINAL CHARACTERISTICS

7. The “Pacific-Alaska’’ P roject(figure 30)

A project to transport LNG from Cook Inletgas fields near Kenai, Alaska, to California ispending before FPC.73 A terminal is plannedat either Oxnard or Los Angeles, Calif. Ques-tions of terminal siting now being addressedby the State of California are delaying somedecisions on this project. It is planned that ini-tially two 130,000 cubic meter tankers wouldbe used to import 73 billion cubic feet of gasper year. Sun Shipbuilding Company hassigned contracts for these ships with an affili-

~JDean Hale, “Cold Winter Spurs LNG Activity,”:31.

Arzew to Port O'Connor — 5024 n mi

Contract FPC Number Ships/ Estimated Investment (S106) EstimatedExpected volume status Shipyard/ price ($)

operational Bcf/yr (as of Capacity m3 / - Receiving - delivered intodate (MMcfd) 9/1/77) Tank design Tankers terminal pipeline/MMBtu

12125,000 m3, 2,000 457 —

1982-83 365 Pending shipyard &(1 000) tank design

not known

— — — . . ————.

Storage capacity Regasification Type of storage Number of Terminal(MMcf) capacity ( MMcfd) containers storage tanks— acreage

4168 — Aboveground 3— Source OTA


ate of Pacific Lighting Company, but no con-struction has started.74

8. The “El Paso--Alaskan’’ Project(figure 31)

This project is one of the proposed transpor-tation systems to deliver gas from the majorAlaskan North Slope fields to the lower 48States. While the other systems involve gaspipelines through Canada, this project pro-poses a gas pipeline from the North Slopealong the present oi l pipel ine route tosouthern Alaska, A liquefaction facility wouldbe built at Gravina Point, Alaska, and an ini-tial fleet of eight 165,000 cubic meter LNG

74 Feder a 1 power c Ommission, ~ecom mendatzon t.the President Alaskan Natural GUS TransportationSystems (Washington, D. C.: Federal Power Commis-sion, May 1, 1977).

9 6 - 5 9 7 0 - 7 7 - 4

751 bid,


Figure 31.Project Data Sheet: El Paso-AlaskaLNG Source: Gravina Point, Alaska’LNG Terminal: Oxnard, Ca. and/or Point Conception, Ca.

LocationCompanies revolved of u s Project

(project status) terminals designation

Liquefaction plant budder O x n a r d ,and sh ipper E l Paso CaAlaska Co and for

PROPOSED LNG SOURCE AND TERMINAL CHARACTERISTICS 1 via pipeline from the North Slope

Location

Terminals Oxnard, Ca.

Point Conception, Ca.

Source Gravina Point, Ak.

Iiuefactlon or I2 Not the ultimate (combined) terminal , which

Storaqe capacity reqasification Type of storaqe Number of Terminal I will have an estimated cost of $460 million(MMcf) capacity (MMcfd) containers - storage tanks acreage I

7700 4600 Aboveground9% nickel



Under the Alaska Natural Gas Transporta-tion Act of 1976, the President is required torecommend to Congress on the selection of thebest transportation system and Congress willthen have 60 days to review this recommenda-

4 38-55(210 acresite)

4 1000 acres

4Source OTA

tion. The President’s recommendation wasannounced in favor of a trans-Canada gaspipeline on September 8, 1977, but formalrecommendation had not yet been made toCongress at this printing.

9/25/12 Liquefied Natural Gas | Energy Sector

1/3www.nrcan.gc.ca/energy/sources/natural-gas/1608

Liquefied Natural Gas

What is LNG?LNG in North AmericaLNG Supply ChainWhere Does LNG Come From?Where is LNG Delivered?Canadian LNG Import & Export Projects UpdateReports

What is LNG?

LNG is simply natural gas in its liquid state. When natural gas is chilled to a temperature of aboutminus 160° C (minus 260° F) at atmospheric pressure, it becomes a clear, colourless and odourlessliquid.

