LNG - What Is It [PDF]

Zitiervorschau

RESOURCE FILES

About LNG

(Liquified Natural Gas) From the campaign to prevent LNG terminals in Passamaquoddy Bay Documents and references used to explain LNG

Compiled by Arthur MacKay Bocabec, NB, Canada September, 2012 Joyce Morrell cover graphic

RESOURCE FILES

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 specified 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.

LNG (Liquified Natural Gas) 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 noncorrosive. Hazards include flammability, freezing and asphyxia. The liquefaction process involves removal of certain components, such as dust, acid gases, helium, water, and heavy hydrocarbons, which could cause difficulty downstream. The natural gas is then condensed into a liquid at close to atmospheric pressure (maximum transport pressure set at around 25 kPa/3.6 psi) by cooling it to approximately −162 °C (−260 °F). LNG achieves a higher reduction in volume than compressed natural gas (CNG) so that the energy density of 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 carriers) or cryogenic road tankers are used for its transport. LNG is principally used for transporting natural ga s 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 production 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 savepassamaquoddybay.org have and will contribute to this. If you have information or a question, please send it to artmackay@ scep.org 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 economic 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 immediate 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 usually 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 savepassamaquoddybay.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 moving 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 something like, “based on current information”. Times have changed and the Americans have been testing our sovereignty 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. SECURITY See 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 sovereignty issue. Who pays for the escorts? If there are two terminals in here we will have a constant stream of tankers 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 numerous 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 severe 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 regassified 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 devastate 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 Developers 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. ***************************************************************************************** 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 areas, 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 annually and provide more than 5,000 jobs. Tourism is worth $340 million and supports thousands of jobs. Interruptions can result in downtime for commercial and tourism operations ranging from 30%-100% depending on number of tankers and weather conditions. 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 increasingly 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 conservation of marine resources, the prevention of infringement on fisheries laws, and the preservation of the environment of the coastal state. Escorts LNG tankers approaching American terminals are escorted by armed Coast Guard cutters, which would continue 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-established 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

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Liquefied natural gas - Wikipedia, the free encyclopedia

Liquefied natural gas From 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 certain components, such as dust, acid gases, helium, water, and heavy hydrocarbons, which could cause difficulty downstream. The natural gas is then condensed into a liquid at close to atmospheric pressure (maximum transport pressure set at around 25 kPa/3.6 psi) by cooling it to approximately −162 °C (−260 °F). LNG achieves a higher reduction in volume than compressed natural gas (CNG) so that the energy density of 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 carriers) 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 production and the need to store it in expensive cryogenic tanks have hindered widespread commercial use. The Economist Intelligence Unit brought out a report in August 2012 entitled "Tankers on the horizon: Australia’s coming LNG boom" on the dominant trends in the development of Australia's gas resources and details the LNG projects that will unlock these resources for export to markets in Asia. Download the complimentary report (http://www.eiu.com/public/topical_report.aspx? campaignid=AusGas2012) .

Contents

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.

1 Energy density and other physical properties 2 Production en.wikipedia.org/wiki/Liquefied_natural_gas#Safety_and_accidents

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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 parity 5.2 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 Storage 7.2 Transportation 7.2.1 Terminals 7.3 Refrigeration 8 Environmental concerns 8.1 Safety and accidents 9 See also 10 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. The higher 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 times greater than that of CNG which makes it economical to transport natural gas by ship in the form of LNG. The energy 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 en.wikipedia.org/wiki/Liquefied_natural_gas#Safety_and_accidents

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components that will freeze (e.g., benzene) under the low temperatures needed for storage or be destructive to the liquefaction 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 almost 100% 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 one or more LNG trains, each of which is an independent unit for gas liquefaction. The largest LNG train now in operation 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 a capacity of 5 mmtpa. The Qatargas II plant has a production capacity of 7.8 mmtpa for each of its two trains. LNG is loaded onto ships and delivered to a regasification terminal, where the LNG is allowed to expand and reconvert into gas. Regasification terminals are usually connected to a storage and pipeline distribution network to distribute natural 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 Qatargas II

Location Ras Laffan

Country

Startup Date

Capacity (mmtpa)

Corporation

Qatar

2009

7.8

Arzew GL4Z

Algeria

1964

0.90

Arzew GL1Z

Algeria

1978

Arzew GL1Z

Algeria

1997

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

Point Fortin

Trinidad and Tobago

1999

Point Fortin

Trinidad and Tobago

2003

9.9

Atlantic LNG

Egypt

2004

5.5

Segas LNG

Damietta

en.wikipedia.org/wiki/Liquefied_natural_gas#Safety_and_accidents

7.9

22.6 Atlantic LNG

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Idku

Egypt

2005

7.2

Bintulu MLNG 1

Malaysia

1983

7.6

Bintulu MLNG 2

Malaysia

1994

7.8

Bintulu MLNG 3

Malaysia

2003

3.4

Nigeria LNG

Nigeria

1999

23.5 16.3

Northwest Shelf Venture

Karratha

Australia

2009

Withnell Bay

Karratha

Australia

1989

Withnell Bay

Karratha

Australia

1995

(7.7)

Russia

2009

9.6.[7]

Sakhalin II Yemen LNG

Balhaf

Yemen

2008

6.7

Tangguh LNG Project

Pappua Barat

Indonesia

2009

6.7

Qatargas I

Ras Laffan

Qatar

1996

(4.0)

Qatargas I

Ras Laffan

Qatar

2005

10.0

Qatar

2010

7.8

Qatar

1999

6.6

Qalhat

Oman

2000

7.3

Das Island I

United Arab Emirates

1977

Das Island I and II

United Arab Emirates

1994

5.7

TOTAL

WORLD

1990

50[8]

TOTAL

WORLD

2002

130[9]

TOTAL

WORLD

2007

160[8]

Qatargas III Rasgas I and II

Ras Laffan

As most LNG plants are located in "stranded" areas not served by pipelines and the costs of LNG treatment and transportation are huge, development was slow during the second half of the last century. The construction of an LNG plant costs at least $1.5 billion per 1 mmtpa capacity, a receiving terminal costs $1 billion per 1 bcf/day throughput 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, the prices for construction of LNG plants, receiving terminals and vessels have fallen, making LNG a more competitive means of energy distribution, but increasing material costs and demand for construction contractors have driven up prices in the last few years. The standard price for a 125,000 cubic meter LNG vessel built in European and Japanese shipyards used to be USD 250 million. When Korean and Chinese shipyards entered the race, increased competition reduced profit margins and improved efficiency, costs were reduced by 60%. Costs in US dollar terms also declined due to the devaluation of the currencies of the world's largest shipbuilders, Japanese yen and Korean en.wikipedia.org/wiki/Liquefied_natural_gas#Safety_and_accidents

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won. Since 2004, ship costs have increased due to a large number of orders which have increased demand for shipyard slots. The per-ton construction cost of an LNG liquefaction plant fell steadily from the 1970s through the 1990s. 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 building liquefaction and regasification terminals has doubled. Due to energy shortage concerns, many new LNG terminals are being contemplated in the United States. Concerns over the safety of such facilities has created extensive controversy in the regions where plans have been created to build 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 on the New York side. Local politicians including the Suffolk County Executive have raised questions about the terminal. 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 of resistance and questions. The commercial development of LNG is a style called value chain, which means LNG suppliers first confirm sales to the downstream buyers and then sign 20–25 year contracts with strict terms and structures for gas pricing. Only when the customers are confirmed and the development of a greenfield project deemed economically feasible could the sponsors of an LNG project invest in their development and operation. Thus, the LNG liquefaction business has been regarded as a game of the rich, where only players with strong financial and political resources could get involved. 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 by signing a sale and purchase agreement (SPA) between a supplier and receiving terminal, and by signing a gas sale agreement (GSA) between a receiving terminal and end-users. Most of the contract terms used to be DES or ex ship, holding the seller responsible for the transport of the gas. With low shipbuilding costs, and the buyers preferring to ensure reliable and stable supply, however, contract with the term of FOB increased. Under such term, the buyer, who often owns a vessel or signs a long-term charter agreement with independent carriers, is responsible for the transport. LNG purchasing agreements used to be for a long term with relatively little flexibility both in price and volume. If the annual contract quantity is confirmed, the buyer is obliged to take and pay for the product, or pay for it even if not taken, 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 flexibilities on volume and price. The buyers had more upward and downward flexibilities in TOP, and short-term SPAs less than 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 more sophisticated 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. Russia and Qatar, countries with the largest and the third largest natural gas reserves in the world, have finally supported such move.[citation needed] en.wikipedia.org/wiki/Liquefied_natural_gas#Safety_and_accidents

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Until 2003, LNG prices have closely followed oil prices. Since then, LNG prices in Europe and Japan have been lower 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 has increased 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 gasfired combined cycle generating units for electric power generation, coupled with the inability of North American and 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 biggest LNG exporters in 2007 were Qatar (28 MT), Malaysia (22 MT) and Indonesia (20 MT) and the three biggest LNG 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 to be increased to about 200 MT in 2009 and about 300 MT in 2012. During next several years there would be significant increase in volume of LNG Trade and only within next three years; about 82 MTPA of new LNG supply will come to the market. For example just in 2009, about 59 MTPA of new LNG supply from 6 new plants comes to 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 en.wikipedia.org/wiki/Liquefied_natural_gas#Safety_and_accidents

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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 a heat equivalent basis), of which LNG forms a small but rapidly growing part. Much of this growth is driven by the need for clean fuel and some substitution effect due to the high price of oil (primarily in the heating and electricity generation 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 world that 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, Spain imported 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 to sharing the profits from such a diversion. In some jurisdictions such as in the European Union, it is not permitted to apply 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 reducing costs. 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 increased from 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 decline in construction cost of LNG plants, however the extent of such a decline is still unclear. en.wikipedia.org/wiki/Liquefied_natural_gas#Safety_and_accidents

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Small-scale liquefaction plants Small-scale liquefaction plants are advantageous because their compact size enables the production of LNG close to the location where it will be used. This proximity decreases transportation and LNG product costs for consumers. The small-scale LNG plant also allows localized peakshaving to occur – balancing the availability of natural 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 various non-oil factors, but usually a constant determined by negotiation at a level which can prevent LNG prices from falling 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 LNG price exceeds the price of crude oil in BOE terms, then the situation is called broken oil parity. A coefficient of 0.1724 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, to dampen 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 called the Japan Crude Cocktail (JCC). In Indonesian LNG contracts, price formula is linked to Indonesian Crude Price (ICP). en.wikipedia.org/wiki/Liquefied_natural_gas#Safety_and_accidents

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

Price review Usually there exists a clause allowing parties to trigger the price revision or price reopening in LNGSPAs. In some contracts there are two options for triggering a price revision. regular and special. Regular ones are the dates that will 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 the agreed specifications in the sale and purchase agreement is regarded as “off-specification” (off-spec) or “offquality” 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, CO 2 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 pay liquidated 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 the sensitivity of liquefaction facilities to sulfur and mercury elements, the gas being sent to the liquefaction process shall be accurately refined and tested in order to assure the minimum possible concentration of these two elements before 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 en.wikipedia.org/wiki/Liquefied_natural_gas#Safety_and_accidents

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1,160 Btu/scf. There are some methods to modify the heating value of produced LNG to the desired level. For the purpose of increasing 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 a solutions; however all of these solutions while theorically viable can be costly and logistically difficult to manage in large scale.

Liquefaction technology Currently there are 4 Liquefaction processes available: 1. 2. 3. 4.

C3MR (sometimes referred to as APCI): designed by Air Products & Chemicals, Incorporation. Cascade: designed by ConocoPhillips. Shell DMR Linde

It is expected that by the end of 2012, there will be 100 liquefaction trains on stream with total capacity of 297.2 MMTPA. The majority of these trains use either APCI or Cascade technology for the liquefaction process. The other processes, used in a small minority of some liquefaction plants, include Shell's DMR technology and the Linde technology. 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 or under-construction, 86 trains, with a total capacity of 243 MMTPA have been designed based on the APCI process: the second most used is the Philips Cascade process which is used in 10 trains with a total capacity of 36.16 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 and transfer 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 has a prestressed concrete outer wall and a high-nickel steel inner tank, with extremely efficient insulation between the walls. Large tanks are low aspect ratio (height to width) and cylindrical in design with a domed steel or concrete roof. Storage pressure in these tanks is very low, less than 10 kPa (1.45 psig). Sometimes more expensive underground tanks are used 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 less than 50 kPa to over 1,700 kPa (7 psig to 250 psig).

LNG storage tank at EG LNG

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be some heat leakage into the LNG, resulting in vapourisation of the LNG. This boil-off gas acts to keep the LNG cold. 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 hulls protecting the cargo systems from damage or leaks. There are several special 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]

Tanker LNG Rivers, LNG capacity of 135,000 cubic metres

Transportation and supply is an important aspect of the gas business, since natural gas reserves are normally quite distant from consumer markets. Natural gas has far more volume than oil to transport, and most gas is transported by pipelines. There is a natural 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 can transmit only about a fifth of the amount of energy per day due to the lower density. Natural gas is usually liquefied to 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. Longer pipelines, 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. LNG will be sometimes taken to cryogenic temperatures to increase the tanker capacity. The first commercial ship-toship transfer (STS) transfers were undertaken in February 2007 at the Flotta facility in Scapa Flow[30] with 132,000 m³ of LNG being passed between the vessels Excalibur and Excelsior. Transfers have also been carried out by Exmar Shipmanagement, the Belgian gas tanker owner in the Gulf of Mexico, which involved the transfer of LNG from a conventional LNG carrier to an LNG regasification vessel (LNGRV). Prior to this commercial exercise 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, LNG terminals 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 and vapourise the LNG. Industry practice is to store LNG as a boiling cryogen. That is, the liquid is stored at its boiling point for the pressure at which it is stored (atmospheric pressure). As the vapour boils off, heat for the phase change cools the remaining liquid. Because the insulation is very efficient, only a relatively small amount of boil off is necessary to maintain temperature. This phenomenon is also called auto-refrigeration. en.wikipedia.org/wiki/Liquefied_natural_gas#Safety_and_accidents

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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 in extraction (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 asthma and 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 in the order of 1.2 million tonnes equivalent carbon dioxide of direct emissions. The greenhouse gas emissions associated with the combustion of 4.5 million tonnes of LNG is approximately 12 million tonnes equivalent carbon dioxide. 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 of an 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 not consider the life cycle emissions of natural gas production, which include significant carbon dioxide emissions from gas compression and transport. On a per kilometer transported basis, LNG carbon dioxide emissions are lower than piped natural gas emissions. Natural gas could be considered the most environmentally friendly fossil fuel, because it has the lowest CO 2 emissions per unit of energy and because it is suitable for use in high efficiency combined cycle power stations. On a per kilometre transported basis, emissions from LNG are lower than piped natural gas, which is a particular issue in Europe, where significant amounts of gas are piped several thousand kilometres from Russia. However, emissions from natural gas transported as LNG are higher than for natural gas produced locally to the point of combustion as emissions associated with transport are lower.

Safety and accidents Natural gas is a fuel and a combustible substance. To ensure safe and reliable 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 to burn, 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 a leak, LNG vaporizes rapidly, turning into a gas (methane plus trace gases), and mixing with air. If this mixture is within the flammable range, there is risk of ignition which would create fire and thermal radiation hazards. en.wikipedia.org/wiki/Liquefied_natural_gas#Safety_and_accidents

Green bordered white diamond symbol used on LNG-powered vehicles in China

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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 gas Liquefied 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 Diesel Engine 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 (NHST Media 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 en.wikipedia.org/wiki/Liquefied_natural_gas#Safety_and_accidents

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8. 9.

10. 11.

12. 13. 14. 15.

16. 17. 18. 19. 20. 21. 22.

23. 24. 25. 26. 27.

28. 29.

30. 31. 32. 33. 34. 35. 36.

