American Oil and Gas Reporter - October 2015 - 53

SpecialReport: LNG & Market Update
dexed to oil are certainly more competitive with Henry Hub-indexed LNG prices.
For another, the 2014-15 lull in LNG demand growth continues, even as a long list
of mostly U.S. and Australian LNG export
projects are poised to begin operation.
That said, however, long-term LNG demand is expected to rise at an annual rate
of 5 percent or more, with most of the
growth coming in Asia (Figure 2). In time,
it is likely that growing demand will absorb all the new liquefaction export capacity coming on line over the next five years,
and could lead to the development of additional North American projects (including some on the U.S. West Coast and
in British Columbia).
Certainly, in an increasingly liquid,
competitive and lower-margin market,
that the most successful natural gas producers and LNG exporters will be those
that offer ample gas supplies, low-cost gas
production, supportive pipeline infrastructure, competitive liquefaction costs,
easy access to multiple markets, and destination flexibility. The U.S. production
and liquefaction/export sectors appear to
offer these benefits, as well as the bonus
of LNG prices tied to U.S. natural gas.
The prospects for U.S. gas pro ducers/LNG exporters appear to stack up
well against both Qatar (the biggest existing player in LNG supply) and Australia
(which, along with the United States, is the

FIGURE 1
Global LNG Price Trends
22
20
18
16

Long-term
contract price

Asia spot price
JCC (crude oil)

12
10
8

2014
Source: BG Group

Jul

Jun

May

Apr

Mar

Feb

Jan

Dec

Nov

Oct

Sep

Aug

Jul

Jun

May

Apr

Mar

Feb

NBP + shipping

Jan

International LNG Market
The international LNG market has
experienced dramatic change in recent
years. LNG demand spiked in Japan, already the world's largest LNG consumer,
in the aftermath of the 2011 Fukushima nuclear disaster. By early 2014, Japanese and
other Asian buyers were paying more than
$18 an MMBtu for LNG, partly because
long-term supply deals were indexed to
then-high crude oil prices and partly because LNG demand was outstripping
supply.

However, Asian demand began to sag
in late 2014 as a result of high LNG prices,
mild weather, Korean nuclear unit startups, declining oil prices, and new supply
from the startup of new liquefaction export projects in Papau New Guinea and
Australia (Figure 1). Suddenly, it became a buyer's market, with spot prices
dropping to less than $8/MMBtu.
Even before that price decline, U.S. developers building the first round of lower-48 liquefaction/export facilities had
already rattled the international LNG
market. Among other things, they linked
their LNG prices to relatively low-cost
U.S. natural gas and not to global crude oil
prices, as had been the LNG industry's
practice for decades. Moreover, in many
cases, unlike most international LNG
deals, U.S. exporters give buyers the
"destination flexibility" to ship LNG anywhere they want, and not only to specific ports.
Thanks to the soon-to-be-expanded
Panama Canal, the United States is wellpositioned on the map to serve both Asia
and Europe. Moreover, liquefaction fees
at U.S. plants generally are less than other facilities around the world because of
the projects' lower development costs.
These factors would seem to give the
United States a leg up in the competition
for LNG, but other factors are at play. For
one, at today's oil prices, LNG prices in-

Price ($/MMBtu)

All four of these multibillion-dollar liquefaction/export terminals previously
were LNG import facilities developed before the shale era. Consequently, most of
the dock facilities and other infrastructure
is already in place, providing a capital-cost
edge that enables the projects to offer attractively low liquefaction tolling fees and
to reach long-term deals with international off-takers.
All four also have solid financial foundations. Most of the LNG buyers are obligated under the terms of take-or-pay contracts to compensate project developers for
the capacities they hold under contract,
even if buyers do not use those capacities.
The degree to which liquefaction/export
capacities are used will depend, in part, on
provisions in the export contracts and on
how competitive U.S.-sourced LNG will
be on the international market.
In addition to the four projects converted from previous LNG landing facilities,
even more "green field" LNG export capacity is in various stages of construction
and permitting. For example, Cheniere Energy's Corpus Christi, Tx., facility is
scheduled for startup by early 2019. With
five planned trains, Corpus Christi ultimately will require 3.2 Bcf/d of gas supply (22.5 MTPA total capacity). The six
planned liquefaction trains at Cheniere's
Sabine Pass will demand nearly 4.0 Bcf/d
(27 MTPA total capacity), beginning
with 650 million cubic feet a day for the
first train. When operating at full capacity, these two plants alone represent a demand load equal to roughly 10 percent of
current daily U.S. gas production.
Despite a pullback in drilling activity
and lower prices in recent years, lower-48
U.S. gas production (after extraction of natural gas liquids) is averaging about 73
Bcf/d-45 percent higher than 10 years
ago-and there is no reason production
could not continue to grow to supply LNG
export facilities.

2015

OCTOBER 2015 53

American Oil and Gas Reporter - October 2015

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