Stepping on the gas
Australia
GAS
Stepping on the gas
Nic Newman looks at how Australia’s LNG sector
is restructuring its business model to cope with
changing market conditions.
A
ustralia and the US
have accounted for 75%
of the 260tn cf gain in
proven gas reserves since 2005,
according to BP figures. A decadelong investment boom in gas
exploration and development,
coupled with investments in
LNG export processing facilities,
have turned Australia into a
significant exporter. And there is
more to come – according to the
International Energy Agency’s
2016 Medium term gas market
report. Australia could add another
six new LNG export terminals
by 2020, tripling its liquefaction
capacity to over 13bn cf/d. By
2021 Australia will rival, if not
overtake, Qatar for the position of
the world’s largest LNG exporter,
whilst the US could be exporting as
much as 10bn cf/d.
The first LNG ship, the Seri
Bakti, to dock at the Santos
GLNG site on Curtis Island,
Gladstone, arrived on 28
September 2015
Source: Santos
LNG exports
Australia’s LNG plants will add
another 15mn tonnes to world
markets in 2016 alone. Over the
14 Petroleum Review | December 2016 / January 2017
last decade more than A$172bn
($132bn) has been invested in LNG
export plants located offshore on
the North West Shelf and on the
eastern coast of Australia. Nearly
half of this amount (A$80bn) was
invested by Chevron in the Gorgon
and Wheatstone LNG export
projects on the North West Shelf.
Gorgon LNG dispatched its first
cargo to Japan’s Chubu Electric
Power in March 2016. Once fully
commissioned, the project will
have a total production capacity of
about 2.6bn cf/d of natural gas and
20,000b/d of condensate. Three
other offshore projects currently
under development – Prelude,
Wheatstone and Ichthys, with a
combined capacity of 2.8bn cf/d –
are expected to come onstream in
2018.
Meanwhile, on the eastern coast
of Australia, three major LNG
plants – Queensland Curtis,
Gladstone and Australia Pacific –
are at various stages of completion.
Two trains from Queensland Curtis
and one train from Gladstone were
commissioned in 2015. In June
2016, Australia Pacific LNG
dispatched its first cargo to Japan’s
Kansai Electric Power Company. All
three LNG plants are designed to
process coalbed methane (CBM)
into liquid natural gas for export.
They have a current combined
capacity of around 2.3bn cf/d,
which should reach 3.4bn cf/d once
fully completed in 2018.
Over 90% of gas from Australian
LNG plants is forward-sold on
long-term contracts to Asian
markets, most notably Japan,
China, India, South Korea and
Taiwan, according to an Oxford
Institute for Energy Studies (OIES)
2014 study entitled The future of
Australian LNG exports. Japan and
China, currently Australia’s main
markets, have contracted for 79%
and 15% respectively of current
Australian LNG exports, but for
only 35% and 23% respectively of
new LNG plant supplies, according
to the EIA. As a result, export plants
coming onstream in the future will
have to look for new customers,
possibly in competition with new
US suppliers.
Market issues
According to Graeme Bethune,
Chief Executive Officer,
EnergyQuest, Australia’s LNG
plants are comparatively
unscathed by the current supply
glut. They are ‘competing fine so
far (only one US cargo has been
shipped so far to north Asia)
[with output] largely contracted
to major credit-worthy buyers,
while no project from east Africa
has reached FID [final investment
decision],’ he says. Nevertheless,
the strains are beginning to show
with 40% fall in LNG spot market
prices in spring 2016. Indeed,
the entire east coast onshore gas
export industry of Australia may
currently be running at a loss,
suggest some industry insiders.
In Western Australia, the
A$40bn Browse LNG project has
been cancelled, due to low LNG
prices and insufficient interest
from potential customers willing
to sign long-term contracts.
The high cost of LNG export
plants, especially those located
offshore, has not helped. A 2013
McKinsey study identified cost
Australia
overruns of 20% to 30% as a major
Australian problem. For example,
the Gorgon LNG plant is now
A$17bn over budget. At the time
the FID was announced in 2009 no
one had foreseen the prospect, let
alone the scale, of US LNG exports
onto world markets.
Investors and operators in new
and planned LNG export plants are
vulnerable to being caught
between falling LNG prices, high
and escalating costs of bringing
their projects to fruition, lower
than expected demand and
competition from new supply. A
case in point is the delay of the
A$34bn offshore Ichthys LNG plant
near Darwin, a joint venture
between American, Japanese and
Australian companies, following
contract disagreements.
According to the IEA,
liquefaction capacity will increase
by 45% between 2015 and 2021, of
which Australia and the US will
account for 90% of new LNG
exports. The current mismatch
between demand and supply will,
therefore, be exacerbated by this
large wave of new supplies
expected in the next five years and
by the slowing down of demand
from China and a decline from
Japan as it returns to nuclear
power. In conditions of a supply
glut, new customers, unlike their
predecessors, may be reluctant to
lock themselves into long- term
contracts at a specified price, thus
creating additional uncertainty for
forthcoming new supplies.
market prices in Tokyo of $8.42/GJ,
whereas the Adelaide spot price
was $13.90/GJ, reported Renew
economy in September 2016.