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. ^ a b http://www.lngpedia.com/wp-content/uploads/2009/01/lng-exports-by-country-1982-20072.jpg ^ "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. ^ Long Island Business News, 2005 (http://www.allbusiness.com/legal/laws-government-regulationsenvironmental/917040-1.html) ^ "Indian core sector growth slows down in April 2012" (http://www.engineeringfromindia.com/indian-coresector-growth-slows-down-in-april/) . www.engineeringfromindia.com. http://www.engineeringfromindia.com/indian-core-sector-growth-slows-down-in-april/. ^ [2] (http://www.economist.com/node/21558456) ^ [3] (http://www.economist.com/node/21558456) ^ The role of LNG in a global gas market (http://wwwstatic.shell.com/static/media/downloads/speeches/lcook_speech_oilandmoneyconf.pdf) ^ 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/CEC200-2007-017/CEC-200-2007-017.PDF) ^ World Gas Intelligence, May 6, 2009, Page 8 ^ [4] (http://www.economist.com/node/21558456) ^ [5] (http://www.economist.com/node/21558456) ^ [6] (http://www.economist.com/node/21558456) ^ [7] (http://www.economist.com/node/21558456) ^ https://inlportal.inl.gov/portal/server.pt/document/43128/liquefied_natural_gas_plant_4_pdf_%282%29 ^ 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. ^ http://www.walterenergy.info/mainframe.php?page=gas&level=9 ^ a b LNG Quality and Market Flexibility Challenges and Solutions Com.qa (http://www.lng14.com.qa/lng14.nsf/attach/$file/PS3-1.ppt) ^ http://www.platts.com/weblog/oilblog/2011/03/31/shell_australia.html ^ http://www.ft.com/cms/s/0/9ccaed4a-82ba-11e0-b97c-00144feabdc0.html#axzz1NADgzzOH ^ "LNG Carrier Leak Test Completed Outside Korea" (http://www.oilandgasonline.com/article.mvc/LNG-CarrierLeak-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. ^ [8] (http://www.economist.com/node/21558456) ^ 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. ^ http://www.orkneyharbours.com/ship_to_ship_transfers.asp ^ LNGpollutes.org (http://www.lngpollutes.org/article.php?list=type&type=12) Ratepayers for Affordable Clean Energy: LNG and Climate Change ^ LNGpollutes.org (http://www.lngpollutes.org/article.php?list=type&type=13) Ratepayers for Affordable Clean Energy: LNG and Your Health ^ LNGpollutes (http://www.lngpollutes.org/article.php?list=type&type=13) Ratepayers for Affordable Clean Energy: LNG and Your Health ^ LNGpollutes (http://www.lngpollutes.org/article.php?list=type&type=4) Excerpt from "Collision Course: How Imported Liquefied Natural Gas Will Undermine Energy in California" by Rory Cox and Robert Freehling ^ Pacific Environment : California Energy Program (http://www.pacificenvironment.org/article.php? list=type&type=21) ^ Ratepayers for Affordable Clean Energy : Search (http://www.lngwatch.com/race/truth.htm)

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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 Retrieved from "http://en.wikipedia.org/w/index.php?title=Liquefied_natural_gas&oldid=509211954" Categories: Liquefied natural gas Fuel gas Natural gas Petroleum production This page was last modified on 26 August 2012 at 08:10. Text is available under the Creative Commons Attribution-ShareAlike License; additional terms may apply. en.wikipedia.org/wiki/Liquefied_natural_gas#Safety_and_accidents

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Section 1: Characteristics of a Generic LNG Project for the Passamaquoddy Bay Region (DRAFT) Table of Contents Summary of a Generic LNG Facility...................................................................................2 Potential Locations of Generic LNG Terminal....................................................................2 Footprint...............................................................................................................................3 Throughput/Sendout Capacity.............................................................................................3 Pipeline................................................................................................................................3 Shipping Route.....................................................................................................................5 LNG Transport by Truck.....................................................................................................6 LNG Vessels........................................................................................................................6 Number of Vessel Transits per Year....................................................................................6 Employment & Spending.....................................................................................................7 Construction Phase...........................................................................................................7 Operation Phase...............................................................................................................7 Employment at Sea .........................................................................................................7 Tax Revenues...................................................................................................................7 Traffic..................................................................................................................................7 List of Figures Figure 1: Potential Locations of LNG Facilities (attached) Figure 2: Exclusion Zones for LNG Storage Tanks Figure 3: Potential Natural Gas Pipeline Routes (attached) Figure 4: Shipping Lane for LNG Vessels from the South Figures 5-9: Navigation Waypoints for LNG Vessel (attached)

List of Tables Table 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

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Summary of a Generic LNG Facility A 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 LNG facility showing storage tank, pier, and LNG vessel. 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 Terminal Based 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.

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

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Footprint Federal guidelines require that all LNG facilities Exclusion Zone have exclusion zones around the LNG storage (1000 ft radius) 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 100 ft zone. As a result, there is often a minimum parcel size on which a facility can legally exist. LNG Storage Tanks 100 ft 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 Figure 2: Exclusion Zones for LNG Storage Tanks 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 Capacity The 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).

Pipeline In 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). _____________________________________________________________________ Yellow Wood Associates, Inc., 228 North Main St., St. Albans, VT 05478, 802-524-6141

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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-ofway, 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-ofway 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

A B C D E

Segment Name

Pleasant Point - Mill Cove Mill Cove - NMP Mill Cove - NMP Mill Cove - NMP Red Beach - NMP

Length (mi.)

Area of Construction right-of-way (acres)

Area of Permanent right-of-way (acres)

2.8 7.2 5.7 6.7 5.2

25.2 65.3 51.6 60.8 46.9

16.8 43.5 34.4 40.5 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 Yellow Wood Associates, Inc., 228 North Main St., St. Albans, VT 05478, 802-524-6141

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Shipping Route The 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.

Figure 4: Shipping Lane for LNG Vessels from the South

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 500yard 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 _____________________________________________________________________ Yellow Wood Associates, Inc., 228 North Main St., St. Albans, VT 05478, 802-524-6141

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A typical LNG 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 Truck Should 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 Vessels The 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

A typical LNG Vessel

Number of Vessel Transits per Year If 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 131141 ships to deliver 365 BCF per year (365/2.6 or 365/2.8). This would mean that there _____________________________________________________________________ Yellow Wood Associates, Inc., 228 North Main St., St. Albans, VT 05478, 802-524-6141

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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 Phase The 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 Phase Once 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 Revenues The annual tax revenue resulting from this project could be as much as $X.

Traffic For 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

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

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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.pdf iii 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. 21 v http://www.dom.com/about/gas-transmission/covepoint/expansion/pdf/pipeline_safety.pdf vi 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 LNG x http://www.gsenet.org/host/lng-logan/PDF/MAY%203%202004%20COMMENT%20LETTER%20TO%20FERC.pdf xi 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

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FERC: Help - Frequently Asked Questions (FAQs) - LNG

Frequently Asked Questions (FAQs)

CONTACT

LNG

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Office of External Affairs Telephone: 202-502-8004 Toll-free: 1-866-208-3372 Email: [email protected]

FAQS A bout FE RC

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

A c c ounting - M aterial D eviations A c tive P artic ipation/I ntervention in FE RC C as es

LNG properties are: LNG (liquefied natural gas) is natural gas, primarily methane, which has been cooled to its liquid state at -260°F (162.2°C ) Liquefying natural gas reduces the volume it occupies by more than 600 times, making it a practical size for storage and transportation LNG (the liquid itself) is not flammable or explosive LNG vapor (methane) is colorless, odorless and non-toxic. Methane can become an asphyxiant when it displaces the amount of oxygen that humans need for breathing LNG vapor (methane) typically appears as a visible white cloud since its cold temperature causes humidity in the air to condense C old 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 the fuel to become too dilute for ignitionv LNG vapor (methane) is not explosive in an unconfined environment After LNG vapors (methane) become warmer than -160°F (-106.7°C ), they become lighter than air and will rise and disperse rather than collect near the ground Top of page

C itizen I nformation about FE RC C ode of Federal Regulations (C FR) C ommis s ion M eetings C ourt C as es

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LNG

M arket O vers ight

P ower M arketers P ublic Referenc e Room

2. Where does LNG come from?

Q ualifying Fac ilities (Q F)

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

Shoreline M anagement

Top of page T ree T rimming and V egetation M anagement L andowners

3. How is LNG shipped?

Demand Response 2 0 1 2 Survey

LNG is shipped via:

Document s & Filing eFiling & Forms

Specially designed ships are used to transport LNG to U.S. import terminals. The ships can carry LNG over long distances and are constructed of specialized materials and equipped 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 the integrity of the hull system, provides insulation for the LNG and provides protection for the cargo tanks in case of an accident Three basic tank designs have been developed for LNG ship containment and transport: prismatic free-standing, spherical, membrane

eL ibrary

The "International C ode for the C onstruction and Equipment of Ships C arrying Liquefied Gases in Bulk" (Gas Tanker C ode) and C oast Guard regulations require that LNG ships meet a Type IIG standard of subdivision, damage stability, and cargo tank location LNG is also transported via truck. LNG tanker trucks typically carry between 10,000 and 12,000 gallons (38-to-45 m3) of LNG. LNG trucks are used to deliver LNG from its source to remote or satellite peak sharing facilities. LNG trucks are also used with portable vaporizers as a temporary supply of natural gas if normal supplies are interrupted or for peak sharing during abnormal winter conditions

FE RC - 5 6 6

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E lec tric Q uarterly Reports (E Q Rs ) E lec tric Q uarterly Reports (E Q Rs ) Software FERC Forms N o. 5 4 9 D N o. 5 5 2 N o. 5 6 1

FE RC - 5 8 0 Hydrokinet ics H ydrokinetic P rojec ts C onditioned L ic ens e - G eneral C oordination with Federal and State Res ourc e A genc ies and I ndian T ribes N E P A A nalys is and T reatment of Res ourc e A genc y Rec ommendations H ydrokinetic - Rehearings , L ic ens e T rans fers , and O ther P os tL ic ens e I s s uanc e M atters

4. Where do ships unload LNG? Ships unload LNG at specially designed terminals where the LNG is pumped from the ship to insulated storage tanks at the terminal. LNG is also converted back to gas at the terminal, which is connected to natural gas pipelines that transport the gas to where it is needed. Specially designed trucks may also be used to deliver LNG to other storage facilities in different locations. Top of page

5. How is LNG stored? LNG is stored:

www.ferc.gov/help/faqs/lng.asp

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FERC: Help - Frequently Asked Questions (FAQs) - LNG LNG is stored: At more than 100 US facilities, either for use during periods of peak natural gas demand or as a real-time source of natural gas (from marine imports). Most facilities were constructed between 1965 and 1975. In double-walled, insulated tanks, at pressures only slightly higher than atmospheric pressure. The inner tank contains the LNG, while the outer tank contains the insulation and prevents any vapor (methane) from escaping In facilities are required to have a dike or impounding wall capable of containing 110% of the maximum LNG storage capacity. In the unlikely event of a spill, this feature will prevent any LNG from flowing off of the site Storage facilities also use advanced monitoring systems to immediately detect any natural gas leaks or fires at the plant All LNG storage facilities must comply with DOT (Department of Transportation) Title 49 C FR Part 193 - Liquefied Natural Gas Facilities: Federal Safety Standards and NFPA (National Fire Protection Association) 59A - Standard for the Production, Storage and Handling of Liquefied Natural Gas. Please visit our For C itizens LNG Overview page for similar LNG information and photographs. Top of page

6. Why make LNG? C ooling natural gas to -260°F (-162.2°C ) changes it from a vapor into a liquid. This reduces the space natural gas occupies by more than 600 times, making it a practical size for storage and transportation. Top of page

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

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. C old LNG vapor will appear as a white cloud If 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 of the fuel To keep the public safe, vapor dispersion exclusion zones are calculated and plotted to determine how far LNG vapors (methane) could possibly travel from a storage facility and still be flammable. These zones must not reach beyond a property line that can be built upon Fires If LNG is spilled in the presence of an ignition source, a fire will result from the continuous evaporation of the LNG contained within the impoundment Since this fire would burn with intense heat, thermal exclusion zones are also calculated and 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 C FR Part 193 (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 be released rapidly enough to cause the overpressures associated with an explosion LNG vapors (methane) mixed with air are not explosive in an unconfined environment Top of page

Print this page Updated: May 30, 2012

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NEB - Energy Reports - Liquefied Natural Gas - A Canadian Perspective - Energy Market Asssessment

National Energy Board Liquefied Natural Gas - A Canadian Perspective - Energy Market Asssessment Please note that certain documents in this section are available in PDF format. To inquire about receiving these documents in another format, please contact us. If you do not have PDF viewing software, you can download a free PDF viewer from the Adobe® Web site. Please note that this version includes the changes in the Errata, dated 7 April 2009, which has been added to the Adobe Acrobat report. 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 neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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NEB - Energy Reports - Liquefied Natural Gas - A Canadian Perspective - Energy Market Asssessment

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

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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

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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. [*] NO TE: Vie w our m ost re ce nt Strate gic Plan to se e our Purpose , Vision, Goals, Value s and Strate gie s.

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. neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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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 num be r of facilitie s have e x iste d for m any ye ars in Q ue be c, O ntario, and British C olum bia that lique fy pipe line natural gas and store the LNG for late r re gasification and use during pe ak de m and pe riods.

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 neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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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 highlevel 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 inservice 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. neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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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 de scribe d in Appe ndix 5. [4] LNG Safe ty and Se curity, C e nte r for Ene rgy Econom ics (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 re source s conside re d too far from m ark e t to be acce sse d e conom ically by pipe line .

Figure 1.1 - LNG Share of World Natural Gas Market neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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Source : BP Statistical R e vie w of W orld Ene rgy

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 Inte rnational Ene rgy O utlook , Se pte m be r 2008.

Figure 1.2 - Global Natural Gas Consumption and Outlook

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Source : EIA Inte rnational Ene rgy O utlook 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

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Source : BP Statistical R e vie w of W orld Ene rgy

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 neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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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] Include s m ajor consum ing countrie s of Japan, South Kore a, C hina 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) neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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Source : BP Statistical R e vie w of W orld Ene rgy

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 Inte rnational Ene rgy O utlook , Se pte m be r 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

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Source : EIA Inte rnational Ene rgy O utlook 2008

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 re fe rre d to as lique faction.

Figure 2.4 - World LNG Production

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Source : BP Statistical R e vie w of W orld Ene rgy

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 onequarter of which was produced in the Middle East. By 2015, the Middle East may supply over onethird 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

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Source : BP Statistical R e vie w of W orld Ene rgy

Figure 2.6 - World LNG Markets

Source : BP Statistical R e vie w of W orld Ene rgy

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 neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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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

* Pre dom inate ly From C hina Source : BP Statistical R e vie w of W orld Ene rgy

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

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Source : Various data source s

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

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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 large st nucle ar re actor, the 8.2-Me gawatt Kashiwazak i Kariwa nucle ar re actor was close d for re pairs following a m ajor e arthquak e on July 16, 2007. C urre nt plans e x pe ct the plant to re turn to se rvice in m id-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*

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* Include s Japan, South Kore a and C hina Source : EIA Inte rnational Ene rgy O utlook 2008, Se pte m be r 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

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Source : BP Statistical R e vie w of W orld Ene rgy

Figure 2.12 - European Natural Gas Balance

Source : BP Statistical R e vie w of W orld Ene rgy

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]. neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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[10] IEA Natural Gas Mark e t R e vie w 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 neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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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

Source : BP Statistical R e vie w of W orld Ene rgy

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. neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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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

* C onve rte d to US$/MMBtu from data de rive d from the Inte rC ontine ntal Ex change (IC E) 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 neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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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] Fre e port LNG and Sabine Pass LNG [13] O nce ope rational, it is ge ne rally de sirable to m aintain the LNG-handling facilitie s at a constant low te m pe rature .

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] Se e Appe ndix 2 and Appe ndix 3 for a sum m ary of global lique faction and re gasification capacity.

Figure 2.15 - Global LNG Liquefaction and Regasification Outlook

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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.

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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 e stim ate s

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 neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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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

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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 neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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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 AsiaPacific 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 EastAsia 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 neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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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 Inte rnational Ene rgy O utlook 2008 [16] Most re ce nt proje ctions for the U.S. natural gas production from the EIA Annual Ene rgy O utlook (e arly re le ase , De ce m be r 2008) e x pe cts U.S. natural gas production in 2020 to be 228 10 6m 3/d (8 Bcf/d), highe r than 2005 le ve ls.