LNG is non-corrosive and non-toxic. The liquefaction process removes water, oxygen, carbon dioxideand sulfur compounds contained in the natural gas. This results in an LNG composition of mostlymethane with small amounts of other hydrocarbons and nitrogen.

As a liquid, natural gas is reduced to 1/600th of its original volume. This makes it feasible andeconomical to transport over long distances in specially designed ocean tankers. Once received, theLNG goes into storage tanks, is re-gasified, and delivered to markets.

LNG in North America

LNG has been a source of energy in the United States since the 1960s and is available from bothdomestic and foreign sources of natural gas. Domestic LNG is produced, liquefied and stored in NorthAmerica. Marine, or imported LNG, is foreign-produced natural gas, which is liquefied abroad andtransported to North America via ocean tankers.

North America accounts for a relatively small portion of worldwide LNG demand, as it is largely self-sufficient in terms of natural gas production. In 2009, Canada received its first ever shipment ofLNG, while the United States accounted for less than 5 percent of global LNG imports.

Table 1 – Existing North American LNG Import and Export Facilities (2010)

Country Import Export

Canada 1 0

United States 11 1

Source: U.S. Energy Information Administration, National Energy Board

Although LNG remains an important source of supply for the North American natural gas market, itsrole in North America’s energy future remains uncertain. In the early 2000's, optimistic projectionsabout future LNG demand spurred an investment boom to build new import facilities.

However, many LNG import terminal projects in North America have recently been delayed orcancelled on account of the following:

1. Low natural gas prices,2. Weak industrial demand, and

Natural Resources Canada



3. Massive U.S. shale gas production.

Canada currently has one operating LNG import facility, the Canaport terminal in Saint John, NewBrunswick. Kitimat LNG also has a proposal for a LNG export facility in the Port of Kitimat, B.C. (Consult the Canadian LNG Import and Export Projects Update for more information on the status ofCanadian projects).

Despite the current economic downturn, energy demand is expected to increase over the long-termand global LNG production is also expected to grow.

LNG Supply Chain

The LNG supply chain (as illustrated in the figure below) consists of several interconnectedelements.

In LNG exporting countries, natural gas is extracted from basins and transported by pipeline toliquefaction plants. There, the natural gas is liquefied and stored.

Liquefaction plants are built at marine terminals so the LNG can be loaded onto special tankers fortransport overseas. After tankers deliver the LNG cargo to import terminals, the LNG is stored, re-gasified and injected into pipeline systems for delivery to end users.

Where Does LNG Come From?

World natural gas reserves are abundant. However, much of this natural gas is considered“stranded” as it is located in regions distant from consuming markets (e.g. Russia and Qatar).

Liquefying natural gas and shipping it overseas provides an opportunity for these regions toeconomically develop their natural gas reserves.

18 countries currently produce and ship LNG:

AlgeriaAustraliaBruneiEgyptEquatorial GuineaIndonesiaLibyaMalaysiaNigeriaNorwayOmanPeruQatarRussiaTrinidad and TobagoUnited Arab Emirates



The United States*Yemen

* Since the 1970s, small quantities of LNG have been produced in Alaska by Kenai LNG (located inCook Inlet) for export to Japan

Where is LNG Delivered?

At present, 19 countries import LNG:

ArgentinaBelgiumCanadaChinaDominican RepublicFranceGreeceIndiaItalyJapanMexicoPortugalPuerto RicoSouth KoreaSpainTaiwanTurkeyThe U.K.The United States

In general, the countries listed above import LNG for one of two reasons:

1) Domestic supplies of natural gas are not readily available, or2) Demand for natural gas exceeds what can be produced domestically.

Canadian LNG Import and Export Projects Update

For up to date information on the status of Canadian LNG import and export projects, please consultthe Canadian LNG Import and Export Projects Update

Reports

The reports below provide additional information on LNG.

Liquefied Natural Gas: Properties and ReliabilityLiquefied Natural Gas Regulatory Requirements

Date Modified: 2011-02-24

9/25/12 LNG - Liquefied Natural Gas: Import Export

1/3geology.com/articles/lng-liquefied-natural-gas/

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Home » Oil and Gas » What is LNG?

