American Oil and Gas Reporter - May 2015 - 101

achieved by 2035.
Of this new supply, 16 Bcf/d is expected to come from Australia. U.S. projects are expected to add more than 14
Bcf/d to this new LNG supply base (The
United States is expected to be producing
75 percent of the world's shale gas by
2035). New projects in East Africa are
forecast to add another 12 Bcf/d to global
LNG supplies.
Based on BP's forecast, Qatar's production should level to the point of dropping into the number three slot in global
LNG exports. Meanwhile, production
from Russia, the United States, Australia
and Africa are all forecast to increase.
BP's analysis also anticipates global
LNG demand rising to meet supply at
the 80 Bcf/d level in 2035. Asia will
comprise the largest market for LNG in
the future, with about a 70 percent share.
Japan is currently the world's largest
consumer of LNG at 13 Bcf/d, and China
is right behind at 12 Bcf/d.
The United Kingdom and Western Europe have become net importers as domestic gas supplies for Europe have diminished (declining North Sea production).
At about 10 Bcf/d, these regions represent
20 percent of the world's LNG market.
Moving forward, the growth rate in
demand for LNG is expected to be about
2 percent a year, with Asia-Pacific tripling
its imports and representing 50 percent
of the global LNG market by 2035. China
and India will lead the way as the world's
number one and two economies, respectively, since their forecast economic
growth is pegged at 5.5 percent a year.
China, in particular, has begun to retire
coal-fired plants in deference to using more
natural gas in an on-going effort to reduce
pollution. Market growth for LNG also is
expected in Indonesia, Malaysia, Singapore
and Thailand, although to a lesser extent.
Pricing Mechanisms
LNG contracting varies from region
to region. The vast majority of agreements
are for longer terms and provide for
pricing based on some form of crude-indexing on an MMBtu-equivalent basis.
In Asia, LNG prices normally are tied
to a basket of crude oil indexes posted
by industry publications. In Japan, a
mechanism known as the Japanese Crude
Cocktail is used. It represents the average
price of imported crude oil officially
"cleared" by Japanese customs authorities.
Korea and Thailand also use this calculation to purchase LNG.
In most of Europe, a mix of Brent
North Sea crude oil, gasoil and fuel oil is
used to calculate the index. But for northwestern Europe and the United Kingdom,
actual natural gas prices are used. The

FIGURE 2
World LNG Estimated April 2015 Landed Prices ($/MMBtu)

Source: U.S. Energy Information Administration

United Kingdom's National Balancing
Point is a transactional point for trading
natural gas. It is similar to the New York
Mercantile Exchange's Henry Hub contract for natural gas, but without the possibility of physical delivery.
Given the oil-based pricing for much
of the world's LNG market, it's no wonder
importers are interested in natural-gasderived pricing. With the availability of
Henry Hub pricing for natural gas in the
United States, foreign LNG importers
can more readily purchase supply based
on how the commodity itself trades, and
not crude oil (Japan already has made it
known it wants to reprice some contracts
using natural gas in the mix).
However, weakening oil prices may
lessen the disparity between crude and
natural gas on an MMBtu basis. January
prices for LNG imports outside of North
America ranged from the low $8.00s in
Western Europe to $10.00 in Japan and
Korea. Forecast prices for April 2015
ranged from the $6.70s in Western Europe
to $8.00 in South America (Figure 2).
At a 12-month average price for U.S.
natural gas of $3.00 an MMBtu at Henry
Hub and liquefaction/transportation/regasification costs of about $4.10, "landed"
prices abroad have to exceed $7.10 an
MMBtu to be profitable.
There are some more inventive ways
in which LNG export projects may guarantee themselves some level of success,
other than merely selling the LNG. Foreign
markets have taken to investing in new
LNG terminal projects in the United
States, while others are entering "tolling"
arrangements. The latter agreements obligate a party to supply the natural gas to
the LNG facility and to export it once
liquefied. The operator of the terminal
receives a "toll" for providing the service.
Thus, there is no commodity price risk

for the project owners.

U.S. Infrastructure
The United States has seven import
terminals: three along the East Coast and
four in the Gulf Coast region. While not
capable of producing and exporting LNG,
these facilities have 60-70 percent of the
infrastructure in place to facilitate the
process. The terminals have the ability to
dock and offload large LNG tankers, access
to pipeline supplies, and storage capacity.
One of the myths about exporting
LNG is that the regasification (import)
terminals can simply be "turned-around"
to liquefy the gas. But import facilities
merely heat LNG back into a gas. There
are no components with which to cool
the gas to a liquid state.
The fact is, liquefaction trains are
needed and are quite capital-intensive.
In most cases, they represent 80 percent
of new infrastructure costs. Compressors
are needed to pull inlet supply from the
upstream pipelines, as well as for plant
recirculation as the gas goes through the
various stages of purification, dehydration,
and refrigeration. For example, Qatargas
has a refrigeration train process that
utilizes four gas turbines alone.
In addition to abundant supplies, the
United States has an extensive pipeline
grid, which makes access to all supply
basins a reality for LNG exporters. Large
gas storage facilities also aid in assuring
gas availability. Existing import terminals
are connected to the U.S. grid already and
could, as a result, stand the best chances
of success. This also provides them gas
that meets pipeline quality standards, saving
on treating and processing the gas stream.
Regulatory Approvals
The U.S. Department of Energy has
the authority to grant automatic permit
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American Oil and Gas Reporter - May 2015

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