Figure 3.1 - North American Natural Gas Consumption and LNG Imports

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Source s: Historical from BP, Proje ction from EIA Inte rnational O utlook 2008 with adjustm e nt from 2009 Annual Ene rgy O utlook

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 neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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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 offseason 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. De partm e nt of Ene rgy

To these new LNG suppliers, the North American market may not be the most proximate and may neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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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 neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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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

Source s: EIA Inte rnational Ene rgy O utlook 2008 and Annual Ene rgy O utlook 2009

Figure 3.4 - Natural Gas Production and Consumption in Europe

Source : EIA Inte rnational Ene rgy O utlook 2008

The competitive relationship between North America and Europe for Atlantic Basin natural gas neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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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

Source s: Inte rcontine ntal Ex change , U.S. De partm e nt of Ene rgy

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

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Source : NEB e stim ate s

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 EastAsian 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 neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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major markets. This swing market characteristic is unlikely to be significantly altered in the nearterm, 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, the re has be e n othe r activity re late d to the e x am ination of the pote ntial de ve lopm e nt of gas supplie s in the C anadian Arctic and the transportation of that gas to m ark e t as LNG.

Figure 4.1 - Canadian LNG Projects

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Location

Terminal

Proponents

Proponents' Estimated Capacity On-Stream Date

Existing LNG Terminals 1. Saint John, Ne w Brunswick

C anaport LNG[1]

R e psol YPF and Irving O il

7.6 m tpa 1.0 Bcf/d

2008

Proposed LNG Receiving and Regasification Projects 2. Bish C ove , British C olum bia

Kitim at LNG

Galve ston Ene rgy

3-4 m tpa 0.5 Bcf/d

na

3. Goldboro, Nova Scotia

Maple LNG

4 Gas BV & Sunte ra C anada Ltd.

7.6 m tpa

2012

1.0 Bcf/d 4. Q ué be c C ity, Q ue be c

R abask a

5. R iviè re -du-Loup, Q ué be c Gros C acouna LNG

Gaz Mé tro, Enbridge and Gaz de France

3.8 m tpa 0.5 Bcf/d

2014

Pe tro-C anada and TransC anada Pipe line s

3.8 m tpa 0.5 Bcf/d

Suspe nde d

6. Sague nay, Q ue be c

Éne rgie Grande - Sague nay Port Authority and Éne rgie Anse Grande -Anse Inc.

7.6 m tpa 1.0 Bcf/d

2013

7. Te x ada Island, British C olum bia

W e stPac LNG

3.8 m tpa 0.5 Bcf/d

2014

na

2011

5 m tpa 0.6 Bcf/d

2013

W e stPac Te rm inals Inc.

Proposed LNG Storage and Transshipment Projects 8. Place ntia Bay,

Grassy Point LNG Ne wfoundland LNG Ltd.

Ne wfoundland Proposed Liquefaction and LNG Export Projects 9. Bish C ove , British C olum bia

Kitim at LNG[2]

Galve ston Ene rgy

na not available [1] At tim e of writing, construction of the C anaport LNG te rm inal is ne aring com ple tion and is e x pe cte d to be inse rvice in e arly 2009. [2] Kitim at LNG is now proposing to construct an LNG lique faction and e x port te rm inal at the pre viously approve d site for an LNG re ce iving and re gasification te rm inal.

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. neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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[18] Although a num be r of facilitie s have e x iste d for m any ye ars in Q ue be c, O ntario and British C olum bia that lique fy pipe line natural gas and store the LNG for late r re gasification and use during pe ak de m and pe riods.

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] Assum ptions include : LNG ve sse l capacity of 138 000 m 3 and m arine die se l cost of US$400/tonne . Transportation costs m ay be substantially re duce d through the use of ne we r 'supe r-size d' tank e rs in long-haul transportation. In the case of transportation of LNG from Q atar, the use of large r Q -Fle x or Q -Max LNG ve sse ls can alm ost double the size of tank e rs and provide e conom y of scale savings and e nable Q atari supply to be cost com pe titive with conve ntional transport of LNG from othe r re gions.

Figure 4.2 - Illustrative Transportation Costs to Atlantic Basin Markets

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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

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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. neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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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 neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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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 AsiaPacific 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 EastAsia is likely to maintain a competitive market for global LNG supply. However, the amount of LNG neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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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.

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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 A major natural gas trading point in the United Kingdom, used in this report to Balancing Point 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 Natural gas that is contained in a non-traditional reservoir rock that requires gas 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 neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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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 * Spe cial Adm inistration R e gions of C hina

Appendix 2 - Existing Global LNG Liquefaction Capacity Basin

Region

Capacity 109 m 3

per year

Capacity Capacity mtpa Bcf/d

Existing LNG Liquefaction Terminals Atlantic

Am e ricas

20.6

15.1

2.0

Europe

5.6

4.1

0.5

Africa

72.3

53.1

6.9

64.3

47.2

6.1

Am e ricas

2.0

1.5

0.2

O ce ania

106.3

78.1

10.1

Middle East Middle East Asia-Pacific

Total

23.8

LNG Liquefaction Terminals Under Construction Atlantic

Africa

13.2

9.7

1.3

72.8

53.6

6.9

Am e ricas

6.0

4.4

0.6

R ussia

13.1

9.6

1.2

O ce ania

21.3

15.7

2.0

Middle East Middle East Asia-Pacific

Total

12.0

Source : IEA neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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Appendix 3 - Current Global LNG Regasification Capacity Capacity

Capacity LNG Storage Bcf/d 109 m 3 per year m3

Region

Underground Natural Gas Storage 109 m 3

Existing Re-gasification Terminals North Am e rica

109.8

10.5

South & C e ntral Am e rica

7.9

0.8

Europe

120.2

11.4

4 003 000

76

Asia

375.2

35.6

21 863 200

1.3

Total

2 973 720

117

320 000

58.2

Re-gasification Terminals Under Construction North Am e rica

71.4

6.8

2 240 000

South & C e ntral Am e rica

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 Country

Heat Content (Btu per cubic foot)

Supply Region

Libya

1160 - 1190

Atlantic

Brune i

1133 - 1150

Asia-Pacific

Unite d Arab Em irate s

1127 - 1160

Middle East

O m an

1100 - 1160

Middle East

Nige ria

1110 - 1145

Atlantic

Malaysia

1120 - 1133

Asia-Pacific

Indone sia

1107 - 1118

Asia-Pacific

Australia

1065 - 1143

Asia-Pacific

Q atar

1024 - 1124

Middle East

Alge ria

1041 - 1121

Atlantic

Trinidad & Tobago

1050 - 1082

Atlantic

Equatorial Guine a

1050

Atlantic

USA (Alask a)

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 neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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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 neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/…/lqfdntrlgscndnprspctv2009-eng.html

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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.

Date Modified: 2012-02-03

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About LNG

Home / Technology & Innovation / Gas refining / Liquefied natural gas (LNG) / About LNG

About LNG Liquefaction offers a unique solution for transporting natural gas located in areas far from a pipeline infrastructure.

LNG stands for liquefied natural gas, and is produced by cooling dow n natural gas below its dew point. Methane usually accounts for about 85-95% of LNG, w hich 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, noncorrosive 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 teraw att-hours statoil.com/en/TechnologyInnovation/gas/LiquefiedNaturalGasLNG/…/AboutLiquefiedNaturalGas.aspx

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About LNG

(TWh). A TWh equals one billion kilow att-hours. Since a Norw egian family consumes some 20,000 kWh of electricity per year, one LNG cargo represents the annual pow er consumption of roughly 50,000 households in Norw ay. Useful conversion units relating to LNG: 1 standard cubic metre (scm) LNG = 11 kilow att-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, w hich have been tackled in-house. Together w ith Linde Statoil developed spirally-w ound 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, w hich ended in 2007, has also yielded a patented cooling solution, liquefaction process currently used in the Snøhvit LNG plant, w hich is operated by Statoil. This represents Europe’s first and only largescale base load gas liquefaction facility plant. Over tw o 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 Norw ay. 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.

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—

Description of LNG Technology and Import System

Volumetric Conversion Table VOLUME RELATIONSHIPS LNG Gas/Liquid Ratio 619.8 to 1 1086 Btu/Cu. Ft. Spec. Grav. 0.465

LNG Conversion Factors 1 MCF

Gas

Liquid

Cubic Feet 1000.0

MCF -

Pounds 46758

1 Gallon

82850 0.082850

3.87390

1 Imp, Gal

99503 0.099503

4.6526

1 Cubic Foot 1 Barrel

619.80

061980

348008

3.48008

28.981 162,72

Imp. Gal.

Cubic Feet

12070 10.051

1,6134

0.28735 0.045692

.02123

0.13367

0,02380 0,003785

0001759

0.89975

016054

0.02858 0,004546

000211

1,08059

0.17810 0.02832

0.01316

6.7311

Gallons

-

0.8327

1,201

-

7.4811

6.229

42,005 34,97

5,6148

1 Cubic Meter

21,886 21,886

1023,3

264.16 220,0

35314

1 Metric Ton

47,103 4 7 1 0 3

2202,4

568,53 473,4

75.996

1 Therm

92081 0,09208

4,3055

1.1114 0,92546 0,14856

Barrels

6.2888 13.535

Cubic Meters

0,15901 2.1522

0.02646 0,00421

Metric Tons

0.07388 0.46463 -

0.00195

10.860

37,794 32768 511 54

Chapter I

Description of LNG Technology and Import System

Figure 2. World Proportional Natural Gas Reserves By Major Supplier Country

SUPPLY AND DEMAND Natural gas is a major source of energy for the United States, supplying 20 trillion cubic feet, more than one-quarter of the total energy consumed in this country, during 1976.1 Although U.S. production of natural gas has been declining since 1971 (figure 1), there are significant supplies of natural gas in several regions of the world where there is lit-

Country USSR. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Iran’ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . United States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Algeria*. . . . . . . . . . . . . . . . . . . . . . . . . . . Abu Dhabi* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total

Percentage 33 14 10 10 8 75

● Countries with little or no gas demand.

Figure 1. U.S. Natural Gas Consumption 1971-1976

Source Department of the lnterior World Natural Gas Annual – 1975

Yearly Total 25 Consumption Trillion Cubic 20 Feet

tle or no gas demand (figure 2). To date, much of this natural gas has been wasted—in 1975, 6.5 trillion cubic feet were vented or flared worldwide. z

15

10

5

1971

1972

1973

1974

1975

1976

U S Production

Source Federal Energy Administration Monthly Energy

1

To use the natural gas which would otherwise be untapped or wasted, importation of natural gas is one of several supplemental supply schemes used by those areas of the world with large energy demand, primarily the United States, Europe, and Japan. Natural gas has been carried overland by conventional pipelines, and about 1 trillion cubic feet of natural gas is imported in that manner from Canada to the United States each year. However, in order to import natural gas in a form practical for water transportation from Eastern Hemisphere nations, a system has been developed to convert the gas to liquid form at about l/600th the volume. The lique-

Review, March 1977

Federa] Ener~ Administration, Monthly Energy Reuzew, March 1977.

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 in specially constructed tankers, introducing a marine link in the supply and demand of natural gas. This marine link is a large component, consisting of the liquefaction facility Figure 3. Existing International LNG Trade

Date Started

Supplier to Importer

Amount per Day (million cubic feet)

1972 1977 1964 1969 1969 1969 1964 1971

Brunei to Japan Indonesia to Japan Algeria to France Libya to Italy Libya and Algeria to Spain Alaska to Japan Algeria to United Kingdom Algeria to Boston, Mass.

737 550 400 235 160 135 100 44

at the source of the gas, the LNG tanker, and

the receiving terminal and regasification facility at a location near a gas distribution network. It is a very capital-intensive system, which can cost more than $1 billion to construct. A large 500 million cubic feet per day project with four ships could require a $2 billion capital expenditure for liquefaction/export facilities ($1 billion), ships ($150 million each), and import/regasification facilities ($300 million to $400 million). Implementation of all announced LNG projects could require capital expenditures in excess of $35 billion worldwide. In the United States alone, construction of facilities and ships for the import of LNG could require $20 billion. a :1’’LNG

Source Pipeline and

Gas Journal,

June 1977

Figure 4. U.S. LNG Import Projection

1977).

Rep&rt,” Pipeline and Gas Journal 204 (June

—

—

Such huge capital expenditures are generally financed by a multinational mix of governments and private firms. The U.S. Government has already provided about $716 million in subsidies, loans, and loan guarantees in connection with LNG projects. More than two-thirds of that support has been given to the foreign portions of the projects. A Europe became the first steady market for LNG in 1964 (figure 3). Japan took over as the key market about 1972, receiving about 49 percent of the LNG moving in international trade. However, the United States—which has used very limited imports of LNG only since 1971–is projected to become a major LNG customer if ventures now planned go forward. b 41nterview with Officials of Export-Import Bank of the United States, Washington, D. C., June 16, 1977. JDavid Hawdon, World Transport of Energy 1975 to 1985 (London: Stanil and Hall Associates Limited, April 1977), p. 39.

The United States is presently a net exporter of LNG. More than 32 billion cubic feet of natural gas in the form of LNG has been sent to Japan from southern Alaska each year for the past 5 years, while only about 15 billion cubic feet per year is imported from Algeria to Everett, Mass. The LNG imported to Everett is a very small amount, less than one-twentieth of 1 percent of the U.S. consumption of natural gas in 1976. 6 According to industry representatives, however, LNG could be 5 to 15 percent of the total U.S. gas consumption by 1985 (figure 4).7 Projects are now proposed which could bring as much as 3.5 trillion cubic feet of LNG per year to the United States from foreign sources within the next 10 to 15 years (figure 5). 6Federa1 power

commission,

“Table of

LNG Imports

and Exports for 1976,” News Release, June 3, 1977, and Federal Energy Administration, Monthly Energy Review, March 1977. TOffice of Technology Assessment LNG panel meeting, Washington, D. C., June 23, 1977.

Figure 5. Status of U.S. LNG Import Projects Project

Start-up Date

Supply Source

Status (AGA/FPC)

Existing & Firm Foreign Imports Distrigas I Distrigas IV El Paso I

1972 1978 1978

Algeria Algeria Algeria

Existing/Operational Firm/Pending Firm/Approved

Quantity (billion cubic feet/y r.) 1,6 42* 365

407

Note -- Eascogas project IS deleted here because of recent questions regarding approvals and project viability

Probable Foreign Imports Panhandle Eastern Pacific Lighting Int El Paso II

1980 1980 1980-82

Algeria Indonesia Algeria

Probable/Approved Probable/Approved Probable/Pending

179 197 365 741

1985 1985 +/1985 +/1985 +/1985 +/1985 +/-

Algeria USSR USSR Iran Iran Nigeria

Possible/Filed Possible/Not Filed Possible/Not Filed Possible/Not Filed Possible/Not Filed Possible/Not Filed

397 365 547 285 547

Possible Foreign Imports Tenneco-N B. Canada Occidental-El Paso Brown/Root-Tenneco Kalingas El Paso-Iran Shell-BP

237 2,378

Grand Total

● Replaces Distrigas 1.

96-597 0-77 -2

3,526 Sources American Gas Association and the Institute of Gas Technology,

——

.

Note Other possible future sources of LNG include Iran, Russia, and NIgerIa Bcf/y = billion cubic feet per year Source OTA.

Ultimately, the supply of natural gas is limited, But since it is currently an underutilized resource in many foreign countries, importing it as LNG could satisfy a significant portion of the U.S. energy demand for at least the next 20 years. Imports of LNG could be particularly useful in alleviating near-term fuel shortages in certain sectors of the economy or parts of the country. In California, which accounts for 11 percent of U.S. natural gas consumption, s LNG could help to alleviate projected energy shortfalls and air quality problems.

~Douglas M . Considive, cd., Energy Technology Handbook (New York: McGraw-Hill, 1977).

If presently planned and approved projects move forward, Algeria would be the major source of the increased imports (figure 6). A smaller amount of LNG would come from Indonesia, and there is a possibility of supplies from the U.S.S.R, Iran, and Nigeria after 1 9 8 5 .9 The stability of these foreign supplies and likely results of possible curtailment of LNG shipments to the United States has been identified by this study as one of the potential problems of the LNG system. Foreign supply is discussed further in the critical review section which follows this chapter.

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 gas discoveries in Alaska could be transported to the west coast as LNG. This possible supply of gas from the North Slope and southern Alaska could be more than 1 trillion cubic feet a year as early as 1984.10

million tons. 11 In 1977, there were 441 LPG tankers operating worldwide with a capacity of 3.5 million cubic meters. In comparison, 30 LNG tankers were operating worldwide at the same time with a capacity of 2.2 million cubic meters.