What is LNG - Liquefied Natural Gas?An efficient way to transport natural gas where pipelines are not available

Cartoon of LNG liquefaction and regasification terminals. At the liquefaction terminal (left) natural gas is received by pipeline from a wellfield, liquefied, stored and loaded onto LNG carrier ships. At the regasification terminal (right) LNG is offloaded into storage tanks, regasifiedand placed into storage. It is then compressed and sent into a pipeline distribution system that delivers natural gas to end-use consumers.

What is LNG?

LNG or liquefied natural gas is natural gas that has been temporarilyconverted into a liquid. This is done to save space - 610 cubic feet ofnatural gas can be converted into a single cubic foot of LNG.Converting natural gas into LNG makes it easier to store and easierto transport where pipelines are not available.

A refrigeration process is used to condense natural gas into LNG bycooling it to a temperature of minus 260 degrees Fahrenheit. Thisrefrigeration process is usually accompanied by treatments thatremove water, carbon dioxide, hydrogen sulfide and other impurities.

To maintain this low temperature during storage and transport, LNGmust be placed into cryogenic tanks - heavily insulated tanksequipped with refrigeration units.

When a shipment of LNG reaches its destination or when LNG isbeing removed from storage it must be regasified. This is done byheating the LNG and allowing it to evaporate back into natural gas.Regasification is usually done at a facility where the gas can beplaced into storage or directly into a pipeline for transport.

Liquefaction and Regasification Terminals

There are two types of LNG terminals: 1) terminals that convertnatural gas into LNG, and, 2) terminals that convert LNG back into

natural gas. These are called liquefaction terminals andregasification terminals, respectively. Liquefaction terminals are onthe export side of transactions and regasification terminals are on theimport side of transactions.

Liquefaction terminals generally receive natural gas by pipeline froma well field. Before it is liquefied the gas must be cleaned of water,carbon doixoide, hydrogen sulfide and other impurities that mightfreeze, become corrosive or interfere with the liquefaction process.Once liquefied the LNG is sent by pipeline to a LNG carrier ship orinto storage to await transport.

Regasification terminals receive natural gas - usually by ship - fromother areas. At a regasification terminal the LNG might be temporarilystored or sent directly to a regasification plant. Once regasified it issent by pipeline for distribution or placed in temporary storage until itis needed.

The Changing Role of LNG in the United States

As recently as 2008, demand for natural gas in the United Statesgreatly exceeded domestic supplies. To meet demand, a largeamount of natural gas was imported by pipeline from Canada andseveral terminals to receive liquefied natural gas from Africa, South

An LNG carrier docked at the Bontang LNG liquefaction terminal in East

Kalimantan, Indonesia. The LNG is carried in the ship's four dome-shaped

tanks. Image © Mayumi Terao, iStockphoto.

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Regasification Terminal: Fos-sur-Mer, France



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several terminals to receive liquefied natural gas from Africa, SouthAmerica and the Middle East were built or planned on the easternand Gulf coasts of the United States. Construction costs for each ofthese terminals was billions of dollars.

Then, the use of hydraulic fracturing and horizontal drilling causedan enormous surge in the production of domestic natural gas. Aflood of new production from shale plays such as the Marcellus,Haynesville, Fayetteville, Barnett and others overwhelmed themarket. Domestic natural gas prices fell from over ten dollars perthousand cubic feet down to below two dollars. The terminals builtto receive the liquefied natural gas are now underutilized or idle.

Now, several companies are working to convert the LNG importterminals into terminals suitable to export gas. Their goal is tomove the gas to Asian markets where prices are much higher.Although this sounds like a fantastic idea, a tremendous amount ofgas has recently been discovered off Australia, Indonesia andSouthern Asia. These areas have a significant transportationadvantage over shipments leaving the Atlantic or Gulf coast of theUnited States. Converting the US import terminals into exportfacilities is a gamble without long-term contracts.

Liquefied natural gas is a very dynamic business and there isalways interesting news about LNG.

Where is LNG Produced?