Meanwhile, according to a report
by Credit Suisse Bank, the APA
Group’s pipelines are ‘over-earning’
by between 30% and 80% against
the theoretical regulated revenue
level reports. ‘Few of APA’s assets
are subject to significant
regulatory oversight, despite the
fact that very little pipe-on-pipe
competition exists and that high
greenfield capital costs and low
brownfield costs effectively
entrench it as the monopoly
provider in most cases,’
commented Credit Suisse analyst
Peter Wilson in a research note.
Regulations not fit-for-purpose
Currently, Australia’s 20,000 miles
of gas pipeline networks are largely
unregulated since access terms and
pricing were determined in longterm contracts made between the
pipeline operator and gas producer.
Three quarters of Australia’s gas
pipeline network is owned by one
company, APA Group, which has
acknowledged that only about 10%
of its A$2.1bn pipeline revenues
are subject to regulation. Under
current law, for a pipeline to be
regulated, it must be proved that
access is required to promote a
material increase in competition
in the upstream or downstream
markets. It does not matter at
all whether monopolistic price
gouging exists. Unsurprisingly,
downstream gas retailers such
as Santos, Origin Energy and
Closer to home
AGL have not mounted a legal
Meanwhile, Australia’s domestic
challenge, since on these terms
gas customers are at the receiving
they have been unlikely to win.
end of uncompetitive market
However, ACCC Chairman Rod
structures, inadequate regulation
Sims has taken up this issue. He
and lack of transparency. A key
said in September 2016: ‘A new test
issue arises from the lack of
is needed to consider three issues
competition amongst upstream
– whether a pipeline has
gas suppliers and gas pipeline
substantial market power, whether
companies. The East Coast, the
that market power is likely to
biggest market in Australia,
continue, and whether regulation
consumes some 700 petajoules
will promote economic efficiency.’
(PJ) of gas annually, according to
Whilst his views have political
the Financial Review in September
2016, and is largely supplied by one support, it may take at least five
years before any new legislation is
pipeline company, the APA.
fully implemented. As Bethune
According to EnergyQuest’s
observes: ‘This seems to assume
Bethune: ‘There is currently a lack
that there should be some
of competition in east coast
domestic gas reservation policy
upstream supply for domestic
which has been firmly rejected by a
industrial buyers’, which may
number of federal government
explain complaints of price
inquiries.’
gouging. It is also a sign of weak
regulation, which has allowed the
Domestic gas shortages?
country’s dominant gas suppliers
Gas-rich Australia’s domestic
and pipeline operators to force up
market customers face prospective
gas prices. Indeed, Australians are
shortages in supply as domestic
paying more for their gas than
customers in Japan are. In July, the supplies are diverted to LNG
export projects, while existing
Japanese Ministry of Economy,
and prospective low gas prices
Trade and Industry reported spot
By 2021 Australia
will rival, if not
overtake, Qatar for
the position of the
world’s largest
LNG exporter,
whilst the US could
be exporting as
much as 10bn cf/d
reduce the incentive and ability
of producers on the east coast
to explore and develop new gas
resources. For example, gas from
traditional sources of domestic
supply including output from the
Cooper Basin in South Australia is
being diverted to Gladstone LNG
facilities, whilst Origin Energy
has cancelled plans to develop
800 PJ of coal seam gas, enough
to supply New South Wales for
eight years. Meanwhile, the
upstream gas industry has been
hit by a moratorium on onshore
gas exploration and development,
and there are other regulatory
restrictions in New South Wales,
Victoria and Tasmania, and
potentially the Northern Territory,
according to ABC reports in April
2016.
As a result, the main source of
gas for South Eastern Australia lies
offshore in the Bass Strait, between
Victoria and Tasmania. The
Northern Territories state
government has promoted one
solution to the expected gas
shortages facing eastern markets,
also arguing that this would
improve energy security and
competition. It proposes using gas
from the soon to be opened Ichthys
LNG project located in the Browse
Basin in Western Australia for
delivery to eastern Australian
markets. It envisages using a mix
of existing, planned and proposed
pipelines. At present Ichthys LNG is
being linked to Darwin by a
900-km subsea gas export pipeline
to an LNG export terminal in
Darwin. Instead of exporting the
gas overseas, the government
proposes to send gas south to
Tennent Creek near Alice Springs,
from there it intends building a
new A$1.3bn, 1,000-km pipeline
that would join the Eastern
pipeline network at Mount Isa in
Queensland. At Mount Isa, the gas
would be distributed to east coast
markets. Industry insiders also
suggest that such a pipeline project
could double the amount of
onshore gas reserves that could be
fracked in the Northern Territories
to around 40tn cf.
Looking ahead
Market prospects would seem
problematic for Australia’s
new LNG export plants given
foreseeable persistent oversupply,
possible further price falls and
competition from the US. However,
new customers in South Africa,
India and the Middle East should
represent an opportunity. As for
the domestic market, the threat
and, indeed, the actuality of
gas shortages will have to be
resolved. ●
Petroleum Review | December 2016 / January 2017 15