The North Slope is by far the largest of the two Alaskan supplies of natural gas. The method of transportation to be used to bring the North Slope gas to the west coast was to be determined by the President in September? A proposal to transport this gas by pipeline through Canada was being weighed against a proposal to use an LNG system.

Some unique properties of LNG which affect the design of tankers or terminals are: ●

●

Liquefied natural gas and LPG are similar in many ways and are treated together as “liquefied gases’ by most regulators. Liquefied petroleum gas, however, appears to be better known and accepted by the public. In 1976, 10 million tons of LPG were moving in world trade, most of it going to Japan from the Middle East countries. It is estimated that by 1980, LPG trade will more than double, and that U.S. demand will be as much as 12 *NOTE: On September 8, 1977, the President announced that an agreement had been reached with Canada for a pipeline to carry natural gas across that country from Alaska to the west coast of the United States. The Congress has 60 days after formally receiving the President’s plan in which to disapprove the choice if it so desires.

it weighs about 28 pounds/cubic foot, slightly less than half the weight of water, and would therefore float;

●

at normal ambient temperatures, it evaporates very rapidly and expands to about 600 times its liquid volume;

●

in the vapor state, and when still very cold, the gas is heavier than air and, in the event of a spill, would hug to the earth’s surface for a period of time until substantially dissipated;

●

when the vapor warms up, reaching temperatures of about –100° F, it is lighter than air and would rise and dissipate in the air;

●

in the vapor state, it is not poisonous, but could cause asphyxiation due to the absence of oxygen;

DESCRIPTION OF LNG Liquefied natural gas is not the only hazardous cargo transported in the United States today, or is it necessarily the most dangerous. Other cargoes which pose unique hazards when transported in large volumes include liquefied petroleum gas (LPG), chlorine, acids, and gasoline.

it has an extremely low temperature of –259° F;

●

in the vapor state, concentrations of 5 to 15 percent natural gas are flammable.

Liquefied natural gas is odorless and colorless. It looks much like water. Except for its extremely cold temperature, which requires special handling techniques and materials, the liquid is relatively safe. In bulk form it will not burn or explode. Momentary contact on the skin is harmless although extended contact will cause severe freeze burns, On contact with certain metals such as carbon steel ship decks, LNG can cause immediate cracking.

IOFedera] power ~o~missio~, Recomme~da~~on to

the President Alaskan Natural Gas Transportation Systems (Washington, D. C.: Federal Power Commission, May 1, 1977) p. I-44.

1 IH. Magelssen, “LPG-Transportation Cost, Market Potential and Future Charterers,” Gastech 76 Proceedings LNG and LPG Conference, New York, Oct. 5-8, 1976, (Herts, England: Gastech Exhibitions, 1977).

8 CH.

I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM

The behavioral patterns of LNG vapor in the atmosphere, however, are not so well understood and may create hazards. If spilled on the ground, LNG would “boil,” (vaporize) very rapidly for 2 or 3 minutes until the ground was frozen and no longer emitting heat to the LNG on top of it. This would slow the rate of vaporization and minimize cloud formation dangers. If spilled on water in a large-scale accident, it is unlikely the water would freeze. Instead the water would continue to warm the floating LNG, vaporizing it and forming a spreading cloud. Researchers currently disagree on the shape, size, movement, and composition of the vapor cloud and the factors which will affect it. It is believed that the concentration of LNG vapor within the cloud is not homogeneous. At the edge of the cloud, where the greatest mixing with ambient air occurs, the concentration of gas is lowest. At the core of the cloud, the concentration is highest. Where the concentration falls within the flammable limits of 5 to 15 percent, the cloud may be ignited and burn back toward the source of the spill. It is generally agreed that, if the vapor from a large LNG spill ignites, it would be beyond the capability of existing firefighting methods to extinguish it. 12 Therefore, the key to reducing the hazard of an LNG fire is a strong prevention program. The hazards of transporting LNG are somewhat similar to those of LPG, if the two are considered in equal volumes. However, LPG is somewhat more dense than LNG vapor at comparable temperatures. In the event of a spill of either liquid on water, the liquid would rapidly spread by gravity until a large vapor cloud would form. LNG would vaporize considerably faster than LPG because LNG is more volatile. Thus, the LPG vapor cloud would evolve over a longer period of time, and would be more cohesive than the LNG cloud. LPG has the greatest potential for detonation both 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 surrounding flame causes a rise in pressure which leads to detonation. Open-air detonations of LPG 13 have been demonstrated by experiment whereas the same is not true of LNG. 14 Research into the behavior of spilled LNG and an LNG cloud is another critical area discussed in the next chapter. SAFETY RECORD OF EARLY USE OF LNG Liquefaction of natural gas is achieved by cooling the gas to –259° F. The process was developed on a large scale during the first quarter of the 20th century to simplify the transportation and storage of natural gas, since the liquid state is l/600th the volume of the gaseous state. Until recently, LNG was utilized primarily in operations which produced the liquid and stored it for use only during peak demand, for example, in cold winter weather. There are 89 of these facilities operating in the United States today to produce and/or store domestic LNG. Known as “peak shaving plants,” they have a combined storage capacity of 2 million c u b i c m e t e r s .15 In addition, one plant in Boston imports and stores foreign LNG. Its capacity is 146,000 cubic meters. The peak shaving plants have existed safely for years, without much public attention to either their location in heavily populated areas or their operations. Only one major incident has marred the safety record of these plants. That accident occurred at the first LNG installation in 1944. At that time, a storage tank owned by East Ohio Gas Company in Cleveland ruptured, spilling 6,200 cubic meters of LNG into adjacent streets and sewers. The liquid evaporated, the gas ignited and, where confined, exploded, The disaster remains the l~elephone interview with staff of the Bureau of Mines, Pittsburgh, Pa., Sept. 7, 1977. ld’l_’elephone interview with staff of Naval Weapons Laboratory, China Lake, Calif,, Aug. 25, 1977, 15A~erican Gas Association, LNG

Information Book

1973 (Arlington, Va.: American Gas Association, 1973).

.

CH. I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM 9 most serious LNG accident anywhere in the world. It resulted in 128 deaths, 300 injuries, and approximately $7 million in property d a m a g e . l6

took four lives in Oregon. This accident, however, took place during construction of the storage tank before LNG had ever been introduced into the facility. l9

Based on investigations made by the U.S. Bureau of Mines after the accident, it was generally agreed that the tank failed because it was constructed of 3.5 percent nickel steel, which becomes brittle on contact with the extreme cold of LNG. Since the Cleveland disaster, it has become standard practice in the LNG industry to use 9 percent nickel steel, aluminum, or concrete and to surround storage facilities with dikes capable of containing the contents of the tank if a rupture occurs.

Over the past 10 to 20 years, the peak shaving facilities have been engaged in all phases of LNG handlings: liquefaction, regasification, loading and unloading, storage, and shipment by pipeline, truck, rail, and barge. However, new LNG projects involve much larger scale facilities entirely dependent on marine shipment, and these are the focus of this study.

The only other significant accident related to LNG to date occurred at a Staten Island import facility in 1973; where 40 workmen repairing an empty LNG tank were killed when the roof of the tank collapsed as a result of a fire. While the Staten Island tank disaster precipitated active local opposition to LNG, the gas industry has repeatedly argued that the accident was not due to any characteristic or handling of LNG 17 , but was an industrial accident involving an insulation fire. However, a Bureau of Mines study of the accident indicated that there was enough LNG in the insulation that it could have been released very quickly into the tank once ignition had started. 18 The only other accident in the United States mentioned in connection with LNG IGU.S. Department of the Interior, Bureau of Mines, Report on the Investigation of the Fire at the Liquefaction, Storage and Regasification Plant of the East Ohio Gas 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 Impact Report for the Proposed Oxnard LNG Facilities, Safety, Appendix B (Los Angeles, Ca.: Socio-Economic Systems, 1976), p. 10. 18U.S, ConWess, House, Staten Island Explosion: Safety Issues Concerning LNG Storage Facilities. Hearings before the Special Subcommittee on Investigations of the Committee on Interstate and Foreign Commerce. 93rd Cong., first sess., July 10, 11, 12, 1973, pp. 143, 145.

REGULATION OF IMPORT PROJECTS Before any LNG import or export project can begin operation, more than 130 permits must be obtained from Federal, State, and local agencies (see appendix A), and 12 different Federal agencies are involved in approvals and controls. The Federal Power Commission (FPC), the Coast Guard, and the Office of Pipeline Safety Operations (OPSO), are the agencies most involved in LNG and are discussed in appropriate sections of this chapter. The others are explained in appendix B. The most crucial agency in this milieu is the Federal Power Commission, which under the Natural Gas Act of 1938, has power to approve or reject any proposed project in three ways: 20 ●

it must determine whether of not the public interest will be served by LNG importation;

●

it must authorize construction or extension of any facilities to be used in the transportation or sale of interstate natural gas;

●

it has the authority to establish the price at 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).

—

10 CH. I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM

The Federal Power Commission has broad discretionary powers in determining what is and what is not in the public interest and in stipulating conditions which must be met in order to meet the public interest. To date, the FPC has been asked to rule on one LNG export project and 10 LNG import projects (see figure 5). The export project, with liquefaction facilities in Kenai, Alaska, has been approved and is operating. Of the import projects, three have received final approval; one has received initial approval, subject to review. One import project with its terminal and regasification plant in Everett, Mass., is in operation. Another, with import facilities ‘in Cove Point, Md., and Savannah, Ga., is scheduled to begin operation later this year. Facilities for the approved project at Lake Charles, La., have not yet been constructed, nor have facilities for the Oxnard, Calif., terminal which has received only initial approval. The FPC approves the import projects by means of an express order authorizing importation and certificates of public convenience and necessity (authorization and stipulations for construction and operation of facilities). The approvals are obtained by means of a complicated quasi-judicial procedure which routinely takes several years from the time an application is filed until it is approved. First, an evidentiary hearing is held before an administrative law judge, in which the applicant, staff, and interveners each present their views of the nature of the project, cost estimates, the need for additional supply of gas, and environmental consequences of the project. The evidence presented also includes an environmental impact statement prepared by the FPC, an engineering and safety review by the cryogenics division of the National Bureau of Standards, and a risk analysis by the FPC staff. On the basis of this evidence, the FPC administrative law judge makes an initial decision. “ Second, there is a period of review during which any of the parties may file exceptions to the decision. At the end of the review period, the commissioners make a final decision

which may uphold the initial decision or change it completely. The final decision is subject to an appeal in one of the U.S. Courts of Appeal. Since the historic role of FPC has been to regulate the entry of suppliers into the interstate natural gas market and to ensure that interstate sales of gas take place at prices that are “just and reasonable,” 21 the agency has limited its activities to licensing and ratemaking. There is little onsite inspection to assure compliance with stipulations contained in the licenses. The exception to this general rule occurs when a company wishes to expand existing facilities and submits a new application. In that context, FPC engineers inspect the facility to judge its operating performance. 22 A critical analysis of the decisionmaking process which leads to certification of LNG projects and the difficulties of pricing policies are discussed in the next chapter. LNG TANKER TECHNOLOGY Liquefied natural gas import projects involve a complex consortia of energy and transportation companies. The gas supplier is usually represented by a foreign government or State-owned subsidiary company. The recipient of the gas at the import terminal is generally a consortia of gas utilities and/or pipeline companies, which use the gas in their own systems and sell to other distribution or utility companies. The supplier and receiver are connected by a transportation company, the subsidiary of an oil, gas, or pipeline company, which owns and operates the LNG tankers. Liquefied natural gas tanker technology has been developed over the past 20 years to the point where, currently, about a dozen worldwide trade routes are either in operation, 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

Washington, D. C., May 31 and June 24, 1977.

staff,

CH. I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM 11

o

0

& i

a

Q

12 CH. I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM Figure 8. Total Capacity of World LNG and LPG Tanker Fleet

26

51

39

28

32

44

34

22

145

172

209

242

274

307

339

352

30 379

67 404

66 418

60 441

5

4 5

6 5

9 5

13 8

23 11

24 14

28 17

45 20

49 27

42 35

43 39

176

232

259

284

327

385

411

419

475

547

561

583

vessels Total

8,000

Source Liquid Gas Carrier Register 1977

been rapid (figure 8). Seventy-two ships will be operational by 1980, with a possibility that 33 more would be required if all planned LNG projects go through. 23 23

Edward Faridany, LNG: 1974-1990 Marine Operations and Market Prospects for Liquefied Natural Gas, (London: Economist Intelligence Unit Limited, June 1974), p. 69,

Currently, only one LNG tanker is engaged in regular import trade with the United States, that is the French ship, the Descartes, which has brought 25 shipments from Algeria

CH. I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM Figure 9.

LNG Tankers On Order or Under Construction In U.S. Shipyards

Shipyard Avondale

General Dynamics

No. of Vessels

3

10

Containment System Design Conch

Self-supporting aluminum alloy prismatlc tanks, British design

KvaernerMoss

Spherical aluminum alloy tank, Norwegian design

Newport News

3

Technigaz

Stainless steel alloy membrane French design

Sun Shipbuilding

2

MacDonald Douglas/ Gas Transport

Invar ( nickel-steel), American/French design

13

Liquefied natural gas tankers are bulk cargo ships which require unique design and materials to handle the very low-temperature gas. Most LNG tankers range in size from about 40,000 cubic meters to planned ships of 165,000 cubic meters (figure 10). The industry standard has become the 125,000- to 130,000 cubic meter ship. Each ship this size carries enough LNG to heat a city of 100,000 population for 1 month. 26 Figure 10. Profiles of Typical LNG Ships

METHANE PRINCESS 27,400 cubic meters

to the Distrigas peak shaving plant in Boston

since July 1975.24 Nine more LNG tankers will join the U.S. trade early next year when import terminals under construction at Cove Point, Md., and Savannah, Ga., begin operation, and five more when an import terminal at Lake Charles, La., is online about 1980 (figure 9). If other projects now proposed are approved, it is possible that 12 additional LNG tankers will be required for imports to the United States and 14 for shipments from Alaska to the continental United States. By 1985, a total of 41 tankers could be calling at continental U.S. ports. (In addition, two tankers are involved in export of LNG from Alaska to Japan through 1985). 25 ziInterviews with Officials of Distrigas Inc., Boston, Mass., .June 15, 1977. 2 5 a , “LNG Scorecard,’ Pipeline and Gas Journal 203 (June 1976): 20. b. American Gas Association, “Update of Status of LNG Projects,” Gas Supply Review 5 (February 1977): 8. c. U.S. Department of Commerce, Maritime Adm i n i t r a t i o n , S t a t u s o f LNG V e s s e l s (Washington, D. C.: U.S. Department of Commerce, Maritime Administration, March 15, 1977). d, U.S. Department of Commerce, Maritime Adm i n i s t r a t i o n , S t a t u s o f LNG P r o j e c t s (Washington, D. C.: U.S. Department of Commerce, Maritime Administration, September 1976).

DESCARTES 50,000 cubic meters

Source National Maritime Research Center

zGInterview with official of General Dynamics Company, Boston, Mass., June 15, 1977.

14 CH. I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM By comparison to the better known crude oil tankers, the largest LNG ships are one-half to one-fourth the total size of the very large crude carriers (VLCC or “supertanker’ ) (figure 11), some of which are more than 400,000 deadweight tons. A 130,000 cubic meter LNG tanker with a 143-foot beam and a 900- to 1,000-foot length is roughly equivalent to a 100,000-deadweight ton oil tanker. The LNG tanker is a shallow draft vessel, about 36 feet, on which the cargo-carrying capacity is increased by adding to the length instead of the depth. It has an unusually large amount of freeboard, rising about 50 feet out of the water. Because of its visible length and height, the LNG tanker appears larger than some VLCCs. The LNG tanker is a high-powered, highspeed ship, with an optimum service speed in the 20-knot range, about 5 knots faster than most oil tankers. New LNG tankers are fueled by their own cargoes. Immediately upon being loaded in the tanker, LNG begins to evaporate and continues to do so throughout the entire voyage. In a typical design, the vapor produced during the voyage is used as the ship’s fuel and may be sufficient to meet 100 percent of the fuel requirements. However, safety regulations require that the ship carry, and be equipped to use, fuel oil as well. After the ship is unloaded,

a small percentage of the LNG cargo is retained in the tanks for cooling purposes and this supplies part of the fuel requirements for the return trip.