The world's first large shipmentof liquefied natural gas occurredin 1964 when a ship was loadedwith LNG in Algeria and sailedfor Le Havre, France. Prior to1964, natural gas in Algeria was

a waste product of oil production.It was a "waste product"because there was no localmarket for natural gas and nopipeline to transport the gas to adistant market. The natural gaswas either vented into theatmosphere or flared at the wellsite. This waste of natural gasand degradation of theatmosphere continues todaywhere there is no market,

pipeline or LNG plant to utilize the gas.

Today, LNG is exported from locations such as: Algeria, Egypt,Nigeria, Angola, Oman, Qatar, Yemen, Russia, Trinidad and Tobago,Australia, Malaysia, and Indonesia where natural gas production farexceeds the consumption abilities of local markets. In these locationsthe price of natural gas is low because there is an abundant supplywith little local demand. That low price offsets the expenses ofbuilding an LNG liquefaction plant, converting natural gas into LNGand transporting it to a distant market.

Where is LNG Received?

Japan, South Korea and Taiwan were the first major buyers of LNG.These areas have very high populations and very little access todomestic fossil fuel resources. LNG gave them access to a clean-burning fuel that was easy to distribute once pipelines were in place.Many other countries now have regasification terminals. Theseinclude: Belgium, Brazil, Canada, Chile, China, France, India, Italy,Greece, Mexico, Spain, UK and the United States.

How is LNG Stored?

LNG is stored in heavily insulated storage tanks that are speciallydesigned to hold a cold-temperature liquid. Most tanks are double-wall with an outer wall of thick concrete and an inner wall of highquality steel. Between the walls is a thick layer of highly efficientinsulation. Many facilities have underground storage tanks forincreased insulation.

No matter how well the tanks are insulated some LNG will boil off andevaporate as natural gas. This gas is generally removed from thetank. It is either used on-site as a fuel or refrigerated back to the liquidstate and returned to the tank.

©2012 Google -

Imagery ©2012 Cnes/Spot Image, DigitalGlobe, GeoEye, IGN-France,

Google Map of the Gaz de France LNG regasif ication terminal located at

Fos-sur-Mer, France. View Larger Map

Existing LNG terminals in the United States as of June, 2010. Kenai, Alaska

w as the only liquefaction terminal built for export use. The rest are

regasif ication terminals built for import use. In April, 2012 the Federal

government approved a plan to convert the Sabine, Louisiana terminal to a

liquefaction facility for exporting United States natural gas to Asian

markets. Image after the Federal Energy Regulatory Commission.

LNG in the News

Exporting Russian Natural Gas to Japan: Russia and Japanhave an agreement to build...

China & Singapore Investing $1B in Cheniere LNG?: CheniereEnergy Partners may have two new major...

More Debate on Exporting Natural Gas: An article in BloombergBusinessweek explores many arguments...

Debate: Export LNG?: Several companies have applied forpermission to export...

Hawaii as a Natural Gas Customer?: Hawaii imports all of itsfossil fuels, however,...

LNG from East Africa?: Several big natural gas discoveries in theIndian...

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How is LNG Transported?

Most LNG is transported in specially designed ships known as "LNGcarriers". These ships have double hulls to protect the cargo fromdamage and as a safeguard against leaks. Smaller quantities of LNGare transported in specially designed trucks and railcars.

Environmental Impact of LNG

Natural gas has a much lower environmental impact when it isburned than other fossil fuels. It emits less carbon dioxide, lessparticulate matter and produces less ash. Although LNG is burned inthe form of natural gas it has a greater environmental impact thannatural gas that has not been liquefied. This is because LNGrequires an expenditure of energy to liquefy, transport and regasify.

After these impacts are considered, LNG has a greater environmentalimpact than natural gas but generally has a lower impact thanburning coal or oil. If one considers that the LNG might have beenflared at the source as a waste product the environmental impact islowered.