The tankers are equipped with specialized systems for handling LNG and for combating potential hazards associated with liquid spillage and fire. These include high-expansion foam and dry powder fire protection systems, water-spray systems for flooding deck piping, and pressure-, temperature-, and leak-monitoring systems. Cargo handling systems are provided for loading and discharging LNG, for cooling down and warming up tanks, for transmittal of boiloff gas to the ship boilers and, most importantly, to provide inert atmospheres in the spaces surrounding the cargo tanks and in the tanks themselves prior to and after aeration at the time of drydocking. Each LNG tanker is a complicated vessel, representing approximately a $100- to $150million investment.27 Most U.S. flag LNG tankers are financed with a variety of aids from the Maritime Administration, including construction differential subsidies, operating differential subsidies, and ship mortgage guarantees. zT’’General Dynamics Gets Tanker Job for

$310

million, ’ 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 Dlsplacement c of a 125,000 Cubic Meter LNG Ship and a Variety of Crude Oil Tankers

80,000 dwt

100,000 dwt

137,000 dwt

Oil Tanker

Oil Tanker

811 125 57 44 80,459 105,000

848 128 65 50 100,300 128,500

Oil Tanker

Length Breadth Depth Draft Dwt Full-Load Displacement

974 134 85 54 137,010 172,500

125,000 cu/m LNG Ship

476,000 dwt Oil Tanker

554,000 dwt Oil Tanker

936 144 82 36 63,100 94,500

1,243 203 118 93 476,025 509.000

1,359 207 118 94 553,700 631,000

‘IN FEET b

lN LONG TONS IN LONG TONS

C

Source Engineering Computer Opteconomics Inc

—

CH. I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM 15 To date, the Maritime Administration has authorized approximately $270.3 million for subsidy of all LNG tankers. 28 (Federal financial aids are also provided by the Export-Import Bank, although that aid is made available to foreign governments in order to promote the use of U.S. goods and services in their projects. To date, the Export-Import Bank has provided approximately $483 million in loans and loan guarantees to Algeria to support 28’’$ubsidized Shipbuilding Contract Awards’ Statistical Quarterly (First quarter 1977),

construction of liquefaction plants and related facilities.) 29 The construction cost of an LNG tanker is roughly twice that of an oil tanker of similar size. Most of the increased cost for LNG tankers is due to special design features of the containment system which holds the low-temperature, low-density cargo. The standard 125,000 cubic meter LNG tanker usually has five cargo tanks, each with a capacity of about 25,000 cubic meters (figure 12). An eight-story building could fit inside zgInterview with officials of Export-Import Bank of the United States, Washington, D. C., June 16, 1977.

Figure 12. Inboard Profile of LNG Tanker

Liquefied natural gas tankers constructed by General Dynamics use five spherical tanks of about 25,000 cubic meters each Tanks for the ships are constructed in South Carolina and towed by barge to the shipyard at Ouincy, Mass , where they are mounted into the ship hull

—

16 CH. I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM each of these large cargo tanks, which function in the same way as the common Thermos bottle. A cold product—LNG—is introduced into the container and the insulation surrounding the tank (comparable to the vacuum jacket in the Thermos bottle) is the sole means by which the cargo is kept cold. No refrigeration is employed on the LNG carrier. From the 15 or more cargo tank system designs, two basic types have become most common: the freestanding tank and the membrane tank. The freestandin g tanks are self-contained, usually spherical or prismatic in shape, made of aluminum alloy or 9 percent nickel steel with layers of insulation on the outside (figures 13 and 14). The tanks are welded to cylindrical skirts or otherwise tied to supporFigure 13. Free-Standing Spherical LNG Tank

Source U S Maritime Administration

ters which are welded to the ship structure. With the membrane design (figure 15), the ship’s hull, in effect, becomes the outer tank. Insulation is installed thereon, and a membrane placed on the inside to retain the liquid. The inner surface of this “double hull’ is either high nickel steel or stainless steel. The unique design problems associated with LNG tankers stem primarily from the need to contain and insulate the extremely cold LNG cargo and from the fact that many materials such as mild steel will become brittle and fail at very low temperatures. Special materials used for the interior of cargo tanks must be able to withstand both the very low temperatures when filled with LNG and the normal temperatures when empty. When metals are subject to these temperature

18 CI-I. I

– DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM

changes of as much as 300 degrees, they expand and contract and, in the case of freestanding tanks, the whole structure of the tank interior must be able to move within the ship. In addition, up to 2 feet of very efficient insulation is necessary around each tank in order to minimize heat leak into the tank during the voyage from liquefaction plant to receiving terminal and back.

more cargo tanks and spill a large amount of LNG onto the water. A water spill would spread much farther and evaporate much more quickly than a land spill. While it is most likely that a collision would produce some source of ignition which could fire the LNG vapor around the ship, a huge vapor cloud could be generated if no ignition occurred.

So far, none of the containment systems in use has been established as clearly superior to the others (figure 16), and it is too early in the history of LNG carriers to have determined meaningful life-cycle cost comparisons. However, each of the present systems is based on many years of design and testing, and research is continuing into new containment systems using materials such as concrete and glass-reinforced plastic.

A critique of LNG tanker design and construction is included in the next chapter.

Safety analyses conducted for LNG projects have constantly identified a ship accident as the most likely event that could trigger the most serious type of LNG accident. A ship collision could result in the rupture of one or

LNG TANKER CERTIFICATION AND REGULATION The Coast Guard has primary responsiblity for the safe construction and operation of the LNG tankers and activities in ports where the tankers call. Under the Ports and Waterways Safety Act of 1972 and the Dangerous Cargo Act of 1970, the Coast Guard is required to establish and enforce design and construction standards for

Figure 16. Comparative Characteristics of Some LNG Tank Systems

Safest system in event of grounding or collision — tank structure independent of hull and most void space between vessel hull and cargo tanks. Spherical tanks can be pressurized for emergency discharge in case of cargo pump failure.

Safety in event of vessel grounding/collision or other emergency.

Reliability of Containment System. -

Source

Most ship years operating experience and most experience without primary barrier failure. Structure can be analyzed and risk of fatigue failures minimized. Tanks can be constructed and 100% inspected prior to installation in vessel.

National Maritime Research Center

Tank system easiest to analyze structurally: therefore can be made most reliable,

CH. I – DESCRIPTION OF LNGT ECHNOLOGY AND IMPORT SYSTEM 19 U.S. flag LNG tankers and foreign flag LNG tankers entering the 3-mile territorial waters of this country. It does so by letters of compliance for foreign vessels and certificates of inspection for U.S. vessels. The criteria used for both are essentially the same, however, Federal regulations which are specifically applied to U.S. flag ships are simply used as guidelines for foreign ships. The Letter of Compliance program which is now in operation requires that the Coast Guard review the vessel with respect to cargo containment, cargo safety, and the safety of life and property in U.S. ports. Features covered by the review include: 30 ●

design and arrangement of cargo tanks and cargo piping and vent systems;

●

arrangement and adequacy of installed fire extinguishing system and equipment;

●

safety devices and related systems which check the cargo and surrounding spaces to give warning of leaks or other disorders which could result in a casualty;

●

isolation of toxic cargoes;

●

compatibility of one cargo with another and with the materials of the containment system; and

●

suitability of electrical equipment installed in hazardous areas.

The review is accomplished by inspection of detailed plans and specifications submitted in writing by the vessel owner, inspection of documentation that the vessel is accepted by a recognized foreign classification society whose standards provide the same degree of safety as comparable U.S. standards, and inspection of the ship itself on its first visit to a U.S. port. Coast Guard boarding parties examine the vessel’s arrangement and cargo systems, tanks, piping, machinery, and alarms. They also observe the condition of the vessel, vessel operation, cargo handling operations, firetollepartxnent of Transportation, U.S. Coast Guard, Liquefied Natural Gas, Views and Practices Policy and Safety (Washington, D. C.: Department of Transportation, U.S. Coast Guard, Feb. 1, 1976), p. III-B (2).

fighting capability, and personnel performance. Serious problems, such as any involving inoperative safety equipment, leaking cargo piping, or nonexplosion-proof electrical installations, may require immediate correction. Minor problems may require correction prior to a return trip to the United States. If the vessel meets all applicable requirements, a Letter of Compliance will be issued and the vessel must continue to meet the standards of the first visit on all subsequent calls at U.S. ports. To assure continued compliance, the Coast Guard makes a less extensive examination of the vessel each time it enters U.S. ports. The Coast Guard requirements for the design, construction, and testing of U.S. flag vessels are contained in 46 CFR 38. New regulations are being drawn up but are not yet complete. The Coast Guard has also proposed regulations which would set minimum standards for persons employed on U.S. flag LNG ships and is working with international groups to develop standards for foreign crews. The regulations now in effect cover ship stability and survivability, ship hull materials, gas dangerous areas, electrical arrangements, firefighting arrangements, ventilation, cargo containment systems, temperature and pressure control, and instrumentation of the ship. They also cover systems relating to the transfer of LNG, such as the means of loading and offloading the cargo, piping materials, piping insulation, valving,’ instrumentation, construction, and testing of the systems. Inspections for compliance with these standards are carried out during construction of the vessels. In general, requirements result in the design of ships which the Coast Guard believes to meet a consistent and reasonable level of safety and provide for means of dealing with casualties such as tank overfilling, overpressuring, and emergency shutdowns. In general, the vessels are designed t O S u r v i v e two-compartment flooding from collision or stranding with reserve stability. They are not designed to withstand a major collision or stranding without cargo release, but the

—

20 CH.

I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM

design does limit the release to the tanks directly involved in an incident. In addition to minimizing the possibility of collisions, strandings, or other incidents, the Coast Guard has specified operational controls on the vessels while entering, moored, or leaving a U.S. port. By regulations promulgated under 50 USC 191, Executive Order 10173, and the Ports and Waterways Safety Act of 1972, the Coast Guard Captain of the Port has control over any vessel within the territorial sea and may prescribe conditions and restrictions for the operation of waterfront facilities. 31 Under the regulations, the Captain of the Port in Boston has drawn up an Operations/Emergency Plan 32 for LNG shipments coming into the Everett, Mass., LNG facility. Similar plans will be drawn up for all LNG import terminals. The plan takes into account the individual geographic features and environmental characteristics of each import terminal and surrounding waterway as well as the unique nature of the LNG cargo. The result is a set of operational constraints on LNG vessels in order to enhance port safety. These constraints may include such things as the requirement for a Coast Guard escort; enforcement of a “sliding safety zone,’ which is an area around the LNG ship from which all other vessels are excluded as the LNG tanker proceeds to its berth; restriction of operations to certain times of day; prohibitions against certain other types of work, such as welding, or the transfer of other types of cargo, such as LPG, during discharge of LNG; and others.33 The regulation of LNG tanker construction and operations is discussed in the following chapter. 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/Emergency Plan (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 and Safety, p. IV-3.

The Coast Guard claims jurisdiction over the entire portion of the LNG system that connects the tanker to the distribution system. Existing regulations give the Captain of the Port authority to control and monitor LNG waterfront operations. However, there currently are no Coast Guard regulations which specifically apply to the terminal facilities. Development of these regulations is underways 34 and publication is expected in the fall of 1977. LNG TERMINAL TECHNOLOGY The proposed LNG import projects and projects to receive LNG which may come from Alaska require the construction of large terminals to receive and store the product and gasification plants to return the liquid to its vapor form. A large terminal capable of supplying 500 million cubic feet of gas per day can represent an investment of more than $350 million by the sponsoring companies. The technology for these terminals is an extrapolation of many small LNG peak shaving plants which have been operating for years. This technology has been proved operationally satisfactory for the small plants. Even so, baseload LNG import terminals, which are intended to provide a continuous flow of gas into commercial pipelines, are designed to meet much more stringent requirements than smaller peak shaving units. 35 Offloading of the LNG tankers is accomplished at a specially constructed pier where the tanker is connected to pipelines by articulated unloading arms and the cargo is pumped ashore (figure 17). The LNG is stored in large insulated tanks on shore and later pumped to regasification facilities before it enters the distribution

Wbid., p. IV-4. ssConversation with officials of Columbia LNG Corporation, Cove Point, Md., June 8, 1977.

CH. I – DESCRIPTION OF LNG Technology AND IMPORT SYSTEM 21

22 CH.

I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM

Figure 18. Aboveground LNG Storage Tank

land, and Japan. The U.S. tanks were built for peak shaving operations in New Jersey and Massachusetts, but have since been abandoned in favor of other types of storage because the units failed to perform satisfactorily. In any type of tank, the one hazard most often mentioned in connection with the storage of LNG is a phenomena known as “roll over.’ Peak shaving plants have a greater potential for rollover due to weathering of the LNG and/or introduction of new LNG into a partially filled tank.

Source Scientific American.

system (figure 18). The storage capacity of the tanks is roughly equivalent to twice the capacity of a single LNG ship, but—unlike peak shaving storage tanks—the import terminal tanks are intended to hold LNG only briefly. In either type of facility, the storage tanks represent a significant portion of the costs, and the gas industry has spent much time and money in research to develop effective storage systems. Currently, there are four storage concepts: double-wall metal tanks, prestressed concrete tanks,’ frozen holes, and mined caverns. Techniques for storing liquids in aboveground tanks are well established and the LNG industry has drawn on these techniques. In addition, the tanks are surrounded by earthen dikes. These dikes are a safety measure, in that they could contain the entire contents of a tank in the event of a spill. However, they increase the land requirements for aboveground storage several times over. Much research has focused on the idea of underground storage tanks because little or no insulation other than the earth appears to be needed and there is no need for diking to contain spills. Underground storage tanks have been built for LNG in the United States, Algeria, Eng-

Rollover refers to the convection or motion of fluid which occurs when liquids of different densities exist in a storage tank. If different densities or stratification do occur within a tank such that a denser and warmer liquid is at the bottom of the tank and subject to heat leak, that liquid can ultimately become heated to the point that it is less dense than the liquid above it, and it will be rapidly moved by buoyant forces up the tank side walls to the surface. At this point, it experiences a sudden decrease in pressure and being above its normal boiling point vaporizes very rapidly in large quantities causing a significant pressure rise in the tank. As a result of this rapid expansion, cracks or even tank rupture can occur. However, industry research on rollover has been extensive, resulting in deliberate controlled mixing of the tank contents, selected top, side, or bottom filling, careful monitoring of the temperature of the LNG contents throughout the tank, higher design tank pressures combined with low normal operating pressures, and improved venting. In addition, the potential of the phenomena occurring at a baseload plant is further reduced by an operational practice of unloading tankers into empty tanks, not partially filled tanks as can occur at peak-shaving plants. From the storage tanks, LNG is pumped to the regasification plant where it is vaporized by heating it. Frequently, the LNG is heated in systems using the naturally occurring heat in nearby seawater. Other systems use process

CH. I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM 23 heat from other equipment or have heat exchangers fueled with oil, electricity, gas, or ambient air. None of the vaporizer systems is obviously the most economical or technically superior. The choice depends primarily on the location and design of a specific terminal and environmental regulations. The regasification facility is one of the least costly sections of the terminal, but is considered important because if it should fail to operate, the entire purpose of the plant—to provide natural gas —will have been defeated.

LNG TERMINAL SITING

There are several factors related to proposed LNG import terminals that set them apart from the existing peak shaving plants. The proposed terminals are large-scale operations located in the coastal zone and major shipping channels, some in major harbors-or near large population centers (figures 19 and 20). They require large amounts of land and capital, and represent a large concentration of energy at a single site.

Figure 19. Layout of Cove Point, Md., LNG Receiving Terminal

Source Columbia

LNG Corp

24 CH.

I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM

The location of a terminal can be a major factor in its safety. The magnitude and extent of any damage from an LNG spill can depend on the proximity of the terminal and storage sites to other industrial and residential areas. The site selection process is currently conducted by the company or consortium proposing the project. Gas industry officials consider such factors as accessibility by large tankers, the availability of the market, which is largely determined by the proximity of an existing pipeline network; costs of land acquisition; availability of skilled labor supply; and availability of public facilities such as roads, electricity, sewers, etc. Some companies also consider area land-use characteristics and environmental sensitivities important aspects of site selection. The FPC position is that, unless otherwise stipulated, FPC approval of the facility allows Federal preemption of State and local laws relating to siting. Therefore, local and State land-use regulations could be overruled. A company makes application to the FPC only after it has done as much preliminary work as possible, which includes at least gaining control over, if not outright ownership of, the proposed site. Thus, neither the general public nor the Federal Government become involved in the site selection decision until it has already been made by the company. There are, at present, no Federal siting criteria, and those projects which are now proposed have a variety of sites, ranging from remote coastal and riverine areas with 1,000-acre buffer zones to as little as a 90-acre site on Staten Island. LNG TERMINAL REGULATION The construction and operation of LNG terminals are primarily regulated by three Federal agencies; the Federal Power Commission (FPC), and the Office of Pipeline Safety Operations (OPSO), and the Coast Guard. Federal Power Commission jurisdiction over the terminals is included in the process of licensing import projects. The FPC considers approval of any LNG import project to be “a major Federal action significantly affecting the quality of the human environment” subject to the National Environmental Policy Act

requirement that an environmental impact statement (E IS) be prepared. As a part of the EIS, the National Bureau of Standards’ cryogenics division in Boulder, Colo., u n d e r c o n t r a c t t o F P C , r e v i e w s engineering and safety aspects of the proposed terminal. Also as part of the EIS, the FPC staff prepare a quantitative risk analysis, which is its principal method for determining whether a project can be considered safe. The risk analysis considers the major events which might cause an LNG spill, such as ship collision, grounding, or ramming; failure of the unloading arms or other major pieces of equipment; and damage to the facility from natural phenomena or unusual accidents. The risk analysis determines the extent of damage and the number of deaths and injuries which may result from a disaster and the probability that certain types of disasters would occur. The death probabilities from natural disasters are typically about 1 in 10 million. In some recent applications, the FPC rejected a site because it posed a public risk to life with a probability of greater than 1 in 10 million. Therefore, that figure has become the informal criteria which projects must meet for FPC approval. 36 The FPC exerts its influence over the facilities by attaching stipulations to the certification of public convenience and necessity which it issues if the project is approved. These stipulations are designed to minimize environmental consequences and to promote the safety of the facility. The applicant is required to comply with these stipulations if he accepts the certificate. Statements of compliance and operating reports are required regularly, but there is little or no post-certification oversight by the FPC. Onsite FPC inspection generally occurs only when a company wishes to expand its facilities and submits a new application. 37 aG1nterV& with staff of Woodward-Clyde Consultants, Washington, D. C., June 28, 1977, and Federal Power Commission, Alaska Natural Gas Transportation System, R“nal Environmental Impact Statement, Vol. 111, p. 425d and 4253. (Washington, D. C.: Federal Power Commission, 1976). 371nt,erview with staff of Federal Power Commission, Washington, D, C., May 31, and June 24, 1977.

CH. I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM 25 Figure 21. Storage and Diking at Onshore LNG Plant

Source El

Paso LNG Terminal Co

The safety of the terminal facilities is largely an OPSO responsibility. Under the Natural Gas Pipeline Safety Act of 1968, OPSO is responsible for establishing minimum Federal safety standards for all pipeline facilities in or affecting interstate or foreign commerce. Pipeline facilities have been given an extremely broad interpretation to include all components of an LNG import terminal, including the offloading facilities, storage tanks, regasification facilities and all associated pipelines. Permits are not required by OPSO, which exercises its authority solely by inspecting facilities for compliance with Federal stand-

ards. The standards are currently built around the safety code of the National Fire Protection Association, known as 59(A). In addition to setting minimum standards for materials, equipment, and systems the code relies upon two basic concepts to protect the public from LNG hazards: the requirement for a diking and containment system and the requirement that specific distances be maintained between certain components and between components and the property line. Dikes are the primary device used to prevent the uncontrolled spreading of an LNG spill on land (figure 21). The dikes make it

— —-—

26 CH.

—

I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM

possible to use either of two methods of control: ●

●

In the event of an LNG spill, the liquid can be contained within the dike and the rate of evaporation slowed by the use of high expansion foam. All sources of ignition can be eliminated. In this way, the LNG can dissipate in harmless concentrations into the atmosphere. Or, in the event of an LNG spill, the liquid can be contained within the dike and its evaporation controlled or even ignited so that it immediately burns in the confined space where the fire can be controlled by known firefighting methods.

The NFPA 59(A) regulations adopted by OPSO specify the size struction of the dike and the design equipment necessary for the diking

currently and conof related system.

The other technique used to enhance safety is to establish the distance which must lie between the dikes around the storage tanks and the property line. The distance required is one which would assure that heat from an LNG fire inside the dikes would not be severe enough at the property line to cause death or third degree burns. Current regulations require that this distance be 0.8 times the square root of the area inside the dikes.

pected that the proposed standards will seriously limit the choice of sites for LNG terminals. The Coast Guard’s responsibility for terminal facilities is an extension of the Captain of the Port’s jurisdiction over waterfront facilities. The Coast Guard maintains that its jurisdiction, with regard to LNG vessel movements and waterfront facilities, is sufficient to promulgate and enforce safety requirements for the LNG transfer operations at the receiving terminal and, in that light, considers the pipelines between tanks and loading or offloading equipment, the loading and offloading equipment, storage tanks, and the entire portion of the LNG system which connects the tanker to the distribution system to be under its jurisdiction. The inland distribution system is not the responsibility of the Coast Guard. The Coast Guard currently has no regulations specific to LNG terminals but has undertaken development of such regulations to implement appropriate sections of the Ports and Waterways Safety Act of 1972. In the meantime, the Captain of the Port in each area where LNG is handled exercises authority by developing contingency plans for operations. A critique of the Government role in the regulation of LNG terminal siting and operations is included in the following chapter.

Regulations also require that the facility be designed to meet the maximum earthquake specifications of the Uniform Building Code.

TRENDS IN LNG USE AND FACILITIES

New LNG terminal standards have been proposed by OPSO and are being circulated for public comment. Generally, the proposed standards are more strict and cover more aspects of terminal design than do current standards, but in many cases they are less definitive. The standards increase the distance between dikes and property line, require a vapor dispersion zone or a redundant automatic ignition system, and set more stringent seismic design criteria. 38 It is ex-

Liquefied natural gas could be an important short-term energy supply for the United States over the next few decades and could help alleviate some near-term fuel shortages in selected sectors of the economy. Ultimately, however, the supply of natural gas which may be sold to the United States as LNG is limited. LNG is not a major new source of energy which will allow unrestrained use of natural gas, and it is unlikely that many import projects will be forthcoming beyond those already proposed.

SNU.S. llepartrnent of Transportation, Office of Pipeline Safety Operations, “Liquefied Natural Gas Facilities (LNG); Federal Safety Standards,” Federal Register 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 expected that U.S. consumption of natural gas will continue to decline slightly and it is possible as much as 15 percent of the total natural gas consumed could be transported as LNG by 1985-95 (figure 22). This figure may be lower if a pipeline is used to transport Alaskan gas to the continental United States.

in Chile, Nigeria, and Colombia and there is a possibility of additional export projects if technology and reserves are proven in Russia, Iran, China, and Australia. 39 It is likely that sponsors of some U.S. import projects will turn to these exporters for additional supplies of LNG, thus reducing the dependency on Algeria.

Imports of LNG to the United States currently come from Algeria, and there is some concern about the wisdom of becoming dependent upon any one country as the major source of supply. However, several other countries also control major portions of the world’s natural gas reserves. For example, liquefaction and export facilities are being developed

Changes are also likely to occur in the sites chosen for U.S. import terminal facilities, in some types of equipment which may be used, and in the onshore distribution of LNG.

Figure 22. Projected Future LNG Imports (Based on Proposed Projects and Reasonable Approval Time) Percent of 1976 U.S. Natural Gas Consumption

Trillions of cubic feet per year

20%

4

15%

10%O

5 %

1977-80 Projects Constructed or Operating

1980-85 Planned Projects Approved or Pending Before FPC

1985-90 Possible New Projects

El Paso I Distrigas El Paso II Panhandle Pac/lndonesia Possible Future Supplies From USSR, Iran, and Nigeria Source OTA

Currently, public pressure exists for, and the industry trend is toward, “remote” siting of LNG terminals and storage facilities. Controversy over the meaning of remote and the characteristics which make a site acceptable for an LNG facility, coupled with the difficulty firms may have in finding acceptable sites, have led to the suggestion that LNG facilities could be located offshore, away from populated areas and congested harbors and waterways. Several designs have been proposed for offshore platforms to house LNG facilities, but no detailed design has been developed for any specific site. At the present time, these preliminary designs limit site selection to locations with water depths of 600 feet. Most of the design concepts are self-contained facilities which look like large floating barges installed to a mooring system (figure 23). Other concepts propose that the platforms be floated to a site, then grounded to the beach or seabed. There are also two other, more elaborate concepts: One would make use of subsea storage structures, similar to those used in the North Sea to store oil, with a semisubmersible or tension-leg concrete platform moored above for the liquefaction or regasification plant. The other features separate moored or jack-up platforms for the process plant and the storage structures. According to industry figures, offshore facilities will require 3 to 4 years construction time. Crude estimates range from $175 million 39JJLNG Report, ’ ~“peline and Gas Journal 204 (June 1977).

28 CH.

I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM

Figure 23.

Artist’s Rendering of Offshore LNG Terminal

to $220 million for a receiving terminal with a

500 million cubic feet plant and storage for and from $350 million 500 million cubic feet plant.

per day regasification 200,000 cubic meters to $425 million for a per day 40 liquefaction

There are many designs for LNG tankers and onshore facilities. However, with the 4{)1bid.

limited operating experience now available, no particular designs for either ship cargo systems or onshore storage facilities have yet emerged as obviously superior. Therefore, it is likely that a variety of equipment will come into use as more projects are approved. It is also possible that increased use of LNG will result in increased onshore transportation of LNG to secondary markets by means other than pipeline. Although the proposed

CH. I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM baseload import terminals have no specific provisions for truck and rail shipment of LNG, such shipments appear to be possible and permissible in the future. Shipment by truck is already a reality at most peak shaving operations and from the import terminal at Everett, Mass. Prior to 1969, only a few LNG trucking operations had been attempted in this country, using equipment originally designed for liquid nitrogen service. Based on the success of the operations, equipment was designed and fabricated especially for LNG. It is estimated that there are 75 LNG trucks currently in operation in the United States. 41 Typical of the trucking which has taken place was the shipment of nearly 4.5 million gallons of LNG from Philadelphia, Pa., to Lowell, Mass., during the winter of 1969. Since then large volumes have been transported all over the United States to help supply outlying communities, to provide temporary supplies when service is interrupted, and to provide small quantities for experimental work. Liquefied natural gas could also be moved from import terminals or liquefaction plants by barges or railway tank cars. The use of barges was first proposed to transport LNG up the Mississippi River to the Chicago Union Stockyards, and one barge was constructed and tested for this purpose in the 1950’s. It was never used commercially. Another barge, the 297-foot Massachusetts, was constructed by Distrigas for distributing LNG from a Staten Island import terminal. However, that barge has been taken out of service because of opposition. Railway tank cars have been proposed as a means of carrying LNG to isolated areas which do not justify construction of pipelines. Tank cars now in use hauling liquid oxygen, nitrogen, and hydrogen would be suitable for LNG service, but the economics are such that it is unlikely there would be much emphasis on rail movement of LNG.

,

~ I Interviews with officials of Distrigas Inc., Boston, Mass., June 15, 1977.

29

EXISTING AND PROPOSED PROJECTS, IN BRIEF

There are two operating LNG marine transport projects in the United States today, the “Distrigas” project importing gas from Algeria into Everett, Mass., and the “Phillips/Marathon’ project exporting gas from Alaska to Japan. Construction of the first large baseload import project to be approved by FPC, “El Paso I,” is nearing completion, and the facility is expected to become operational early in 1978 importing gas from Algeria to both Cove Point, Md., and Elba Island, Ga., (near Savannah). 42 One additional large import project has recently been given final approval by FPC, but no construction has begun. This is the “Trunkline’ project to import LNG from Algeria to Lake Charles, La. 43 The “PacificIndonesia’ project to import LNG from Indonesia to Oxnard, Calif., 44 has received only initial FPC approval and no construction has begun. Three additional projects have been filed with the FPC for some time and decisions or approvals are expected soon. These are: the “El Paso II*’ project to import LNG from Algeria to Port O’Connor, Tex., the “PacificAlaska” project to transport LNG from Cook Inlet in southern Alaska to California; and the “El Paso-Alaska” project to transport the huge North Slope Alaska gas reserves from Gravina Point, Alaska (after pipelining from the North Slope) to California. 45 Since these eight projects have a reasonable probability of being operational in the future (the early 1980’s), a brief description of each is included in this section. Other planned or proq~Dean Hale, “Cold Winter Spurs LNG Activity,” Pipeline and Gas Journal 204 (June 1977): 30. q:~Federal Power Commission, TrunkZine LNG Cornp a n y et al., O p i n i o n N o . 7 9 6 - A , D o c k e t N o s . CP74-138-140 (Washington, D. C.: Federal Power Commission, June 30, 1977). ~~Federal Power Commission, “FPC Judge Approves Importation of Indonesia LNG,” News Release, No. 23292, July 22, 1977. ~~Dean Hale, “Cold Winter Spurs LNG Activity,”: 31.

30 CH.

I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM

posed projects have not been included for various reasons. For example: the “Eascogas’ project which was planned for Staten Island, N. Y., and Providence, R. I., terminals has been delayed so many times that its viability is in question. A project planned by Tenneco to import gas from Algeria to St. John’s, N. B., in Canada, and then pipe the gas to the United State 46 is now in the early review stages by FPC. Another recently announced project is one by the Peoples Natural Gas Company of Chicago to import LNG from either Iran or Chile to a terminal near Corpus Christi, T e x . 47 AGIbid., p. 31. ATFederal Power Commission, “NGP-LNG Inc., Application and Request for Phased Proceeding,” Federal Register 42, No. 131, July 8, 1977.

This report reflects the situation as of the summer of 1977. Many other projects are in the early planning states. Many factors affect these plans, however, and changes are common prior to actual construction of facilities. 1. The Distrigas Project (figure 24) This project has been in operation since 1971. The 50,000 cubic meter LNG tanker D e s c a r t e s is now on a regular delivery schedule on approximately a 20-day cycle. 4 8 The ship, which was built in France in 1971 and operates under the French flag, 49 h a s A~Interviews with officials of Distrigas Inc., Boston, Mass, June 15, 1977. AgU.S. Department of Commerce, Maritime Administration, Status of LZVG Vessels (Washington, D, C.: U.S. Department of Commerce, March 1977).

Figure 24. Project Data Sheet: Distrigas Import Source: Skikda, Algeria Import Terminal: Everett, Mass.

Companies revolved

Location of u s terminal

Project designation

Expected operational date

Contract volume Bcf/yr (M Mcfd)

FPC status (as of 9/1/77)

Number Ships/ Estimated investment ($106) Estimated Shipyard/ price ($) 3 Capacity m / Receiving delivered into Tank design Tankers terminal pipeline/MMBtu — —

Supplier. Sonatrach (Algerian National Gas Co ). Shipper. Alocean (Sonatrach subsidiary).

U S. Importer: Distrigas Corp Distributors: Various gas companies in New England, New York, and New Jersey Supplier. Sonatrach. Importer Distrigas (Project pending),

Everett, Ma,

Distrigas I

Operational 16 since 1971 (43 6)

Everett, Ma,

Distrigas Ill

1977 (1,5 16 total yr. supple- (43.6) mental contract)

Everett, Ma,

Distrigas 2

1978

Iv

Storage capacity Regasification Type of storage Number of Terminal (MMcf) capacity (MMcfd) containers storage tanks acreage —

135

1972,

Reopened 1974, Approved 1977

CURRENT IMPORT TERMINAL CHARACTERISTICS

3250

Approved

Aboveground 9% nickel steel

– -

2

37

1/Chantier- — Atlantique l (France)/ 50,000 m3/ membrane

33

1.90

—

2.80

—

2.91 9–lo (added investment)

Pending

42 (115)

Filed Feb. 1977

1/ChantiersCiotat (France)/ 125,000 m3/ Spherical free-standing

1 The 50,000 cubic meter ship “Descartes’ wiII be taken out of service upon arrival of the latest contract (Distrigas IV). The Distrigas I and Ill projects will be phased into the Distrigas IV project when the latter commences

2

Source OTA

CH. I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM 31 and total import volume has been filed and is pending approval by FPC. Under the terms of a new 20-year contract with the Algerian National Gas Company, Distrigas would import 42 billion cubic feet of gas per year beginning in 1978. 53 This contract would replace the existing one and a new 125,000 cubic meter ship, the Mostefa Ben Boulaid, would be used in place of the Descartes. Additional unloading facilities, but no new storage tanks, are planned for this expansion. 54

been delivering LNG from Skikda, Algeria, to the terminal at Everett, Mass., at the rate of about 15 trips each year. The terminal is located on the Mystic River, up from the main Boston harbor and less than one-half mile from the Boston city limits, in a highly industrialized region with both LPG and gasoline terminals adjacent to the property. so The Everett facility has operated without major incident for 6 years. The principal market for this LNG is the Northeastern States with distribution made by both truck and pipeline. At present 40 percent of the LNG is distributed by trucks and more than 60 trucks operate out of the facility to other satellite storage tanks in the Northeast. 51 The Distrigas project has contracted for a supply of 16 billion cubic feet of gas per year, and in 1976 actual imports totaled slightly over 10 billion cubic feet. 52

2. The Phillips/Marathon Project (figure 25) The oldest operating marine LNG project in the United States is the project now exporting gas from fields in Cook Inlet in southern Alaska, through a terminal at Kenai, to Neigishi, Japan. This project has been operated by the Phillips Petroleum Company and Marathon Oil Company since 1969.