Public Support and Opposition to LNG Terminals

Public support for LNG projects is generally mixed - especially on theimport side where large numbers of people may be located near theregasification facility. Although some people hope that LNG will bringthem a reliable source of economical natural gas, others haveconcerns that the regasification plant or the transport vehicles mightexplode or catch fire. Some people are also concerned that LNGfacilities are terrorist targets. Although LNG has an excellent history ofsafety, these concerns can not be assigned a probability of zero.

The Geography of Natural Gas

The geography of natural gas is constantly changing. New naturalgas discoveries, new pipelines and new LNG terminals can boostlocal supplies. An increase in local supply can lower prices which canstimulate demand. Growing demand can raise prices, stimulatedrilling activity, launch pipeline projects and attract investments inLNG facilities. The geography of natural gas is dynamic.

Contributor: Hobart King

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LNG Daily is essential reading as LNG supply dynamics continue tochange in big markets like Japan, China, India and the U.S. Thispremier independent news publication for the global LNG industrygives readers information on every aspect of the global market fromnew LNG supply projects to gas quality issues.

Features

LNG Daily gives you the edge by providing:

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and plants

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terminals

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Reports and news on shipping

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Review of supply/demand fundamentals

Monitoring of the impact of competitive fuels

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Congressional proceeding reports

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Liquified Natural Gas (LNG)

For even more information on LNG, check out the Center for LNG.

Cooling natural gas to about -260°F at normal pressure results in the condensation of the gas intoliquid form, known as Liquefied Natural Gas (LNG). LNG can be very useful, particularly for thetransportation of natural gas, since LNG takes up about one six hundredth the volume of gaseousnatural gas. While LNG is reasonably costly to produce, advances in technology are reducing thecosts associated with the liquification and regasification of LNG. Because it is easy to transport,LNG can serve to make economical those stranded natural gas deposits for which the constructionof pipelines is uneconomical.

LNG, when vaporized to gaseous form, will only burn inconcentrations of between 5 and 15 percent mixed with air. Inaddition, LNG, or any vapor associated with LNG, will notexplode in an unconfined environment. Thus, in the unlikelyevent of an LNG spill, the natural gas has little chance ofigniting an explosion. Liquification also has the advantage ofremoving oxygen, carbon dioxide, sulfur, and water from thenatural gas, resulting in LNG that is almost pure methane.

LNG is typically transported by specialized tanker withinsulated walls, and is kept in liquid form by autorefrigeration,a process in which the LNG is kept at its boiling point, so thatany heat additions are countered by the energy lost from LNGvapor that is vented out of storage and used to power thevessel.

The use of LNG allows for the production and marketing ofnatural gas deposits that were previously economicallyunrecoverable. Imported LNG accounts for slightly more than 1percent of natural gas used in the United States. According to

the EIA, the U.S. imported 0.41 Tcf of natural gas in the form of LNG in 2010. However, due toincreased domestic production, LNG imports are expected to decrease by an average annual rate of4.1 percent, to levels of 0.14 Tcf of natural gas by 2035.

Liquefied natural gas (LNG) imports represent an important part of the natural gas supply picture inthe United States. LNG takes up much less space than gaseous natural gas, allowing it to beshipped much more efficiently.

LNG that is imported to the United States comes via ocean tanker. The U.S. gets a majority of itsLNG from Trinidad and Tobago, Qatar, and Algeria, and also receives shipments from Nigeria, Oman,Australia, Indonesia, and the United Arab Emirates.

For more information:

The Center for LNGFederal Energy Regulatory Commission: LNGInterstate Natural Gas Association of America - LNGUniversity of Houston: Commercial Frameworks for LNG in North America, Introduction toLNGCenter for Energy Economics/UT-Austin: LNG Safety and Security

2/2www.naturalgas.org/lng/lng.asp

Center for Energy Economics/UT-Austin: LNG Safety and SecurityPlatts Guide to LNGLNG Safety VideoU.S. LNG Markets and UsesLNG One WorldCalifornia Energy Commission: LNGInternational Liquefied Natural Gas AllianceAdventures in Energy

Overview of Natural Gas | Natural Gas - From the Wellhead... | Business Overview | Natural Gas Regulations | Environment & Technology | Focus on LNG

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