While this project has received FPC approval, a modification to expand the terminal

Two 71,500 cubic meter LNG tankers, the

~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).

30.

~:~Dean Hale, “Cold Winter Spurs LNG Activity,”: ~qlnterViews with officials of Distrigas Inc., Boston,

Mass, June 1

Figure 25. Project Data Sheet: Phillips/Marathon LNG Export Source: Kenai, Alaska (Plant at Nikiski) LNG Export Terminal: Neigishi, Japan Kenai to Neigishi – 3,280 nmi I

— —-

Companies Involved

Location of u s facility

Expected operational date

Project — designation

Contract volume Bcf/yr (MMcfd) .

FPC status (as of 9/1/77)

Number Ships/ Estimated Investment ($10°) Shipyard/ — — — Capacity m3/ Receiving Exported price Tank design Tankers terminal ($)-1976 /MMBtu

Gas Supplier: Phillips

and Marathon Plant. Operator: Phillips Petroleum Shipper: Marathon Oil. Importers Tokyo Electric, Tokyo Gas.

Kenai. Alaska

Phillips/ Marathon

—

Operational 49,3 since 1969 (135) 1 5-year contract) —

Approved

2/K, M, – Verkstads (Sweden)/ 7 1 , 5 0 0 m3 / – membrane

— 1 66

CURRENT EXPORT SOURCE CHARACTERISTICS Storage capacity

Liquefaction

(MMcf)

capacity (M Mcfd) —

2300

185

Type of storage Number of containers Aboveground aluminum

Facility storage tanks acreage 3 Source OTA

32 CH.

1 – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM the Jones Act prohibiting the use of foreign flag tankers in U.S. trade. A French-built 3,5,000 cubic meter tanker, the Kenai Multina, flying the Liberian flag was used. 57 This project contract expires in 1985. Beyond that, application may be made to bring the gas to southern California.

Arctic Tokyo and the Polar Alaska, were built in Sweden and operate under the Liberian flag with Italian crews. 55 The contract to supply Tokyo Electric and Tokyo Gas companies is for 135 billion cubic feet of gas per year, and in 1976 about 50 billion cubic feet were actually delivered. 56 This project has operated without a major problem since initiation.

3. The El Paso I Project (figure 26) The agreement between El Paso Natural Gas Company and Sonatrach (Algeria) will lead to the initial transport of the LNG

During the extreme winter of 1977 a special delivery of one shipload of LNG was made to Everett, Mass., from Alaska, after a waiver of MU.S. Ilepartrnent of Commerce, Maritime Administration, Status of LNG Vessels. sGFederal Power Commission, United States Imports and Exports of Natural Gas 1976.

s~ean

Hale, “Cold Winter Spurs LNG Activity ”,:

21.

Figure 26. Project Data Sheet: El Paso I Import Source: Arzew, Algeria Import Terminal: Cove Point, Md. and Elba Island, Ga. Arzew to Cove Point– 3,570 n mi Arzew to Savannah – 3,77o n mi I

Companies involved — Suppliers: Sonatrach (Algerian National Gas Co. ) Shipper: El Paso Algeria Corp.

Location of u s terminals

Project designation ——

Expected operational dale

Cove Point, Md

Contract volume Bcf/yr (MMcfd)

FPC status (as of 9/1/77)

3/ChantiersDunkirk Approved (France)/ 1972, 125,000 m3/ 1973: membrane Reopened 1974

3651 (1000)

Cove Point purchasers: Consolidated System

LNG Co and Columbia LNG Co. (also operators) Elba Island purchasers: Southern Energy Co (also operators) Drstributors Columbia Gas Transmission Corp., Consolidated Gas Supply Co., Southern Natural Gas Co

El Paso I

Number Ships/ Estimated Investment ($106) Estimated price ($) Shioyard/ .-—————–— Receiving delivered iinto Capacity m3/ Tank design terminal pipeline/MMBtu Tankers

1978

Approved 1-1977

Elba Island, Ga.

350

1.66-181

(Cove Point)

3/Avondale 1100 for all (U.S.A.)/ 3 125,000 m / 9 ships Free-standing Prismatic

127

1.70

(Elba Is, )

3/Newport (U.S.A.)/ 125,000 m3/ Technigaz membrane

CURRENT IMPORT TERMINAL CHARACTERISTICS Storage capacity Regasification Location

(MMcf)

capacity (MMcfd)

Cove Point, Md.

5000

1000

Elba Island, Ga.

4000

325

1 —

Type of storage containers

Number of storage tanks

Terminal acreage

Aboveground, aluminum

4

60 (plant, structures) 300 acres allocated 1100 acre tract 150 acres allocated 800 acre tract

—

3

I

Of this amount. Cove Point shall receive about two-thirds, Elba Island one-third

Source OTA

CH. I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM 33 equivalent of 1 billion cubic feet per day (365 billion cubic feet per year) of natural gas to the United States. The Columbia Gas System, along with the Consolidated Gas System, has entered into contract for some two-thirds of this gas. The LNG will be delivered to a terminal located on the Chesapeake Bay at Cove Point, Md. The terminal will be jointly owned by Columbia and Consolidated and will become operational early in 1978. The remainder of LNG will be delivered to Southern Natural Gas at a new terminal under construction on Elba Island, Ga. 58 The Cove Point terminal has two tanker berths, four storage tanks and several process areas. The two tanker berths are located about 1 mile offshore along a 2,500-foot pier which is connected to shore by an underground tunnel containing both LNG pipes and vapor return lines. The initial operating plans call for about 140 ship arrivals per year. The Cove Point facility is located on a 1,100-acre tract of land along the Chesapeake Bay in Calvert County, Md. 59 The gas will be piped from Cove Point to an existing pipeline in Loudoun County, Va., and then to markets in middle Atlantic States served by Columbia and Consolidated Natural Gas Companies. The Elba Island terminal is on an 800-acre site of undeveloped land, wholly owned by Southern Natural Gas. It is located 5 miles downriver from Savannah, Ga., and will supply gas to southeastern U.S. markets. This LNG is expected to represent about 15 percent of Southern Natural Gas sales when the terminal is operational. It is planned that 50 LNG tankers will call at the Elba Island terminal each year, substantially increasing the ship traffic at the Savannah port entrance. GO

Wbid., p. 30. ~gMax Levy, “The Cove Point, Maryland LNG Terminal,” Conference on LNG Importation and Terminal Safety, Boston, Mass., June 13-14, 1972. GoSouthern Natural Gas Company, Facts on Elba Island, Savannah, Georgia LNG Terminal, (n. p.: Southern Natural Gas Company, n.d. ).

Nine 125,000 cubic meter LNG tankers are to be used to serve both El Paso I terminals. Three tankers were built in France, are now completed and laid-up, and are planned to be operated by El Paso under the Liberian flag. Six others are under construction at two U.S. shipyards (Avondale and Newport News), and are planned to be operated by El Paso under U.S. flag. 6l The entire project is about 2 years behind schedule. The principal technical problem was completion of the large liquefaction facilities in Algeria. After one U.S. contractor failed to perform, the Algerian National Gas Company canceled the contract and hired a new contractor. The U.S. terminals and the U.S.-built tankers are now almost completed, after a slow-down to await completion of the Algerian terminal. The present schedule is for LNG shipments to begin in January 1978. 62 The FPC approved the El Paso I project in June 1972. 4. The “Trunkline’’Project (figure 27) The Trunkline project was approved by FPC on June 30, 1977, after an appeal of an initial opinion in April. 63 The proposed LNG facility would be near the Lake Charles Harbor in Louisiana and within the Terminal District Industrial Park. It would be located on a 139-acre site and would be used to unload, store, and ship LNG imported from Algeria. The LNG terminal would consist of a berthing dock for LNG unloading, an onshore facility consisting of three 600,000-barrel LNG storage tanks surrounded by a dike, two 25,000-gallon liquid nitrogen storage tanks, one 250,000 Bunker C fuel-oil tank for servicing the LNG tankers, and a process area which would contain equipment for all LNG transfer operations. GIU.S. Department of Commerce, Maritime Administration, Status of LNG Vessels. 621bid. 63Federal Power commission, Trunk/ine LN(j corn.

pany et al., O p i n i o n N o . 7 9 6 - A , D o c k e t N O S. CP74-138-140 (Washington, D. C.: Federal Power Commission, June 30, 1977).

——

34 CH. I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORTS SYSTEM

Figure Project Import Import

27. Data Sheet: Trunkline Source: Arzew, Algeria Terminal: Lake Charles, La. FPC

Contract Companies Involved

Location of u s terminal

Terminal builder & operator Trunkline LNG Co

Project designation -

Supplier Sonatrach (Algerian National Gas Co. )

Lake Charles, La

-

‘- “

Number Ships/ Estimated investment ($106)

Estimated

Expected operational date

–

“Panhandle’ ‘‘Trunkline” ‘‘Calcasleu’

1980-81 3/125,000 m3/ shipyard & design not known

Buyer & distributor Trunkline Gas Co (Subsidiary of Panhandle Eastern Pipeline Co) Market Illinois. Indiana, Michigan, Ohio (primarily) CURRENT . . IMPORT TERMINAL CHARACTERISTICS Storage capacity Regasification Type of storage Number of (MMcf)

capacity (MMcfd)

containers

6000

540

Above-ground, aluminum

Terminal storage tanks acreage 3

75 (plant, structures) (139 acre site)

Ancillary facilities would include offices, equipment for wastewater treatment, fire control and detection, fire protection equipment, water supply, electrical power, and communications. 64

The project is planned for importing 179 billion cubic feet of gas per year using five 125,000 cubic meter LNG tankers. The tankers would reach the facility at the arrival rate of 65 per year through a 24-mile channel from the Gulf of Mexico.65 Subsidiaries of Panhandle Eastern Pipe Line Company, G e n e r a l D y n a m i c s , a n d Moore-McCormack Bulk Transport, Inc., have formed a partnership, Lachmar, to build, own, and operate two of the ships. These two 6 4 Federa] power commission, Flnaz ~nuironmental Impact Statement Calcasieu LNG Project Trunkline LNG C o m p a n y D o c k e t N o . CP74- 138 et al., (Washington, D.C.: Federal Power Commission, September 1976). b51bid.

Source OTA

ships are to be built at General Dynamics’, Quincy, Mass., shipyard. The three other vessels for this project are expected to be provided by the Algeria National Shipping Comp a n y .66 5. The “Pacific Indonesia” Project (figure 28) In an initial decision on July 22, 1977, an FPC Administrative Law Judge approved a proposal to import 200 billion cubic feet of gas per year from Indonesia to a terminal in Oxnard, Calif. The decision is subject to Commission review. 67 There is considerable controversy in California over the site, and some State legislation on siting is pending. GGDean Hale, “Cold Winter Spurs LNG Activity,”:

30. ~TFederal Power Commission, “FPC Judge Approves Importation of Indonesia LNG.”

CH. I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM 35

Figure 28. Project Data Sheet: Pacific-Indonesia Indonesia

Oxnard, Ca Sumatra,

Sumatra 10 Oxnard – 8,300 n ml

Project designatlon

PacificIndonesia Project

Expected operational date

48 months

Contract volume Bcf/yr (MMcfd)

200

after approv- (550)

al (Liquefaction facilities m Indonesia under construction)

FPC status (as of 9/1/77)

Number Ships/ Estimated investment ($106 Estimated Shipyard/ — price ($) 3 ‘Receiving Capacity m / delivered into Tank design Tankers terminal pipeline/MMBtu

Initial approval

155 per 61U.S.A.)/ 1 2 5 , 0 0 0 m 3 / U S Tanker shipyard & tank design not known

6-77, subject to review 2/ ChandlersAtlantique (France)/ 125,000 m3/ membrane 1/ChantiersCiotat/ 125,000 m3/ Free standing spherical

270

306-360

PROPOSED IMPORT TERMINAL CHARACTERISTICS . capacity Regasification Type of storage Number of Terminal containers storage tanks acreage (MMcfi) capacity (MMcfd)

Storage

7700

4600

Above-ground, 90/0 nickel steel

—

4

Plant, -

structures 38 (ultimately 55) 21 O-acre site

The proposed Oxnard facility would be owned and operated by Western LNG Terminals. It would be located on a 210-acre site in the City of Oxnard, on the coast of California. This plant would import LNG at a rate of 546 million cubic feet of gas per day for markets within the State of California. The LNG storage and vaporization facilities would occupy 38 acres of the site containing two to four 550,000-barrel, double-wall, above-ground tanks, 240-feet in diameter with an overall height of 129 feet. The plant facilities would require 55 acres of the site, and the marine terminal would occupy 34 acres of leased subtidal land extending approximately 6,000 feet offshore at Ormand Beach. Unloading arms at the marine terminal would

Source OTA

transfer the LNG from the ship to the storage facilities through 42-inch cryogenic pipes. 68 Liquefaction facilities in Indonesia are now under construction. Conditional agreements have been reached with shipping companies for nine 125)000 cubic meter LNG tankers. Pacific Indonesia will charter the ships, three of which will be French built and the remaining six U.S. built. 69 No U.S. ship construction contract has been announced. 68 Federa] power commission, Final Environmental Impa et Sta tern en t Pacific Indonesia Project (Washington, D. C.: Federal Power Commission, December 1976). fi~u.s. Department of Commerce, Maritime Administration, Status of LNG Vessels.

36 CH.

I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM

6. The El Paso II Project (figure 29)

7. The “Pacific-Alaska’’ P roject

(figure 30) The El Paso II project is pending before the FPC. The proposal is to transport 365 billion cubic feet of gas per year from Algeria to a new facility at Port O’Connor, Tex. TO A fleet of twelve 125,000 cubic meter LNG tankers would be required. It is planned that six of these would be U.S. flag and U.S. built, but no construction contracts have been announced. 71 Safety reports have been submitted and FPC hearings were held during the summer of 1977. Draft and final environmental impact statements have been issued. 72

A project to transport LNG from Cook Inlet gas fields near Kenai, Alaska, to California is pending before FPC. 73 A terminal is planned at either Oxnard or Los Angeles, Calif. Questions of terminal siting now being addressed by the State of California are delaying some decisions on this project. It is planned that initially two 130,000 cubic meter tankers would be used to import 73 billion cubic feet of gas per year. Sun Shipbuilding Company has signed contracts for these ships with an affili-

~[~Federa] Power Commission, Algeria 11 Proj”ect Outline of Contracts, El Paso Eastern Company, et al., Docket No. CP77-330, et al. (Washington, D. C.: Federal Power Commission, n.d. ) ~IU.S. Department of Commerce, Maritime Administrate ion, Status of LNG Vessels. ~~Federal Power Commission, Joint LNG Safety Report of El Paso Atlantic Company et al., Respecting the Proposed Algeria II Project, Docket No. CP73-258, et al. (Washington, D. C.: Federal Power Commission, Apr. 1, 19’77).

Figure Project Import Import

~JDean Hale, “Cold Winter Spurs LNG Activity,”: 31.

29. Data Sheet: El Paso II Source: Algeria Terminal: Port O’Connor, Tex. Arzew to Port O'Connor — 5024 n mi Location of u s terminals

Companies Involved (project status)

Supplier Sonatrach (Algerian National Gas Co. ) Shipper El Paso Atlantic co Receiver El Paso Eastern Co Distributors El Paso, LNG Terminal, United Gas Pipeline.

Port O’Connor, Tx. Matagorda Bay

Project designation

Expected operational date

El Paso II

1982-83

FPC status (as of 9/1/77)

Number Ships/ Estimated Investment (S106) Estimated Shipyard/ price ($) 3 Capacity m/ Receiving delivered into Tankers terminal Tank design pipeline/MMBtu

Pending

12 125,000 m3, shipyard & tank design not known

Contract volume Bcf/yr (MMcfd)

365 (1 000)

—

——.

2,000

457

—

. ————.

CURRENT IMPORT TERMINAL CHARACTERISTICS Storage capacity Regasification Type of storage Number of capacity ( MMcfd) (MMcf) containers storage tanks —

—

4168

—

Aboveground

3

Terminal acreage Source OTA

CH. I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM 37

ate of Pacific Lighting Company, but no construction has started. 74 8. The “El Paso--Alaskan’’ Project (figure 31) This project is one of the proposed transportation systems to deliver gas from the major Alaskan North Slope fields to the lower 48 States. While the other systems involve gas pipelines through Canada, this project proposes a gas pipeline from the North Slope along the present oil pipeline route to southern Alaska, A liquefaction facility would be built at Gravina Point, Alaska, and an initial fleet of eight 165,000 cubic meter LNG 7 4 Feder

a

1 power

c Ommission, ~ecom mendatzon t.

the President Alaskan Natural GUS Transportation Systems (Washington, D. C.: Federal Power Commission, May 1, 1977). 96-597 0-77 -4

751 bid,

38 CH.

I – DESCRIPTION OF LNG TECHNOLOGY AND IMPORT SYSTEM

Figure 31. Project Data Sheet: El Paso-Alaska LNG Source: Gravina Point, Alaska’ LNG Terminal: Oxnard, Ca. and/or Point Conception, Ca.

Companies revolved (project status)

Location of u s terminals

Project designation

Liquefaction plant budder O x n a r d , and shipper El Paso Ca Alaska Co and for

1

PROPOSED LNG SOURCE AND TERMINAL CHARACTERISTICS Location

Iiuefactlon or Storaqe capacity reqasification Type of storaqe Number of (MMcf) capacity (MMcfd) containers - storage tanks

7700

4600

Aboveground 9% nickel

Point Conception, Ca.

7700

3300

Source Gravina Point, Ak.

6000

3375

Aboveground 9% nickel Aboveground 9% nickel

Terminals Oxnard, Ca.

Under the Alaska Natural Gas Transportation Act of 1976, the President is required to recommend to Congress on the selection of the best transportation system and Congress will then have 60 days to review this recommenda-

4

Terminal acreage

I I I

2

via pipeline from the North Slope Not the ultimate (combined) terminal , which will have an estimated cost of $460 million

38-55 (210 acre

site) 4 1000 acres

4 Source OTA

tion. The President’s recommendation was announced in favor of a trans-Canada gas pipeline on September 8, 1977, but formal recommendation had not yet been made to Congress at this printing.

9/25/12

Liquefied Natural Gas | Energy Sector

Natural Resources Canada Liquefied Natural Gas What is LNG? LNG in North America LNG Supply Chain Where Does LNG Come From? Where is LNG Delivered? Canadian LNG Import & Export Projects Update Reports

What is LNG? LNG is simply natural gas in its liquid state. When natural gas is chilled to a temperature of about minus 160° C (minus 260° F) at atmospheric pressure, it becomes a clear, colourless and odourless liquid. LNG is non-corrosive and non-toxic. The liquefaction process removes water, oxygen, carbon dioxide and sulfur compounds contained in the natural gas. This results in an LNG composition of mostly methane 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 and economical to transport over long distances in specially designed ocean tankers. Once received, the LNG 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 both domestic and foreign sources of natural gas. Domestic LNG is produced, liquefied and stored in North America. Marine, or imported LNG, is foreign-produced natural gas, which is liquefied abroad and transported to North America via ocean tankers. North America accounts for a relatively small portion of worldwide LNG demand, as it is largely selfsufficient in terms of natural gas production. In 2009, Canada received its first ever shipment of LNG, 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, its role in North America’s energy future remains uncertain. In the early 2000's, optimistic projections about 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 or cancelled on account of the following: 1. Low natural gas prices, 2. Weak industrial demand, and www.nrcan.gc.ca/energy/sources/natural-gas/1608

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Liquefied Natural Gas | Energy Sector

3. Massive U.S. shale gas production. Canada currently has one operating LNG import facility, the Canaport terminal in Saint John, New Brunswick. 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 of Canadian projects). Despite the current economic downturn, energy demand is expected to increase over the long-term and global LNG production is also expected to grow.

LNG Supply Chain The LNG supply chain (as illustrated in the figure below) consists of several interconnected elements.

In LNG exporting countries, natural gas is extracted from basins and transported by pipeline to liquefaction 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 for transport overseas. After tankers deliver the LNG cargo to import terminals, the LNG is stored, regasified 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 to economically develop their natural gas reserves. 18 countries currently produce and ship LNG: Algeria Australia Brunei Egypt Equatorial Guinea Indonesia Libya Malaysia Nigeria Norway Oman Peru Qatar Russia Trinidad and Tobago United Arab Emirates www.nrcan.gc.ca/energy/sources/natural-gas/1608

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Liquefied Natural Gas | Energy Sector

The United States* Yemen * Since the 1970s, small quantities of LNG have been produced in Alaska by Kenai LNG (located in Cook Inlet) for export to Japan

Where is LNG Delivered? At present, 19 countries import LNG: Argentina Belgium Canada China Dominican Republic France Greece India Italy Japan Mexico Portugal Puerto Rico South Korea Spain Taiwan Turkey The 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, or 2) 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 consult the Canadian LNG Import and Export Projects Update

Reports The reports below provide additional information on LNG. Liquefied Natural Gas: Properties and Reliability Liquefied Natural Gas Regulatory Requirements Date Modified: 2011-02-24

www.nrcan.gc.ca/energy/sources/natural-gas/1608

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Home » Oil and Gas » What is LNG?

What is LNG - Liquefied Natural Gas?

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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 well field, liquefied, stored and loaded onto LNG carrier ships. At the regasification terminal (right) LNG is offloaded into storage tanks, regasified and 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 temporarily converted into a liquid. This is done to save space - 610 cubic feet of natural gas can be converted into a single cubic foot of LNG. Converting natural gas into LNG makes it easier to store and easier to transport where pipelines are not available. A refrigeration process is used to condense natural gas into LNG by cooling it to a temperature of minus 260 degrees Fahrenheit. This refrigeration process is usually accompanied by treatments that remove water, carbon dioxide, hydrogen sulfide and other impurities. To maintain this low temperature during storage and transport, LNG must be placed into cryogenic tanks - heavily insulated tanks equipped with refrigeration units.

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When a shipment of LNG reaches its destination or when LNG is being removed from storage it must be regasified. This is done by heating the LNG and allowing it to evaporate back into natural gas. Regasification is usually done at a facility where the gas can be placed into storage or directly into a pipeline for transport.

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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Liquefaction and Regasification Terminals There are two types of LNG terminals: 1) terminals that convert natural gas into LNG, and, 2) terminals that convert LNG back into natural gas. These are called liquefaction terminals and regasification terminals, respectively. Liquefaction terminals are on the export side of transactions and regasification terminals are on the import side of transactions. Liquefaction terminals generally receive natural gas by pipeline from a well field. Before it is liquefied the gas must be cleaned of water, carbon doixoide, hydrogen sulfide and other impurities that might freeze, become corrosive or interfere with the liquefaction process. Once liquefied the LNG is sent by pipeline to a LNG carrier ship or into storage to await transport. Regasification terminals receive natural gas - usually by ship - from other areas. At a regasification terminal the LNG might be temporarily stored or sent directly to a regasification plant. Once regasified it is sent by pipeline for distribution or placed in temporary storage until it is needed.

The Changing Role of LNG in the United States As recently as 2008, demand for natural gas in the United States greatly exceeded domestic supplies. To meet demand, a large amount of natural gas was imported by pipeline from Canada and several terminals to receive liquefied natural gas from Africa, South

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LNG Safety Consulting Hazard and Risk Assessment, Public Communication, Training w w w .iomosaic.com

Fracking In Canada Fracking Is A Safe Government Regulated Technology. Get The Facts morefactslessfriction.ca

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Regasification Terminal: Fos-sur-Mer, France

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LNG - Liquefied Natural Gas: Import Export several terminals to receive liquefied natural gas from Africa, South America and the Middle East were built or planned on the eastern and Gulf coasts of the United States. Construction costs for each of these terminals was billions of dollars. Then, the use of hydraulic fracturing and horizontal drilling caused an enormous surge in the production of domestic natural gas. A flood of new production from shale plays such as the Marcellus, Haynesville, Fayetteville, Barnett and others overwhelmed the market. Domestic natural gas prices fell from over ten dollars per thousand cubic feet down to below two dollars. The terminals built to receive the liquefied natural gas are now underutilized or idle. Now, several companies are working to convert the LNG import terminals into terminals suitable to export gas. Their goal is to move the gas to Asian markets where prices are much higher. Although this sounds like a fantastic idea, a tremendous amount of gas has recently been discovered off Australia, Indonesia and Southern Asia. These areas have a significant transportation advantage over shipments leaving the Atlantic or Gulf coast of the United States. Converting the US import terminals into export facilities is a gamble without long-term contracts.

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Google Map of the Gaz de France LNG regasification terminal located at Fos-sur-Mer, France. View Larger Map

Liquefied natural gas is a very dynamic business and there is always interesting news about LNG.

Where is LNG Produced?

Marcellus Shale

The world's first large shipment of liquefied natural gas occurred in 1964 when a ship was loaded with LNG in Algeria and sailed for Le Havre, France. Prior to 1964, natural gas in Algeria was

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a waste product of oil production. It was a "waste product" because there was no local market for natural gas and no pipeline to transport the gas to a San Andreas distant market. The natural gas Fault was either vented into the atmosphere or flared at the well The Only site. This waste of natural gas Diamond Mine in and degradation of the the USA atmosphere continues today where 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 far exceeds the consumption abilities of local markets. In these locations the price of natural gas is low because there is an abundant supply with little local demand. That low price offsets the expenses of building an LNG liquefaction plant, converting natural gas into LNG and 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 to domestic fossil fuel resources. LNG gave them access to a cleanburning fuel that was easy to distribute once pipelines were in place. Many other countries now have regasification terminals. These include: 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 specially designed to hold a cold-temperature liquid. Most tanks are doublewall with an outer wall of thick concrete and an inner wall of high quality steel. Between the walls is a thick layer of highly efficient insulation. Many facilities have underground storage tanks for increased insulation. No matter how well the tanks are insulated some LNG will boil off and evaporate as natural gas. This gas is generally removed from the tank. It is either used on-site as a fuel or refrigerated back to the liquid state and returned to the tank.

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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 regasification 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 Japan have an agreement to build... China & Singapore Investing $1B in Cheniere LNG?: Cheniere Energy Partners may have two new major... More Debate on Exporting Natural Gas: An article in Bloomberg Businessweek explores many arguments... Debate: Export LNG?: Several companies have applied for permission to export... Hawaii as a Natural Gas Customer?: Hawaii imports all of its fossil fuels, however,... LNG from East Africa?: Several big natural gas discoveries in the Indian...

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LNG - Liquefied Natural Gas: Import Export

How is LNG Transported?

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Most LNG is transported in specially designed ships known as "LNG carriers". These ships have double hulls to protect the cargo from damage and as a safeguard against leaks. Smaller quantities of LNG are transported in specially designed trucks and railcars.

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Environmental Impact of LNG Marcellus Shale

Natural gas has a much lower environmental impact when it is burned than other fossil fuels. It emits less carbon dioxide, less particulate matter and produces less ash. Although LNG is burned in the form of natural gas it has a greater environmental impact than natural gas that has not been liquefied. This is because LNG requires an expenditure of energy to liquefy, transport and regasify.

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After these impacts are considered, LNG has a greater environmental impact than natural gas but generally has a lower impact than burning coal or oil. If one considers that the LNG might have been flared at the source as a waste product the environmental impact is lowered.

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Public Support and Opposition to LNG Terminals Public support for LNG projects is generally mixed - especially on the import side where large numbers of people may be located near the regasification facility. Although some people hope that LNG will bring them a reliable source of economical natural gas, others have concerns that the regasification plant or the transport vehicles might explode or catch fire. Some people are also concerned that LNG facilities are terrorist targets. Although LNG has an excellent history of safety, these concerns can not be assigned a probability of zero.

The Geography of Natural Gas The geography of natural gas is constantly changing. New natural gas discoveries, new pipelines and new LNG terminals can boost local supplies. An increase in local supply can lower prices which can stimulate demand. Growing demand can raise prices, stimulate drilling activity, launch pipeline projects and attract investments in LNG facilities. The geography of natural gas is dynamic.

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LNG Daily is essential reading as LNG supply dynamics continue to change in big markets like Japan, China, India and the U.S. This premier independent news publication for the global LNG industry gives readers information on every aspect of the global market from new LNG supply projects to gas quality issues. Features LNG Daily gives you the edge by providing: Information on new LNG supply projects Reports on development/construction of new liquefaction projects and plants Updates on siting/development/construction of new receipt terminals Information regarding regulatory proceedings Reports and news on shipping Details of contract pricing terms Review of supply/demand fundamentals Monitoring of the impact of competitive fuels Safety updates Gas quality reviews Congressional proceeding reports Updates on state and local government proceedings Details of LNG project financing Who Should Buy The liquefied natural gas market really demands attention. Market participants such as energy executives, risk managers, traders, brokers, and analysts who need to make informed and accurate decisions can rely on LNG Gas Daily every day to do business and maximize strategies within this rapidly developing marketplace. Benefits LNG Daily is an unrivalled resource that ensures comprehensive coverage, the most reliable data, and the most accurate information. With LNG Daily, you can uncover what's moving the market today for more timely and accurate decision making, better risk management results, and more profitable trading.

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Liquified Natural Gas (LNG)

> Hom e > Overview of Natural Gas > Natural Gas - From Wellhead to Burner Tip

For even more information on LNG, check out the Center for LNG.

> Business Overview > Natural Gas Regulations > Environm ent & Technology > Focus on LNG > Focus on Jobs > Natural Gas Quiz

Cooling natural gas to about -260°F at normal pressure results in the condensation of the gas into liquid form, known as Liquefied Natural Gas (LNG). LNG can be very useful, particularly for the transportation of natural gas, since LNG takes up about one six hundredth the volume of gaseous natural gas. While LNG is reasonably costly to produce, advances in technology are reducing the costs 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 construction of pipelines is uneconomical. LNG, when vaporized to gaseous form, will only burn in concentrations of between 5 and 15 percent mixed with air. In addition, LNG, or any vapor associated with LNG, will not explode in an unconfined environment. Thus, in the unlikely event of an LNG spill, the natural gas has little chance of igniting an explosion. Liquification also has the advantage of removing oxygen, carbon dioxide, sulfur, and water from the natural gas, resulting in LNG that is almost pure methane. LNG is typically transported by specialized tanker with insulated walls, and is kept in liquid form by autorefrigeration, a process in which the LNG is kept at its boiling point, so that any heat additions are countered by the energy lost from LNG vapor that is vented out of storage and used to power the vessel. The use of LNG allows for the production and marketing of natural gas deposits that were previously economically LNG Delivery Facility with Tanker unrecoverable. Imported LNG accounts for slightly more than 1 Source: NGSA percent 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 to increased domestic production, LNG imports are expected to decrease by an average annual rate of 4.1 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 in the United States. LNG takes up much less space than gaseous natural gas, allowing it to be shipped much more efficiently. LNG that is imported to the United States comes via ocean tanker. The U.S. gets a majority of its LNG from Trinidad and Tobago, Qatar, and Algeria, and also receives shipments from Nigeria, Oman, Australia, Indonesia, and the United Arab Emirates. For more information:

www.naturalgas.org/lng/lng.asp

The Center for LNG Federal Energy Regulatory Commission: LNG Interstate Natural Gas Association of America - LNG University of Houston: Commercial Frameworks for LNG in North America, Introduction to LNG Center for Energy Economics/UT-Austin: LNG Safety and Security

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Center for Energy Economics/UT-Austin: LNG Safety and Security Platts Guide to LNG LNG Safety Video U.S. LNG Markets and Uses LNG One World California Energy Commission: LNG International Liquefied Natural Gas Alliance Adventures in Energy

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